- Reported full-year 2021 net income of $25 million and EBITDA of $462 million, despite $435 million in RINs expense due to the broken Renewable Fuel Standard program that we are working diligently to repair.
- Improved environmental, health and safety performance year-over-year.
- Paid a special dividend valued at approximately $492 million, an equivalent of $4.89 per share, to CVR Energy stockholders during the second quarter of 2021.
- CVR Partners declared distributions of $9.89 per common unit for 2021, paid down $30 million in debt in 2021 and expects to pay down another $65 million in debt on February 22, 2022.
SUGAR LAND, Texas, Feb. 22, 2022 (GLOBE NEWSWIRE) -- CVR Energy, Inc. (“CVR Energy” or the “Company”) (NYSE: CVI) today announced a fourth quarter 2021 net loss of $14 million, or 14 cents per diluted share, on net sales of $2.1 billion, compared to a fourth quarter 2020 net loss of $67 million, or 67 cents per diluted share, on net sales of $1.1 billion. Fourth quarter 2021 EBITDA was $116 million, compared to fourth quarter 2020 EBITDA of $1 million.
For full-year 2021, the Company reported net income of $25 million, or 25 cents per diluted share, on net sales of $7.2 billion, compared to net loss for full-year 2020 of $256 million, or $2.54 per diluted share, on net sales of $3.9 billion. Full-year 2021 EBITDA was $462 million, compared to full-year 2020 EBITDA loss of $7 million.
“While our 2021 results reflected positive improvements in crack spreads compared to last year, ridiculously high Renewable Identification Number (“RIN”) prices continued to weigh on our performance,” said Dave Lamp, CVR Energy’s President and Chief Executive Officer. “We remain focused on offsetting the impact of this broken program and look forward to the expected startup of Wynnewood’s renewable diesel unit in the second quarter of 2022. We also have taken a large step forward in our focus on decarbonization with approval by our Board of Directors of a comprehensive plan to restructure our business to segregate our renewables operations, which we currently expect to execute over the following year. We believe we are uniquely positioned, given the synergistic relationship between refining and renewables as well as our proximity to the farm belt.
“CVR Partners achieved solid production during 2021, with a combined ammonia utilization rate of 92 percent,” Lamp said. “Ammonia and UAN pricing continued to strengthen into the 2021 fourth quarter, and we expect the momentum to continue into the spring 2022 planting season, with grain prices near multi-year highs and crop inventory levels near multi-year lows.”
Petroleum
The Petroleum Segment reported a fourth quarter 2021 operating loss of $27 million, on net sales of $1.9 billion, compared to a fourth quarter 2020 operating loss of $120 million, on net sales of $1.0 billion.
Refining margin per total throughput barrel was $7.13 in the fourth quarter 2021, compared to $1.32 during the same period in 2020. The increase in refining margin of $119 million was primarily driven by the 101 percent increase in the Group 3 2-1-1 crack spread caused by improved market demand for refined products in the fourth quarter 2021 compared to the economic downturn and demand destruction observed in the fourth quarter 2020. This was combined with a favorable inventory valuation impact of $17 million, or 85 cents per total throughout barrel, in the fourth quarter 2021 compared to a favorable inventory valuation impact of $15 million, or 76 cents per total throughput barrel, in the fourth quarter of 2020. The Petroleum Segment also recognized a fourth quarter 2021 derivative gain of $2 million, or 9 cents per total throughput barrel, compared to a fourth quarter 2020 derivative loss of $15 million, or 76 cents per total throughput barrel. Included in this derivative gain for the fourth quarter of 2021 was a nominal unrealized gain, compared to a fourth quarter 2020 $23 million unrealized loss. The costs to comply with the Renewable Fuel Standard (“RFS”) offset the improvements to refining margins resulting in expense of $100 million, or $4.89 per total throughput barrel, in the fourth quarter 2021, which included an additional $9 million revaluation of our RFS liability as of December 31, 2021, compared to an expense of $120 million, or $5.97 per total throughput barrel, in the fourth quarter 2020, which included a $66 million revaluation of our RFS liability as of December 31, 2020.
Fourth quarter 2021 combined total throughput was approximately 222,000 barrels per day (“bpd”), compared to approximately 219,000 bpd of combined total throughput for the fourth quarter 2020.
Full-year 2021 operating loss was $27 million, on net sales of $6.7 billion, compared to full-year 2020 operating loss of $281 million, on net sales of $3.6 billion.
The Petroleum Segment’s refining margin per total throughput barrel for 2021 was $8.14, compared to $4.44 for 2020. The increase in refining margin of $323 million was primarily driven by the 93 percent increase in the Group 3 2-1-1 crack spread caused by improved market demand for refined products in 2021 compared to the economic downturn and demand destruction observed in 2020. This was combined with favorable inventory valuation impacts totaling $127 million, or $1.66 per total throughput barrel, in 2021 driven by increased prices for crude oil and refined products in 2021 compared to 2020. The unfavorable inventory valuation impacts of $58 million in 2020 were driven by lower crude oil prices in the first half of 2020 with some offsetting increases observed through the end of 2020. Offsetting these improvements to refining margin, the Company recognized RINs expense of $435 million, or $5.70 per throughput barrel, and $190 million, or $2.84 per throughput barrel, for the years ended December 31, 2021 and 2020, respectively, reflecting its costs to comply with the RFS. This was combined with derivative losses of $44 million recognized during the year ended December 31, 2021, primarily a result of unfavorable crack spread swaps, compared to derivative gains of $55 million recognized during the year ended December 31, 2020, primarily resulting from WCS sales.
Combined total throughput for full-year 2021 improved to approximately 209,000 bpd, compared to approximately 183,000 bpd for full-year 2020.
Nitrogen Fertilizer
The Nitrogen Fertilizer Segment reported operating income of $72 million on net sales of $189 million for the fourth quarter of 2021, compared to an operating loss of $1 million on net sales of $90 million for the fourth quarter of 2020.
Fourth quarter 2021 average realized gate prices for urea ammonia nitrate (“UAN”) improved by 150 percent to $347 per ton and ammonia improved by 179 percent to $745 per ton when compared to the fourth quarter of 2020. Average realized gate prices for UAN and ammonia were $139 per ton and $267 per ton, respectively, for the fourth quarter of 2020.
CVR Partners’ fertilizer facilities produced a combined 197,000 tons of ammonia during the fourth quarter of 2021, of which 70,000 net tons were available for sale while the rest was upgraded to other fertilizer products, including 288,000 tons of UAN. During the fourth quarter 2020, the fertilizer facilities produced 220,000 tons of ammonia, of which 75,000 net tons were available for sale while the remainder was upgraded to other fertilizer products, including 335,000 tons of UAN.
Full-year 2021 operating income was $134 million on net sales of $533 million, compared to an operating loss of $35 million on net sales of $350 million for full-year 2020.
The average realized gate prices for full-year 2021 for UAN improved by 74 percent to $264 per ton and for ammonia improved 92 percent to $544 per ton when compared to the year ended 2020. Average realized gate prices for UAN and ammonia were $152 per ton and $284 per ton, respectively, for full-year 2020.
For the year ended 2021, our fertilizer facilities produced a combined 807,000 tons of ammonia, of which 275,000 tons were available for sale, while the rest was upgraded to other fertilizer products, including 1,208,000 tons of UAN. For the year ended 2020, the fertilizer facilities produced 852,000 tons of ammonia, of which 303,000 net tons were available for sale, while the remainder was upgraded to other fertilizer products, including 1,303,000 tons of UAN.
Corporate
The Company reported an income tax benefit of $8 million, or -12.4 percent of income before income taxes, for the year ended December 31, 2021, compared to an income tax benefit of $95 million, or 23.0 percent of loss before income taxes, for the year ended December 31, 2020. The fluctuation in income tax benefit was due primarily to changes in pretax earnings and pretax earnings attributable to noncontrolling interests between all periods presented. In addition, the change in the effective tax rate was due primarily to reductions in state income tax rates enacted during 2021, changes to pretax earnings attributable to noncontrolling interests and the impact of state income tax credits generated between all periods presented.
Cash, Debt and Dividend
Consolidated cash and cash equivalents was $510 million at December 31, 2021. Consolidated total debt and finance lease obligations was $1.7 billion at December 31, 2021, including $611 million held by the Nitrogen Fertilizer Segment.
During the year ended December 31, 2021, CVR Partners repurchased 24,378 of its common units on the open market pursuant to a repurchase program (the “Unit Repurchase Program”) approved by the board of directors of its general partner (the “UAN GP Board”) and in accordance with a repurchase agreement under Rules 10b5-1 and 10b-18 of the Securities Exchange Act of 1934, as amended, at a cost of $1 million, inclusive of transaction costs, or an average price of $21.70 per common unit. During the year ended December 31, 2020, as adjusted to reflect the impact of the 1-for-10 reverse unit split of CVR Partners’ common units that was effective as of November 23, 2020, CVR Partners repurchased 623,177 common units, respectively, at a cost of $7 million, inclusive of transaction costs, or an average price of $11.35 per common unit. As of December 31, 2021, CVR Partners had $12 million in authority remaining under the Unit Repurchase Program. This Unit Repurchase Program does not obligate CVR Partners to acquire any common units and may be cancelled or terminated by the UAN GP Board at any time.
On September 23, 2021, and December 22, 2021, CVR Partners redeemed an additional $15 million and $15 million, respectively, in aggregate principal amount of its outstanding 9.25% Senior Secured Notes due June 2023 (the “2023 UAN Notes”) at par and settled accrued interest of less than $1 million through the date of redemptions. On February 7, 2022, CVR Partners delivered a notice of full redemption for the remaining balance of its 2023 UAN Notes at a par redemption price, plus accrued and unpaid interest on the redeemed portion of the 2023 UAN Notes, to be redeemed today, February 22, 2022. As of February 7, 2022, there was outstanding an aggregate principal amount of $65 million of the 2023 UAN Notes.
On September 30, 2021, CVR Partners entered into a new credit agreement with an aggregate principal amount of up to $35 million with a maturity date of September 30, 2024 (the “Nitrogen Fertilizer ABL”) and terminated its $35 million ABL Credit Agreement, dated as of September 30, 2016, as amended (the “UAN 2016 ABL Credit Agreement”). The Nitrogen Fertilizer ABL has substantially similar terms as the UAN 2016 ABL Credit Agreement. The proceeds of the Nitrogen Fertilizer ABL may be used to fund working capital, capital expenditures and for other general corporate purposes.
CVR Energy will not pay a cash dividend for the 2021 fourth quarter.
Today, CVR Partners announced that the UAN GP Board declared a fourth quarter 2021 cash distribution of $5.24 per common unit, which will be paid on March 14, 2022, to common unitholders of record as of March 7, 2022.
Fourth Quarter 2021 Earnings Conference Call
CVR Energy previously announced that it will host its fourth quarter and full-year 2021 Earnings Conference Call on Tuesday, February 22, at 1 p.m. Eastern. This Earnings Conference Call may also include discussion of Company developments, forward-looking information and other material information about business and financial matters.
The fourth quarter and full-year 2021 Earnings Conference Call will be webcast live and can be accessed on the Investor Relations section of CVR Energy’s website at www.CVREnergy.com. For investors or analysts who want to participate during the call, the dial-in number is (877) 407-8291. The webcast will be archived and available for 14 days at https://edge.media-server.com/mmc/p/3cxbsksd. A repeat of the call can be accessed for 14 days by dialing (877) 660-6853, conference ID 13726866.
Forward-Looking Statements
This news release may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements concerning current estimates, expectations and projections about future results, performance, prospects, opportunities, plans, actions and events and other statements, concerns, or matters that are not historical facts are “forward-looking statements,” as that term is defined under the federal securities laws. These forward-looking statements include, but are not limited to, statements regarding future: Renewable Fuel Standards and repair thereof; continued safe and reliable operations; impacts of COVID-19 and any variants thereof, including the duration thereof; improvements in crack spreads; RIN pricing, including its impact on performance and the Company’s ability to offset the impact thereof; timing of startup of Wynnewood’s renewable diesel unit; the Company’s focus on decarbonization and restructure to segregate its renewables operations and the timing thereof; ammonia and UAN pricing; grain prices; crop inventory levels; refining margin; crude oil and refined product pricing impacts on inventory valuation; derivative gains and losses; costs to comply with the RFS and revaluation of our RFS liability; market demand for refined products; economic downturns and demand destruction; production rates; production levels and utilization at our nitrogen fertilizer facilities; nitrogen fertilizer sales volumes; ability to upgrade ammonia to other fertilizer products; changes to pretax earnings and our effective tax rate; purchases under the Unit Repurchase Program (if any); reduction of outstanding debt, including through the redemption of outstanding notes; use of funds under the Nitrogen Fertilizer ABL; dividends and distributions, including the timing, payment and amount (if any) thereof; total throughput, direct operating expenses, capital expenditures, depreciation and amortization and turnaround expense; timing of turnarounds; and other matters. You can generally identify forward-looking statements by our use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “explore,” “evaluate,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “seek,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. These forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. Investors are cautioned that various factors may affect these forward-looking statements, including (among others) the health and economic effects of COVID-19, the rate of any economic improvement, demand for fossil fuels and price volatility of crude oil, other feedstocks and refined products; the ability of Company to pay cash dividends and of CVR Partners to make cash distributions; potential operating hazards; costs of compliance with existing or new laws and regulations and potential liabilities arising therefrom; impacts of the planting season on CVR Partners; general economic and business conditions; and other risks. For additional discussion of risk factors which may affect our results, please see the risk factors and other disclosures included in our most recent Annual Report on Form 10-K, any subsequently filed Quarterly Reports on Form 10-Q and our other Securities and Exchange Commission (“SEC”) filings. These and other risks may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Given these risks and uncertainties, you are cautioned not to place undue reliance on such forward-looking statements. The forward-looking statements included in this news release are made only as of the date hereof. CVR Energy disclaims any intention or obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except to the extent required by law.
About CVR Energy, Inc.
Headquartered in Sugar Land, Texas, CVR Energy is a diversified holding company primarily engaged in the petroleum refining and marketing business through its interest in CVR Refining and the nitrogen fertilizer manufacturing business through its interest in CVR Partners, LP. CVR Energy subsidiaries serve as the general partner and own 36 percent of the common units of CVR Partners.
Investors and others should note that CVR Energy may announce material information using SEC filings, press releases, public conference calls, webcasts and the Investor Relations page of its website. CVR Energy may use these channels to distribute material information about the Company and to communicate important information about the Company, corporate initiatives and other matters. Information that CVR Energy posts on its website could be deemed material; therefore, CVR Energy encourages investors, the media, its customers, business partners and others interested in the Company to review the information posted on its website.
For further information, please contact:
Investor Relations:
Richard Roberts
CVR Energy, Inc.
(281) 207-3205
InvestorRelations@CVREnergy.com
Media Relations:
Brandee Stephens
CVR Energy, Inc.
(281) 207-3516
MediaRelations@CVREnergy.com
Non-GAAP Measures
Our management uses certain non-GAAP performance measures, and reconciliations to those measures, to evaluate current and past performance and prospects for the future to supplement our GAAP financial information presented in accordance with U.S. GAAP. These non-GAAP financial measures are important factors in assessing our operating results and profitability and include the performance and liquidity measures defined below.
As a result of volatile market conditions related to the RFS during the first half of 2021 and the impacts certain significant non-cash items have on the evaluation of our operations, the Company began disclosing Adjusted EBITDA, as defined below, in the second quarter of 2021. We believe the presentation of this non-GAAP measure is meaningful to compare our operating results between periods and peer companies. All prior periods presented have been conformed to the definition below. The following are non-GAAP measures we presented for the year ended December 31, 2021:
EBITDA - Consolidated net income (loss) before (i) interest expense, net, (ii) income tax expense (benefit) and (iii) depreciation and amortization expense.
Petroleum EBITDA and Nitrogen Fertilizer EBITDA - Segment net income (loss) before segment (i) interest expense, net, (ii) income tax expense (benefit), and (iii) depreciation and amortization.
Refining Margin - The difference between our Petroleum Segment net sales and cost of materials and other.
Refining Margin adjusted for Inventory Valuation Impacts - Refining Margin adjusted to exclude the impact of current period market price and volume fluctuations on crude oil and refined product inventories purchased in prior periods and lower of cost or net realizable value adjustments, if applicable. We record our commodity inventories on the first-in-first-out basis. As a result, significant current period fluctuations in market prices and the volumes we hold in inventory can have favorable or unfavorable impacts on our refining margins as compared to similar metrics used by other publicly-traded companies in the refining industry.
Refining Margin and Refining Margin adjusted for Inventory Valuation Impacts, per Throughput Barrel - Refining Margin and Refining Margin adjusted for Inventory Valuation Impacts divided by the total throughput barrels during the period, which is calculated as total throughput barrels per day times the number of days in the period.
Direct Operating Expenses per Throughput Barrel - Direct operating expenses for our Petroleum Segment divided by total throughput barrels for the period, which is calculated as total throughput barrels per day times the number of days in the period.
Adjusted EBITDA, Adjusted Petroleum EBITDA and Adjusted Nitrogen Fertilizer EBITDA - EBITDA, Petroleum EBITDA and Nitrogen Fertilizer EBITDA adjusted for certain significant non-cash items and items that management believes are not attributable to or indicative of our on-going operations or that may obscure our underlying results and trends.
Adjusted Earnings (Loss) per Share - Earnings (loss) per share adjusted for certain significant non-cash items and items that management believes are not attributable to or indicative of our on-going operations or that may obscure our underlying results and trends.
Free Cash Flow - Net cash provided by (used in) operating activities less capital expenditures and capitalized turnaround expenditures.
Net Debt and Finance Lease Obligations - Net debt and finance lease obligations is total debt and finance lease obligations reduced for cash and cash equivalents.
Total Debt and Net Debt and Finance Lease Obligations to EBITDA Exclusive of Nitrogen Fertilizer - Total debt and net debt and finance lease obligations is calculated as the consolidated debt and net debt and finance lease obligations less the Nitrogen Fertilizer Segment’s debt and net debt and finance lease obligations as of the most recent period ended divided by EBITDA exclusive of the Nitrogen Fertilizer Segment for the most recent twelve-month period.
We present these measures because we believe they may help investors, analysts, lenders and ratings agencies analyze our results of operations and liquidity in conjunction with our U.S. GAAP results, including but not limited to our operating performance as compared to other publicly-traded companies in the refining and fertilizer industries, without regard to historical cost basis or financing methods and our ability to incur and service debt and fund capital expenditures. Non-GAAP measures have important limitations as analytical tools, because they exclude some, but not all, items that affect net earnings and operating income. These measures should not be considered substitutes for their most directly comparable U.S. GAAP financial measures. See “Non-GAAP Reconciliations” included herein for reconciliation of these amounts. Due to rounding, numbers presented within this section may not add or equal to numbers or totals presented elsewhere within this document.
Factors Affecting Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons discussed below.
Petroleum Segment
Coffeyville Refinery - The Coffeyville Refinery’s next planned turnaround is expected to start in the spring of 2023, with pre-planning expenditures of $5 million expected to be incurred during 2022. During the year ended December 31, 2020, we capitalized costs of $155 million related to the planned turnaround which began in February 2020 and was completed in April 2020. During the fourth quarter of 2019, our Coffeyville Refinery capitalized costs of $15 million related to preparations for the same planned turnaround.
Wynnewood Refinery - The next planned turnaround for the Wynnewood Refinery is in the spring of 2022. During the years ended December 31, 2021 and December 31, 2020, we capitalized $7 million related to pre-planning activities at the Wynnewood Refinery. During the first quarter of 2019, the second phase of the fourth quarter 2017 turnaround on the Wynnewood Refinery hydrocracking unit was completed and $24 million was capitalized.
Nitrogen Fertilizer Segment
Coffeyville Fertilizer Facility - The next planned turnaround at the Coffeyville Fertilizer Facility is expected to occur in the summer of 2022. Additionally, the Coffeyville Fertilizer Facility had planned downtime for certain maintenance activities, which was completed in the fourth quarter of 2021 at a cost of $2 million. For the year ended December 31, 2021, we also incurred less than $1 million for the Coffeyville Fertilizer Facility expected turnaround in the summer of 2022.
East Dubuque Fertilizer Facility - The next planned turnaround at the East Dubuque Fertilizer Facility is expected to occur in the summer of 2022. For the year ended December 31, 2021, we incurred approximately $1 million in turnaround expense related to planning for the East Dubuque Fertilizer Facility’s expected turnaround in the summer of 2022.
Goodwill Impairment
As a result of lower expectations for market conditions in the fertilizer industry during 2020, the market performance of CVR Partners’ common units, a qualitative analysis, and additional risks associated with the business, CVR Partners performed an interim quantitative impairment assessment of goodwill for the Coffeyville Facility reporting unit as of June 30, 2020. The results of the impairment test indicated the carrying amount of this reporting unit exceeded the estimated fair value, and a full, non-cash impairment charge of $41.0 million was required.
CVR Energy, Inc.
(unaudited)
Consolidated Statement of Operations Data
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
| (in millions, except per share data) | 2021 | 2020 | 2021 | 2020 | |||||||||||
| Net sales | $ | 2,112 | $ | 1,119 | $ | 7,242 | $ | 3,930 | |||||||
| Operating costs and expenses: | |||||||||||||||
| Cost of materials and other | 1,805 | 1,025 | 6,185 | 3,373 | |||||||||||
| Direct operating expenses (exclusive of depreciation and amortization) | 160 | 125 | 569 | 478 | |||||||||||
| Depreciation and amortization | 71 | 68 | 270 | 268 | |||||||||||
| Cost of sales | 2,036 | 1,218 | 7,024 | 4,119 | |||||||||||
| Selling, general and administrative expenses (exclusive of depreciation and amortization) | 33 | 19 | 119 | 86 | |||||||||||
| Depreciation and amortization | 3 | 2 | 9 | 10 | |||||||||||
| Loss on asset disposal | — | 6 | 3 | 7 | |||||||||||
| Goodwill impairment | — | — | — | 41 | |||||||||||
| Operating income (loss) | 40 | (126 | ) | 87 | (333 | ) | |||||||||
| Other income (expense): | |||||||||||||||
| Interest expense, net | (24 | ) | (32 | ) | (117 | ) | (130 | ) | |||||||
| Investment (loss) income on marketable securities | (1 | ) | 54 | 81 | 41 | ||||||||||
| Other income, net | 3 | 3 | 15 | 7 | |||||||||||
| Income (loss) before income tax expense | 18 | (101 | ) | 66 | (415 | ) | |||||||||
| Income tax benefit | (7 | ) | (23 | ) | (8 | ) | (95 | ) | |||||||
| Net income (loss) | 25 | (78 | ) | 74 | (320 | ) | |||||||||
| Less: Net income (loss) attributable to noncontrolling interest | 39 | (11 | ) | 49 | (64 | ) | |||||||||
| Net (loss) income attributable to CVR Energy stockholders | $ | (14 | ) | $ | (67 | ) | $ | 25 | $ | (256 | ) | ||||
| Basic and diluted (loss) earnings per share | $ | (0.14 | ) | $ | (0.67 | ) | $ | 0.25 | $ | (2.54 | ) | ||||
| Dividends declared per share | $ | — | $ | — | $ | 4.89 | $ | 1.20 | |||||||
| EBITDA * | $ | 116 | $ | 1 | $ | 462 | $ | (7 | ) | ||||||
| Adjusted EBITDA* | $ | 109 | $ | 21 | $ | 301 | $ | 126 | |||||||
| Weighted-average common shares outstanding - basic and diluted | 100.5 | 100.5 | 100.5 | 100.5 | |||||||||||
| * | See “Non-GAAP Reconciliations” section below. | ||
Selected Balance Sheet Data
| (in millions) | December 31, 2021 | December 31, 2020 | |||
| Cash and cash equivalents | $ | 510 | $ | 667 | |
| Working capital | 213 | 743 | |||
| Total assets | 3,906 | 3,978 | |||
| Total debt and finance lease obligations, including current portion | 1,660 | 1,691 | |||
| Total liabilities | 3,136 | 2,759 | |||
| Total CVR stockholders’ equity | 553 | 1,019 | |||
Selected Cash Flow Data
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
| (in millions) | 2021 | 2020 | 2021 | 2020 | |||||||||||
| Net cash flows provided by (used in) | |||||||||||||||
| Operating activities | $ | 14 | $ | 28 | $ | 396 | $ | 90 | |||||||
| Investing activities | (34 | ) | (27 | ) | (238 | ) | (423 | ) | |||||||
| Financing activities | (36 | ) | (6 | ) | (315 | ) | 355 | ||||||||
| Net (decrease) increase in cash and cash equivalents | $ | (56 | ) | $ | (5 | ) | $ | (157 | ) | $ | 22 | ||||
| Free cash flow * | $ | (24 | ) | $ | 4 | $ | 167 | $ | (193 | ) | |||||
| * | See “Non-GAAP Reconciliations” section below. | |
Selected Segment Data
| Three Months Ended December 31, 2021 | Year Ended December 31, 2021 | ||||||||||||||||||||||
| (in millions) | Petroleum | Nitrogen Fertilizer | Consolidated | Petroleum | Nitrogen Fertilizer | Consolidated | |||||||||||||||||
| Net sales | $ | 1,927 | $ | 189 | $ | 2,112 | $ | 6,721 | $ | 533 | $ | 7,242 | |||||||||||
| Operating (loss) income | (27 | ) | 72 | 40 | (27 | ) | 134 | 87 | |||||||||||||||
| Net (loss) income | (19 | ) | 61 | 25 | 4 | 78 | 74 | ||||||||||||||||
| EBITDA * | 27 | 93 | 116 | 186 | 213 | 462 | |||||||||||||||||
| Capital Expenditures (1) | |||||||||||||||||||||||
| Maintenance capital expenditures | $ | 18 | $ | 9 | $ | 27 | $ | 47 | $ | 16 | $ | 65 | |||||||||||
| Growth capital expenditures | — | 3 | 10 | 3 | 10 | 161 | |||||||||||||||||
| Total capital expenditures | $ | 18 | $ | 12 | $ | 37 | $ | 50 | $ | 26 | $ | 226 | |||||||||||
| Three Months Ended December 31, 2020 | Year Ended December 31, 2020 | ||||||||||||||||||||||
| (in millions) | Petroleum | Nitrogen Fertilizer | Consolidated | Petroleum | Nitrogen Fertilizer | Consolidated | |||||||||||||||||
| Net sales | $ | 1,030 | $ | 90 | $ | 1,119 | $ | 3,586 | $ | 350 | $ | 3,930 | |||||||||||
| Operating loss | (120 | ) | (1 | ) | (126 | ) | (281 | ) | (35 | ) | (333 | ) | |||||||||||
| Net loss | (114 | ) | (17 | ) | (78 | ) | (271 | ) | (98 | ) | (320 | ) | |||||||||||
| EBITDA * | (66 | ) | 18 | 1 | (74 | ) | 41 | (7 | ) | ||||||||||||||
| Capital Expenditures (1) | |||||||||||||||||||||||
| Maintenance capital expenditures | $ | 11 | $ | 2 | $ | 14 | $ | 77 | $ | 12 | $ | 92 | |||||||||||
| Growth capital expenditures | 11 | 1 | 11 | 13 | 4 | 29 | |||||||||||||||||
| Total capital expenditures | $ | 22 | $ | 3 | $ | 25 | $ | 90 | $ | 16 | $ | 121 | |||||||||||
| * | See “Non-GAAP Reconciliations” section below. | ||
| (1) | Capital expenditures are shown exclusive of capitalized turnaround expenditures and business combinations. | ||
| December 31, 2021 | December 31, 2020 | ||||||||||||||||||||||
| (in millions) | Petroleum | Nitrogen Fertilizer | Consolidated | Petroleum | Nitrogen Fertilizer | Consolidated | |||||||||||||||||
| Cash and cash equivalents (1) | $ | 305 | $ | 113 | $ | 510 | $ | 429 | $ | 31 | $ | 667 | |||||||||||
| Total assets | 3,368 | 1,127 | 3,906 | 2,991 | 1,033 | 3,978 | |||||||||||||||||
| Total debt and finance lease obligations, including current portion (2) | 54 | 611 | 1,660 | 61 | 636 | 1,691 | |||||||||||||||||
| (1) | Corporate cash and cash equivalents consisted of $92 million and $207 million at December 31, 2021 and December 31, 2020, respectively. | |
| (2) | Corporate total debt and finance lease obligations, including current portion consisted of $995 million and $994 million at December 31, 2021 and December 31, 2020, respectively. | |
Petroleum Segment
Key Operating Metrics per Total Throughput Barrel
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||
| (in millions) | 2021 | 2020 | 2021 | 2020 | |||||||
| Refining margin * | $ | 7.13 | $ | 1.32 | $ | 8.14 | $ | 4.44 | |||
| Refining margin, excluding inventory valuation impacts * | 6.28 | 0.56 | 6.48 | 5.31 | |||||||
| Direct operating expenses * | 4.84 | 3.99 | 4.83 | 4.76 | |||||||
| * | See “Non-GAAP Reconciliations” section below. | |
Throughput Data by Refinery
| Three Months Ended December 31, | Year Ended December 31, | ||||||
| (in bpd) | 2021 | 2020 | 2021 | 2020 | |||
| Coffeyville | |||||||
| Regional crude | 24,958 | 29,813 | 27,133 | 34,652 | |||
| WTI | 63,604 | 78,052 | 62,694 | 51,656 | |||
| WTL | 482 | — | 511 | — | |||
| Midland WTI | 160 | — | 452 | — | |||
| Condensate | 5,692 | 7,473 | 7,911 | 8,243 | |||
| Heavy Canadian | 6,129 | — | 3,684 | 1,020 | |||
| Other crude oil | 27,611 | 10,789 | 19,129 | 5,151 | |||
| Other feedstocks and blendstocks | 13,730 | 12,253 | 10,788 | 8,321 | |||
| Wynnewood | |||||||
| Regional crude | 63,158 | 68,471 | 60,287 | 56,932 | |||
| WTL | — | 3,977 | 3,430 | 6,235 | |||
| Midland WTI | 4,047 | 333 | 2,107 | 1,262 | |||
| Condensate | 7,654 | 3,324 | 7,360 | 6,207 | |||
| Other Crude Oil | 803 | — | 202 | — | |||
| Other feedstocks and blendstocks | 4,229 | 4,056 | 3,396 | 3,616 | |||
| Total throughput | 222,257 | 218,541 | 209,084 | 183,295 | |||
Production Data by Refinery
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||
| (in bpd) | 2021 | 2020 | 2021 | 2020 | |||||||
| Coffeyville | |||||||||||
| Gasoline | 79,259 | 77,816 | 71,070 | 59,419 | |||||||
| Distillate | 57,033 | 55,816 | 53,441 | 43,209 | |||||||
| Other liquid products | 3,098 | 3,019 | 4,481 | 3,999 | |||||||
| Solids | 4,566 | 3,780 | 4,246 | 3,073 | |||||||
| Wynnewood | |||||||||||
| Gasoline | 41,459 | 42,533 | 39,858 | 38,640 | |||||||
| Distillate | 33,547 | 32,943 | 31,662 | 30,638 | |||||||
| Other liquid products | 2,971 | 2,918 | 2,862 | 2,629 | |||||||
| Solids | 25 | 25 | 21 | 25 | |||||||
| Total production | 221,958 | 218,850 | 207,641 | 181,632 | |||||||
| Light product yield (as % of crude throughput) (1) | 103.4 | % | 103.4 | % | 100.6 | % | 100.3 | % | |||
| Liquid volume yield (as % of total throughput) (2) | 97.8 | % | 98.4 | % | 97.3 | % | 97.4 | % | |||
| Distillate yield (as % of crude throughput) (3) | 44.3 | % | 43.9 | % | 43.7 | % | 43.1 | % | |||
| (1) | Total Gasoline and Distillate divided by total Regional crude, WTI, WTL, Midland WTI, Condensate, and Heavy Canadian throughput. | |
| (2) | Total Gasoline, Distillate, and Other liquid products divided by total throughput. | |
| (3) | Total Distillate divided by total Regional crude, WTI, WTL, Midland WTI, Condensate, and Heavy Canadian throughput. | |
Key Market Indicators
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
| (dollars per barrel) | 2021 | 2020 | 2021 | 2020 | |||||||||||
| West Texas Intermediate (WTI) NYMEX | $ | 77.10 | $ | 42.70 | $ | 68.11 | $ | 39.34 | |||||||
| Crude Oil Differentials to WTI: | |||||||||||||||
| Brent | 2.71 | 2.49 | 2.81 | 3.84 | |||||||||||
| WCS (heavy sour) | (16.60 | ) | (11.44 | ) | (13.55 | ) | (12.09 | ) | |||||||
| Condensate | 0.04 | (0.28 | ) | (0.40 | ) | (1.19 | ) | ||||||||
| Midland Cushing | 0.63 | 0.37 | 0.45 | 0.20 | |||||||||||
| NYMEX Crack Spreads: | |||||||||||||||
| Gasoline | 18.52 | 8.51 | 20.11 | 10.31 | |||||||||||
| Heating Oil | 22.77 | 11.20 | 18.80 | 13.15 | |||||||||||
| NYMEX 2-1-1 Crack Spread | 20.64 | 9.85 | 19.45 | 11.73 | |||||||||||
| PADD II Group 3 Product Basis: | |||||||||||||||
| Gasoline | (4.50 | ) | (2.74 | ) | (2.60 | ) | (3.50 | ) | |||||||
| Ultra Low Sulfur Diesel | (2.79 | ) | (0.08 | ) | (0.02 | ) | (1.15 | ) | |||||||
| PADD II Group 3 Product Crack Spread: | |||||||||||||||
| Gasoline | 14.02 | 5.76 | 17.51 | 6.82 | |||||||||||
| Ultra Low Sulfur Diesel | 19.98 | 11.12 | 18.78 | 12.00 | |||||||||||
| PADD II Group 3 2-1-1 | 17.00 | 8.44 | 18.14 | 9.41 | |||||||||||
Nitrogen Fertilizer Segment
Ammonia Utilization Rates (1)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||
| (percent of capacity utilization) | 2021 | 2020 | 2021 | 2020 | |||||||
| Consolidated | 90 | % | 101 | % | 92 | % | 98 | % | |||
| (1) | Reflects ammonia utilization rates on a consolidated basis and at each of the Nitrogen Fertilizer Segment’s facilities. Utilization is an important measure used by management to assess operational output at each of the facilities. Utilization is calculated as actual tons produced divided by capacity. The Nitrogen Fertilizer Segment presents utilization on a two-year rolling average to take into account the impact of current turnaround cycles on any specific period. The two-year rolling average is a more useful presentation of the long-term utilization performance of our plants. Additionally, we present utilization solely on ammonia production rather than each nitrogen product as it provides a comparative baseline against industry peers and eliminates the disparity of plant configurations for upgrade of ammonia into other nitrogen products. With the Nitrogen Fertilizer Segments’ efforts being primarily focused on ammonia upgrade capabilities, this measure provides a meaningful view of how well the facilities operate. | |
Sales and Production Data
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||
| Consolidated sales (thousand tons): | |||||||||||
| Ammonia | 105 | 114 | 269 | 332 | |||||||
| UAN | 265 | 325 | 1,196 | 1,312 | |||||||
| Consolidated product pricing at gate (dollars per ton): (1) | |||||||||||
| Ammonia | $ | 745 | $ | 267 | $ | 544 | $ | 284 | |||
| UAN | $ | 347 | $ | 139 | $ | 264 | $ | 152 | |||
| Consolidated production volume (thousand tons): | |||||||||||
| Ammonia (gross produced) (2) | 197 | 220 | 807 | 852 | |||||||
| Ammonia (net available for sale) (2) | 70 | 75 | 275 | 303 | |||||||
| UAN | 288 | 335 | 1,208 | 1,303 | |||||||
| Feedstock: | |||||||||||
| Petroleum coke used in production (thousand tons) | 124 | 131 | 514 | 523 | |||||||
| Petroleum coke used in production (dollars per ton) | $ | 47.96 | $ | 30.65 | $ | 44.69 | $ | 35.25 | |||
| Natural gas used in production (thousands of MMBtus) (3) | 1,970 | 2,203 | 8,049 | 8,611 | |||||||
| Natural gas used in production (dollars per MMBtu) (3) | $ | 5.43 | $ | 2.77 | $ | 3.95 | $ | 2.31 | |||
| Natural gas in cost of materials and other (thousands of MMBtus) (3) | 2,412 | 2,689 | 7,848 | 9,349 | |||||||
| Natural gas in cost of materials and other (dollars per MMBtu) (3) | $ | 5.10 | $ | 2.59 | $ | 3.83 | $ | 2.35 | |||
| (1) | Product pricing at gate represents sales less freight revenue divided by product sales volume in tons and is shown in order to provide a pricing measure that is comparable across the fertilizer industry. | |
| (2) | Gross tons produced for ammonia represent total ammonia produced, including ammonia produced that was upgraded into other fertilizer products. Net tons available for sale represent ammonia available for sale that was not upgraded into other fertilizer products. | |
| (3) | The feedstock natural gas shown above does not include natural gas used for fuel. The cost of fuel natural gas is included in direct operating expense. | |
Key Market Indicators
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||
| Ammonia — Southern plains (dollars per ton) | $ | 1,090 | $ | 256 | $ | 681 | $ | 251 | |||
| Ammonia — Corn belt (dollars per ton) | 1,199 | 340 | 746 | 337 | |||||||
| UAN — Corn belt (dollars per ton) | 583 | 163 | 384 | 168 | |||||||
| Natural gas NYMEX (dollars per MMBtu) | $ | 4.84 | $ | 2.76 | $ | 3.73 | $ | 2.13 | |||
Q1 2022 Outlook
The table below summarizes our outlook for certain refining statistics and financial information for the first quarter of 2022. See “Forward-Looking Statements” above.
| Q1 2022 | |||||||
| Low | High | ||||||
| Petroleum Segment | |||||||
| Total throughput (bpd) | 185,000 | 200,000 | |||||
| Direct operating expenses (in millions) (1) | $ | 90 | $ | 95 | |||
| Turnaround (3) | $ | 60 | $ | 70 | |||
| Nitrogen Fertilizer Segment | |||||||
| Ammonia utilization rates (2) | |||||||
| Consolidated | 92 | % | 97 | % | |||
| Coffeyville Facility | 95 | % | 100 | % | |||
| East Dubuque Facility | 90 | % | 95 | % | |||
| Direct operating expenses (in millions) (1) | $ | 50 | $ | 55 | |||
| Capital Expenditures (in millions) (3) | |||||||
| Petroleum | $ | 35 | $ | 45 | |||
| Renewables (4) | 10 | 15 | |||||
| Nitrogen Fertilizer | 4 | 7 | |||||
| Other | — | 1 | |||||
| Total capital expenditures | $ | 49 | $ | 68 | |||
| (1) | Direct operating expenses are shown exclusive of depreciation and amortization and, for the Nitrogen Fertilizer segment, turnaround expenses and inventory valuation impacts. | |
| (2) | Ammonia utilization rates exclude the impact of turnarounds. | |
| (3) | Turnaround and capital expenditures are disclosed on an accrual basis. | |
| (4) | Renewables reflects spending on the Wynnewood renewable diesel unit (“RDU”) project. Amounts spent in 2020 were previously reported under Other. Upon completion and meeting of certain criteria under accounting rules, Renewables is expected to be a new reportable segment. As of December 31, 2021, Renewables does not the meet the definition of a reporting segment as defined under Accounting Standards Codification 280. | |
Non-GAAP Reconciliations
Reconciliation of Consolidated Net Income (Loss) to EBITDA and Adjusted EBITDA
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
| (in millions) | 2021 | 2020 | 2021 | 2020 | |||||||||||
| Net income (loss) | $ | 25 | $ | (78 | ) | $ | 74 | $ | (320 | ) | |||||
| Interest expense, net | 24 | 32 | 117 | 130 | |||||||||||
| Income tax benefit | (7 | ) | (23 | ) | (8 | ) | (95 | ) | |||||||
| Depreciation and amortization | 74 | 70 | 279 | 278 | |||||||||||
| EBITDA | 116 | 1 | 462 | (7 | ) | ||||||||||
| Adjustments: | |||||||||||||||
| Revaluation of RFS liability | 9 | 66 | 63 | 59 | |||||||||||
| Loss (gain) on marketable securities | 1 | (54 | ) | (81 | ) | (34 | ) | ||||||||
| Unrealized loss (gain) on derivatives | — | 23 | (16 | ) | 9 | ||||||||||
| Inventory valuation impacts, (favorable) unfavorable | (17 | ) | (15 | ) | (127 | ) | 58 | ||||||||
| Goodwill impairment | — | — | — | 41 | |||||||||||
| Adjusted EBITDA | 109 | 21 | 301 | 126 | |||||||||||
Reconciliation of Basic and Diluted (Loss) Earnings per Share to Adjusted Loss per Share
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||
| Basic and diluted (loss) earnings per share | $ | (0.14 | ) | $ | (0.67 | ) | $ | 0.25 | $ | (2.54 | ) | ||||
| Adjustments: (1) | |||||||||||||||
| Revaluation of RFS liability | 0.06 | 0.48 | 0.46 | 0.43 | |||||||||||
| Loss (gain) on marketable securities | 0.01 | (0.40 | ) | (0.59 | ) | (0.25 | ) | ||||||||
| Unrealized loss (gain) on derivatives | — | 0.17 | (0.12 | ) | 0.07 | ||||||||||
| Inventory valuation impacts, (favorable) unfavorable | (0.13 | ) | (0.11 | ) | (0.93 | ) | 0.43 | ||||||||
| Goodwill impairment (2) | — | — | — | 0.07 | |||||||||||
| Adjusted loss per share | $ | (0.20 | ) | $ | (0.53 | ) | $ | (0.93 | ) | $ | (1.79 | ) | |||
| (1) | Amounts are shown after-tax, using the Company’s marginal tax rate, and are presented on a per share basis using the weighted average shares outstanding for each period. | |
| (2) | Amount is shown exclusive of noncontrolling interests. | |
Reconciliation of Net Cash Provided by Operating Activities to Free Cash Flow
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
| (in millions) | 2021 | 2020 | 2021 | 2020 | |||||||||||
| Net cash provided by operating activities | $ | 14 | $ | 28 | $ | 396 | $ | 90 | |||||||
| Less: | |||||||||||||||
| Capital expenditures | (36 | ) | (23 | ) | (224 | ) | (124 | ) | |||||||
| Capitalized turnaround expenditures | (2 | ) | (1 | ) | (5 | ) | (159 | ) | |||||||
| Free cash flow | $ | (24 | ) | $ | 4 | $ | 167 | $ | (193 | ) | |||||
Reconciliation of Petroleum Segment Net (Loss) Income to EBITDA and Adjusted EBITDA
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
| (in millions) | 2021 | 2020 | 2021 | 2020 | |||||||||||
| Petroleum net (loss) income | $ | (19 | ) | $ | (114 | ) | $ | 4 | $ | (271 | ) | ||||
| Interest (income) expense, net | (5 | ) | (3 | ) | (21 | ) | (5 | ) | |||||||
| Depreciation and amortization | 51 | 51 | 203 | 202 | |||||||||||
| Petroleum EBITDA | 27 | (66 | ) | 186 | (74 | ) | |||||||||
| Adjustments: | |||||||||||||||
| Revaluation of RFS liability | 9 | 66 | 63 | 59 | |||||||||||
| Unrealized gain (loss) on derivatives | — | 23 | (16 | ) | 9 | ||||||||||
| Inventory valuation impact, (favorable) unfavorable (1) (2) | (17 | ) | (15 | ) | (127 | ) | 58 | ||||||||
| Petroleum Adjusted EBITDA | 19 | 8 | 106 | 52 | |||||||||||
Reconciliation of Petroleum Segment Gross Profit (Loss) to Refining Margin and Refining Margin Adjusted for Inventory Valuation Impacts
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
| (in millions) | 2021 | 2020 | 2021 | 2020 | |||||||||||
| Net sales | $ | 1,928 | $ | 1,030 | $ | 6,721 | $ | 3,586 | |||||||
| Less: | |||||||||||||||
| Cost of materials and other | (1,782 | ) | (1,003 | ) | (6,100 | ) | (3,288 | ) | |||||||
| Direct operating expenses (exclusive of depreciation and amortization) | (99 | ) | (81 | ) | (369 | ) | (319 | ) | |||||||
| Depreciation and amortization | (50 | ) | (49 | ) | (197 | ) | (194 | ) | |||||||
| Gross profit (loss) | (3 | ) | (103 | ) | 55 | (215 | ) | ||||||||
| Add: | |||||||||||||||
| Direct operating expenses (exclusive of depreciation and amortization) | 99 | 81 | 369 | 319 | |||||||||||
| Depreciation and amortization | 50 | 49 | 197 | 194 | |||||||||||
| Refining margin | 146 | 27 | 621 | 298 | |||||||||||
| Inventory valuation impact, (favorable) unfavorable (1) (2) | (17 | ) | (15 | ) | (127 | ) | 58 | ||||||||
| Refining margin, excluding inventory valuation impacts | $ | 129 | $ | 12 | $ | 494 | $ | 356 | |||||||
| (1) | The Petroleum Segment’s basis for determining inventory value under GAAP is First-In, First-Out (“FIFO”). Changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable inventory valuation impact when crude oil prices increase and an unfavorable inventory valuation impact when crude oil prices decrease. The inventory valuation impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. In order to derive the inventory valuation impact per total throughput barrel, we utilize the total dollar figures for the inventory valuation impact and divide by the number of total throughput barrels for the period. | |
| (2) | Includes an inventory valuation charge of $58 million recorded in the first quarter of 2020, as inventories were reflected at the lower of cost or net realizable value. No such charge was recognized in the second, third and fourth quarters of 2021 or the 2020 periods. | |
Reconciliation of Petroleum Segment Total Throughput Barrels
| Three Months Ended December 31, | Year Ended December 31, | ||||||
| 2021 | 2020 | 2021 | 2020 | ||||
| Total throughput barrels per day | 222,257 | 218,541 | 209,084 | 183,295 | |||
| Days in the period | 92 | 92 | 365 | 366 | |||
| Total throughput barrels | 20,447,613 | 20,105,780 | 76,315,701 | 67,085,913 | |||
Reconciliation of Petroleum Segment Refining Margin per Total Throughput Barrel
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||
| (in millions, except per total throughput barrel) | 2021 | 2020 | 2021 | 2020 | |||||||
| Refining margin | $ | 146 | $ | 27 | $ | 621 | $ | 298 | |||
| Divided by: total throughput barrels | 20 | 20 | 76 | 67 | |||||||
| Refining margin per total throughput barrel | $ | 7.13 | $ | 1.32 | $ | 8.14 | $ | 4.44 | |||
Reconciliation of Petroleum Segment Refining Margin Adjusted for Inventory Valuation Impacts per Total Throughput Barrel
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||
| (in millions, except per total throughput barrel) | 2021 | 2020 | 2021 | 2020 | |||||||
| Refining margin, excluding inventory valuation impacts | $ | 129 | $ | 12 | $ | 494 | $ | 356 | |||
| Divided by: total throughput barrels | 20 | 20 | 76 | 67 | |||||||
| Refining margin, excluding inventory valuation impacts, per total throughput barrel | $ | 6.28 | $ | 0.56 | $ | 6.48 | $ | 5.31 | |||
Reconciliation of Petroleum Segment Direct Operating Expenses per Total Throughput Barrel
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||
| (in millions, except per total throughput barrel) | 2021 | 2020 | 2021 | 2020 | |||||||
| Direct operating expenses (exclusive of depreciation and amortization) | $ | 99 | $ | 81 | $ | 369 | $ | 319 | |||
| Divided by: total throughput barrels | 20 | 20 | 76 | 67 | |||||||
| Direct operating expense per total throughput barrel | $ | 4.84 | $ | 3.99 | $ | 4.83 | $ | 4.76 | |||
Reconciliation of Nitrogen Fertilizer Segment Net Income (Loss) to EBITDA and Adjusted EBITDA
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||
| (in millions) | 2021 | 2020 | 2021 | 2020 | |||||||||
| Nitrogen fertilizer net income (loss) | $ | 61 | $ | (17 | ) | $ | 78 | $ | (98 | ) | |||
| Add: | |||||||||||||
| Interest expense, net | 11 | 16 | 61 | 63 | |||||||||
| Depreciation and amortization | 21 | 19 | 74 | 76 | |||||||||
| Nitrogen Fertilizer EBITDA | 93 | 18 | 213 | 41 | |||||||||
| Goodwill impairment | — | — | — | 41 | |||||||||
| Adjusted Nitrogen Fertilizer EBITDA | $ | 93 | $ | 18 | $ | 213 | $ | 82 | |||||
Reconciliation of Total Debt and Net Debt and Finance Lease Obligations to EBITDA Exclusive of Nitrogen Fertilizer
| (in millions) | Twelve Months Ended December 31, 2021 | ||
| Total debt and finance lease obligations (1) | $ | 1,660 | |
| Less: | |||
| Nitrogen Fertilizer debt and finance lease obligations (1) | $ | (611 | ) |
| Total debt and finance lease obligations exclusive of Nitrogen Fertilizer | 1,049 | ||
| EBITDA exclusive of Nitrogen Fertilizer | $ | 249 | |
| Total debt and finance lease obligations to EBITDA exclusive of Nitrogen Fertilizer | 4.21 | ||
| Consolidated cash and cash equivalents | $ | 510 | |
| Less: | |||
| Nitrogen Fertilizer cash and cash equivalents | (113 | ) | |
| Cash and cash equivalents exclusive of Nitrogen Fertilizer | 397 | ||
| Net debt and finance lease obligations exclusive of Nitrogen Fertilizer (2) | $ | 652 | |
| Net debt and finance lease obligations to EBITDA exclusive of Nitrogen Fertilizer (2) | 2.62 | ||
| (1) | Amounts are shown inclusive of the current portion of long-term debt and finance lease obligations. | |
| (2) | Net debt represents total debt and finance lease obligations exclusive of cash and cash equivalents. | |
| Three Months Ended December 31, | Twelve Months Ended December 31, 2021 (1) | |||||||||||||||||
| (in millions) | March 31, 2021 | June 30, 2021 | September 30, 2021 | December 31, 2021 | ||||||||||||||
| Consolidated | ||||||||||||||||||
| Net (loss) income | $ | (55 | ) | $ | (2 | ) | $ | 106 | $ | 25 | $ | 74 | ||||||
| Interest expense, net | 31 | 38 | 23 | 24 | 117 | |||||||||||||
| Income tax benefit | (42 | ) | (6 | ) | 47 | (7 | ) | (8 | ) | |||||||||
| Depreciation and amortization | 66 | 72 | 67 | 74 | 279 | |||||||||||||
| EBITDA | $ | — | $ | 102 | $ | 243 | $ | 116 | $ | 462 | ||||||||
| Nitrogen Fertilizer | ||||||||||||||||||
| Net (loss) income | $ | (25 | ) | $ | 7 | $ | 35 | $ | 61 | 78 | ||||||||
| Interest expense, net | 16 | 23 | 11 | 11 | 61 | |||||||||||||
| Depreciation and amortization | 14 | 21 | 18 | 21 | 74 | |||||||||||||
| EBITDA | $ | 5 | $ | 51 | $ | 64 | $ | 93 | $ | 213 | ||||||||
| EBITDA exclusive of Nitrogen Fertilizer | $ | (5 | ) | $ | 51 | $ | 179 | $ | 23 | $ | 249 | |||||||
| (1) | Due to rounding, numbers within this table may not add or equal to totals presented. | |
