WASHINGTON, D.C. 20549
For the transition period from . . . . to . . . .
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.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
This Form 10-Q contains “forward-looking statements” as defined by the Securities and Exchange Commission (“SEC”). Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:
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.
All forward-looking statements contained in this Form 10-Q only speak as of the date of this document. We undertake no obligation to update or revise publicly any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this Form 10-Q, or to reflect the occurrence of unanticipated events.
The financial statements include the accounts of Frontier Oil Corporation (“FOC”), a Wyoming corporation, and its wholly-owned subsidiaries, collectively referred to as “Frontier” or “the Company”. The Company is an energy company engaged in crude oil refining and wholesale marketing of refined petroleum products (the “refining operations”).
The Company operates refineries (“the Refineries”) in Cheyenne, Wyoming and El Dorado, Kansas. 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. The Company’s investment in 8901 Hangar, Inc. was $99,000 and $95,000 at March 31, 2006 and December 31, 2005, respectively, and is included in “Other assets” on the Consolidated Balance Sheets. The Company also owned, until its sale as of November 30, 2005, FGI, LLC, an asphalt terminal and storage facility in Grand Island, Nebraska. The activities of FGI, LLC have been included in the consolidated financial statements since December 1, 2003, when the Company increased its ownership from 50% to 100%, through November 30, 2005. All of the operations of the Company are in the United States, with its marketing efforts focused in the Rocky Mountain and Plains States regions of the United States. The Rocky Mountain region includes the states of Colorado, Wyoming, Montana and Utah, and the Plains States include the states of Kansas, Oklahoma, 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. The financial statements included herein should be read in conjunction with the financial statements and the notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2005.
Earnings per share (“EPS”) has been computed based on the weighted average number of common shares out-standing. No adjustments to income are used in the calculation of earnings per share. The basic and diluted average shares outstanding are as follows:
For the three months ended March 31, 2006 and 2005, there were no outstanding stock options that could potentially dilute EPS in future years that were not included in the computation of diluted EPS (as the exercise prices were all under the average market price for the period).
The Company’s Board of Directors declared both a special cash dividend of $1.00 per share and a regular quarterly cash dividend of $0.04 per share in December 2005, which were paid in January 2006. In addition, a quarterly cash dividend of $0.04 per share was declared in March 2006 and paid in April 2006. The total cash required for the dividend declared in March 2006 was approximately $2.3 million and was reflected as “Accrued dividends” on the Consolidated Balance Sheet as of March 31, 2006.
Related party transaction
As of March 31, 2006 and December 31, 2005, the Company had an outstanding relocation-related loan to a non-officer employee in the amount of $300,000, which is included in “Other receivables” on the Consolidated Balance Sheets. This loan matures in November 2006.
New accounting pronouncements
The Emerging Issues Task Force (“EITF”) reached a consensus on Issue No. 04-13 (“Issue”), “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” and the FASB ratified it on September 28, 2005. This Issue addresses accounting matters that arise when one company both sells inventory to and buys inventory from another company in the same line of business, specifically, when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The consensus in this Issue is to be applied to new arrangements entered into in reporting periods beginning after March 15, 2006. The Company has certain crude oil procurement and product exchange transactions that it accounts for on a net cost basis. The Company does not believe that its revenues or cost of sales will be materially affected by applying the Issue’s consensus.
On September 30, 2005, the Financial Accounting Standards Board (“FASB”) issued a revision for an Exposure Draft issued on December 15, 2003, that would amend Financial Accounting Standards (“FAS”) No. 128, “Earnings per Share”, to clarify guidance for mandatorily convertible instruments, the treasury stock method, contracts that may be settled in cash or shares, and contingently issuable shares. The proposed statement, originally issued in December 2003, has been reissued due to the significance of changes to the computational guidance applicable to the treasury stock method. The proposed statement would be effective for interim and annual periods ending after June 15, 2006. The Company is currently evaluating the provisions that this proposed statement would have on its earnings per share calculations.
An exposure draft “Accounting for Uncertain Tax Positions - An Interpretation of FAS No. 109, Accounting for Income Taxes”, was issued by the FASB on July 14, 2005. The proposed interpretation is intended to reduce the significant diversity in practice associated with recognition and measurement of income taxes by establishing consistent criteria for evaluating uncertain tax positions in the areas of recognition, measurement, derecognition, financial statement classification and disclosure. This exposure draft would be effective as of the beginning of the first annual period beginning after December 15, 2006. The final interpretation is expected to be issued in the second quarter of 2006. The Company is in the process of evaluating the provisions of this exposure draft.
On March 8, 2006, the FASB met to discuss the accounting for planned major maintenance activities (“turnarounds”). Currently there are four alternative accounting methods for turnarounds: direct expense, built-in overhaul, deferral and accrual. At this meeting, the FASB determined they would issue guidance in the form of a FASB Staff Position (“FSP”) to eliminate the accrual method of accounting for turnarounds. At an April 19, 2006 meeting, the FASB concluded the proposed FSP would require the adoption of the provisions as a change in accounting principle through retrospective application as described in SFAS 154 “Accounting Changes and Error Corrections”. The FASB is expected to issue a proposed FSP in early June 2006 with an effective date for fiscal years beginning after December 15, 2006. The Company currently accounts for turnarounds on the accrual method and is currently evaluating the provisions of this proposed FSP, which will require the Company to adopt an alternative method should the FSP be finalized.
The FASB issued an exposure draft on March 31, 2006, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”, which includes proposed amendments to FAS No. 87, “Employers’ Accounting for Pensions”, FAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”, and FAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits. The comment period for this exposure draft ends May 31, 2006. The objective of this project is to comprehensively reconsider guidance in order to improve the reporting of pensions and other postretirement benefit plans in the financial statements by making information more useful and transparent for investors, creditors, employees, retirees, donors, and other users. The first phase includes improving the reporting of employers’ obligations for pensions and other postretirement benefits by recognizing the over- or under-funded status of defined postretirement plans as an asset or a liability in the statement of financial position. Currently, the exposure draft does not change how plan assets and benefit obligations are measured under FAS No. 87 and FAS No. 106, or the basic approach for measuring the amount of annual net benefit cost reported in earnings. The FASB expects the effective date for the first phase to be for fiscal years ending after December 15, 2006. The Company is currently evaluating the provisions of this exposure draft.
2. Inventories
Inventories of crude oil, unfinished products and all finished products are recorded at the lower of cost on a first-in, first-out (“FIFO”) basis or market. Crude oil includes both domestic and foreign crude oil volumes at its cost and associated freight and other cost. Unfinished products (work in process) include any crude oil that 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 components of raw material, the associated raw material freight and other costs, and direct refinery operating expense allocated when refining begins relative to their proportionate market values. Refined product exchange transactions are considered asset exchanges with deliveries offset against receipts (See Note 1 “New accounting pronouncements” above for a discussion of EITF Issue No. 04-13). The net exchange balance is included in inventory. Inventories of materials and supplies and process chemicals are recorded at the lower of average cost or market.
Components of inventory | |
| | | March 31, | | December 31, | |
| | | 2006 | | 2005 | |
| | | (in thousands) | |
| Crude oil | | $ | 132,529 | | $ | 97,766 | |
| Unfinished products | | | 75,130 | | | 53,200 | |
| Finished products | | | 83,485 | | | 75,790 | |
| Process chemicals | | | 6,224 | | | 5,441 | |
| Repairs and maintenance supplies and other | | | 16,105 | | | 15,424 | |
| | | $ | 313,473 | | $ | 247,621 | |
3. Treasury Stock
The Company accounts for its treasury stock under the cost method on a FIFO basis. The Company has a Board of Directors’ approved stock repurchase program for up to 16 million shares of the Company’s common stock. On November 30, 2005, the Company’s Board of Directors confirmed utilizing up to $100 million for share repurchases under this program. The Company may repurchase its common stock under this program from time to time in the open market depending on price, market conditions and other factors. As of March 31, 2006, $14.1 million (349,294 shares) of the $100 million had been utilized for repurchases, of which $6.4 million (153,494 shares) was purchased in the three months ended March 31, 2006. An additional $1.9 million of cash was paid during the quarter ended March 31, 2006 to settle purchases made at the end of 2005. Through March 31, 2006, 9,609,026 shares of common stock had been purchased under the stock repurchase program. During the three months ended March 31, 2006, the Company received 21,821 shares ($1.2 million) of its stock, which became treasury stock, from stock surrendered by employees to pay their withholding taxes on shares of restricted stock that vested during the first quarter. The Company issued 194,923 shares of its treasury stock as restricted stock (see Stock-based Compensation below) during the quarter ended March 31, 2006. As of March 31, 2006, the Company had 10,445,806 shares of treasury stock.
4. Stock-based Compensation
Effective January 1, 2006, the Company adopted FAS No. 123(R), “Share-Based Payment” which requires companies to recognize the fair value of stock options and other stock-based compensation in the financial statements. The Company adopted FAS No. 123(R) using the modified prospective application method, and accordingly prior period amounts have not been restated. At March 31, 2006, the Company had two share-based compensation plans; a stock plan and a restricted stock plan (nonvested stock), which are discussed below. Upon adoption of FAS No. 123(R), deferred compensation recorded as contra-equity in prior periods was eliminated against the appropriate equity accounts. In the first quarter of 2006, the adoption of FAS No. 123(R) resulted in incremental stock-based compensation expense of $850,000, resulting in a decrease in income before income taxes by that amount. The incremental stock-based compensation expense also caused net income to decrease $527,000 and basic earnings per share to decrease by $0.01, but resulted in no change to diluted earnings per share. Cash provided by operating activities decreased $4.8 million and cash provided by financing activities increased by the same amount due to excess income tax benefits from stock-based payment arrangements. Compensation costs and income tax benefits recognized in the statements of income for the three months ended March 31, 2006 and 2005 are as follows (* including $935,000 additional restricted stock plan expense due to the 2006 retirement of one of the Company’s executive officers) :
| | |
| | | Three months ended March 31, | |
| | | 2006 | | 2005 | |
| | | (in thousands) | |
| Stock plan: | | | | | |
Restricted stock units | | $ | 88 | | $ | - | |
Stock options | | | 236 | | | - | |
Stock grant to retiring executive | | | 90 | | | - | |
Total stock plan | | | 414 | | | - | |
| Restricted stock plan * | | | 2,145 | | | 266 | |
| Total compensation expense | | $ | 2,559 | | $ | 266 | |
| | | | | | | | |
| Income tax benefit recognized in the income statement | | $ | 972 | | $ | 101 | |
Stock plan
At March 31, 2006, the Company had a stock plan (“Plan”), which authorized the granting of stock-based awards, including options to purchase shares, to employees and non-employee members of the Company’s Board of Directors. The Plan through March 31, 2006, had reserved for new share issuance a total of 7,200,000 shares of common stock based awards, of which only 158,385 remained available for grant. Stock options are issued at the current market price of the Company’s common stock on the date of grant and generally, vest ratably over three years and expire after five years. The grant date fair value is calculated using the Black-Scholes option pricing model. For the weighted-average assumptions used in the Black-Scholes option pricing model for grants made in 2004 and prior years, please refer to the Company’s annual report on Form 10-K for the year ended December 31, 2005. No options were granted in 2005 and no options were granted during the three months ended March 31, 2006; however, a stock grant of 1,515 shares was made valued at $90,000.
During 2005, 56,000 nonvested restricted stock units were granted to non-employee members of the Board of Directors. At March 31, 2006, there were 48,000 restricted stock units outstanding as 8,000 restricted stock units vested during the third quarter of 2005 upon the death of a member of the Company’s Board of Directors. Restricted stock units, when granted, are valued at the current market price of the Company’s common stock on the grant date and amortized to compensation expense over the respective vesting periods of the restricted stock units. The restricted stock units vest three years after issuance.
As of March 31, 2006 there was $786,000 of total unrecognized compensation cost related to the Plan, including both the stock options and restricted stock units, which is expected to be recognized over a weighted-average period of 1.7 years.
Previously, the Company accounted for stock-based compensation in accordance with APB Opinion No. 25. Had compensation costs for share awards been determined based on the fair value at grant dates and amortized over the vesting period pursuant to FAS No. 123, the Company’s income and EPS would have been the pro forma amounts listed in the following table for the three months ended March 31, 2005. The pro forma compensation expense for the three months ended March 31, 2005 includes amortization for options granted in 2004, 2003 and 2002.
| | | Three Months Ended March 31, 2005 | |
| | | (in thousands, except per share amounts) | |
| Net income as reported | | $ | 34,436 | |
| Pro forma compensation expense, net of tax | | | (478 | ) |
| Pro forma net income | | $ | 33,958 | |
Basic EPS: | | | | |
As reported | | $ | 0.64 | |
Pro forma | | | 0.63 | |
Diluted EPS: | | | | |
As reported | | $ | 0.62 | |
Pro forma | | | 0.61 | |
Changes during the three months ended March 31, 2006 in the Plan are presented below:
| | | Number of Awards | | Weighted-Average Exercise Price | | Aggregate Intrinsic Value of Options (in thousands) | |
| Outstanding at beginning of period | | | 738,850 | | $ | 8.70 | | | | |
| Granted | | | 1,515 | | | n/a | | | | |
| Exercised or issued | | | (248,315 | ) | | 8.94 | | | | |
| Expired | | | - | | | - | | | | |
| Outstanding at end of period | | | 492,050 | | | 8.57 | | $ | 22,548 | |
Exercisable at end of period | | | 425,300 | | | 8.54 | | | 21,610 | |
| Available for grant at end of period | | | 158,385 | | | | | | | |
Weighted-average fair value of options granted during the period | | | - | | | - | | | | |
The Company received $2.2 million of cash for options exercised during the three months ended March 31, 2006 ($2.1 million in the quarter ended March 31, 2006 and the remaining amount in April 2006). The total intrinsic value of options exercised during the three months ended March 31, 2006 was $11.2 million. The Company realized $4.3 million of income tax benefits during the three months ended March 31, 2006, related to the exercises and the stock grant from the Plan, nearly all of which was excess income tax benefits. Excess income tax benefits are the benefits from additional deductions allowed for income tax purposes in excess of expenses recorded in the financial statements. These excess income tax benefits are recorded as an increase to paid-in capital.
The following table summarizes information about stock options and other stock-based awards outstanding at March 31, 2006:
Stock-based Awards Outstanding at March 31, 2006 |
Number Outstanding | | Weighted-Average Remaining Contractual Life (Years) | | Exercise Price | | Exercisable |
| 369,550 | | 1.89 | | $ 8.325 | | 369,550 |
| 52,500 | | 2.91 | | 9.325 | | 33,750 |
| 22,000 | | 1.04 | | 10.925 | | 22,000 |
| 48,000 | | 2.07 | | n/a | | n/a |
Restricted stock plan
On March 13, 2001, the Company established the Frontier Oil Corporation Restricted Stock Plan (the “Restricted Stock Plan”), which reserved 2,000,000 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 valued at the market value on the date of issuance and amortized to compensation expense on a straight-line basis over the nominal vesting period of the stock, and for restricted stock issuances subsequent to the adoption of FAS No. 123(R), adjusted for retirement eligible employees, as required. For awards granted prior to the adoption of FAS No. 123(R), $478,000 of compensation cost was recognized during the three months ended March 31, 2006, and continues to be recognized over the nominal vesting period. The shares have vesting periods from issue ranging from one to three years. The following table summarizes the Company’s Restricted Stock Plan as of March 31, 2006 and changes during the three months ended March 31, 2006.
Restricted Stock Shares | Shares | Weighted-Average Grant-Date Market Value |
| Nonvested at January 1, 2006 | 159,846 | $ 16.55 |
| Granted | 194,923 | 51.97 |
| Vested | (64,298) | 25.73 |
| Forfeited | - | - |
| Nonvested at March 31, 2006 | 290,471 | 38.29 |
| | | |
As of March 31, 2006, there was $10.0 million of total unrecognized compensation cost related to the Restricted Stock Plan and is expected to be recognized over a weighted-average period of 1.9 years. The total fair value of shares vested during the three months ended March 31, 2006 was $3.5 million. The Company realized $1.3 million of income tax benefits related to the vesting of restricted stock during the three months ended March 31, 2006, of which $707,000 was excess income tax benefits.
5. Employee Benefit Plans
The Company established a defined benefit cash balance pension plan, effective January 1, 2000, for eligible El Dorado Refinery employees to supplement retirement benefits that those employees lost upon the purchase of the El Dorado Refinery by Frontier. No other current or future employees are eligible to participate in the plan. This plan had assets of $8.3 million at December 31, 2005, and its funding status is in compliance with ERISA.
The Company provides post-retirement healthcare and other benefits to certain employees of the El Dorado Refinery. Eligible employees are those hired by the El Dorado Refinery before certain defined dates and who satisfy certain age and service requirements. Employees hired on or before November 16, 1999 qualify for retirement healthcare insurance until eligible for Medicare. Employees hired on or before January 1, 1995 are also eligible for Medicare supplemental insurance. These plans had no assets as of March 31, 2006 or December 31, 2005. The post-retirement health care plan requires retirees to pay between 20% and 40% of total health care costs based on age and length of service. The plan’s prescription drug benefits are at least equivalent to the new Medicare Part D benefits.
The following table set forth the amounts recognized for these benefit plans in the Company’s consolidated statements of income for the three months ended March 31, 2006 and 2005:
| | | Pension Benefits | | Post-retirement Healthcare and Other Benefits | |
| | | 2006 | | 2005 | | 2006 | | 2005 | |
Components of net periodic benefit cost: | | (in thousands) | |
| Service cost | | $ | - | | $ | - | | $ | 313 | | $ | 216 | |
| Interest cost | | | 136 | | | 158 | | | 564 | | | 365 | |
| Expected return on plan assets | | | (167 | ) | | (120 | ) | | - | | | - | |
| Amortization of prior service cost | | | - | | | - | | | - | | | - | |
| Recognized net actuarial loss | | | - | | | 5 | | | 371 | | | 122 | |
| Net periodic benefit cost | | $ | (31 | ) | $ | 43 | | $ | 1,248 | | $ | 703 | |
As of March 31, 2006, the Company had contributed $270,000 to its pension plan in 2006 and expects to make additional contributions in the subsequent quarters of 2006.
6. Price Risk Management Activities
The Company, at times, enters into commodity derivative contracts to manage its price exposure to its inventory positions, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on certain future production. The commodity derivative contracts used by the Company may take the form of futures contracts, collars or price swaps and are entered into with credit worthy counterparties. The Company believes that there is minimal credit risk with respect to its counterparties. 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 under FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” 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, while gains and losses on transactions accounted for using mark-to-market accounting are reflected in “Other revenues” at each period end. The market value of open derivative contracts is included on the Consolidated Balance Sheets in “Accrued liabilities and other” when the unrealized value is a loss ($6.2 million and $854,000 at March 31, 2006 and December 31, 2005, respectively) or in “Other current assets” when the unrealized value is a gain.
Mark-to-market activities
During the three months ended March 31, 2006 and 2005, the Company had the following derivative activities which, while economic hedges, were not accounted for as hedges and whose gains or losses are reflected in “Other revenues” on the Consolidated Statements of Income:
| · | Crude purchases in-transit. As of March 31, 2006, the Company had open derivative contracts on 48,000 barrels of crude oil to hedge in-transit Canadian crude oil costs for the El Dorado Refinery. At March 31, 2006, these positions had a $146,000 unrealized loss. During the three months ended March 31, 2006, the Company recorded $1.3 million in net gains on positions to hedge in-transit Canadian crude oil for the El Dorado Refinery. During the three months ended March 31, 2005, the Company had no derivative contracts for this purpose. |
| · | Derivative contracts on crude oil to hedge excess intermediate, finished product and crude oil inventory for both the Cheyenne and El Dorado Refineries. As of March 31, 2006, the Company had open derivative contracts on 665,000 barrels of crude oil to hedge crude oil, intermediate and finished product inventories. At March 31, 2006, these positions had net unrealized losses of $1.7 million. During the three months ended March 31, 2006, the Company recorded $2.1 million in net realized gains on these types of positions. During the three months ended March 31, 2005, the Company recorded $585,000 in losses on these types of positions. |
Hedging activities
During the three months ended March 31, 2006, the Company had the following derivatives which were appropriately designated and accounted for as hedges.
| · | Crude purchases in-transit. As of March 31, 2006, the Company had open derivative contracts on 1,417,000 barrels of crude oil to hedge in-transit Canadian crude oil costs for the El Dorado Refinery, which are being accounted for as fair value hedges. At March 31, 2006, these positions had nearly $4.3 million in unrealized losses, of which $7.2 million increased the related crude oil in-transit inventory to fair market value, offset by $2.9 million which increased income and was reflected in “Other revenues” in the Consolidated Statements of Income for the ineffective portion of this hedge. During the three months ended March 31, 2006, the Company recorded $344,000 in realized losses on derivative contracts to hedge in-transit Canadian crude oil for the Cheyenne Refinery of which $522,000 increased crude costs (“Raw material, freight and other costs”), offset by $178,000 which increased income and was reflected in “Other revenues” in the Consolidated Statements of Income for the ineffective portion of this hedge. |
During the three months ended March 31, 2005, the Company had no derivative contracts that were designated and accounted for as hedges.
7. 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”) has 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. The Company has, in recognition of the EPA’s reinterpretation of certain regulatory requirements associated with the Initiative, determined that Frontier will incur expenditures totaling approximately $9.2 million to further reduce emissions from the Refineries’ flare systems. At the Cheyenne Refinery, the Company estimates spending $4.7 million on the flare system, of which $223,000 was spent in 2004, $4.1 million in 2005 and the remaining $350,000 was incurred in the first quarter of 2006. At the El Dorado Refinery, the Company spent $1.2 million in prior years, and it estimates incurring $3.3 million during 2006, on the flare system. In addition to Frontier’s expenditures, Shell Oil Products US (“Shell”) is expected to contribute $5.0 million for modification of the El Dorado Refinery flare system in accordance with certain provisions of the 1999 asset purchase and sale agreement for the El Dorado Refinery entered into between Frontier and Shell.
Although the Company has not received any formal notice of any violation of any of the following regulatory requirements, EPA Headquarters has recently stated their expectation that all domestic refineries, including both of the Company’s Refineries, enter into Consent Decrees to address all four of the EPA’s “marquee” regulatory programs. These programs are:
| · | New Source Review (“NSR”) - a program requiring permitting of certain facility modifications, |
| · | New Source Performance Standards - a program establishing emission standards for new emission sources as defined in the regulations, |
| · | Benzene Waste National Elimination System for Hazardous Air Pollutants (“NESHAPS”) - a program limiting the amount of benzene allowable in industrial wastewaters, and |
| · | Leak Detection and Repair (“LDAR”) - a program designed to control hydrocarbon emissions from refinery pipes, pumps and valves. |
Settlement negotiations with the EPA and state regulatory agencies regarding these items are underway. The Company now estimates that capital expenditures totaling approximately $30 million at each of its Refineries, in addition to the flare gas recovery projects discussed above, will be required prior to 2013 to satisfy these issues. Notwithstanding these anticipated legal settlements, many of these same expenditures would be required for the Company to implement its planned facility expansions. Previous settlements between the EPA and other refiners have required monetary penalties in addition to capital expenditures. While the EPA has not yet proposed monetary penalties for Frontier, it is possible that such penalties may be imposed; however, the amount of any potential penalties is not currently estimatable.
The EPA has promulgated regulations requiring 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 its small refinery interim gasoline sulfur standard at each of the Refineries until 2011 and to comply with the highway diesel sulfur standard by June 2006, as discussed below. The Cheyenne Refinery has spent approximately $28.9 million (including capitalized interest) to meet the interim gasoline sulfur standard, which was required by January 1, 2004. An additional $7.0 million in estimated costs to meet the final standard, and an additional $6.0 million for facilities to handle intermediate inventories, for the Cheyenne Refinery are expected to be incurred between 2008 and 2010. The total capital expenditures estimated as of March 31, 2006, for the El Dorado Refinery to achieve the final gasoline sulfur standard are approximately $21.0 million, and are expected to be incurred between 2007 and 2009.
The EPA has promulgated regulations that will limit the sulfur content of highway diesel fuel beginning in mid-2006. As indicated above, Frontier has elected to comply with the highway diesel sulfur standard by June 2006. As of March 31, 2006, capital costs, including capitalized interest, for diesel desulfurization are expected to be approximately $106.5 million for the El Dorado Refinery and approximately $16.6 million for the Cheyenne Refinery. The expenditures, including capitalized interest, for the ultra low sulfur diesel projects through March 31, 2006 (including 2004, 2005 and first quarter 2006 expenditures) were $88.0 million (including $10.2 million in the first quarter of 2006) at the El Dorado Refinery and $10.8 million (including $4.6 million in the first quarter of 2006) at the Cheyenne Refinery. The remaining costs for the ultra low sulfur diesel projects at both Refineries will be incurred before mid-2006. Certain provisions of the American Jobs Creation Act of 2004 are providing federal income tax benefits to 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 income tax credit on compliant diesel fuel produced up to an amount equal to the remaining 25% of these qualified capital costs.
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 (“bpd”) of non-road diesel fuel from the 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 but locomotive and marine uses. 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. The loss of such status through merger, acquisition or non-compliance with the enabling regulations could result in the loss of the benefits described in the above paragraphs and the possible acceleration of certain associated expenditures.
As is the case with companies engaged in similar industries, the Company faces potential exposure from future claims and lawsuits involving environmental matters, including 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 investigation and interim remediation actions at the Cheyenne Refinery’s property that may have been impacted by past operational activities. As a result of past and ongoing investigative efforts, capital expenditures and remediation of conditions found to exist have already taken place, including the completion of surface impoundment closures, waste stabilization activities and other site remediation projects totaling approximately $4.0 million. In addition, the Company estimates that an ongoing groundwater remediation program averaging approximately $200,000 in annual operating and maintenance costs will be required for approximately ten more years. As of March 31, 2006, the Company has a reserve included in “Other long-term liabilities” of $1.5 million in environmental liabilities reflecting the estimated present value of these expenditures ($2.0 million, discounted at a rate of 5.0%). Based upon the results of the ongoing investigation, additional remedial action could be required by a subsequent administrative order or permit.
The Company is negotiating the settlement of a Notice of Violation from the Wyoming Department of Environmental Quality alleging non-compliance with certain refinery waste management requirements. The Company has estimated that the capital cost for required corrective measures will be approximately $1.5 million, with an additional $1.2 million of expense work which was accrued as of March 31, 2006 and December 31, 2005. Penalty amounts are still in negotiation; however, an estimated penalty amount of $250,000 was accrued as of December 31, 2005 and is included in “Accrued liabilities and other” on the Consolidated Balance Sheets as of March 31, 2006 and December 31, 2005.
The Company has agreed to contribute $750,000 toward a City of Cheyenne project to relocate a city storm water conveyance pipe, which is presently located on Refinery property and therefore potentially subject to contaminants from Refinery operations. This amount was accrued as of December 31, 2005 and is included in “Accrued liabilities and other” on the Consolidated Balance Sheets as of March 31, 2006 and December 31, 2005.
El Dorado Refinery. The El Dorado Refinery is subject to a 1988 consent order with the Kansas Department of Health and Environment (“KDHE”). Subject to the terms of the purchase and sale agreement for the El Dorado Refinery entered into between the Company and Shell, Shell is responsible for the costs of continued compliance with this order. This order, including various subsequent modifications, requires the El Dorado Refinery to continue the implementation of a groundwater management program with oversight provided by the KDHE Bureau of Environmental Remediation. More specifically, the El Dorado 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. The Company intends to assume management of the existing groundwater remediation activities from Shell as soon as practicable. Shell will continue to fund these existing activities per its contractual obligation.
8. 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 seven such suits: Moss et al. v. Venoco, 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. Venoco, Inc. et al., filed in August 2003; Jacobs v. Wainoco Oil & Gas Company et al., filed in December 2003; Bussel et al. v. Venoco, Inc. et al., filed in January 2004; Steiner et al. v. Venoco, Inc. et al., filed in May 2004; and Kalcic et al. v. Venoco, Inc. et al., filed in April 2005. Of the approximately 1,025 plaintiffs in the seven lawsuits, Wainoco Oil & Gas Company and Frontier are named as defendants by approximately 450 of those plaintiffs. Other defendants in these lawsuits include the Beverly Hills Unified School District, the City of Beverly Hills, three other oil and gas companies (and their related companies), and one company involved in owning or operating a power plant adjacent to the Beverly Hills High School and its related 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 seven pending lawsuits have been consolidated and are pending before 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 is ongoing and a trial date has been set for October 30, 2006.
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 a highly-rated insurance company 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. In October 2003, the Company paid $6.25 million to the insurance company for loss mitigation insurance and also funded with the insurance company a commutation account of approximately $19.5 million, which is funding the first costs incurred under the policy including, but not limited to, the costs of defense of the claims. 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. As of March 31, 2006, the commutation account balance was approximately $11.7 million. Frontier has the right to terminate the policy at any time prior to September 30, 2008, and receive a refund of the unearned portion of the premium (approximately $2.7 million as of March 31, 2006, and declining by approximately $270,000 each quarter) 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 also has been 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. The Company has reached a settlement on some of the policies and is continuing to pursue coverage efforts on other policies.
Frontier believes that neither the claims that have been made, the seven 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.
Other. The Company is also involved in various other lawsuits which are incidental to its business. In management’s opinion, the adverse determination of such lawsuits would not have a material adverse effect on the Company’s liquidity, financial position or results of operations.
9. Other Contingencies
El Dorado Earn-out Payments. On November 16, 1999, Frontier acquired the 110,000 bpd El Dorado Refinery from 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 annually, 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 as additional acquisition cost when the payment is considered probable and estimatable. A contingent earn-out payment of $7.5 million was required based on 2005 results and was accrued as of December 31, 2005 and paid in early 2006. Including the payment made in early 2006, the Company has paid a total of $22.5 million to date for contingent earn-out payments. Based on the results of operations for the three months ended March 31, 2006, it is probable that a payment will be required in early 2007, and $2.3 million was accrued at March 31, 2006.
Income Tax Contingencies. The Company recognizes liabilities for potential tax issues based on its estimate of whether, and the extent to which, additional taxes may be due. As of March 31, 2006, amounts reserved for such contingencies were $22.7 million (including interest) and are included in “Accrued liabilities and other” on the consolidated balance sheet. Interest expensed during the three months ended March 31, 2006 for these contingencies was $244,000.
10. New Crude Oil Purchase and Sale Contract
Effective March 10, 2006, the Company’s subsidiary, Frontier Oil and Refining Company (“FORC”), entered into a Master Crude Oil Purchase and Sale Contract (“Contract”) with Utexam Limited (“Utexam”), a wholly-owned subsidiary of BNP Paribas Ireland. Under this Contract, Utexam will purchase, transport and subsequently sell crude oil to FORC at a location near Cushing, Oklahoma or other locations as agreed. Utexam will be the owner of record of the crude oil as it is transported from the point of injection, which is expected to be Hardisty, Alberta, to the point of ultimate sale to FORC. The Company has provided a guarantee of FORC’s obligations under this Contract, primarily to receive crude oil and make payment for crude oil purchases arranged under this Contract. As of March 31, 2006, FORC and Utexam had entered into certain commitments to purchase and sell crude oil in April 2006 under this Contract; however, neither party has a continuing commitment to purchase or sell crude oil in the future.
11. Subsequent Events
2-for-1 Stock Split and Increase of Dividend. The Company announced on April 27, 2006 that its Board of Directors (“Board”) had approved a 2-for-1 stock split by means of a stock dividend on the Company’s common stock. Effective with the stock split, the Board also approved a 50% increase in the regular quarterly dividend to $0.03 per share ($0.12 annualized) from the current split-adjusted level of $0.02 per share. The stock split, and subsequent dividend increase, are subject to shareholder approval of an amendment to the Company’s restated articles of incorporation, as amended, to increase the number of authorized shares from 90 million to 180 million at a special shareholders’ meeting scheduled for June 9, 2006. If the increase in authorized shares is approved at the special meeting, the stock dividend will be paid on June 26, 2006, to shareholders of record on June 19, 2006.
Omnibus Incentive Compensation Plan. The shareholders of the Company approved the Frontier Oil Corporation Omnibus Incentive Compensation Plan (the “Omnibus Plan”) at the Annual Meeting held on April 26, 2006. The Omnibus Plan is a broad-based incentive plan that provides for granting stock options, stock appreciation rights, restricted stock awards, performance awards, stock units, bonus shares, dividend equivalent rights, other stock-based awards and substitute awards to employees, consultants and non-employee directors of the Company. The Omnibus Plan amends and restates the Company’s previously approved Stock Plan and also includes the Restricted Stock Plan, which was merged into the Omnibus Plan. The maximum number of shares of the Company’s common stock that may be issued under the Omnibus Plan with respect to awards is 6,000,000 shares, subject to certain adjustments as provided by the Omnibus Plan.
12. Consolidating Financial Statements
Frontier Holdings Inc. and its subsidiaries (“FHI”) are full and unconditional guarantors of Frontier Oil Corporation’s (“FOC”) 6⅝% 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 because the 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 | |
Condensed Consolidating Statement of Operations | |
For the Three Months Ended March 31, 2006 | |
| (Unaudited, in thousands) | |
| | | | | | | | | | | | |
| | | FOC (Parent) | | FHI (Guarantor Subsidiaries) | | Other Non-Guarantor Subsidiaries | | Eliminations | | Consolidated | |
| | | | | | | | | | | | |
Revenues: | | | | | | | | | | | |
Refined products | | $ | - | | $ | 1,007,463 | | $ | - | | $ | - | | $ | 1,007,463 | |
Other | | | 4 | | | 4,684 | | | 42 | | | - | | | 4,730 | |
| | | | 4 | | | 1,012,147 | | | 42 | | | - | | | 1,012,193 | |
| | | | | | | | | | | | | | | | | |
Costs and expenses: | | | | | | | | | | | | | | | | |
Raw material, freight and other costs | | | - | | | 833,487 | | | - | | | - | | | 833,487 | |
Refinery operating expenses, excluding depreciation | | | - | | | 68,904 | | | - | | | - | | | 68,904 | |
Selling and general expenses, excluding depreciation | | | 4,123 | | | 4,791 | | | - | | | - | | | 8,914 | |
Depreciation, accretion and amortization | | | 21 | | | 8,985 | | | - | | | (139 | ) | | 8,867 | |
| | | | 4,144 | | | 916,167 | | | - | | | (139 | ) | | 920,172 | |
| | | | | | | | | | | | | | | | | |
Operating income (loss) | | | (4,140 | ) | | 95,980 | | | 42 | | | 139 | | | 92,021 | |
| | | | | | | | | | | | | | | | | |
| Interest expense and other financing costs | | | 2,929 | | | 966 | | | - | | | (1,460 | ) | | 2,435 | |
| Interest and investment income | | | (1,673 | ) | | (873 | ) | | - | | | - | | | (2,546 | ) |
| Equity in earnings of subsidiaries | | | (97,528 | ) | | - | | | - | | | 97,528 | | | - | |
| | | | (96,272 | ) | | 93 | | | - | | | 96,068 | | | (111 | ) |
| | | | | | | | | | | | | | | | | |
Income before income taxes | | | 92,132 | | | 95,887 | | | 42 | | | (95,929 | ) | | 92,132 | |
| Provision for income taxes | | | 34,512 | | | 35,415 | | | - | | | (35,415 | ) | | 34,512 | |
Net income | | $ | 57,620 | | $ | 60,472 | | $ | 42 | | $ | (60,514 | ) | $ | 57,620 | |
FRONTIER OIL CORPORATION | |
Condensed Consolidating Statement of Operations | |
For the Three Months Ended March 31, 2005 | |
| (Unaudited, in thousands) | |
| | | | | | | | | | | | |
| | | FOC (Parent) | | FHI (Guarantor Subsidiaries) | | Other Non-Guarantor Subsidiaries | | Eliminations | | Consolidated | |
| | | | | | | | | | | | |
Revenues: | | | | | | | | | | | |
Refined products | | $ | - | | $ | 693,219 | | $ | - | | $ | - | | $ | 693,219 | |
Other | | | (6 | ) | | (585 | ) | | 12 | | | - | | | (579 | ) |
| | | | (6 | ) | | 692,634 | | | 12 | | | - | | | 692,640 | |
| | | | | | | | | | | | | | | | | |
Costs and expenses: | | | | | | | | | | | | | | | | |
Raw material, freight and other costs | | | - | | | 558,323 | | | - | | | - | | | 558,323 | |
Refinery operating expenses, excluding depreciation | | | - | | | 61,351 | | | - | | | - | | | 61,351 | |
Selling and general expenses, excluding depreciation | | | 4,756 | | | 2,287 | | | - | | | - | | | 7,043 | |
Depreciation and amortization | | | 16 | | | 8,383 | | | - | | | (139 | ) | | 8,260 | |
| | | | 4,772 | | | 630,344 | | | - | | | (139 | ) | | 634,977 | |
| | | | | | | | | | | | | | | | | |
Operating income (loss) | | | (4,778 | ) | | 62,290 | | | 12 | | | 139 | | | 57,663 | |
| | | | | | | | | | | | | | | | | |
| Interest expense and other financing costs | | | 2,609 | | | 500 | | | - | | | (72 | ) | | 3,037 | |
| Interest and investment income | | | (653 | ) | | (84 | ) | | - | | | - | | | (737 | ) |
| Equity in earnings of subsidiaries | | | (62,076 | ) | | - | | | - | | | 62,076 | | | - | |
| | | | (60,120 | ) | | 416 | | | - | | | 62,004 | | | 2,300 | |
| | | | | | | | | | | | | | | | | |
Income before income taxes | | | 55,342 | | | 61,874 | | | 12 | | | (61,865 | ) | | 55,363 | |
| Provision for income taxes | | | 20,906 | | | 23,159 | | | - | | | (23,138 | ) | | 20,927 | |
Net income | | $ | 34,436 | | $ | 38,715 | | $ | 12 | | $ | (38,727 | ) | $ | 34,436 | |
FRONTIER OIL CORPORATION | |
Condensed Consolidating Balance Sheet | |
As of March 31, 2006 | |
| (Unaudited, in thousands) | |
| | | | | | | | | | | | |
| | | FOC (Parent) | | FHI (Guarantor Subsidiaries) | | Other Non-Guarantor Subsidiaries | | Eliminations | | Consolidated | |
ASSETS | | | | | | | | | | | |
| Current assets: | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 90,749 | | $ | 117,296 | | $ | - | | $ | - | | $ | 208,045 | |
| Trade and other receivables | | | 4,858 | | | 138,249 | | | - | | | - | | | 143,107 | |
| Receivable from affiliated companies | | | 61,342 | | | - | | | 231 | | | (61,573 | ) | | - | |
| Inventory | | | - | | | 313,473 | | | - | | | - | | | 313,473 | |
| Deferred tax assets | | | 3,930 | | | 5,835 | | | - | | | (5,835 | ) | | 3,930 | |
| Other current assets | | | 675 | | | 5,047 | | | - | | | - | | | 5,722 | |
| Total current assets | | | 161,554 | | | 579,900 | | | 231 | | | (67,408 | ) | | 674,277 | |
| | | | | | | | | | | | | | | | | |
| Property, plant and equipment, at cost | | | 1,267 | | | 710,885 | | | - | | | (7,292 | ) | | 704,860 | |
| Less - accumulated depreciation and amortization | | | 1,009 | | | 253,953 | | | - | | | (8,100 | ) | | 246,862 | |
| | | | 258 | | | 456,932 | | | - | | | 808 | | | 457,998 | |
| Deferred financing costs, net | | | 2,654 | | | 695 | | | - | | | - | | | 3,349 | |
| Commutation account | | | 11,726 | | | - | | | - | | | - | | | 11,726 | |
| Prepaid insurance, net | | | 3,028 | | | - | | | - | | | - | | | 3,028 | |
| Other intangible asset, net | | | - | | | 1,395 | | | - | | | - | | | 1,395 | |
| Other assets | | | 2,822 | | | 75 | | | - | | | - | | | 2,897 | |
| Investment in subsidiaries | | | 581,294 | | | - | | | - | | | (581,294 | ) | | - | |
| Total assets | | $ | 763,336 | | $ | 1,038,997 | | $ | 231 | | $ | (647,894 | ) | $ | 1,154,670 | |
| | | | | | | | | | | | | | | | | |
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | | | | | | | |
| Accounts payable | | $ | 595 | | $ | 307,695 | | $ | - | | $ | - | | $ | 308,290 | |
| Accrued turnaround cost | | | - | | | 11,655 | | | - | | | - | | | 11,655 | |
| Accrued interest | | | 4,969 | | | - | | | - | | | - | | | 4,969 | |
| Accrued liabilities and other | | | 29,338 | | | 20,890 | | | 269 | | | - | | | 50,497 | |
| Total current liabilities | | | 34,902 | | | 340,240 | | | 269 | | | - | | | 375,411 | |
| | | | | | | | | | | | | | | | | |
| Long-term debt | | | 150,000 | | | - | | | - | | | - | | | 150,000 | |
| Long-term accrued and other liabilities | | | - | | | 50,825 | | | - | | | - | | | 50,825 | |
| Deferred compensation liability | | | 2,524 | | | - | | | - | | | - | | | 2,524 | |
| Deferred income taxes | | | 74,182 | | | 74,665 | | | - | | | (74,665 | ) | | 74,182 | |
| Payable to affiliated companies | | | - | | | 99,233 | | | - | | | (99,233 | ) | | - | |
| | | | | | | | | | | | | | | | | |
| Shareholders’ equity | | | 501,728 | | | 474,034 | | | (38 | ) | | (473,996 | ) | | 501,728 | |
| Total liabilities and shareholders’ equity | | $ | 763,336 | | $ | 1,038,997 | | $ | 231 | | $ | (647,894 | ) | $ | 1,154,670 | |
FRONTIER OIL CORPORATION | |
Condensed Consolidating Balance Sheet | |
As of December 31, 2005 | |
| (Unaudited, in thousands) | |
| | | | | | | | | | | | |
| | | FOC (Parent) | | FHI (Guarantor Subsidiaries) | | Other Non-Guarantor Subsidiaries | | Eliminations | | Consolidated | |
ASSETS | | | | | | | | | | | |
| Current assets: | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 244,357 | | $ | 111,708 | | $ | - | | $ | - | | $ | 356,065 | |
| Trade and other receivables | | | 6,381 | | | 123,254 | | | - | | | - | | | 129,635 | |
Receivable from affiliated companies | | | - | | | 4,556 | | | 189 | | | (4,745 | ) | | - | |
| Inventory | | | - | | | 247,621 | | | - | | | - | | | 247,621 | |
| Deferred tax assets | | | 6,819 | | | 7,514 | | | - | | | (7,514 | ) | | 6,819 | |
| Other current assets | | | 499 | | | 7,436 | | | - | | | - | | | 7,935 | |
| Total current assets | | | 258,056 | | | 502,089 | | | 189 | | | (12,259 | ) | | 748,075 | |
| | | | | | | | | | | | | | | | | |
| Property, plant and equipment, at cost | | | 1,235 | | | 675,639 | | | - | | | (8,752 | ) | | 668,122 | |
| Less - accumulated depreciation and amortization | | | 988 | | | 245,157 | | | - | | | (7,961 | ) | | 238,184 | |
| | | | 247 | | | 430,482 | | | - | | | (791 | ) | | 429,938 | |
| Deferred financing costs, net | | | 2,775 | | | 774 | | | - | | | - | | | 3,549 | |
| Commutation account | | | 12,606 | | | - | | | - | | | - | | | 12,606 | |
| Prepaid insurance, net | | | 3,331 | | | - | | | - | | | - | | | 3,331 | |
| Other intangible asset, net | | | - | | | 1,422 | | | - | | | - | | | 1,422 | |
| Other assets | | | 2,508 | | | 80 | | | - | | | - | | | 2,588 | |
| Investment in subsidiaries | | | 483,766 | | | - | | | - | | | (483,766 | ) | | - | |
| Total assets | | $ | 763,289 | | $ | 934,847 | | $ | 189 | | $ | (496,816 | ) | $ | 1,201,509 | |
| | | | | | | | | | | | | | | | | |
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | | | | | | | |
| Accounts payable | | $ | 2,480 | | $ | 357,097 | | $ | - | | $ | - | | $ | 359,577 | |
| Accrued dividends | | | 58,726 | | | - | | | - | | | - | | | 58,726 | |
| Accrued turnaround cost | | | - | | | 12,696 | | | - | | | - | | | 12,696 | |
| Accrued interest | | | 2,485 | | | - | | | - | | | - | | | 2,485 | |
| Accrued liabilities and other | | | 26,853 | | | 25,205 | | | 269 | | | - | | | 52,327 | |
| Total current liabilities | | | 90,544 | | | 394,998 | | | 269 | | | - | | | 485,811 | |
| | | | | | | | | | | | | | | | | |
| Long-term debt | | | 150,000 | | | - | | | - | | | - | | | 150,000 | |
| Long-term accrued and other liabilities | | | - | | | 47,698 | | | - | | | - | | | 47,698 | |
| Deferred compensation liability | | | 2,214 | | | - | | | - | | | - | | | 2,214 | |
| Deferred income taxes | | | 70,727 | | | 71,563 | | | - | | | (71,563 | ) | | 70,727 | |
| Payable to affiliated companies | | | 4,745 | | | 7,026 | | | - | | | (11,771 | ) | | - | |
| | | | | | | | | | | | | | | | | |
| Shareholders’ equity | | | 445,059 | | | 413,562 | | | (80 | ) | | (413,482 | ) | | 445,059 | |
| Total liabilities and shareholders’ equity | | $ | 763,289 | | $ | 934,847 | | $ | 189 | | $ | (496,816 | ) | $ | 1,201,509 | |
FRONTIER OIL CORPORATION | |
Condensed Consolidating Statement of Cash Flows | |
For the Three Months Ended March 31, 2006 | |
| (Unaudited, in thousands) | |
| | | | | | | | | | | | |
| | | FOC (Parent) | | FHI (Guarantor Subsidiaries) | | Other Non-Guarantor Subsidiaries | | Eliminations | | Consolidated | |
Cash flows from operating activities: | | | | | | | | | | | |
| Net income | | $ | 57,620 | | $ | 60,472 | | $ | 42 | | $ | (60,514 | ) | $ | 57,620 | |
Adjustments to reconcile net income to net cash from operating activities: | | | | | | | | | | | | | | | | |
Equity in earnings of subsidiaries | | | (97,528 | ) | | - | | | - | | | 97,528 | | | - | |
Depreciation, accretion and amortization | | | 21 | | | 8,985 | | | - | | | (139 | ) | | 8,867 | |
Stock-based compensation expense | | | 2,559 | | | - | | | - | | | - | | | 2,559 | |
Income tax benefits of stock compensation | | | 4,959 | | | - | | | - | | | - | | | 4,959 | |
Excess income tax benefits of share-based payment arrangements | | | (4,843 | ) | | - | | | - | | | - | | | (4,843 | ) |
Deferred income taxes | | | 6,344 | | | - | | | - | | | - | | | 6,344 | |
Income taxes eliminated in consolidation | | | - | | | 35,415 | | | - | | | (35,415 | ) | | - | |
Deferred financing cost amortization | | | 121 | | | 79 | | | - | | | - | | | 200 | |
Amortization of long-term prepaid insurance | | | 303 | | | - | | | - | | | - | | | 303 | |
Long-term commutation account | | | 880 | | | - | | | - | | | - | | | 880 | |
Other | | | (4 | ) | | 5 | | | - | | | - | | | 1 | |
Changes in working capital from operations | | | 3,192 | | | (128,433 | ) | | - | | | (1,460 | ) | | (126,701 | ) |
| Net cash provided by (used in) operating activities | | | (26,376 | ) | | (23,477 | ) | | 42 | | | - | | | (49,811 | ) |
| | | | | | | | | | | | | | | | | |
Cash flows from investing activities: | | | | | | | | | | | | | | | | |
| Additions to property, plant and equipment | | | (28 | ) | | (29,561 | ) | | - | | | - | | | (29,589 | ) |
| El Dorado Refinery contingent earn-out payment | | | - | | | (7,500 | ) | | - | | | - | | | (7,500 | ) |
| Net cash used in investing activities | | | (28 | ) | | (37,061 | ) | | - | | | - | | | (37,089 | ) |
| | | | | | | | | | | | | | | | | |
Cash flows from financing activities: | | | | | | | | | | | | | | | | |
| Proceeds from issuance of common stock | | | 2,127 | | | - | | | - | | | - | | | 2,127 | |
| Purchase of treasury stock | | | (9,545 | ) | | - | | | - | | | - | | | (9,545 | ) |
| Dividends paid | | | (58,542 | ) | | - | | | - | | | - | | | (58,542 | ) |
Excess income tax benefits of share-based payment arrangements | | | 4,843 | | | - | | | - | | | - | | | 4,843 | |
| Other | | | - | | | (3 | ) | | - | | | - | | | (3 | ) |
| Intercompany transactions | | | (66,087 | ) | | 66,129 | | | (42 | ) | | - | | | - | |
| Net cash provided by (used in) financing activities | | | (127,204 | ) | | 66,126 | | | (42 | ) | | - | | | (61,120 | ) |
| (Decrease) increase in cash and cash equivalents | | | (153,608 | ) | | 5,588 | | | - | | | - | | | (148,020 | ) |
| Cash and cash equivalents, beginning of period | | | 244,357 | | | 111,708 | | | - | | | - | | | 356,065 | |
| Cash and cash equivalents, end of period | | $ | 90,749 | | $ | 117,296 | | $ | - | | $ | - | | $ | 208,045 | |
FRONTIER OIL CORPORATION | |
Condensed Consolidating Statement of Cash Flows | |
For the Three Months Ended March 31, 2005 | |
| (Unaudited, in thousands) | |
| | | | | | | | | | | | |
| | | FOC (Parent) | | FHI (Guarantor Subsidiaries) | | Other Non-Guarantor Subsidiaries | | Eliminations | | Consolidated | |
Cash flows from operating activities: | | | | | | | | | | | |
| Net income | | $ | 34,436 | | $ | 38,715 | | $ | 12 | | $ | (38,727 | ) | $ | 34,436 | |
| Equity in earnings of subsidiaries | | | (62,076 | ) | | - | | | - | | | 62,076 | | | - | |
| Depreciation and amortization | | | 16 | | | 8,383 | | | - | | | (139 | ) | | 8,260 | |
| Stock-based compensation expense | | | 266 | | | - | | | - | | | - | | | 266 | |
| Income tax benefits of stock compensation | | | 2,334 | | | - | | | - | | | - | | | 2,334 | |
| Deferred income taxes | | | 11,624 | | | - | | | - | | | - | | | 11,624 | |
| Income taxes eliminated in consolidation | | | - | | | 23,138 | | | - | | | (23,138 | ) | | - | |
| Deferred financing cost amortization | | | 121 | | | 119 | | | - | | | - | | | 240 | |
| Amortization of long-term prepaid insurance | | | 303 | | | - | | | - | | | - | | | 303 | |
| Long-term commutation account | | | 13 | | | - | | | - | | | - | | | 13 | |
| Other | | | 492 | | | - | | | - | | | - | | | 492 | |
| Changes in working capital from operations | | | 7,764 | | | (87,479 | ) | | - | | | - | | | (79,715 | ) |
| Net cash provided by (used in) operating activities | | | (4,707 | ) | | (17,124 | ) | | 12 | | | 72 | | | (21,747 | ) |
| | | | | | | | | | | | | | | | | |
Cash flows from investing activities: | | | | | | | | | | | | | | | | |
| Additions to property, plant and equipment | | | (1 | ) | | (23,040 | ) | | - | | | (72 | ) | | (23,113 | ) |
| El Dorado Refinery contingent earn-out payment | | | - | | | (7,500 | ) | | - | | | - | | | (7,500 | ) |
| Involuntary conversion - net of insurance proceeds | | | - | | | 2,142 | | | - | | | - | | | 2,142 | |
| Net cash used in investing activities | | | (1 | ) | | (28,398 | ) | | - | | | (72 | ) | | (28,471 | ) |
| | | | | | | | | | | | | | | | | |
Cash flows from financing activities: | | | | | | | | | | | | | | | | |
| Revolving credit facility borrowings, net | | | - | | | 32,000 | | | - | | | - | | | 32,000 | |
| Proceeds from issuance of common stock | | | 1,963 | | | - | | | - | | | - | | | 1,963 | |
| Purchase of treasury stock | | | (1,676 | ) | | - | | | - | | | - | | | (1,676 | ) |
| Dividends paid | | | (1,618 | ) | | - | | | - | | | - | | | (1,618 | ) |
| Debt issue costs and other | | | (100 | ) | | (4 | ) | | - | | | - | | | (104 | ) |
| Intercompany transactions | | | 1,148 | | | (1,136 | ) | | (12 | ) | | - | | | - | |
| Net cash provided by (used in) financing activities | | | (283 | ) | | 30,860 | | | (12 | ) | | - | | | 30,565 | |
| Decrease in cash and cash equivalents | | | (4,991 | ) | | (14,662 | ) | | - | | | - | | | (19,653 | ) |
| Cash and cash equivalents, beginning of period | | | 105,409 | | | 18,980 | | | - | | | - | | | 124,389 | |
| Cash and cash equivalents, end of period | | $ | 100,418 | | $ | 4,318 | | $ | - | | $ | - | | $ | 104,736 | |
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, 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.
Overview
The terms “Frontier,” “we” and “our” refer to Frontier Oil Corporation and its subsidiaries. Our Refineries have a total annual average permitted crude capacity of 162,000 barrels per day (“bpd”). The four significant indicators of our profitability, reflected and defined in the operating data at the end of this analysis, are the gasoline crack spread, the diesel crack spread, the light/heavy crude oil differential and the WTI/WTS crude oil differential. 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). We typically do not use derivative instruments to offset price risk on our base level of operating inventories. Under our first-in, first-out (“FIFO”) inventory accounting method, crude oil price trends can cause significant fluctuations in the inventory valuation of our crude oil, unfinished products and finished products, thereby 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 NYMEX crude oil price began the 2006 year at $61.04 per barrel and ended the quarter at $66.63 per barrel. The crude oil market fundamentals and geopolitical considerations continued to support prices higher than historic averages. The increase in crude oil prices, along with additional production of heavy and/or sour crude oil, increased our crude oil differentials during the three months ended March 31, 2006, when compared to the same period in 2005. Our first quarter 2006 gasoline and diesel crack spreads were the highest for a first quarter in our history. Higher demand for gasoline and diesel along with product supply constraints produced higher gasoline and diesel crack spreads.
Overview of Results
We had net income for the three months ended March 31, 2006 of $57.6 million, or $1.02 per diluted share, compared to net income of $34.4 million, or $0.62 per diluted share, in the same period in 2005. Our operating income of $92.0 million for the three months ended March 31, 2006 was an increase of $34.3 million from the $57.7 million for the comparable period in 2005. The average diesel and gasoline crack spreads were higher during the first quarter of 2006 ($15.51 and $9.22 per barrel, respectively) than in the first quarter of 2005 ($9.92 and $7.28 per barrel, respectively), and both the light/heavy and WTI/WTS crude oil differentials increased for the quarter ended March 31, 2006 compared to the same period in 2005.
Specific Variances
Refined product revenues. Refined product revenues increased $314.2 million, or 45%, from $693.2 million to $1.0 billion for the three months ended March 31, 2006 compared to the same period in 2005. This increase was due to increased sales prices ($15.19 higher average per sales barrel), largely the result of higher crude oil prices and continued tight product availability, as well as higher sales volumes in 2006 (18,750 more bpd).
Manufactured product yields. 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 increased 14,533 bpd at the El Dorado Refinery and 835 bpd at the Cheyenne Refinery for the three months ended March 31, 2006 as compared to same period in 2005. An El Dorado Refinery turnaround in the three months ended March 31, 2005 caused yields to be lower than the comparable period in 2006.
Other revenues. Other revenues increased $5.3 million to $4.7 million for the three months ended March 31, 2006, compared to a loss of $579,000 for the same period in 2005, the source of which was $4.7 million in net gains from derivative contracts in the three months ended March 31, 2006 compared to net derivative losses of $585,000 for the same period in 2005. See “Price Risk Management Activities” under Item 3 for a discussion of our utilization of commodity derivative contracts.
Raw material, freight and other costs. 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. Raw material, freight and other costs increased by $275.2 million, from $558.3 million in the three months ended March 31, 2005, to $833.5 million in the same period for 2006. The increase in raw material, freight and other costs was due to greater crude oil charges, higher average crude prices and a small FIFO inventory loss in the three months ended March 31, 2006, compared to significant FIFO inventory gains from rising prices in the three months ended March 31, 2005. We also benefited from improved crude oil differentials during the three months ended March 31, 2006 when compared to the same period in 2005. For the three months ended March 31, 2006, we realized an increase in raw material, freight and other costs as a result of inventory losses of approximately $13,000 after tax ($21,000 pretax loss, comprised of a $140,000 loss at the Cheyenne Refinery and a $119,000 gain at the El Dorado Refinery). For the three months ended March 31, 2005, we realized a reduction in raw material, freight and other costs as a result of inventory gains of approximately $19.4 million after tax ($31.4 million pretax, comprised of nearly $6.5 million at the Cheyenne Refinery and $24.9 million at the El Dorado Refinery) due to increasing crude oil and refined product prices.
The Cheyenne Refinery raw material, freight and other costs of $50.05 per sales barrel for the three months ended March 31, 2006 increased from $41.21 per sales barrel in the same period in 2005 due to higher crude oil prices offset by an improved light/heavy crude oil differential. The light/heavy crude oil differential for the Cheyenne Refinery averaged $18.99 per barrel in the three months ended March 31, 2006 compared to $14.10 per barrel in the same period in 2005.
The El Dorado Refinery raw material, freight and other costs of $58.94 per sales barrel for the three months ended March 31, 2006 increased from $43.21 per sales barrel realized in the same period in 2005 due to higher average crude oil prices offset by an improved WTI/WTS crude oil differential. The WTI/WTS crude oil differential increased from an average of $4.68 per barrel in the three-month period ending March 31, 2005, to $6.44 per barrel in the same period in 2006.
Refinery operating expenses. 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 $68.9 million in the three months ended March 31, 2006 compared to $61.4 million in the comparable period of 2005.
The Cheyenne Refinery operating expenses, excluding depreciation, were $23.8 million in the three months ended March 31, 2006 compared to $17.3 million in the comparable period of 2005. The increase resulted from higher natural gas usage and prices ($2.3 million), higher maintenance costs, primarily due to freezing weather conditions ($2.5 million), consulting and legal fees ($428,000), turnaround accruals ($448,000), environmental expenditures ($233,000) and chemical and additive costs ($232,000).
The El Dorado Refinery operating expenses, excluding depreciation, were $45.1 million in the three months ended March 31, 2006, increasing from $44.0 million in the same three-month period of 2005. The primary areas of increased costs were in electricity ($1.8 million), chemicals and additives ($1.5 million), turnaround accruals ($659,000), lease and rental equipment ($478,000) and non-maintenance contractors ($416,000). Reduced costs resulted from lower turnaround costs in excess of accruals ($2.6 million), salaries and benefits ($482,000) and a net $513,000 reduction in natural gas costs as reduced consumption more than offset an increase in price. Electricity costs were higher during the quarter ended March 31, 2006, compared to the same period in 2005, as we produced electricity from our cogeneration facility in 2005. These increased electricity costs were partially offset by lower natural gas costs, as we did not purchase natural gas for the cogeneration facility.
Selling and general expenses. Selling and general expenses, excluding depreciation, increased $1.9 million, or 27%, from $7.0 million for the three months ended March 31, 2005 to $8.9 million for the three months ended March 31, 2006, primarily due to increases in salaries and benefits from the vesting of stock compensation in 2006 for an executive officer who retired March 31, 2006 and additional stock compensation expense due to the adoption of FAS No. 123(R).
Depreciation and amortization. Depreciation and amortization increased $607,000, or 7%, for the three months ended March 31, 2006 compared to the same period in 2005 because of increased capital investment in our Refineries.
Interest expense and other financing costs. Interest expense and other financing costs of $2.4 million for the three months ended March 31, 2006 decreased $602,000, or 20%, from $3.0 million in the comparable period in 2005. The reduction was due to $1.5 million of interest cost being capitalized in the three months ended March 31, 2006, compared to only $200,000 of interest cost being capitalized in the three months ended March 31, 2005, offset by $400,000 in costs related to the Utexam Master Crude Oil Purchase and Sale Contract (see Note 10 in the “Notes to Interim Consolidated Financial Statements”) and $244,000 in accrued interest on income tax contingencies during the three months ended March 31, 2006. Average debt outstanding decreased to $155.4 million during the three months ended March 31, 2006 from $171.0 million for the same period in 2005.
Interest and investment income. Interest and investment income increased $1.8 million from $737,000 in the three months ended March 31, 2005, to $2.5 million in the three months ended March 31, 2006, because we had more cash available to invest and because of higher interest rates on invested cash.
Provision for income taxes. The provision for income tax for the three months ended March 31, 2006 was $34.5 million on pretax income of $92.1 million (or 37.5%) reflecting a benefit of the “American Jobs Creation Act of 2004” production activities deduction for manufacturers. Our current estimated effective tax rate excluding this benefit is 37.92%. The provision for income taxes for the three months ended March 31, 2005, was $20.9 million on pretax income of $55.4 million (or 37.8%) reflecting a benefit of the “American Jobs Creation Act of 2004” production activities deduction for manufacturers.
LIQUIDITY AND CAPITAL RESOURCES
Cash flows from operating activities. Net cash used by operating activities was $49.8 million for the three months ended March 31, 2006 compared to net cash used by operating activities of $21.7 million during the three months ended March 31, 2005. Improved results of operations increased cash flow significantly but were more than offset by higher uses of cash for working capital.
Working capital changes used a total of $126.7 million of cash in the three months ended March 31, 2006 while using only $79.7 million of cash in the comparable period in 2005. The most significant uses of cash for working capital changes during the three-month period of 2006 were an increase in inventories of $65.9 million, an increase in receivables of $13.4 million and a decrease in trade and other payables of $52.9 million compared to an increase in inventories of $80.6 million, an increase in receivables of $16.1 million and a decrease in accrued liabilities of $10.6 million in the 2005 comparable period. The increase in inventories during the three months ended March 31, 2006, was due to a significant increase in crude oil in-transit inventories, primarily the Canadian crude in-transit for the El Dorado Refinery, as well as other increased inventory levels and slightly higher prices. The decrease in trade and other payables during the three months ended March 31, 2006, was primarily due to a $40.0 million decrease in crude payables between March 31, 2006 and December 31, 2005, a significant portion of which was due to the lower priced Canadian crude now being purchased for the El Dorado Refinery.
At March 31, 2006, we had $208.0 million of cash and cash equivalents, working capital of $298.9 million and $181.5 million of borrowing base availability for additional borrowings under our revolving credit facility.
Cash flows used in investing activities. Capital expenditures during the first three months of 2006 were $29.6 million, which included approximately $16.2 million for the El Dorado Refinery and $13.3 million for the Cheyenne Refinery. The $16.2 million of capital expenditures for our El Dorado Refinery included $10.2 million for the ultra low sulfur diesel project (discussed below) and $2.0 million for the crude unit and vacuum tower expansion as well as operational, payout, safety, administrative, environmental and optimization projects. The $13.3 million of capital expenditures for our Cheyenne Refinery included approximately $4.6 million for the ultra low sulfur diesel project and $4.1 million for the coker expansion as well as environmental, operational, safety, administrative and payout projects.
Under the provisions of the purchase agreement with Shell for our El Dorado Refinery, we have made, and 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 $60.0 million per year of the El Dorado Refinery’s annual revenues less material costs and operating costs, other than depreciation. Such contingency payments are recorded as additional acquisition cost when the payment is considered probable and estimatable. The total amount of these contingent payments is capped at $40.0 million, with an annual cap of $7.5 million. Payments of $7.5 million each were paid in early 2005 and 2006, based on 2004 and 2005 results, and were accrued as of December 31, 2004 and 2005. Including the payment made in early 2006, we have paid a total of $22.5 million to date for contingent earn-out payments. Based on the results of operations for the three months ended March 31, 2006, it is probable that a payment will be required in early 2007, and $2.3 million was accrued at March 31, 2006.
During the first quarter of 2005, we received the remaining payments of $2.1 million from our insurance companies for claims related to the 2004 coker fire at the Cheyenne Refinery.
Cash flows used in financing activities. The payment of $58.5 million in dividends during the three months ended March 31, 2006 was our largest use of cash for financing activities. During the three months ended March 31, 2006, we also used $9.5 million to repurchase stock, of which $1.9 million was for the settlement of stock purchased in December 2005 and $6.4 million was for the purchase of 153,494 shares in the first quarter of 2006 (both of which were made under the authorization of the stock repurchase program discussed below). We also increased our treasury stock by 21,821 shares ($1.2 million) from stock surrendered by employees to pay their withholding taxes on shares of restricted stock which vested during the first quarter of 2006.
During the three months ended March 31, 2006, we issued 246,800 shares of common stock due to stock option exercises by employees and members of our Board of Directors, for which we received $2.1 million in cash by March 31, 2006 and the remaining $80,000 in early April 2006. We have authorization from our Board of Directors to repurchase up to 16 million shares of our common stock. Through March 31, 2006, we had purchased 9,609,026 shares of common stock under this stock repurchase program and had authorization remaining under this program to purchase an additional 6,390,974 shares. On November 30, 2005, our Board of Directors confirmed utilizing up to $100 million for share repurchases under this program. We may repurchase our common stock under this program from time to time in the open market depending on price, market conditions and other factors. As of March 31, 2006, $14.1 million (349,294 shares) of the $100 million had been utilized for repurchases.
As of March 31, 2006, we had $150.0 million of long-term debt and no borrowings under our revolving credit facility. We also had $43.5 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 March 31, 2006. We had shareholders’ equity of $501.7 million as of March 31, 2006. 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.”
Our Board of Directors (“Board”) declared both a special cash dividend of $1.00 per share and a regular quarterly cash dividend of $0.04 per share in December 2005, which were paid in January 2006. In addition, a quarterly cash dividend of $0.04 per share was declared in March 2006 and paid in April 2006. The total cash required for the dividend declared in March 2006 was approximately $2.4 million and was included in “Accrued dividends” on the March 31, 2006 Consolidated Balance Sheet.
We announced on April 27, 2006 that our Board had approved a 2-for-1 stock split by means of a stock dividend on our common stock. Effective with the stock split, the Board also approved a 50% increase in the regular quarterly dividend to $0.03 per share ($0.12 annualized) from the current split-adjusted level of $0.02 per share. The stock split is subject to shareholder approval of an amendment to our restated articles of incorporation, as amended, to increase the number of authorized shares from 90 million to 180 million at a special shareholders’ meeting scheduled for June 9, 2006. If the increase in authorized shares is approved at the special meeting, the stock dividend will be paid on June 26, 2006, to shareholders of record on June 19, 2006.
Future capital expenditures. Compliance with the upcoming ultra low sulfur diesel requirements affecting our Refineries will require additional capital expenditures through mid-2006. Total capital, including capitalized interest, which we expect to spend to comply with these regulations is currently estimated to be approximately $106.5 million at the El Dorado Refinery and $16.6 million at the Cheyenne Refinery. Expenditures for the ultra low sulfur diesel projects through March 31, 2006 (including 2004, 2005 and 2006 expenditures) were $88.0 million at the El Dorado Refinery and $10.8 million at the Cheyenne Refinery. The remaining costs for the ultra low sulfur diesel projects at both Refineries will be incurred before mid-2006. As of March 31, 2006, current outstanding commitments for ultra low sulfur diesel projects at the El Dorado and Cheyenne Refineries were $6.9 million and $1.6 million, respectively. The American Jobs Creation Act of 2004 allows 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 and will provide income tax credits based on the resulting production of ultra low sulfur diesel for up to 25% of the remaining qualified costs. Production of ultra low sulfur diesel is expected to begin by mid-2006 at our Refineries.
Capital expenditures aggregating approximately $206 million are currently planned for 2006, and include $105 million at our El Dorado Refinery, $100million at our Cheyenne Refinery, and $700,000 for capital expenditures in our Denver and Houston offices, and for our share of crude oil pipeline projects. The $105 million of planned capital expenditures for our El Dorado Refinery includes approximately $28.7 million for the ultra low sulfur diesel project discussed above, $47 million for the crude unit and vacuum tower expansion, discussed below, as well as environmental, operational, safety, administrative and payout projects. The $100 million of planned capital expenditures for our Cheyenne Refinery includes approximately $10.4 million for the ultra low sulfur diesel project discussed above, $51 million for the coker expansion, $7.5 million for a new amine unit and $5 million for the crude fractionation project, which are discussed below, as well as environmental, operational, safety, administrative and payout projects. Our 2006 capital expenditures are being funded with cash generated by our operations and by using our existing cash, as necessary.
Our Board of Directors has also approved four major capital projects which we expect to complete between 2006 and 2008. These projects include a $150.0 million crude unit and vacuum tower expansion at our El Dorado Refinery and, at our Cheyenne Refinery, a $78.5 million coker expansion and revamp, a $7.5 million new amine unit and an $8.2 million crude fractionation project. The above amounts include estimated capitalized interest. At March 31, 2006, outstanding purchase commitments for the crude unit and vacuum tower expansion project at our El Dorado Refinery were $2.7 million. At our Cheyenne Refinery, the coker expansion project’s outstanding commitments at March 31, 2006 were $7.8 million.
The crude unit and vacuum tower expansion at the El Dorado Refinery will allow for higher crude charge rates (including a significantly greater percentage of heavy crude oil) and higher gasoline and distillate yields. This project will likely be implemented in the spring of 2008 during the next planned turnaround for the crude/vacuum unit complex. The coker expansion at the Cheyenne Refinery, which is anticipated to be completed in 2007, will significantly decrease the amount of asphalt produced and increase the amount of higher margin light products such as gasoline and diesel. The new amine unit at the Cheyenne Refinery is intended to result in improved alkylation unit reliability and provide environmental compliance if the main amine unit is not operating. The project is expected to be completed in 2006. The crude fractionation project at the Cheyenne Refinery will allow us to replace light crude purchases with less expensive heavier crude oil while maintaining gasoline and diesel yields. We expect to fund these projects with existing cash and internally generated cash flow.
The Energy Tax Incentives Act of 2005 (the “Act”) contains provisions that may affect certain of our financial or operational considerations in the coming years. The Act includes a provision that allows a refiner to expense capital costs associated with expansion of refining capacity, as determined by the manufacture of liquid products other than asphalt and lube oil, in excess of 5% above previously produced volumes. The Act also requires that refiners, importers and blenders ensure that renewable fuel (e.g., ethanol) is blended into the nation’s gasoline pool at escalating, prescribed rates beginning with a 4.0 billion gallon requirement in 2006 and increasing to 7.5 billion gallons in 2012. We are currently evaluating the potential consequence that these and other provisions of the Act may have on our future operations.
CONTRACTUAL OBLIGATIONS
We entered into a definitive agreement with Rocky Mountain Pipeline System LLC (“Rocky Mountain”) on March 31, 2006 to support construction of a new crude pipeline from Guernsey, Wyoming to Rocky Mountain’s Fort Laramie, Wyoming tank farm and then to our Cheyenne Refinery. We made a ten year commitment to ship 35,000 bpd on the new pipeline and will concurrently lease approximately 300,000 barrels of dedicated storage capacity in the Rocky Mountain tank farm. The pipeline, which is designed to transport 55,000 bpd of heavy crude and is expandable to 90,000 bpd, is expected to first transport crude oil in the second quarter of 2007, shortly after our planned Cheyenne Refinery coker expansion from 10,000 bpd to 13,500 bpd.
On February 22, 2006, our Compensation Committee of the Board of Directors approved the Executive Retiree Medical Benefit Plan. The Executive Retiree Medical Benefit Plan provides a post-retirement medical benefit for certain of our executive officers. Due to the plan design, the amount to be contributed by the retirees is expected to cover the full cost of the plan.
Operating Data
The following tables set forth the refining operating statistical information on a consolidated basis and for each Refinery for the three months ended March 31, 2006 and 2005. The statistical information includes the following terms:
| · | Charges - the quantity of crude oil and other feedstock processed through Refinery units on a bpd basis. |
| · | Manufactured product yields - the volumes of specific materials that are obtained through the distilling of crude oil and the operations of other refinery process units on a bpd basis. |
| · | Gasoline and diesel crack spreads - The average non-oxygenated gasoline and diesel net sales prices that we receive for each product less the average WTI crude oil price at Cushing, Oklahoma. |
| · | Light/heavy crude oil differential - the average differential between the benchmark WTI crude oil priced at Cushing, Oklahoma and the heavy crude oil delivered to the Cheyenne Refinery. |
| · | WTI/WTS crude oil differential - the average differential between benchmark WTI crude oil priced at Cushing, Oklahoma and the West Texas sour crude oil priced at Midland, Texas. |
Consolidated: | | | | | |
| | | Three Months Ended | |
| | | March 31, | |
| | | 2006 | | 2005 | |
| Charges (bpd) | | | | | |
| Light crude | | | 40,304 | | | 33,575 | |
| Heavy and intermediate crude | | | 109,198 | | | 102,442 | |
| Other feed and blend stocks | | | 16,700 | | | 14,563 | |
| Total | | | 166,202 | | | 150,580 | |
| | | | | | | | |
| Manufactured product yields (bpd) | | | | | | | |
| Gasoline | | | 83,564 | | | 67,006 | |
| Diesel and jet fuel | | | 52,627 | | | 49,111 | |
| Asphalt | | | 5,271 | | | 4,119 | |
| Other | | | 20,807 | | | 26,666 | |
| Total | | | 162,269 | | | 146,902 | |
| | | | | | | | |
| Total product sales (bpd) | | | | | | | |
| Gasoline | | | 90,073 | | | 73,418 | |
| Diesel and jet fuel | | | 50,839 | | | 49,480 | |
| Asphalt | | | 6,497 | | | 4,507 | |
| Other | | | 17,252 | | | 18,506 | |
| Total | | | 164,661 | | | 145,911 | |
| | | | | | | | |
| Refinery operating margin information (per sales barrel) | | | | | | | |
| Refined products revenue | | $ | 67.98 | | $ | 52.79 | |
| Raw material, freight and other costs (FIFO inventory accounting) | | | 56.24 | | | 42.52 | |
| Refinery operating expenses, excluding depreciation | | | 4.65 | | | 4.67 | |
| Depreciation, accretion and amortization | | | 0.59 | | | 0.63 | |
| | | | | | | | |
| Average WTI crude oil priced at Cushing, OK (per barrel) | | $ | 62.33 | | $ | 49.53 | |
| | | | | | | | |
| Average gasoline crack spread (per barrel) | | $ | 9.22 | | $ | 7.28 | |
| Average diesel crack spread (per barrel) | | | 15.51 | | | 9.92 | |
| | | | | | | | |
| Average sales price (per sales barrel) | | | | | | | |
| Gasoline | | $ | 72.90 | | $ | 57.40 | |
| Diesel and jet fuel | | | 77.69 | | | 59.42 | |
| Asphalt | | | 28.09 | | | 21.07 | |
| Other | | | 28.77 | | | 24.52 | |
Cheyenne Refinery: | | | | | |
| | | Three Months Ended | |
| | | March 31, | |
| | | 2006 | | 2005 | |
| Charges (bpd) | | | | | |
| Light crude | | | 12,414 | | | 7,066 | |
| Heavy crude | | | 32,204 | | | 34,181 | |
| Other feed and blend stocks | | | 2,536 | | | 4,968 | |
| Total | | | 47,154 | | | 46,215 | |
| | | | | | | | |
| Manufactured product yields (bpd) | | | | | | | |
| Gasoline | | | 19,601 | | | 19,708 | |
| Diesel | | | 14,342 | | | 13,371 | |
| Asphalt | | | 5,271 | | | 4,119 | |
| Other | | | 6,097 | | | 7,278 | |
| Total | | | 45,311 | | | 44,476 | |
| | | | | | | | |
| Total product sales (bpd) | | | | | | | |
| Gasoline | | | 25,827 | | | 26,102 | |
| Diesel | | | 12,780 | | | 13,430 | |
| Asphalt | | | 6,497 | | | 4,507 | |
| Other | | | 4,788 | | | 6,477 | |
| Total | | | 49,892 | | | 50,516 | |
| | | | | | | | |
| Refinery operating margin information (per sales barrel) | | | | | | | |
| Refined products revenue | | $ | 64.37 | | $ | 50.78 | |
| Raw material, freight and other costs (FIFO inventory accounting) | | | 50.05 | | | 41.21 | |
| Refinery operating expenses, excluding depreciation | | | 5.30 | | | 3.81 | |
| Depreciation, accretion and amortization | | | 0.99 | | | 0.96 | |
| | | | | | | | |
| Average light/heavy crude oil differential (per barrel) | | $ | 18.99 | | $ | 14.10 | |
| | | | | | | | |
| Average gasoline crack spread (per barrel) | | $ | 9.32 | | $ | 6.87 | |
| Average diesel crack spread (per barrel) | | | 18.28 | | | 11.30 | |
| | | | | | | | |
| Average sales price (per sales barrel) | | | | | | | |
| Gasoline | | $ | 73.69 | | $ | 58.63 | |
| Diesel | | | 80.71 | | | 60.79 | |
| Asphalt | | | 28.09 | | | 21.07 | |
| Other | | | 19.77 | | | 19.06 | |
El Dorado Refinery: | | | | | |
| | | Three Months Ended | |
| | | March 31, | |
| | | 2006 | | 2005 | |
| Charges (bpd) | | | | | |
| Light crude | | | 27,890 | | | 26,509 | |
| Heavy and intermediate crude | | | 76,994 | | | 68,262 | |
| Other feed and blend stocks | | | 14,164 | | | 9,596 | |
| Total | | | 119,048 | | | 104,367 | |
| | | | | | | | |
| Manufactured product yields (bpd) | | | | | | | |
| Gasoline | | | 63,963 | | | 47,297 | |
| Diesel and jet fuel | | | 38,285 | | | 35,740 | |
| Other | | | 14,710 | | | 19,388 | |
| Total | | | 116,958 | | | 102,425 | |
| | | | | | | | |
| Total product sales (bpd) | | | | | | | |
| Gasoline | | | 64,245 | | | 47,316 | |
| Diesel and jet fuel | | | 38,059 | | | 36,050 | |
| Other | | | 12,464 | | | 12,029 | |
| Total | | | 114,768 | | | 95,395 | |
| | | | | | | | |
| Refinery operating margin information (per sales barrel) | | | | | | | |
| Refined products revenue | | $ | 69.56 | | $ | 53.85 | |
| Raw material, freight and other costs (FIFO inventory accounting) | | | 58.94 | | | 43.21 | |
| Refinery operating expenses, excluding depreciation | | | 4.37 | | | 5.13 | |
| Depreciation | | | 0.42 | | | 0.45 | |
| | | | | | | | |
| Average WTI/WTS crude oil differential (per barrel) | | $ | 6.44 | | $ | 4.68 | |
| | | | | | | | |
| Average gasoline crack spread (per barrel) | | $ | 9.18 | | $ | 7.51 | |
| Average diesel crack spread (per barrel) | | | 14.58 | | | 9.40 | |
| | | | | | | | |
| Average sales price (per sales barrel) | | | | | | | |
| Gasoline | | $ | 72.58 | | $ | 56.72 | |
| Diesel and jet fuel | | | 76.67 | | | 58.91 | |
| Other | | | 32.23 | | | 27.46 | |
Impact of Changing Prices. Our earnings and cash flows, as well as estimates of future cash flows, are sensitive to changes in energy prices. The prices of crude oil and refined product have fluctuated substantially in recent years. These prices depend on many factors, including the overall demand for crude oil and refined products, which in turn depend on, among other factors, general economic conditions, the level of foreign and domestic production of crude oil and refined products, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels, the extent of government regulations and global market dynamics. The prices we receive for refined products are also affected by factors such as local market conditions and the level of operations of other refineries in our markets. The price at which we can sell gasoline and other refined products is strongly influenced by the price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. The timing of the relative movement of the prices, however, can impact profit margins, which could significantly affect our earnings and cash flows.
Under our FIFO inventory accounting method, crude oil price movement can cause significant fluctuation in the valuation of our crude oil, unfinished products and finished products inventories, resulting in inventory gains when crude oil prices increase and inventory losses when crude oil prices decrease during the reporting period.
Price Risk Management Activities. At times, we enter into commodity derivative contracts to manage our price exposure to our inventory positions, purchases of foreign crude oil and consumption of natural gas in the refining process or to fix margins on future production. Gains or losses on commodity derivative contracts accounted for as hedges are recognized in the Consolidated Statements of Income as “Raw material, freight and other costs” or “Refinery operating expenses, excluding depreciation” when the associated transactions are consummated, while gains and losses on transactions accounted for using mark-to-market accounting are reflected in “Other revenues” in the Consolidated Statements of Income at each period end. See Note 6 “Price Risk Management Activities” in the “Notes to Interim Consolidated Financial Statements.”
Interest Rate Risk. Borrowings under our revolving credit facility bear a current market rate of interest. A one percent increase or decrease in interest rates on our revolving credit facility would not significantly affect our earnings or cash flows. Our $150.0 million principal of 6⅝% Senior Notes that were outstanding at March 31, 2006, and due 2011, 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 6⅝% Senior Notes at March 31, 2006 was $150.4 million.
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, 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, 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.
| ITEM 1. | | Legal Proceedings - See Note 8 in the Notes to Interim Consolidated Financial Statements. |
ITEM 2. | | Unregistered Sales of Equity Securities and Use of Proceeds -
(c) Issuer Purchases of Equity Securities |
| | Period | Total Number of Shares Purchased | Average Price Paid Per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1) | Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (2) |
| | January 1, 2006 to January 31, 2006 | 125,000 | $41.4412 | 125,000 | 6,419,468 |
| | February 1, 2006 to February 28, 2006 | 28,494 | 43.5484 | 28,494 | 6,390,974 |
| | March 1, 2006 to March 31, 2006 | - | - | - | |
| | Total first quarter | 153,494 | $41.8323 | 153,494 | 6,390,974 |
| | (1) | Shares were purchased under a stock repurchase program which authorizes repurchases up to sixteen million shares. The program has no expiration date but may be terminated by the Board of Directors at any time. On November 30, 2005, our Board of Directors confirmed utilizing up to $100 million for share repurchases under this program, and as of March 31, 2006, $14.1 million (349,294 shares) of the $100 million had been utilized for repurchases. We may repurchase our common stock under this program from time to time in the open market depending on price, market conditions and other factors. No shares were purchased during the periods shown other than through publicly-announced programs. |
| | (2) | Shares shown in this column reflect authorized shares remaining which may be repurchased under the stock repurchase program referenced in note 1 above. |
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.
