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 StatementsThis
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
RobertsCVR Energy, Inc.(281)
207-3205InvestorRelations@CVREnergy.com
Media Relations:Brandee
StephensCVR Energy, Inc.(281)
207-3516MediaRelations@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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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 EndedDecember 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. |
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