UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
____________________________
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) of the
Securities Exchange Act of 1934
Date of report (Date of earliest event reported): March 4, 2015
ALON USA ENERGY, INC.
(Exact Name of Registrant as Specified in Charter)
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| | |
Delaware (State or Other Jurisdiction of Incorporation) | 001-32567 (Commission File Number) | 74-2966572 (IRS Employer Identification No.) |
12700 Park Central Dr., Suite 1600
Dallas, Texas 75251
(Address of Principal Executive Offices) (Zip Code)
Registrant’s telephone number, including area code: (972) 367-3600
____________________________
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
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| | |
o | | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
o | | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
o | | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
o | | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 2.02. Results of Operations and Financial Condition.
On March 4, 2015, Alon USA Partners, LP (“Alon Partners”), a subsidiary of Alon USA Energy, Inc., issued a press release (the “Press Release”) reporting its financial results for the quarter and year ended December 31, 2014. A copy of the Press Release is furnished as Exhibit 99.1 to this Current Report on Form 8-K, and is incorporated herein by reference.
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits.
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| | |
Exhibit Number | | Description |
99.1 | | Press Release dated March 4, 2015. |
SIGNATURE
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 hereunto duly authorized.
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| | | |
| | Alon USA Energy, Inc. |
Date: | March 4, 2015 | By: | /s/ Shai Even |
| | | Shai Even |
| | | Senior Vice President and Chief Financial Officer |
INDEX TO EXHIBITS
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| | |
Exhibit Number | | Description |
99.1 | | Press Release dated March 4, 2015. |
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| NEWS RELEASE |
| | |
| Contacts: | Stacey Hudson, Investor Relations Manager Alon USA Partners GP, LLC
972-367-3808 |
FOR IMMEDIATE RELEASE | | |
| | Investors: Jack Lascar/Stephanie Smith
Dennard § Lascar Associates, LLC 713-529-6600
Media: Blake Lewis
Lewis Public Relations
214-635-3020
Ruth Sheetrit
SMG Public Relations
011-972-547-555551 |
Alon USA Partners, LP Reports Fourth Quarter and Full Year 2014 Results
Schedules conference call for March 6, 2015 at 10:00 a.m. Eastern
DALLAS, TEXAS, March 4, 2015 - Alon USA Partners, LP (NYSE: ALDW) (“Alon Partners”) today announced results for the quarter and year ended December 31, 2014. Net income for the fourth quarter of 2014 was $42.1 million, or $0.67 per unit, compared to $13.5 million, or $0.22 per unit, for the same period last year. Net income for the year ended December 31, 2014 was $169.1 million, or $2.71 per unit, compared to $136.2 million, or $2.18 per unit, for the same period last year.
Paul Eisman, CEO and President, commented, “The Big Spring refinery ran well during the quarter, achieving record quarterly total throughput of 77,000 barrels per day and liquid recovery of approximately 101%. The fourth quarter throughput surpassed the previous record throughput set in the third quarter as we continue to benefit from investments made during the turnaround completed earlier in the year. However, our fourth quarter refining results were negatively impacted by a decline in crude spreads and seasonal weakness in crack spreads. Despite the volatility in petroleum markets during the fourth quarter, the Big Spring refinery was able to generate strong results, once again highlighting the refinery’s operating capabilities and competitive advantages. The solid operational performance drove strong margin capture, as the refinery operating margin of $15.12 per barrel exceeded the Gulf Coast 3/2/1 crack spread adjusted for Midland crude discounts. The efficiency of our operations was also demonstrated by Big Spring’s low direct operating expense of only $3.67 per barrel.
“With the cash generated during the fourth quarter, the Partnership paid a cash distribution of $0.70 per unit on March 2, 2015. Based on our performance in 2014, the Partnership generated cash available for distribution of $2.54 per unit. This is particularly noteworthy given the significant downtime associated with the major five-year turnaround and vacuum tower project completed in the second quarter of 2014. With the turnaround and project completed, the refinery is poised to run well in 2015.
“We expect total throughput at the Big Spring refinery to average approximately 71,000 barrels per day for the first quarter of 2015 and 72,000 barrels per day for the full year of 2015.”
FOURTH QUARTER 2014
Refinery operating margin was $15.12 per barrel for the fourth quarter of 2014 compared to $9.96 per barrel for the same period in 2013. This increase in operating margin was primarily due to a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread, partially offset by a lower Gulf Coast 3/2/1 crack spread.
The Big Spring refinery average throughput for the fourth quarter of 2014 was 76,867 barrels per day ("bpd") compared to 73,613 bpd for the same period in 2013. The increased throughput was due to the completion of both the major turnaround and the vacuum tower project during the second quarter of 2014, which increased crude oil throughput to 73,000 bpd from 70,000 bpd and increased diesel production by 3,000 bpd.
The average Gulf Coast 3/2/1 crack spread was $9.04 per barrel for the fourth quarter of 2014 compared to $13.05 per barrel for the same period in 2013, which was primarily influenced by a reduction in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for the fourth quarter of 2014 was $3.70 per barrel compared to $9.89 per barrel for the
same period in 2013. The average WTI Cushing to WTS spread for the fourth quarter of 2014 was $4.43 per barrel compared to $3.14 per barrel for the same period in 2013. The average WTI Cushing to WTI Midland spread for the fourth quarter of 2014 was $5.79 per barrel compared to $2.32 per barrel for the same period in 2013.
YEAR ENDED DECEMBER 31, 2014
Refinery operating margin was $16.69 per barrel for 2014 compared to $14.59 per barrel for 2013. This increase in operating margin was primarily due to a widening of both the WTI Cushing to WTS spread and the WTI Cushing to WTI Midland spread, partially offset by a lower Gulf Coast 3/2/1 crack spread.
During the second quarter of 2014, we completed a major turnaround at the Big Spring refinery, including the vacuum tower project, which increased crude oil throughput to 73,000 bpd from 70,000 bpd and increased diesel production by 3,000 bpd. As a result of downtime necessary to complete these projects, the refinery and operating results were lower during the second quarter, which reduced profitability and the related distribution amount for the period. However, despite the reduced throughput experienced during the second quarter of 39,000 bpd, our Big Spring refinery average throughput was 66,033 bpd for 2014 compared to 67,103 bpd for 2013.
The average Gulf Coast 3/2/1 crack spread for 2014 was $14.52 per barrel compared to $19.16 per barrel for 2013, which was primarily influenced by a reduction in the Brent to WTI Cushing spread. The average Brent to WTI Cushing spread for 2014 was $7.30 per barrel compared to $12.41 per barrel for 2013. The average WTI Cushing to WTS spread for 2014 was $6.04 per barrel compared to $3.72 per barrel for 2013. The average WTI Cushing to WTI Midland spread for 2014 was $6.93 per barrel compared to $2.59 per barrel for 2013.
CONFERENCE CALL
Alon Partners has scheduled a conference call which will also be webcast live on Friday, March 6, 2015, at 10:00 a.m. Eastern Time (9:00 a.m. Central Time), to discuss the fourth quarter 2014 results. To access the call, please dial 877-404-9648, or 412-902-0030 for international callers, at least 10 minutes prior to the start time and ask for the Alon Partners call. Investors may also listen to the conference live from the Alon Partners' website, http://www.alonpartners.com. A telephonic replay of the conference call will be available through March 20, 2015, and may be accessed by calling 877-660-6853, or 201-612-7415 for international callers, and using the passcode 13599645#. The archived webcast will also be available at http://www.alonpartners.com shortly after the call and will be accessible for approximately 90 days. For more information, please contact Donna Washburn at Dennard § Lascar Associates at 713-529-6600 or email dwashburn@dennardlascar.com.
This release serves as qualified notice to nominees under Treasury Regulation Section 1.1446-4(b). Please note that 100% of Alon Partners’ distributions to foreign investors are attributable to income that is effectively connected with a United States trade or business. Accordingly, all of Alon Partners’ distributions to foreign investors are subject to federal income tax withholding at the highest effective tax rate for individuals or corporations, as applicable. Nominees, and not Alon Partners, are treated as the withholding agents responsible for withholdings on the distributions received by them on behalf of foreign investors.
Any statements in this release that are not statements of historical fact are forward-looking statements. Forward-looking statements reflect our current expectations regarding future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows. Additional information regarding these and other risks is contained in our filings with the Securities and Exchange Commission.
Alon USA Partners, LP is a Delaware limited partnership formed in August 2012 by Alon USA Energy, Inc. (“Alon Energy”) (NYSE: ALJ). Alon Partners owns and operates a crude oil refinery in Big Spring, Texas with a crude oil throughput capacity of 73,000 barrels per day. Alon Partners refines crude oil into finished products, which are marketed primarily in West Texas, Central Texas, Oklahoma, New Mexico and Arizona through its wholesale distribution network to both Alon Energy’s retail convenience stores and other third-party distributors.
- Tables to follow -
ALON USA PARTNERS, LP AND SUBSIDIARIES CONSOLIDATED
EARNINGS RELEASE
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| | | | | | | | | | | | | | | |
RESULTS OF OPERATIONS - FINANCIAL DATA
(ALL INFORMATION IN THIS PRESS RELEASE EXCEPT FOR BALANCE SHEET DATA AS OF DECEMBER 31, 2013, AND INCOME STATEMENT DATA FOR THE YEAR ENDED DECEMBER 31, 2013, IS UNAUDITED) | For the Three Months Ended | | For the Year Ended |
| December 31, | | December 31, |
| 2014 | | 2013 | | 2014 | | 2013 |
| (dollars in thousands, except per unit data, per barrel data and pricing statistics) |
STATEMENT OF OPERATIONS DATA: | | | | | |
Net sales (1) | $ | 800,179 |
| | $ | 878,524 |
| | $ | 3,221,373 |
| | $ | 3,430,287 |
|
Operating costs and expenses: | | | | | | | |
Cost of sales | 697,919 |
| | 811,096 |
| | 2,823,694 |
| | 3,073,044 |
|
Direct operating expenses | 25,944 |
| | 26,923 |
| | 105,760 |
| | 110,940 |
|
Selling, general and administrative expenses | 6,941 |
| | 5,412 |
| | 26,446 |
| | 22,276 |
|
Depreciation and amortization | 14,067 |
| | 11,047 |
| | 47,494 |
| | 45,329 |
|
Total operating costs and expenses | 744,871 |
| | 854,478 |
| | 3,003,394 |
| | 3,251,589 |
|
Loss on disposition of assets | — |
| | — |
| | — |
| | (21 | ) |
Operating income | 55,308 |
| | 24,046 |
| | 217,979 |
| | 178,677 |
|
Interest expense | (12,229 | ) | | (9,985 | ) | | (46,706 | ) | | (40,474 | ) |
Other income, net | 19 |
| | 5 |
| | 646 |
| | 23 |
|
Income before state income tax expense | 43,098 |
| | 14,066 |
| | 171,919 |
| | 138,226 |
|
State income tax expense | 999 |
| | 570 |
| | 2,784 |
| | 2,004 |
|
Net income | $ | 42,099 |
| | $ | 13,496 |
| | $ | 169,135 |
| | $ | 136,222 |
|
Earnings per unit | $ | 0.67 |
| | $ | 0.22 |
| | $ | 2.71 |
| | $ | 2.18 |
|
Weighted average common units outstanding (in thousands) | 62,507 |
| | 62,502 |
| | 62,505 |
| | 62,502 |
|
Cash distribution per unit | $ | 1.02 |
| | $ | — |
| | $ | 2.02 |
| | $ | 2.76 |
|
CASH FLOW DATA: | | | | | | | |
Net cash provided by (used in): | | | | | | | |
Operating activities | $ | 57,130 |
| | $ | 56,618 |
| | $ | 196,504 |
| | $ | 216,337 |
|
Investing activities | (11,719 | ) | | (7,968 | ) | | (74,800 | ) | | (29,626 | ) |
Financing activities | (54,381 | ) | | 44,457 |
| | (168,962 | ) | | (99,129 | ) |
OTHER DATA: | | | | | | | |
Adjusted EBITDA (2) | $ | 69,394 |
| | $ | 35,098 |
| | $ | 266,119 |
| | $ | 224,050 |
|
Cash available for distribution (2) | 44,005 |
| | 11,412 |
| | | | |
Capital expenditures | 2,133 |
| | 6,756 |
| | 16,064 |
| | 23,390 |
|
Capital expenditures for turnarounds and catalysts | 9,586 |
| | 1,212 |
| | 58,736 |
| | 6,236 |
|
KEY OPERATING STATISTICS: | | | | | | | |
Per barrel of throughput: | | | | | | | |
Refinery operating margin (3) | $ | 15.12 |
| | $ | 9.96 |
| | $ | 16.69 |
| | $ | 14.59 |
|
Refinery direct operating expense (4) | 3.67 |
| | 3.98 |
| | 4.39 |
| | 4.53 |
|
|
| | | | | | | | | | | | | | | |
| For the Three Months Ended | | For the Year Ended |
| December 31, | | December 31, |
| 2014 | | 2013 | | 2014 | | 2013 |
| (dollars in thousands, except per unit data, per barrel data and pricing statistics) |
PRICING STATISTICS: | | | | | | | |
Crack spreads (per barrel): | | | | | | | |
Gulf Coast 3/2/1 (5) | $ | 9.04 |
| | $ | 13.05 |
| | $ | 14.52 |
| | $ | 19.16 |
|
WTI Cushing crude oil (per barrel) | $ | 73.37 |
| | $ | 97.47 |
| | $ | 93.10 |
| | $ | 97.97 |
|
Crude oil differentials (per barrel): | | | | | | | |
WTI Cushing less WTI Midland (6) | $ | 5.79 |
| | $ | 2.32 |
| | $ | 6.93 |
| | $ | 2.59 |
|
WTI Cushing less WTS (6) | 4.43 |
| | 3.14 |
| | 6.04 |
| | 3.72 |
|
Brent less WTI Cushing (6) | 3.70 |
| | 9.89 |
| | 7.30 |
| | 12.41 |
|
Product price (dollars per gallon): | | | | | | | |
Gulf Coast unleaded gasoline | $ | 1.85 |
| | $ | 2.49 |
| | $ | 2.49 |
| | $ | 2.70 |
|
Gulf Coast ultra-low sulfur diesel | 2.20 |
| | 2.92 |
| | 2.71 |
| | 2.97 |
|
Natural gas (per MMBtu) | 3.83 |
| | 3.85 |
| | 4.26 |
| | 3.73 |
|
|
| | | | | | | |
| As of December 31, |
| 2014 | | 2013 |
BALANCE SHEET DATA (end of period): | (dollars in thousands) |
Cash and cash equivalents | $ | 106,325 |
| | $ | 153,583 |
|
Working capital | (4,561 | ) | | 18,007 |
|
Total assets | 770,246 |
| | 849,924 |
|
Total debt | 302,376 |
| | 344,322 |
|
Total debt less cash and cash equivalents | 196,051 |
| | 190,739 |
|
Total equity | 188,402 |
| | 145,442 |
|
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| | | | | | | | | | | | | | | | | | | | | | | |
THROUGHPUT AND PRODUCTION DATA: | For the Three Months Ended | | For the Year Ended |
December 31, | | December 31, |
| 2014 | | 2013 | | 2014 | | 2013 |
| bpd | | % | | bpd | | % | | bpd | | % | | bpd | | % |
Refinery throughput: | | | | | | | | | | | | | | | |
WTS crude | 35,663 |
| | 46.4 |
| | 39,775 |
| | 54.0 |
| | 30,323 |
| | 45.9 |
| | 43,705 |
| | 65.1 |
|
WTI crude | 35,691 |
| | 46.4 |
| | 28,690 |
| | 39.0 |
| | 32,429 |
| | 49.1 |
| | 20,706 |
| | 30.9 |
|
Blendstocks | 5,513 |
| | 7.2 |
| | 5,148 |
| | 7.0 |
| | 3,281 |
| | 5.0 |
| | 2,692 |
| | 4.0 |
|
Total refinery throughput (7) | 76,867 |
| | 100.0 |
| | 73,613 |
| | 100.0 |
| | 66,033 |
| | 100.0 |
| | 67,103 |
| | 100.0 |
|
Refinery production: | | | | | | | | | | | | | | | |
Gasoline | 41,015 |
| | 53.0 |
| | 39,170 |
| | 53.0 |
| | 32,932 |
| | 49.7 |
| | 33,736 |
| | 50.4 |
|
Diesel/jet | 27,074 |
| | 34.9 |
| | 24,529 |
| | 33.3 |
| | 23,252 |
| | 35.1 |
| | 22,404 |
| | 33.5 |
|
Asphalt | 2,749 |
| | 3.5 |
| | 3,391 |
| | 4.6 |
| | 2,716 |
| | 4.1 |
| | 3,640 |
| | 5.4 |
|
Petrochemicals | 4,476 |
| | 5.8 |
| | 4,651 |
| | 6.3 |
| | 3,756 |
| | 5.7 |
| | 4,152 |
| | 6.2 |
|
Other | 2,185 |
| | 2.8 |
| | 2,029 |
| | 2.8 |
| | 3,565 |
| | 5.4 |
| | 3,033 |
| | 4.5 |
|
Total refinery production (8) | 77,499 |
| | 100.0 |
| | 73,770 |
| | 100.0 |
| | 66,221 |
| | 100.0 |
| | 66,965 |
| | 100.0 |
|
Refinery utilization (9) | | | 97.7 | % | | | | 97.8 | % | | | | 97.2 | % | | | | 94.9 | % |
| |
(1) | Includes sales to related parties of $115,694 and $138,430 for the three months ended December 31, 2014 and 2013, respectively, and $563,008 and $600,710 for the years ended December 31, 2014 and 2013, respectively. |
| |
(2) | Adjusted EBITDA represents earnings before state income tax expense, interest expense, depreciation and amortization and loss on disposition of assets. Adjusted EBITDA is not a recognized measurement under GAAP; however, the amounts included in Adjusted EBITDA are derived from amounts included in our consolidated financial statements. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of companies in our industry. In addition, our management believes that Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry because the calculation of Adjusted EBITDA generally eliminates the effects of state income tax expense, interest expense, loss on disposition of assets and the accounting effects of capital expenditures and acquisitions, items that may vary for different companies for reasons unrelated to overall operating performance. |
Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:
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• | Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments; |
| |
• | Adjusted EBITDA does not reflect the interest expense or the cash requirements necessary to service interest or principal payments on our debt; |
| |
• | Adjusted EBITDA does not reflect changes in or cash requirements for our working capital needs; and |
| |
• | Our calculation of Adjusted EBITDA may differ from EBITDA calculations of other companies in our industry, limiting its usefulness as a comparative measure. |
Because of these limitations, Adjusted EBITDA should not be considered a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally.
The following table reconciles net income to Adjusted EBITDA for the three months and years ended December 31, 2014 and 2013, respectively:
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| | | | | | | | | | | | | | | |
| For the Three Months Ended | | For the Year Ended |
| December 31, | | December 31, |
| 2014 | | 2013 | | 2014 | | 2013 |
| (dollars in thousands) |
Net income | $ | 42,099 |
| | $ | 13,496 |
| | $ | 169,135 |
| | $ | 136,222 |
|
State income tax expense | 999 |
| | 570 |
| | 2,784 |
| | 2,004 |
|
Interest expense | 12,229 |
| | 9,985 |
| | 46,706 |
| | 40,474 |
|
Depreciation and amortization | 14,067 |
| | 11,047 |
| | 47,494 |
| | 45,329 |
|
Loss on disposition of assets | — |
| | — |
| | — |
| | 21 |
|
Adjusted EBITDA | $ | 69,394 |
| | $ | 35,098 |
| | $ | 266,119 |
| | $ | 224,050 |
|
Cash available for distribution is not a recognized term under GAAP. Our management believes that the presentation of cash available for distribution is useful to investors because it is frequently used by securities analysts, investors, and other interested parties in the evaluation of entities in our industry. Cash available for distribution should not be considered in isolation or as an alternative to net income or operating income as a measure of operating performance. In addition, cash available for distribution is not presented as, and should not be considered, an alternative to cash flows from operations or as a measure of liquidity. Cash available for distribution as reported may not be comparable to similarly titled measures of other entities, thereby limiting its usefulness as a comparative measure.
Available cash for each quarter generally equals our Adjusted EBITDA for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for our expenses in the quarters in which our planned major turnarounds and catalyst replacements occur. Actual distributions are set by the board of directors of our general partner. The board of directors of our general partner may modify our cash distribution policy at any time, and our partnership agreement does not require us to make distributions at all.
The following table reconciles Adjusted EBITDA to cash available for distribution for the three months ended December 31, 2014 and 2013, respectively:
|
| | | | | | | |
| For the Three Months Ended |
| December 31, |
| 2014 | | 2013 |
| (dollars in thousands) |
Adjusted EBITDA | $ | 69,394 |
| | $ | 35,098 |
|
less: Maintenance/growth capital expenditures | 2,133 |
| | 6,756 |
|
less: Major and non-major turnaround and catalyst replacement capital expenditures | 9,586 |
| | 1,212 |
|
less: Major turnaround reserve for future years | 1,500 |
| | 1,150 |
|
less: Principal payments | 625 |
| | 625 |
|
less: State income tax payments | 342 |
| | 570 |
|
less: Interest paid in cash | 11,203 |
| | 9,269 |
|
Cash available for distribution before special expenses | 44,005 |
| | 15,516 |
|
less: Special turnaround reserve | — |
| | 4,104 |
|
Cash available for distribution | $ | 44,005 |
| | $ | 11,412 |
|
| |
(3) | Refinery operating margin is a per barrel measurement calculated by dividing the margin between net sales and cost of sales (exclusive of certain inventory adjustments) by the refinery's throughput volumes. Industry-wide refining results are driven and measured by the margins between refined product prices and the prices for crude oil, which are referred to as crack spreads. We compare our refinery operating margin to these crack spreads to assess our operating performance relative to other participants in our industry. |
The refinery operating margin for three months and year ended December 31, 2014 excludes losses related to inventory adjustments of $4,650.
| |
(4) | Refinery direct operating expense is a per barrel measurement calculated by dividing direct operating expenses by total throughput volumes. |
| |
(5) | We compare our refinery operating margin to the Gulf Coast 3/2/1 crack spread. A Gulf Coast 3/2/1 crack spread is calculated assuming that three barrels of WTI Cushing crude oil are converted, or cracked, into two barrels of Gulf Coast conventional gasoline and one barrel of Gulf Coast ultra-low sulfur diesel. |
| |
(6) | The WTI Cushing less WTI Midland spread represents the differential between the average price per barrel of WTI Cushing crude oil and the average price per barrel of WTI Midland crude oil. The WTI Cushing less WTS, or sweet/sour, spread represents the differential between the average price per barrel of WTI Cushing crude oil and the average price per barrel of WTS crude oil. The Brent less WTI Cushing spread represents the differential between the average price per barrel of Brent crude oil and the average price per barrel of WTI Cushing crude oil. |
| |
(7) | Total refinery throughput represents the total barrels per day of crude oil and blendstock inputs in the refinery production process. |
| |
(8) | Total refinery production represents the barrels per day of various refined products produced from processing crude and other refinery feedstocks through the crude units and other conversion units. |
| |
(9) | Refinery utilization represents average daily crude oil throughput divided by crude oil capacity, excluding planned periods of downtime for maintenance and turnarounds. |
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