SUGAR LAND, Texas, Oct. 30, 2023 (GLOBE NEWSWIRE) -- CVR Energy, Inc. (“CVR Energy” or the “Company”) (NYSE: CVI) today announced net income of $353 million, or $3.51 per diluted share, on net sales of $2.5 billion for the third quarter of 2023, compared to net income of $93 million, or 92 cents per diluted share, on net sales of $2.7 billion for the third quarter of 2022. Adjusted earnings for the third quarter of 2023 was $1.89 per diluted share compared to adjusted earnings of $1.90 per diluted share in the third quarter of 2022. Third quarter 2023 EBITDA was $530 million, compared to third quarter 2022 EBITDA of $181 million. Adjusted EBITDA for the third quarter of 2023 was $313 million, compared to Adjusted EBITDA of $313 million in the third quarter of 2022.
“CVR Energy achieved solid results for the 2023 third quarter driven by continued strong crack spreads,” said Dave Lamp, CVR Energy’s Chief Executive Officer. “In addition to our third quarter 2023 cash dividend of 50 cents, our Board of Directors was pleased to approve a special dividend of $1.50 per share, bringing our year-to-date declared dividends to $4.00 per share.
“CVR Partners posted solid operating results for the 2023 third quarter driven by safe, reliable operations with a combined ammonia production rate of 99 percent,” Lamp said. “CVR Partners also announced a cash distribution of $1.55 per common unit for the 2023 third quarter.”
Petroleum
The Petroleum Segment reported third quarter 2023 operating income of $431 million on net sales of $2.3 billion, compared to operating income of $137 million on net sales of $2.5 billion in the third quarter of 2022.
Refining margin per total throughput barrel was $31.05 in the third quarter of 2023, compared to $16.56 during the same period in 2022. The increase in refining margin of $300 million was primarily due to lower Renewable Fuel Standard (“RFS”) related expense and favorable inventory valuations. The Group 3 2-1-1 crack spread decreased by $4.84 per barrel relative to the third quarter of 2022, driven by a tightening distillate crack spread due primarily to recession concerns and slowing demand trends.
The Petroleum Segment recognized costs to comply with the RFS of $90 million, or $4.64 per throughput barrel, which excludes the RINs’ revaluation benefit impact of $173 million, or $8.88 per total throughput barrel, for the third quarter of 2023. This is compared to RFS compliance costs of $98 million, or $5.28 per throughput barrel, which excludes the RINs’ revaluation expense impact of $38 million, or $2.06 per total throughput barrel, for the third quarter of 2022. The decrease in RFS compliance costs in 2023 was primarily related to a decrease in RIN prices, coupled with an increase in RINs generated by ethanol and biodiesel blending for the third quarter of 2023 compared to the 2022 period. The favorable RINs’ revaluation in 2023 was a result of a mark-to-market benefit in the current period due to a decline in RIN prices and a lower outstanding obligation in the current period compared to the 2022 period.
The Petroleum Segment also recognized a third quarter 2023 derivative net loss of $98 million, or $5.01 per total throughput barrel, compared to a derivative net gain of $13 million, or 71 cents per total throughput barrel, for the third quarter of 2022. Included in this derivative net loss for the third quarter of 2023 was a $53 million unrealized loss, primarily a result of crack spread swaps, inventory hedging activity and Canadian crude forward purchases and sales, compared to a $25 million unrealized gain for the third quarter of 2022. Offsetting these impacts, crude oil prices increased during the quarter, which led to a favorable inventory valuation impact of $82 million, or $4.18 per total throughput barrel, compared to an unfavorable inventory valuation impact of $107 million, or $5.78 per total throughput barrel, during the third quarter of 2022.
Third quarter 2023 combined total throughput was approximately 212,000 bpd, compared to approximately 202,000 bpd of combined total throughput for the third quarter of 2022.
Nitrogen Fertilizer
The Nitrogen Fertilizer Segment reported operating income of $8 million on net sales of $131 million for the third quarter of 2023, compared to an operating loss of $12 million on net sales of $156 million for the third quarter of 2022.
CVR Partners, LP’s (“CVR Partners”) fertilizer facilities produced a combined 217,000 tons of ammonia during the third quarter of 2023, of which 68,000 net tons were available for sale while the rest was upgraded to other fertilizer products, including 358,000 tons of urea ammonia nitrate (“UAN”). During the third quarter 2022, the fertilizer facilities produced 114,000 tons of ammonia, of which 36,000 net tons were available for sale while the remainder was upgraded to other fertilizer products, including 184,000 tons of UAN. These increases were due to operating reliability after completing the planned turnarounds at both fertilizer facilities during the third quarter of 2022.
Third quarter 2023 average realized gate prices for UAN showed a reduction over the prior year, down 48 percent to $223 per ton, and ammonia was down 56 percent over the prior year to $365 per ton. Average realized gate prices for UAN and ammonia were $433 and $837 per ton, respectively, for the third quarter of 2022.
Corporate and Other
The Company reported an income tax expense of $84 million, or 19.3 percent of income before income taxes, for the three months ended September 30, 2023, as compared to an income tax expense of $7 million, or 8.3 percent of income before income taxes, for the three months ended September 30, 2022. The increases in income tax expense and effective tax rate were due primarily to changes in pretax earnings and earnings attributable to noncontrolling interest.
The renewable diesel unit at the Wynnewood refinery continued to increase production, with total vegetable oil throughputs for the third quarter of 2023 of approximately 23.8 million gallons, up from 17.7 million gallons in the third quarter of 2022. The increase was due primarily to operations at the renewable diesel unit still ramping up in the third quarter of 2022 as this was the first full quarter of operations after the unit’s completion in April 2022.
Cash, Debt and Dividend
Consolidated cash and cash equivalents were $889 million at September 30, 2023, an increase of $379 million from December 31, 2022. Consolidated total debt and finance lease obligations were $1.6 billion at September 30, 2023, including $547 million held by the Nitrogen Fertilizer Segment.
On September 26, 2023, CVR Partners and certain of its subsidiaries entered into Amendment No. 1 to the Credit Agreement (the “ABL Amendment”). The ABL Amendment amended that certain Credit Agreement, dated as of September 30, 2021 (as amended, the “Nitrogen Fertilizer ABL”), to, among other things, (i) increase the aggregate principal amount available under the credit facility by an additional $15 million to a total of $50 million in the aggregate, with an incremental facility of an additional $15 million in the aggregate subject to additional lender commitments and certain other conditions, and (ii) extend the maturity date by an additional four years to September 26, 2028. The proceeds of the Nitrogen Fertilizer ABL may be used to fund working capital, capital expenditures and for other general corporate purposes.
CVR Energy announced a third quarter 2023 cash dividend of 50 cents per share. In addition, the Company announced a special dividend of $1.50 per share. The quarterly and special dividends, as declared by CVR Energy’s Board of Directors, will be paid on November 20, 2023, to stockholders of record as of November 13, 2023.
Today, CVR Partners announced that the Board of Directors of its general partner declared a third quarter 2023 cash distribution of $1.55 per common unit, which will be paid on November 20, 2023, to common unitholders of record as of November 13, 2023.
Third Quarter 2023 Earnings Conference Call
CVR Energy previously announced that it will host its third quarter 2023 Earnings Conference Call on Tuesday, October 31, at 1 p.m. Eastern. The Earnings Conference Call may also include discussion of Company developments, forward-looking information and other material information about business and financial matters.
The third quarter 2023 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/ez75egze. A repeat of the call also can be accessed for 14 days by dialing (877) 660-6853, conference ID 13741665.
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: drivers of results; crack spreads, including the continued strength thereof; production rates of CVR Partners, including the impact thereof on results; net income and sales; adjusted earnings including the drivers thereof; EBITDA and Adjusted EBITDA; operating income; net sales; refining margin and the drivers thereof; RFS expense; inventory valuation impacts; crack spreads, including the tightening of distillate cracks; recession; demand trends; cost to comply with the Renewable Fuel Standard, RIN prices and level and valuation of our net RVO; CVR Energy’s blending activity, including its impact on RFS compliance costs; derivative activities and realized and unrealized gains or losses associated therewith; crude oil pricing; throughput rates, including factors impacting same; crude oil supply; UAN, ammonia and nitrogen fertilizer production, demand, pricing and sales volumes, including the factors impacting same; rates at which ammonia will be upgraded to other fertilizer products; operational reliability, including the factors impacting same; tax rates and expense; quarterly and special dividends and distributions, including the timing, payment and amount (if any) thereof; production rates of our renewable diesel unit and related feedstock throughput, including factors impacting same; any decision to return a unit back to hydrocarbon processing following renewable conversion; cash and cash equivalent levels; credit facility availability; continued safe and reliable operations; operating expenses, capital expenditures, depreciation and amortization and turnaround expense; the expected timing and completion of turnaround projects; renewables initiatives; conversion of hydrocrackers at Coffeyville and/or feed pretreaters, including the completion, operation, capacities, timing, costs, optionality and benefits thereof; carbon capture and decarbonization initiatives; labor supply shortages, labor difficulties, labor disputes or strikes; utilization rates; global fertilizer industry conditions; crop and planting conditions; natural gas and global energy costs; and other matters. You can generally identify forward-looking statements by our use of forward-looking terminology such as “outlook,” “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 the rate of any economic improvement, demand for fossil fuels, price volatility of crude oil, other feedstocks and refined products (among others); the ability of the Company to pay cash dividends and CVR Partners to make cash distributions; potential operating hazards; costs of compliance with existing, or compliance with new, laws and regulations and potential liabilities arising therefrom; impacts of planting season on CVR Partners; our controlling shareholder’s intention regarding ownership of our common stock, including any dispositions of our common stock; the health and economic effects of the COVID-19 pandemic and any variant thereof; general economic and business conditions; political disturbances, geopolitical instability and tensions, and associated changes in global trade policies and economic sanctions, including, but not limited to, in connection with the Russia/Ukraine and Israel/Hamas conflicts; impacts of plant outages and weather events on throughput volume; risks related to the conclusion of consideration of a spin-off of some or all of Company’s interests in its nitrogen fertilizer business or potential future reconsideration thereof; our ability to refinance our debt on acceptable terms or at all; 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 renewables, petroleum refining and marketing business as well as in the nitrogen fertilizer manufacturing business through its interest in CVR Partners. CVR Energy subsidiaries serve as the general partner and own 37 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 financial information presented in accordance with accounting principles generally accepted in the United States (“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.
The following are non-GAAP measures we present for the period ended September 30, 2023:
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
Petroleum Segment
Our results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future due to capitalized expenditures as part of planned turnarounds. Total capitalized expenditures were $2 million and $4 million during the three months ended September 30, 2023 and 2022, respectively, and $53 million and $73 million during the nine months ended September 30, 2023 and 2022, respectively. The next planned turnarounds are currently scheduled to take place in the spring of 2024 at the Wynnewood Refinery and in 2025 at the Coffeyville Refinery.
Nitrogen Fertilizer Segment
Our results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future due to expenses incurred as part of planned turnarounds. We incurred turnaround expenses of $1 million and $31 million during the three months ended September 30, 2023 and 2022, respectively, and $2 million and $33 million during the nine months ended September 30, 2023 and 2022, respectively. The next planned turnarounds are currently scheduled to take place in 2025 at the Coffeyville Fertilizer Facility and in 2026 at the East Dubuque Fertilizer Facility.
| CVR Energy, Inc. (all information in this release is unaudited) | |||||||||||||||
| Consolidated Statement of Operations Data | |||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| (in millions, except per share data) | 2023 | 2022 | 2023 | 2022 | |||||||||||
| Net sales | $ | 2,522 | $ | 2,699 | $ | 7,045 | $ | 8,216 | |||||||
| Operating costs and expenses: | |||||||||||||||
| Cost of materials and other | 1,787 | 2,267 | 5,211 | 6,619 | |||||||||||
| Direct operating expenses (exclusive of depreciation and amortization) | 170 | 218 | 503 | 545 | |||||||||||
| Depreciation and amortization | 80 | 74 | 217 | 210 | |||||||||||
| Cost of sales | 2,037 | 2,559 | 5,931 | 7,374 | |||||||||||
| Selling, general and administrative expenses (exclusive of depreciation and amortization) | 38 | 35 | 109 | 110 | |||||||||||
| Depreciation and amortization | 1 | 1 | 4 | 5 | |||||||||||
| Loss on asset disposal | 1 | 1 | 1 | 1 | |||||||||||
| Operating income | 445 | 103 | 1,000 | 726 | |||||||||||
| Other (expense) income: | |||||||||||||||
| Interest expense, net | (11 | ) | (19 | ) | (44 | ) | (67 | ) | |||||||
| Other income (expense), net | 4 | 3 | 10 | (81 | ) | ||||||||||
| Income before income tax expense | 438 | 87 | 966 | 578 | |||||||||||
| Income tax expense | 84 | 7 | 185 | 106 | |||||||||||
| Net income | 354 | 80 | 781 | 472 | |||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | 1 | (13 | ) | 103 | 121 | ||||||||||
| Net income attributable to CVR Energy stockholders | $ | 353 | $ | 93 | $ | 678 | $ | 351 | |||||||
| Basic and diluted earnings per share | $ | 3.51 | $ | 0.92 | $ | 6.74 | $ | 3.49 | |||||||
| Dividends declared per share | $ | 1.50 | $ | 3.00 | $ | 2.50 | $ | 3.40 | |||||||
| Adjusted earnings per share | $ | 1.89 | $ | 1.90 | $ | 4.98 | $ | 4.37 | |||||||
| EBITDA* | $ | 530 | $ | 181 | $ | 1,231 | $ | 860 | |||||||
| Adjusted EBITDA * | $ | 313 | $ | 313 | $ | 994 | $ | 979 | |||||||
| 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) | September 30, 2023 | December 31, 2022 | |||
| Cash and cash equivalents | $ | 889 | $ | 510 | |
| Working capital | 576 | 154 | |||
| Total assets | 4,421 | 4,119 | |||
| Total debt and finance lease obligations, including current portion | 1,590 | 1,591 | |||
| Total liabilities | 3,269 | 3,328 | |||
| Total CVR stockholders’ equity | 957 | 531 | |||
| Selected Cash Flow Data | |||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| (in millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||
| Net cash provided by (used in): | |||||||||||||||
| Operating activities | $ | 370 | $ | 156 | $ | 984 | $ | 868 | |||||||
| Investing activities | (51 | ) | (61 | ) | (181 | ) | (217 | ) | |||||||
| Financing activities | (181 | ) | (370 | ) | (424 | ) | (543 | ) | |||||||
| Net increase (decrease) in cash and cash equivalents and restricted cash | $ | 138 | $ | (275 | ) | $ | 379 | $ | 108 | ||||||
| Free cash flow* | $ | 318 | $ | 93 | $ | 802 | $ | 649 | |||||||
__________________________
* See “Non-GAAP Reconciliations” section below.
| Selected Segment Data | |||||||||||||||||
| Three Months Ended September 30, 2023 | Nine Months Ended September 30, 2023 | ||||||||||||||||
| (in millions) | Petroleum | Nitrogen Fertilizer | Consolidated | Petroleum | Nitrogen Fertilizer | Consolidated | |||||||||||
| Net sales | $ | 2,298 | $ | 131 | $ | 2,522 | $ | 6,290 | $ | 540 | $ | 7,045 | |||||
| Operating income | 431 | 8 | 445 | 838 | 184 | 1,000 | |||||||||||
| Net income | 460 | 1 | 354 | 913 | 162 | 781 | |||||||||||
| EBITDA* | 484 | 32 | 530 | 989 | 243 | 1,231 | |||||||||||
| Capital expenditures (1) | |||||||||||||||||
| Maintenance capital expenditures | $ | 20 | $ | 8 | $ | 30 | $ | 70 | $ | 17 | $ | 92 | |||||
| Growth capital expenditures | 6 | — | 21 | 9 | 1 | 56 | |||||||||||
| Total capital expenditures | $ | 26 | $ | 8 | $ | 51 | $ | 79 | $ | 18 | $ | 148 | |||||
| Three Months Ended September 30, 2022 | Nine Months Ended September 30, 2022 | |||||||||||||||||
| (in millions) | Petroleum | Nitrogen Fertilizer | Consolidated | Petroleum | Nitrogen Fertilizer | Consolidated | ||||||||||||
| Net sales | $ | 2,474 | $ | 156 | $ | 2,699 | $ | 7,497 | $ | 623 | $ | 8,216 | ||||||
| Operating income | 137 | (12 | ) | 103 | 564 | 218 | 726 | |||||||||||
| Net income | 152 | (20 | ) | 80 | 584 | 191 | 472 | |||||||||||
| EBITDA* | 186 | 10 | 181 | 700 | 281 | 860 | ||||||||||||
| Capital expenditures (1) | ||||||||||||||||||
| Maintenance capital expenditures | $ | 22 | $ | 25 | $ | 52 | $ | 59 | $ | 38 | $ | 103 | ||||||
| Growth capital expenditures | 1 | — | 16 | 2 | 1 | 56 | ||||||||||||
| Total capital expenditures | $ | 23 | $ | 25 | $ | 68 | $ | 61 | $ | 38 | $ | 158 | ||||||
__________________________
* See “Non-GAAP Reconciliations” section below.
(1) Capital expenditures are shown exclusive of capitalized turnaround expenditures.
| Selected Balance Sheet Data | |||||||||||||||||
| September 30, 2023 | December 31, 2022 | ||||||||||||||||
| (in millions) | Petroleum | Nitrogen Fertilizer | Consolidated | Petroleum | Nitrogen Fertilizer | Consolidated | |||||||||||
| Cash and cash equivalents (1) | $ | 618 | $ | 89 | $ | 889 | $ | 235 | $ | 86 | $ | 510 | |||||
| Total assets | 4,635 | 1,019 | 4,421 | 4,354 | 1,100 | 4,119 | |||||||||||
| Total debt and finance lease obligations, including current portion (2) | 46 | 547 | 1,590 | 48 | 547 | 1,591 | |||||||||||
__________________________
(1) Corporate cash and cash equivalents consisted of $182 million and $189 million at September 30, 2023 and December 31, 2022, respectively.
(2) Corporate total debt and finance lease obligations, including current portion consisted of $997 million and $996 million at September 30, 2023 and December 31, 2022, respectively.
| Petroleum Segment | |||||||||||
| Key Operating Metrics per Total Throughput Barrel | |||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
| (in millions) | 2023 | 2022 | 2023 | 2022 | |||||||
| Refining margin * | $ | 31.05 | $ | 16.56 | $ | 24.33 | $ | 19.82 | |||
| Refining margin adjusted for inventory valuation impacts * | 26.87 | 22.34 | 23.46 | 18.66 | |||||||
| Direct operating expenses * | 5.39 | 5.53 | 5.58 | 5.74 | |||||||
__________________________
* See “Non-GAAP Reconciliations” section below.
| Throughput Data by Refinery | |||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||
| (in bpd) | 2023 | 2022 | 2023 | 2022 | |||
| Coffeyville | |||||||
| Regional crude | 68,176 | 60,762 | 62,442 | 55,675 | |||
| WTI | 27,837 | 30,261 | 30,161 | 37,465 | |||
| WTL | — | 312 | — | 544 | |||
| WTS | — | 1,222 | — | 412 | |||
| Midland WTI | — | — | — | 858 | |||
| Condensate | 7,401 | 10,674 | 7,718 | 10,871 | |||
| Heavy Canadian | 2,731 | 7,372 | 2,307 | 6,869 | |||
| DJ Basin | 20,504 | 13,526 | 17,006 | 14,092 | |||
| Bakken | 962 | — | 324 | — | |||
| Other feedstocks and blendstocks | 12,260 | 8,846 | 12,538 | 9,811 | |||
| Wynnewood | |||||||
| Regional crude | 53,554 | 45,840 | 51,519 | 45,553 | |||
| WTL | — | 4,915 | 1,639 | 2,323 | |||
| Midland WTI | 543 | — | 183 | 539 | |||
| WTS | — | — | — | 191 | |||
| Condensate | 15,780 | 15,313 | 14,567 | 12,121 | |||
| Other feedstocks and blendstocks | 2,672 | 2,614 | 2,984 | 2,774 | |||
| Total throughput | 212,420 | 201,657 | 203,388 | 200,098 | |||
| Production Data by Refinery | |||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
| (in bpd) | 2023 | 2022 | 2023 | 2022 | |||||||
| Coffeyville | |||||||||||
| Gasoline | 69,833 | 67,048 | 67,463 | 71,005 | |||||||
| Distillate | 60,661 | 56,848 | 56,311 | 56,768 | |||||||
| Other liquid products | 4,463 | 4,832 | 4,461 | 5,183 | |||||||
| Solids | 4,416 | 4,741 | 3,896 | 4,482 | |||||||
| Wynnewood | |||||||||||
| Gasoline | 36,997 | 36,423 | 37,656 | 33,040 | |||||||
| Distillate | 25,615 | 24,605 | 24,825 | 23,154 | |||||||
| Other liquid products | 9,038 | 6,264 | 7,355 | 5,436 | |||||||
| Solids | 9 | 8 | 10 | 12 | |||||||
| Total production | 211,032 | 200,769 | 201,977 | 199,080 | |||||||
| Light product yield (as % of crude throughput) (1) | 97.8 | % | 97.2 | % | 99.1 | % | 98.1 | % | |||
| Liquid volume yield (as % of total throughput) (2) | 97.3 | % | 97.2 | % | 97.4 | % | 97.2 | % | |||
| Distillate yield (as % of crude throughput) (3) | 43.7 | % | 42.8 | % | 43.2 | % | 42.6 | % | |||
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(1) Total Gasoline and Distillate divided by total Regional crude, WTI, WTL, Midland WTI, WTS, Condensate, Heavy Canadian, DJ Basin, and Bakken 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, WTS, Condensate, Heavy Canadian, DJ Basin, and Bakken throughput.
| Key Market Indicators | |||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||
| West Texas Intermediate (WTI) NYMEX | $ | 82.22 | $ | 91.43 | $ | 77.25 | $ | 98.35 | |||||||
| Crude Oil Differentials to WTI: | |||||||||||||||
| Brent | 3.71 | 6.27 | 4.70 | 4.14 | |||||||||||
| WCS (heavy sour) | (15.91 | ) | (20.50 | ) | (16.33 | ) | (16.25 | ) | |||||||
| Condensate | (0.22 | ) | 0.03 | (0.18 | ) | (0.16 | ) | ||||||||
| Midland Cushing | 1.53 | 1.98 | 1.32 | 1.52 | |||||||||||
| NYMEX Crack Spreads: | |||||||||||||||
| Gasoline | 32.40 | 30.07 | 32.61 | 33.31 | |||||||||||
| Heating Oil | 45.20 | 57.56 | 40.35 | 51.00 | |||||||||||
| NYMEX 2-1-1 Crack Spread | 38.80 | 43.82 | 36.48 | 42.16 | |||||||||||
| PADD II Group 3 Product Basis: | |||||||||||||||
| Gasoline | 0.84 | (2.75 | ) | (2.39 | ) | (6.49 | ) | ||||||||
| Ultra-Low Sulfur Diesel | (0.25 | ) | 3.01 | (0.38 | ) | (1.06 | ) | ||||||||
| PADD II Group 3 Product Crack Spread: | |||||||||||||||
| Gasoline | 33.24 | 27.32 | 30.22 | 26.82 | |||||||||||
| Ultra-Low Sulfur Diesel | 44.96 | 60.57 | 39.97 | 49.95 | |||||||||||
| PADD II Group 3 2-1-1 | 39.10 | 43.94 | 35.10 | 38.38 | |||||||||||
| Nitrogen Fertilizer Segment: | |||||||||||
| Ammonia Utilization Rates (1) | |||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
| (percent of capacity utilization) | 2023 | 2022 | 2023 | 2022 | |||||||
| Consolidated | 99 | % | 52 | % | 101 | % | 76 | % | |||
__________________________
(1) Reflects our ammonia utilization rates on a consolidated basis. Utilization is an important measure used by management to assess operational output at each of CVR Partners’ facilities. Utilization is calculated as actual tons produced divided by capacity. We present our utilization for the three and nine months ended September 30, 2023 and 2022 and take into account the impact of our current turnaround cycles on any specific period. 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 our efforts being primarily focused on ammonia upgrade capabilities, this measure provides a meaningful view of how well we operate.
| Sales and Production Data | |||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||
| Consolidated sales (thousand tons): | |||||||||||
| Ammonia | 62 | 27 | 183 | 118 | |||||||
| UAN | 387 | 275 | 1,075 | 884 | |||||||
| Consolidated product pricing at gate (dollars per ton):(1) | |||||||||||
| Ammonia | $ | 365 | $ | 837 | $ | 633 | $ | 1,062 | |||
| UAN | 223 | 433 | 330 | 496 | |||||||
| Consolidated production volume (thousand tons): | |||||||||||
| Ammonia (gross produced) (2) | 217 | 114 | 660 | 494 | |||||||
| Ammonia (net available for sale) (2) | 68 | 36 | 200 | 137 | |||||||
| UAN | 358 | 184 | 1,063 | 832 | |||||||
| Feedstock: | |||||||||||
| Petroleum coke used in production (thousand tons) | 131 | 74 | 386 | 298 | |||||||
| Petroleum coke used in production (dollars per ton) | $ | 84.09 | $ | 51.54 | $ | 78.49 | $ | 52.68 | |||
| Natural gas used in production (thousands of MMBtu) (3) | 2,133 | 1,120 | 6,429 | 4,817 | |||||||
| Natural gas used in production (dollars per MMBtu) (3) | $ | 2.67 | $ | 7.19 | $ | 3.57 | $ | 6.65 | |||
| Natural gas in cost of materials and other (thousands of MMBtu) (3) | 2,636 | 1,330 | 6,354 | 4,566 | |||||||
| Natural gas in cost of materials and other (dollars per MMBtu) (3) | $ | 2.51 | $ | 7.84 | $ | 4.21 | $ | 6.40 | |||
__________________________
(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 September 30, | Nine Months Ended September 30, | ||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||
| Ammonia — Southern plains (dollars per ton) | $ | 429 | $ | 934 | $ | 533 | $ | 1,149 | |||
| Ammonia — Corn belt (dollars per ton) | 501 | 1,048 | 621 | 1,275 | |||||||
| UAN — Corn belt (dollars per ton) | 272 | 496 | 314 | 581 | |||||||
| Natural gas NYMEX (dollars per MMBtu) | $ | 2.66 | $ | 7.95 | $ | 2.58 | $ | 6.70 | |||
Q4 2023 Outlook
The table below summarizes our outlook for certain operational statistics and financial information for the fourth quarter of 2023. See “Forward-Looking Statements” above.
| Q4 2023 | |||||||
| Low | High | ||||||
| Petroleum | |||||||
| Total throughput (bpd) | 205,000 | 220,000 | |||||
| Direct operating expenses (in millions) (1) | $ | 95 | $ | 105 | |||
| Renewables (2) | |||||||
| Total throughput (in millions of gallons) | 15 | 20 | |||||
| Direct operating expenses (in millions) (1) | $ | 6 | $ | 8 | |||
| Nitrogen Fertilizer | |||||||
| Ammonia utilization rates | |||||||
| Consolidated | 90 | % | 95 | % | |||
| Coffeyville Fertilizer Facility | 95 | % | 100 | % | |||
| East Dubuque Fertilizer Facility | 85 | % | 90 | % | |||
| Direct operating expenses (in millions) (1) | $ | 55 | $ | 60 | |||
| Capital Expenditures (in millions) (3) | |||||||
| Petroleum | $ | 40 | $ | 45 | |||
| Renewables (2) | 13 | 17 | |||||
| Nitrogen Fertilizer | 10 | 15 | |||||
| Other | 2 | 4 | |||||
| Total capital expenditures | $ | 65 | $ | 81 | |||
__________________________
(1) Direct operating expenses are shown exclusive of depreciation and amortization and, for the Nitrogen Fertilizer Segment, turnaround expenses and inventory valuation impacts.
(2) Renewables reflects spending on the Wynnewood renewable diesel unit project. As of September 30, 2023, Renewables does not meet the definition of a reportable segment as defined under Accounting Standards Codification 280.
(3) Capital expenditures is disclosed on an accrual basis.
| Non-GAAP Reconciliations: | |||||||||||||||
| Reconciliation of Net Income to EBITDA and Adjusted EBITDA | |||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| (in millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||
| Net income | $ | 354 | $ | 80 | $ | 781 | $ | 472 | |||||||
| Interest expense, net | 11 | 19 | 44 | 67 | |||||||||||
| Income tax expense | 84 | 7 | 185 | 106 | |||||||||||
| Depreciation and amortization | 81 | 75 | 221 | 215 | |||||||||||
| EBITDA | 530 | 181 | 1,231 | 860 | |||||||||||
| Adjustments: | |||||||||||||||
| Revaluation of RFS liability | (174 | ) | 38 | (228 | ) | 108 | |||||||||
| Unrealized loss (gain) on derivatives, net | 48 | (20 | ) | 35 | (5 | ) | |||||||||
| Inventory valuation impacts, (favorable) unfavorable | (91 | ) | 114 | (44 | ) | (63 | ) | ||||||||
| Call Option Lawsuits settlement | — | — | — | 79 | |||||||||||
| Adjusted EBITDA | $ | 313 | $ | 313 | $ | 994 | $ | 979 | |||||||
| Reconciliation of Basic and Diluted Earnings per Share to Adjusted Earnings per Share | |||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||
| Basic and diluted earnings per share | $ | 3.51 | $ | 0.92 | $ | 6.74 | $ | 3.49 | |||||||
| Adjustments: (1) | |||||||||||||||
| Revaluation of RFS liability | (1.30 | ) | 0.28 | (1.69 | ) | 0.80 | |||||||||
| Unrealized loss (gain) on derivatives, net | 0.36 | (0.15 | ) | 0.26 | (0.04 | ) | |||||||||
| Inventory valuation impacts, (favorable) unfavorable | (0.68 | ) | 0.85 | (0.33 | ) | (0.46 | ) | ||||||||
| Call Option Lawsuits settlement | — | — | — | 0.58 | |||||||||||
| Adjusted earnings per share | $ | 1.89 | $ | 1.90 | $ | 4.98 | $ | 4.37 | |||||||
__________________________
(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.
| Reconciliation of Net Cash Provided By Operating Activities to Free Cash Flow | |||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| (in millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||
| Net cash provided by operating activities | $ | 370 | $ | 156 | $ | 984 | $ | 868 | |||||||
| Less: | |||||||||||||||
| Capital expenditures | (50 | ) | (57 | ) | (150 | ) | (145 | ) | |||||||
| Capitalized turnaround expenditures | (3 | ) | (6 | ) | (53 | ) | (74 | ) | |||||||
| Return on equity method investment | 1 | — | 21 | — | |||||||||||
| Free cash flow | $ | 318 | $ | 93 | $ | 802 | $ | 649 | |||||||
| Reconciliation of Petroleum Segment Net Income to EBITDA and Adjusted EBITDA | |||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| (in millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||
| Petroleum net income | $ | 460 | $ | 152 | $ | 913 | $ | 584 | |||||||
| Interest income, net | (26 | ) | (13 | ) | (65 | ) | (24 | ) | |||||||
| Depreciation and amortization | 50 | 47 | 141 | 140 | |||||||||||
| Petroleum EBITDA | 484 | 186 | 989 | 700 | |||||||||||
| Adjustments: | |||||||||||||||
| Revaluation of RFS liability | (174 | ) | 38 | (228 | ) | 108 | |||||||||
| Unrealized loss (gain) on derivatives, net | 53 | (25 | ) | 37 | (8 | ) | |||||||||
| Inventory valuation impacts, (favorable) unfavorable (1) | (82 | ) | 107 | (48 | ) | (63 | ) | ||||||||
| Petroleum Adjusted EBITDA | $ | 281 | $ | 306 | $ | 750 | $ | 737 | |||||||
| Reconciliation of Petroleum Segment Gross Profit to Refining Margin and Refining Margin Adjusted for Inventory Valuation Impacts | |||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| (in millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||
| Net sales | $ | 2,298 | $ | 2,474 | $ | 6,290 | $ | 7,497 | |||||||
| Less: | |||||||||||||||
| Cost of materials and other | (1,691 | ) | (2,167 | ) | (4,939 | ) | (6,414 | ) | |||||||
| Direct operating expenses (exclusive of depreciation and amortization) | (105 | ) | (103 | ) | (310 | ) | (314 | ) | |||||||
| Depreciation and amortization | (50 | ) | (47 | ) | (141 | ) | (140 | ) | |||||||
| Gross profit | 452 | 157 | 900 | 629 | |||||||||||
| Add: | |||||||||||||||
| Direct operating expenses (exclusive of depreciation and amortization) | 105 | 103 | 310 | 314 | |||||||||||
| Depreciation and amortization | 50 | 47 | 141 | 140 | |||||||||||
| Refining margin | 607 | 307 | 1,351 | 1,083 | |||||||||||
| Inventory valuation impacts, (favorable) unfavorable (1) | (82 | ) | 107 | (48 | ) | (63 | ) | ||||||||
| Refining margin adjusted for inventory valuation impacts | $ | 525 | $ | 414 | $ | 1,303 | $ | 1,020 | |||||||
__________________________
(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.
| Reconciliation of Petroleum Segment Total Throughput Barrels | |||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||
| 2023 | 2022 | 2023 | 2022 | ||||
| Total throughput barrels per day | 212,420 | 201,657 | 203,388 | 200,098 | |||
| Days in the period | 92 | 92 | 273 | 273 | |||
| Total throughput barrels | 19,542,631 | 18,552,434 | 55,524,925 | 54,626,789 | |||
| Reconciliation of Petroleum Segment Refining Margin per Total Throughput Barrel | |||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
| (in millions, except for per throughput barrel data) | 2023 | 2022 | 2023 | 2022 | |||||||
| Refining margin | $ | 607 | $ | 307 | $ | 1,351 | $ | 1,083 | |||
| Divided by: total throughput barrels | 20 | 19 | 56 | 55 | |||||||
| Refining margin per total throughput barrel | $ | 31.05 | $ | 16.56 | $ | 24.33 | $ | 19.82 | |||
| Reconciliation of Petroleum Segment Refining Margin Adjusted for Inventory Valuation Impacts per Total Throughput Barrel | |||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
| (in millions, except for throughput barrel data) | 2023 | 2022 | 2023 | 2022 | |||||||
| Refining margin adjusted for inventory valuation impacts | $ | 525 | $ | 414 | $ | 1,303 | $ | 1,020 | |||
| Divided by: total throughput barrels | 20 | 19 | 56 | 55 | |||||||
| Refining margin adjusted for inventory valuation impacts per total throughput barrel | $ | 26.87 | $ | 22.34 | $ | 23.46 | $ | 18.66 | |||
| Reconciliation of Petroleum Segment Direct Operating Expenses per Total Throughput Barrel | |||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
| (in millions, except for throughput barrel data) | 2023 | 2022 | 2023 | 2022 | |||||||
| Direct operating expenses (exclusive of depreciation and amortization) | $ | 105 | $ | 103 | $ | 310 | $ | 314 | |||
| Divided by: total throughput barrels | 20 | 19 | 56 | 55 | |||||||
| Direct operating expenses per total throughput barrel | $ | 5.39 | $ | 5.53 | $ | 5.58 | $ | 5.74 | |||
| Reconciliation of Nitrogen Fertilizer Segment Net Income (Loss) to EBITDA and Adjusted EBITDA | ||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
| (in millions) | 2023 | 2022 | 2023 | 2022 | ||||||||
| Nitrogen Fertilizer net income (loss) | $ | 1 | $ | (20 | ) | $ | 162 | $ | 191 | |||
| Interest expense, net | 8 | 8 | 22 | 26 | ||||||||
| Depreciation and amortization | 23 | 22 | 59 | 64 | ||||||||
| Nitrogen Fertilizer EBITDA and Adjusted EBITDA | $ | 32 | $ | 10 | $ | 243 | $ | 281 | ||||
| Reconciliation of Total Debt and Net Debt and Finance Lease Obligations to EBITDA Exclusive of Nitrogen Fertilizer | ||
| (in millions) | Twelve Months Ended September 30, 2023 | |
| Total debt and finance lease obligations (1) | $ | 1,590 |
| Less: Nitrogen Fertilizer debt and finance lease obligations (1) | 547 | |
| Total debt and finance lease obligations exclusive of Nitrogen Fertilizer | 1,043 | |
| EBITDA exclusive of Nitrogen Fertilizer | 1,179 | |
| Total debt and finance lease obligations to EBITDA exclusive of Nitrogen Fertilizer | 0.88 | |
| Consolidated cash and cash equivalents | 889 | |
| Less: Nitrogen Fertilizer cash and cash equivalents | 89 | |
| Cash and cash equivalents exclusive of Nitrogen Fertilizer | 800 | |
| Net debt and finance lease obligations exclusive of Nitrogen Fertilizer (2) | 243 | |
| Net debt and finance lease obligations to EBITDA exclusive of Nitrogen Fertilizer (2) | $ | 0.21 |
__________________________
(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 | Twelve Months Ended September 30, 2023 (1) | ||||||||||||||
| (in millions) | December 31, 2022 | March 31, 2023 | June 30, 2023 | September 30, 2023 | |||||||||||
| Consolidated | |||||||||||||||
| Net income | $ | 172 | $ | 259 | $ | 168 | $ | 354 | $ | 953 | |||||
| Interest expense, net | 18 | 18 | 16 | 11 | 63 | ||||||||||
| Income tax expense | 50 | 56 | 44 | 84 | 234 | ||||||||||
| Depreciation and amortization | 73 | 68 | 72 | 81 | 294 | ||||||||||
| EBITDA | 313 | 401 | 300 | 530 | 1,544 | ||||||||||
| Nitrogen Fertilizer | |||||||||||||||
| Net income | 95 | 102 | 60 | 1 | 258 | ||||||||||
| Interest expense, net | 8 | 7 | 7 | 8 | 30 | ||||||||||
| Depreciation and amortization | 19 | 15 | 20 | 23 | 77 | ||||||||||
| EBITDA | 122 | 124 | 87 | 32 | 365 | ||||||||||
| EBITDA exclusive of Nitrogen Fertilizer | $ | 191 | $ | 277 | $ | 213 | $ | 498 | $ | 1,179 | |||||
__________________________
(1) Due to rounding, numbers within this table may not add or equal to totals presented.
