Exhibit 99.1
Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2013
During the twelve months ending September 30, 2013, we estimate that we will generate approximately $335.4 million of cash available for distribution, including special turnaround reserve and wholesale business rebranding expenses of approximately $14.9 million. In “—Forecast Assumptions and Considerations” below, we discuss the major assumptions underlying this estimate. The available cash discussed in the forecast should not be viewed as management’s projection of the actual available cash that we will generate during the twelve months ending September 30, 2013. We can give you no assurance that our assumptions will be realized or that we will generate any available cash, in which event we will not be able to pay quarterly cash distributions on our common units.
When considering our ability to generate available cash and how we calculate forecasted available cash, please keep in mind all the risk factors and other cautionary statements under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” which discuss factors that could cause our results of operations and available cash to vary significantly from our estimates.
We do not, as a matter of course, make public projections as to future sales, earnings or other results. However, our management has prepared the prospective financial information set forth below in the table entitled “Alon USA Partners, LP Estimated Available Cash for Distribution” to present our expectations regarding our ability to generate approximately $335.4 million of cash available for distribution for the twelve months ending September 30, 2013, including special turnaround reserve and wholesale business rebranding expenses of approximately $14.9 million. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information.
Although the assumptions and estimates underlying the prospective financial information included herein are considered reasonable by the management team of our general partner (all of whom are employed by Alon
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Energy), such assumptions and estimates are inherently uncertain and are subject to a wide variety of significant business, economic, and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information. Such risks and uncertainties include risks relating to the volatility of prices of crude oil and other refinery feedstocks, refined product prices and competition within our industry. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in the prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.
We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient available cash to allow us to pay the forecasted quarterly distributions on all of our outstanding common units for the twelve months ending September 30, 2013, should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.
The following table shows how we calculate estimated available cash for the twelve months ending September 30, 2013. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “—Forecast Assumptions and Considerations.”
Neither our independent registered public accounting firm, nor any other independent registered public accounting firm, has compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial information. Our independent registered public accounting firm’s reports included elsewhere in this prospectus relate to our audited historical combined financial information. These reports do not extend to the tables and the related forecasted information contained in this section and should not be read to do so.
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The following table illustrates the amount of cash that we estimate we will generate for the twelve months ending September 30, 2013 and for each quarter during that twelve-month period that would be available for distribution to our unitholders. All of the amounts in the table below are estimates. Refinery operating margin per barrel, refinery direct operating expense per barrel, forecasted Gulf Coast (WTI) 3-2-1 crack spread, forecasted Cushing WTI prices and forecasted Midland WTS—Cushing WTI differentials represent weighted averages estimated over the stated period.
Alon USA Partners, LP Estimated Cash Available for Distribution
| | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ending | | | Twelve Months
Ending
September 30, 2013 | |
| | | December 31,
2012 | | | March 31,
2013 | | | June 30,
2013 | | | September 30,
2013 | | |
| | | (Dollars in millions except per unit and per bbl data) | |
Operating data: | | | | | | | | | | | | | | | | | | | | |
Refinery feedstocks (bpd): | | | | | | | | | | | | | | | | | | | | |
Sour crude oil | | | 55,204 | | | | 56,200 | | | | 56,200 | | | | 53,809 | | | | 55,346 | |
Sweet crude oil | | | 13,342 | | | | 10,800 | | | | 10,800 | | | | 10,800 | | | | 11,441 | |
Other feedstocks/blendstocks | | | 3,129 | | | | 2,024 | | | | 655 | | | | 728 | | | | 1,634 | |
| | | | | | | | | | | | | | | | | | | | |
Total throughput | | | 71,675 | | | | 69,024 | | | | 67,655 | | | | 65,337 | | | | 68,421 | |
Refinery product yields (bpd): | | | | | | | | | | | | | | | | | | | | |
Gasoline | | | 36,718 | | | | 34,860 | | | | 33,210 | | | | 30,608 | | | | 33,845 | |
Diesel/jet fuel | | | 23,867 | | | | 22,808 | | | | 22,842 | | | | 22,190 | | | | 22,928 | |
Asphalt | | | 4,358 | | | | 4,815 | | | | 4,815 | | | | 4,619 | | | | 4,651 | |
Other | | | 6,789 | | | | 6,173 | | | | 6,430 | | | | 7,686 | | | | 6,774 | |
| | | | | | | | | | | | | | | | | | | | |
Total production | | | 71,733 | | | | 68,657 | | | | 67,297 | | | | 65,103 | | | | 68,198 | |
| | | | | | | | | | | | | | | | | | | | |
Refinery operating margin per bbl of throughput(a) | | $ | 23.97 | | | $ | 20.85 | | | $ | 21.83 | | | $ | 20.00 | | | $ | 21.71 | |
Refinery direct operating expense per bbl of throughput(a) | | $ | 3.98 | | | $ | 3.93 | | | $ | 4.01 | | | $ | 4.15 | | | $ | 4.02 | |
Forecasted Gulf Coast (WTI) 3-2-1 crack spread (per bbl) | | $ | 27.91 | | | $ | 19.76 | | | $ | 22.09 | | | $ | 20.46 | | | $ | 22.57 | |
Forecasted Cushing WTI (per bbl) | | $ | 89.93 | | | $ | 93.44 | | | $ | 93.35 | | | $ | 92.55 | | | $ | 92.31 | |
Forecasted Cushing WTI—Midland WTS differential (per bbl) | | $ | 3.87 | | | $ | 4.50 | | | $ | 4.50 | | | $ | 4.50 | | | $ | 4.34 | |
Statement of operations data: | | | | | | | | | | | | | | | | | | | | |
Net sales | | $ | 873.1 | | | $ | 812.8 | | | $ | 815.5 | | | $ | 785.1 | | | $ | 3,286.5 | |
Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
Cost of sales | | | 715.0 | | | | 683.2 | | | | 681.1 | | | | 664.9 | | | | 2,744.3 | |
Direct operating expenses | | | 26.2 | | | | 24.4 | | | | 24.7 | | | | 24.9 | | | | 100.3 | |
Selling, general and administrative expenses | | | 4.4 | | | | 4.8 | | | | 5.4 | | | | 4.7 | | | | 19.3 | |
Depreciation and amortization | | | 11.7 | | | | 11.8 | | | | 11.9 | | | | 12.0 | | | | 47.3 | |
Operating income | | $ | 115.8 | | | $ | 88.6 | | | $ | 92.5 | | | $ | 78.5 | | | $ | 375.3 | |
Interest expense | | | (7.9 | ) | | | 7.6 | | | | 7.6 | | | | 7.5 | | | | 30.6 | |
Income before state income tax expense | | $ | 107.8 | | | $ | 81.0 | | | $ | 84.9 | | | $ | 71.0 | | | $ | 344.7 | |
State income tax expense | | | (0.9 | ) | | | (0.7 | ) | | | (0.7 | ) | | | (0.6 | ) | | | (3.0 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net income | | $ | 106.9 | | | $ | 80.3 | | | $ | 84.2 | | | $ | 70.3 | | | $ | 341.7 | |
| | | | | | | | | | | | | | | | | | | | |
Adjustments to reconcile net income to Adjusted EBITDA: | | | | | | | | | | | | | | | | | | | | |
Interest expense | | | 7.9 | | | | 7.6 | | | | 7.6 | | | | 7.5 | | | | 30.6 | |
State income tax expense | | | 0.9 | | | | 0.7 | | | | 0.7 | | | | 0.6 | | | | 3.0 | |
Depreciation and amortization | | | 11.7 | | | | 11.8 | | | | 11.9 | | | | 12.0 | | | | 47.3 | |
| | | | | | | | | | | | | | | | | | | | |
Adjusted EBITDA(b) | | $ | 127.4 | | | $ | 100.3 | | | $ | 104.4 | | | $ | 90.5 | | | $ | 422.6 | |
| | | | | | | | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ending | | | Twelve Months
Ending
September 30, 2013 | |
| | | December 31,
2012 | | | March 31,
2013 | | | June 30,
2013 | | | September 30,
2013 | | |
| | | (Dollars in millions except per unit and per bbl data) | |
Adjustments to reconcile Adjusted EBITDA to estimated cash available for distribution: | | | | | | | | | | | | | | | | | | | | |
less: Maintenance/growth capital expenditures | | $ | (4.8 | ) | | $ | (6.9 | ) | | $ | (6.9 | ) | | $ | (6.9 | ) | | $ | (25.4 | ) |
less: Turnaround and catalyst replacement capital expenditures | | | — | | | | (2.9 | ) | | | (2.9 | ) | | | (2.9 | ) | | | (8.8 | ) |
less: Major turnaround reserve | | | (1.2 | ) | | | (1.2 | ) | | | (1.2 | ) | | | (1.2 | ) | | | (4.6 | ) |
less: Principal payments | | | — | | | | (0.6 | ) | | | (0.6 | ) | | | (0.6 | ) | | | (1.9 | ) |
less: State income tax expense | | | (0.9 | ) | | | (0.7 | ) | | | (0.7 | ) | | | (0.6 | ) | | | (3.0 | ) |
less: Interest paid in cash | | | (7.4 | ) | | | (7.1 | ) | | | (7.1 | ) | | | (7.1 | ) | | | (28.6 | ) |
| | | | | | | | | | | | | | | | | | | | |
Estimated cash available for distribution before special expenses | | $ | 113.2 | | | $ | 81.0 | | | $ | 85.0 | | | $ | 71.3 | | | $ | 350.4 | |
| | | | | | | | | | | | | | | | | | | | |
less: Special turnaround reserve | | | (3.5 | ) | | | (3.5 | ) | | | (3.5 | ) | | | (3.5 | ) | | | (13.8 | ) |
less: Special wholesale rebranding expenses | | | (1.1 | ) | | | — | | | | — | | | | — | | | | (1.1 | ) |
| | | | | | | | | | | | | | | | | | | | |
Estimated cash available for distribution after giving effect to special expenses | | $ | 108.6 | | | $ | 77.5 | | | $ | 81.5 | | | $ | 67.8 | | | $ | 335.4 | |
| | | | | | | | | | | | | | | | | | | | |
Estimated cash available for distribution per unit | | $ | | | | $ | | | | $ | | | | $ | | | | $ | | |
Cash distributions to common unitholders after special expenses | | $ | 108.6 | | | $ | 77.5 | | | $ | 81.5 | | | $ | 67.8 | | | $ | 335.4 | |
| | | | | |
Sensitivity analysis: | | | | | | | | | | | | | | | | | | | | |
Changes in estimated cash available for distribution if: | | | | | | | | | | | | | | | | | | | | |
$1/bbl increase in Gulf Coast (WTI) 3-2-1 crack spread | | $ | 5.6 | | | $ | 5.2 | | | $ | 5.1 | | | $ | 4.9 | | | $ | 20.7 | |
$1/bbl increase in realized crude oil price—Cushing WTI differential | | $ | 6.3 | | | $ | 6.0 | | | $ | 6.1 | | | $ | 5.8 | | | $ | 24.3 | |
1,000 bpd increase in throughput | | $ | 2.1 | | | $ | 1.7 | | | $ | 1.8 | | | $ | 1.7 | | | $ | 7.3 | |
| (a) | For definitions of refining operating margin per bbl of throughput and refinery direct operating expenses per bbl of throughput, see “Prospectus Summary—Summary Historical Combined and Pro Forma Combined Financial and Operating Data.” |
| (b) | For a description of Adjusted EBITDA, see “Prospectus Summary—Summary Historical Combined and Pro Forma Combined Financial and Operating Data—Non-GAAP Financial Measure.” |
| * | Total amounts in the table above may not foot due to rounding. |
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Forecast Assumptions and Considerations
General
The accompanying financial forecast and specific significant forecast assumptions assume that the IPO Transactions had occurred as of October 1, 2012.
Utilization
Our refinery has a throughput capacity of approximately 70,000 bpd. We have assumed that the refinery will operate at an average total throughput of approximately 68,400 bpd during the twelve months ending September 30, 2013 and have assumed no significant downtime during such period. For the year ended December 31, 2011 and the twelve months ended June 30, 2012, the Big Spring refinery operated at an average total throughput of 63,614 bpd and 65,642 bpd, respectively.
The Big Spring refinery completed a reformer regeneration in April 2012, and the next reformer regeneration is scheduled in the third quarter of 2013. During a reformer regeneration (which typically lasts nine to ten days), the refinery runs at a lower throughput versus its normal capacity. During 2011, the Big Spring refinery ran at lower average throughput due to reformer regeneration and fluid catalytic converter unit work during June and July 2011. Average total throughput from August through December 2011 was 70,300 bpd.
Net Sales
We project net sales of $3.3 billion over the twelve months ending September 30, 2013. During the twelve months ended June 30, 2012 and the year ended December 31, 2011, we generated net sales of $3.3 billion and $3.2 billion, respectively.
Gasoline. We estimate net gasoline sales based on forecast future product prices multiplied by the number of barrels of gasoline we estimate that we will sell during the twelve months ending September 30, 2013. We forecast that we will sell approximately 12.4 million barrels of gasoline at a weighted average price of $110.81 per barrel during the twelve months ending September 30, 2013. We forecast the weighted average selling price of gasoline based on a differential between Gulf Coast gasoline pricing and the realized pricing by our Big Spring refinery. Gulf Coast gasoline pricing is based on a differential between Platts Gulf Coast gasoline and NYMEX RBOB futures. The forecasted differentials are based on historical pricing differentials between NYMEX RBOB, Platts Gulf Coast gasoline and realized pricing by our Big Spring refinery.
For the year ended December 31, 2011, we sold approximately 11.7 million barrels of gasoline at a weighted average price of $115.61 per barrel and realized net gasoline sales of approximately $1.4 billion. For the twelve months ended June 30, 2012, we sold approximately 11.9 million barrels of gasoline at a weighted average price of $118.16 per barrel and realized net gasoline sales of approximately $1.4 billion. Increases in forecasted gasoline sales volumes for the twelve months ending September 30, 2013 are due primarily to increases in forecasted throughput at the refinery period compared to prior periods as described above under “—Utilization.”
Diesel/Jet Fuel. We estimate net diesel/jet fuel sales based on forecast future product prices multiplied by the number of barrels of diesel/jet fuel we estimate that we will produce and sell during the twelve months ending September 30, 2013. We forecast that we will sell approximately 8.4 million barrels of diesel/jet fuel at a weighted average price of $126.35 per barrel during the twelve months ending September 30, 2013. We forecast the weighted average selling price of diesel based on a differential between Gulf Coast ultra-low-sulfur diesel (“ULSD”) and the realized pricing by our Big Spring refinery. The Gulf Coast ULSD pricing is based on a differential between Platts Gulf Coast ULSD and NYMEX Heating Oil futures. The forecast differentials are based on historical pricing differentials between NYMEX Heating Oil, Platts Gulf Coast ULSD and realized pricing by our Big Spring refinery. The forecast weighted average selling price of jet fuel is based on the historical differential to ULSD.
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For the year ended December 31, 2011, we sold approximately 7.7 million barrels of diesel/jet fuel at a weighted average price of $124.88 per barrel and realized net diesel/jet fuel sales of approximately $966.1 million. For the twelve months ended June 30, 2012, we sold approximately 7.8 million barrels of diesel/jet fuel at a weighted average price of $127.35 per barrel and realized net diesel/jet fuel sales of approximately $991.2 million. Increases in forecasted diesel/jet fuel sales volumes for the twelve months ending September 30, 2013 are due primarily to increases in forecasted throughput at the refinery compared to prior periods as described above under “—Utilization.”
Asphalt. We estimate net asphalt sales based on forecast future product prices multiplied by the number of barrels of asphalt we estimate that we will produce and sell during the twelve months ending September 30, 2013. Forecast future product prices are estimated assuming that the purchaser will pay all shipping costs. We forecast that we will sell approximately 1.7 million barrels of asphalt at a weighted average price of $67.00 per barrel during the twelve months ending September 30, 2013. We have assumed asphalt sales at a weighted average discount of $25.91 per barrel to the applicable Cushing WTI price over the twelve months ending September 30, 2013. The $25.91 per barrel discount to Cushing WTI is calculated from a regression formula derived from monthly Cushing WTI oil prices and Big Spring refinery realized asphalt prices based on historical data going back further than five years. The Cushing WTI benchmark price per barrel is forecast based on our view of future prices. Based on these assumptions, we forecast our net asphalt sales for the twelve months ending September 30, 2013 to be approximately $114.0 million.
For the year ended December 31, 2011, we sold approximately 1.7 million barrels of asphalt at a weighted average price of $64.69 per barrel and realized net asphalt sales of approximately $107.2 million. For the twelve months ended June 30, 2012, we sold approximately 1.6 million barrels of asphalt at a weighted average price of $67.83 per barrel and realized net asphalt sales of approximately $110.7 million.
Petrochemicals and Other Products. In addition to gasoline, diesel, jet fuel and asphalt, the Big Spring refinery produces and sells other refined products, including benzene, propane, refinery grade propylene, carbon black oil and butane. We forecast that we will sell approximately 2.5 million barrels of these products at a weighted average price of $97.51 per barrel during the twelve months ending September 30, 2013. Based on these forecasted prices and the volumes, we forecast net sales of other products to be approximately $241.0 million during the twelve months ending September 30, 2013.
For the year ended December 31, 2011, we sold approximately 2.7 million barrels of other products at a weighted average price of $94.78 per barrel and realized net sales of approximately $259.0 million. For the twelve months ended June 30, 2012, we sold approximately 2.2 million barrels of other products at a weighted average price of $90.13 per barrel and realized net sales of approximately $202.1 million.
Cost of Sales
We estimate that our cost of sales for the twelve months ending September 30, 2013 will be approximately $2.7 billion. Cost of sales for the year ended December 31, 2011 was approximately $2.7 billion. Cost of sales for the twelve months ended June 30, 2012 was approximately $2.9 billion.
Cost of sales includes the purchased raw material costs for crude oil, isobutane, normal butane, and other costs. Our feedstock and raw material costs consist of blending components for the finished products production process, which are driven primarily by commodity prices and volumes. We assume that our product yield will be approximately 99.7% over the twelve months ending September 30, 2013. For the year ended December 31, 2011, our product yield was 99.8%. For the twelve months ended June 30, 2012, our product yield was 100.0%.
Crude Oil. We estimate that we will purchase approximately 24.4 million barrels of crude oil for the twelve months ending September 30, 2013. We estimate crude oil costs of approximately $2.2 billion and that our realized crude oil cost will be $88.74 per barrel for the twelve months ending September 30, 2013. We forecast
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that the Big Spring refinery will realize an average crude oil price discount of $3.54 per barrel to the benchmark Cushing WTI price. We believe the Big Spring refinery will continue to realize favorable crude differentials to Cushing WTI because we expect to continue to process significant amounts of WTS and as a result of the oversupply of crude oil in Midland due to increased Permian Basin production. Our average crude oil price discount relative to Cushing WTI realized for the six years ended December 31, 2011 was $4.28 per barrel. For the year ended December 31, 2011, we purchased approximately 22.3 million barrels of crude oil at a weighted average price of $93.08 per barrel for a total crude oil cost of approximately $2.1 billion. For the twelve months ended June 30, 2012, we purchased approximately 23.2 million barrels of crude oil at a weighted average price of $92.53 per barrel for a total crude oil cost of approximately $2.1 billion.
Feedstocks and Blendstocks. Cost of sales also includes the cost of isobutane, normal butane, and other costs, among others, that we blend into our gasoline and diesel/jet fuel finished products. We forecast these elements of cost of sales to be approximately $46.0 million over the twelve months ending September 30, 2013. For the year ended December 31, 2011, these elements of cost of sales were approximately $80.7 million. For the twelve months ended June 30, 2012, these elements of cost of sales were approximately $81.5 million.
Direct Operating Expenses
Direct operating expenses include all direct and indirect labor at the facility, materials, supplies, and other expenses associated with the operation and maintenance of the refinery. We estimate that our direct operating expenses for the twelve months ending September 30, 2013 will be approximately $100.0 million, or $4.02 per barrel of throughput. Our direct operating expenses for the year ended December 31, 2011 were $98.2 million, or $4.25 per barrel of throughput. Direct operating expenses for the twelve months ended September 30, 2012 were $97.2 million, or $4.10 per barrel of throughput. Our direct operating expenses are generally fixed in nature, and increases in refinery utilization generally result in a lower direct operating cost per barrel.
Selling, General and Administrative Expenses
Selling, general and administrative expenses include salary and benefits costs for executive management, stock based compensation, accounting and information technology personnel, legal, audit, tax and other professional service costs. We estimate that our selling, general and administrative expense will be approximately $19.3 million for the twelve months ending September 30, 2013, of which approximately $8.4 million is attributed to our wholesale business, approximately $10.9 million is related to our Big Spring refinery. Of these expenses, approximately $1.5 million is related to increased expenses that we expect we will incur as a publicly traded partnership. Selling, general and administrative expenses for the year ended December 31, 2011 were approximately $15.6 million. Selling, general and administrative expenses for the twelve months ended June 30, 2012 were approximately $15.7 million.
Depreciation and Amortization Expense
We estimate the depreciation and amortization expense for the twelve months ending September 30, 2013 to be approximately $47.3 million. Depreciation and amortization expense for the year ended December 31, 2011 was approximately $40.4 million. Depreciation and amortization expense for the twelve months ended June 30, 2012 was approximately $45.0 million. The increase in expected depreciation and amortization expense is related to increased expected capital expenditures as described below under “—Maintenance/Growth Capital Expenditures.”
Interest Expense
Interest expense includes interest incurred under our amended and restated revolving credit facility and new term loan facility, fees relating to our letters of credit and financing costs associated with crude oil purchases as part of our supply and offtake agreement with J. Aron. For the twelve months ending September 30, 2013, our
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forecasted interest expense is $30.6 million, of which $2.0 million relates to our amended and restated revolving credit facility, $18.7 million relates to our new term loan facility, $4.0 million relates to our letters of credit and $4.0 million relates to the J. Aron supply and offtake agreement. We have assumed average borrowings under our amended and restated revolving credit facility of $40.0 million and borrowings under our new term loan facility of $250.0 million (the fully drawn amount), and we have assumed weighted average interest rates on our amended and restated revolving credit facility and new term loan facility of 4.0% and 7.5%, respectively, based on current market rates. Our forecasted interest expense for the twelve months ending September 30, 2013 does not include any interest expense on related party borrowings, as we have assumed the repayment of such borrowings with a portion of the net proceeds of this offering or the conversion of such borrowings into equity. We do not expect to have significant additional borrowings under our amended and restated revolving credit facility during the twelve months ending September 30, 2013. In addition, we do not expect to incur any significant additional intercompany debt following the completion of this offering.
For the year ended December 31, 2011, our pro forma interest expense was $38.3 million, of which $5.9 million related to our amended and restated revolving credit facility, $20.0 million related to our new term loan facility, $6.6 million related to our letters of credit, $4.2 million related to the J. Aron supply and offtake agreement and $1.6 million associated with debt issuance costs. Our historical interest expense for the year ended December 31, 2011 included $17.0 million of interest expense to related parties. As of December 31, 2011, on a pro forma basis, we had $200.0 million outstanding under our amended and restated revolving credit facility and $250.0 million outstanding under our new term loan facility. The assumed weighted average interest rates on our amended and restated revolving credit facility and new term loan facility during the year ended December 31, 2011 were 4.0% and 8.0%, respectively.
For the twelve months ended June 30, 2012, our pro forma interest expense was $40.7 million, of which $7.4 million related to our amended and restated revolving credit facility, $20.0 million related to our new term loan facility, $5.1 million related to our letters of credit and $6.0 million related to the J. Aron supply and offtake agreement. Our historical interest expense for the twelve months ended June 30, 2012 included $17.0 million of interest expense to related parties. As of June 30, 2012, on a pro forma basis, we had $157.0 million outstanding under our amended and restated revolving credit facility and $250.0 million outstanding under our new term loan facility. The assumed weighted average interest rates on our amended and restated revolving credit facility and new term loan facility during the twelve months ended June 30, 2012 were 4.0% and 8.0%, respectively.
State Income Tax Expense
We estimate that we will pay a minimal state income tax in the form of a Texas franchise tax for our refining business during the twelve months ending September 30, 2013 amounting to $3.0 million. For the year ended December 31, 2011 and the twelve months ended June 30, 2012, we paid state income taxes of $2.6 million and $2.5 million, respectively.
Maintenance/Growth Capital Expenditures
We estimate maintenance/growth capital expenditures during the twelve months ending September 30, 2013 of approximately $25.4 million, of which approximately $4.3 million is attributed to the wholesale business. Maintenance/growth capital expenditures for the year ended December 31, 2011 were approximately $5.0 million, of which approximately $1.4 million is attributed to the wholesale business. Maintenance/growth capital expenditures for the twelve months ended June 30, 2012 were approximately $16.0 million, of which approximately $5.1 million is attributed to the wholesale business.
The increase in forecasted maintenance/growth capital expenditures for the twelve months ending September 30, 2013 relative to prior periods includes increased expected maintenance/growth capital expenditures in the fourth quarter of 2012 relating to increasing liquid recovery for the refinery, a new cooling tower and certain regulatory projects. Increased expected maintenance/growth capital expenditures during the first three quarters of 2013 relate to regulatory projects, increasing liquid recovery for the refinery and tank replacement and cleaning.
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Rebranding Expenses
Forecasted cash available for distribution for the twelve months ending September 30, 2013 also gives effect to approximately $1.1 million of one-time additional capital expenditures relating to the rebranding of our wholesale business from FINA to ALON that we expect to incur in the fourth quarter of 2012.
Turnaround and Catalyst Replacement Capital Expenditures
Turnaround and catalyst replacement capital expenditures represent the costs of required annual and major maintenance projects on the refinery processing units. We incur two types of turnaround catalyst replacement expenses: (i) expenses relating to our annual reformer regeneration and catalyst replacement activities and (ii) expenses relating to major turnarounds, which occur every five years. Our annual turnaround expenses relating to reformer regeneration activities are capitalized and included in our capital expenditures in the tables above.
Forecasted turnaround and catalyst replacement capital expenditures relating to our annual reformer regeneration and catalyst replacement activities for the twelve months ending September 30, 2013 are $8.8 million. Capital expenditures relating to annual reformer regeneration and catalyst replacement activities for the year ended December 31, 2011 and the twelve months ended June 30, 2012 were $7.1 million and $11.0 million, respectively.
Major Turnaround Reserve
In advance of scheduled major turnarounds at our refinery, the board of directors of our general partner intends to elect to reserve amounts to fund actual capital expenditures associated with such turnarounds. Such a decision by the board of directors may have an adverse impact on our cash available for distribution in the quarter(s) in which the reserves are withheld and a corresponding mitigating impact on the future quarter(s) in which the reserves are utilized. We currently estimate total major turnaround expense at the Big Spring refinery of approximately $23.0 million in the aggregate over a five-year turnaround cycle. We expect to perform our next major turnaround during the first quarter of 2014.
We estimate reserving approximately $4.6 million of cash available for distribution per year, or approximately $1.2 million per quarter, for capital expenditures relating to the major turnarounds of our refinery that occur every five years.
Special Turnaround Reserve
In order to fund our capital expenditures relating to the major turnaround in the first quarter of 2014, we estimate reserving an additional $3.5 million per quarter for five quarters beginning with the fourth quarter of 2012. Accordingly, our forecasted special turnaround reserve for the twelve months ending September 30, 2013 is $13.8 million and the total forecasted turnaround reserve for the twelve months ending September 30, 2013 is $18.4 million. This assumption is subject to change as we complete our turnaround planning. We intend to use cash reserves or borrowings under our amended and restated revolving credit facility to fund other turnaround and catalyst replacement expenses.
Regulatory, Industry and Economic Factors
Our forecast for the twelve months ending September 30, 2013, is based on the following assumptions related to regulatory, industry and economic factors:
| | • | | No material nonperformance or credit-related defaults by suppliers, customer or vendors; |
| | • | | No new regulation or interpretation of existing regulations that, in either case, would be materially adverse to our business; |
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| | • | | No material accidents, weather-related incidents, floods, unplanned turnarounds or other downtime or similar unanticipated events that would reduce our capacity utilization below what we are currently forecasting; |
| | • | | No material adverse change in the market in which we operate resulting from reduced demand for gasoline, diesel/jet fuel, asphalt or our other products; |
| | • | | No material decreases in the prices we receive for our products; and |
| | • | | No material changes to market or overall economic conditions. |
Actual conditions may differ materially from those anticipated in this section as a result of a number of factors, including, but not limited to, those set forth under “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”
Compliance with Debt Covenants
Our ability to make distributions could be affected if we do not remain in compliance with the covenants in our new term loan facility and our amended and restated revolving credit facility. We have assumed we will remain in compliance with such covenants. The new term loan facility is expected to contain restrictive covenants, such as restrictions on liens, mergers, consolidations, sales of assets, additional indebtedness, different businesses, certain lease obligations, and certain restricted payments. The amended and restated revolving credit facility contains certain restrictive covenants that limit our ability to incur certain additional debt, pay cash distributions, grant liens, make certain investments, enter into certain mergers or consolidations, sell assets and engage in certain other transactions. Additionally, the amended and restated revolving credit facility requires us to maintain certain financial ratios, including requiring our Funded Debt to Adjusted EBITDA ratio, as such terms are defined therein.
Sensitivity Analysis
Our cash available for distribution is significantly impacted by volatility in prevailing crack spreads, crude oil prices and throughput at our refinery. In the paragraphs below, we discuss the impact of changes in these variables, while holding all other variables constant, on our ability to generate our estimated available cash for the twelve months ending September 30, 2013.
Crack Spread Volatility
Crack spreads measure the difference between the price received from the sale of motor fuels and the price paid for crude oil. Holding all other variables constant, we expect that a $1.00 change in the Gulf Coast (WTI) 3-2-1 crack spread per barrel would change our forecasted available cash by $20.7 million for the twelve months ending September 30, 2013.
Crude Oil Price Volatility
We are exposed to significant fluctuations in the price of crude oil. Holding all other variables constant, we expect a $1.00 increase (decrease) in our realized crude price differential to Cushing WTI would increase (decrease) our forecasted available cash by $24.3 million for the twelve months ending September 30, 2013.
Refinery Throughput
Holding all other variables constant, we expect a 1,000 bpd change in our total refinery throughput would change our forecasted available cash by $7.3 million for the twelve months ending September 30, 2013.
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