EDGAR 10-K Filing

Company CIK: 1340122
Filing Year: 2024
Filename: 1340122_10-K_2024_0001340122-24-000015.json

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ITEM 1. BUSINESS
Items 1 and 2. Business and Properties
Overview
We manufacture, formulate and market a diversified slate of specialty branded products and renewable fuels to customers across a broad range of consumer-facing and industrial markets. We are headquartered in Indianapolis, Indiana and operate twelve facilities throughout North America. Our business is organized into the following reportable segments: Specialty Products and Solutions; Montana/Renewables; Performance Brands; and Corporate. In our Specialty Products and Solutions segment, we manufacture and market a wide variety of solvents, waxes, customized lubricating oils, white oils, petrolatums, gels, esters, and other products. Our specialty products are sold to domestic and international customers who purchase them primarily as raw material components for consumer-facing and industrial products. In our Performance Brands segment, we blend, package and market high performance products through our Royal Purple, Bel-Ray, and TruFuel brands. Our Montana/Renewables segment is comprised of two facilities - renewable fuels and specialty asphalt. At our Montana Renewables facility, we process a variety of geographically advantaged renewable feedstocks into renewable diesel, sustainable aviation fuel (“SAF”), renewable hydrogen, renewable natural gas, renewable propane, and renewable naphtha that are distributed into renewables markets in the western half of North America. At our Montana specialty asphalt facility, we process Canadian crude oil into conventional gasoline, diesel, jet fuel and specialty grades of asphalt, with production sized to serve local markets. Our Corporate segment primarily consists of general and administrative expenses not allocated to the Specialty Products and Solutions, Performance Brands or Montana/Renewables segments.
Our Assets
Our primary operating assets consist of:
Sales Volume for the
Year Ended December 31,
2023 in Barrels per
Facility
Location
Year Acquired
Day (“bpd”)
Products
Calumet Packaging
Louisiana
1,068
Specialty products including premium industrial and consumer synthetic lubricants, fuels and solvents
Royal Purple
Texas
Specialty products including premium industrial and consumer synthetic lubricants
Missouri
Missouri
Specialty products including polyol ester-based synthetic lubricants
Karns City
Pennsylvania
1,486
Specialty white mineral oils, solvents, petrolatums, gelled hydrocarbons, cable fillers and natural petroleum sulfonates
Dickinson
Texas
Specialty white mineral oils, compressor lubricants and natural petroleum sulfonates
Cotton Valley
Louisiana
4,743
Specialty solvents used principally in the manufacture of paints, cleaners, automotive products and drilling fluids
Princeton
Louisiana
4,896
Specialty lubricating oils, including process oils, base oils, transformer oils, refrigeration oils, and asphalt
Shreveport
Louisiana
42,400
Specialty lubricating oils and waxes, gasoline, diesel, jet fuel and asphalt
Montana Refining
Montana
13,399
Specialty asphalt, gasoline, diesel, and jet fuel
Montana Renewables
Montana
6,188
Renewable diesel, sustainable aviation fuel, renewable hydrogen, renewable natural gas, renewable propane, and renewable naphtha
Storage, Distribution and Logistics Assets. We own and operate a product terminal in Burnham, Illinois with aggregate storage capacities of approximately 150,000 barrels. The Burnham terminal, as well as additional owned and leased facilities throughout the U.S., facilitate the distribution of products in the Upper Midwest, West Coast and Mid-Continent regions of the U.S. and Canada.
We also use approximately 2,050 leased railcars primarily to receive and ship crude oil and distribute our specialty and fuel products throughout the U.S. and Canada. In addition, we use approximately 450 leased railcars to source renewable feedstocks and distribute renewable fuels products into the western half of North America. In total, we have approximately 7.0 million barrels of aggregate storage capacity at our facilities and leased storage locations.
Montana Renewables. At our Montana Renewables facility, we process a variety of geographically advantaged renewable feedstocks into renewable diesel, sustainable aviation fuel, renewable hydrogen, renewable natural gas, renewable propane, and renewable naphtha. These renewable fuels are distributed into renewable markets in the western half of North America.
Business Strategies
Our management team is dedicated to improving our operations by executing the following strategies:
● Enhance Profitability of Our Existing Assets. We focus on identifying opportunities to improve our asset base, deepening our competitive advantages, and increasing our throughput, profitability, and cash flows. Our highest current priority is streamlining the operations at our Montana Renewables facility and planning for expansion projects at the facility. As part of this project design, we converted the historical Great Falls refinery into two independent facilities: a 15,000 bpd specialty asphalt plant and a 15,000 bpd renewable fuels production facility. At our Montana Renewables facility, we successfully commissioned a renewable hydrogen plant, a feedstock pre-treatment unit, and a sustainable aviation fuel unit in 2023. The feedstock pre-treatment unit is expected to unlock the advantaged price and feedstock optionality we have in Montana and the commissioning of the sustainable aviation fuel unit made Montana Renewables the largest SAF producer in the western hemisphere. Other examples include investments in a polymerized modified asphalt unit at our Great Falls Specialty Asphalt facility in 2022, additional wax blending assets at our Calumet Paralogics, LLC (“Paralogics”) facility in 2021, and the addition of storage capacity to increase sales of our most profitable solvents at our Cotton Valley facility in 2021. In addition, we have undertaken various small expansion and optimization projects in our Performance Brands segment over the past four years, including a new packaging line for 1.0 gallon cans of TruFuel to support growth, a new 2.1 gallon pail TruFuel line to meet the market demand for larger package sizes, and a new quart line in Porter, Texas to recognize efficiencies in packaging Bel-Ray products. We intend to continue increasing the profitability of our existing asset base through various low capital requirement measures which may include investments targeting more efficient logistics, improving the product mix of our processing units, and reducing costs through operational modernizations.
● Maintain Sufficient Levels of Liquidity. We are actively focused on maintaining sufficient liquidity to fund our operations and business strategies. As part of a broader effort to maintain an adequate level of liquidity, the board of directors of our general partner unanimously voted to suspend cash distributions, effective beginning the quarter ended March 31, 2016.
● Concentrate on Positive and Growing Cash Flows. We intend to continue to focus on operating assets and businesses that generate positive and growing cash flows. Approximately 89.0% of our continuing operations gross profit in 2023 was generated by our Specialty Products and Solutions segment, which is characterized by stable customer relationships due to our customers’ requirements for the specialized products we provide. In addition, we manage our exposure to crude oil price fluctuations in this segment by passing on incremental feedstock costs to our specialty products customers. In our Performance Brands segment, which accounted for approximately 18.2% of our continuing operations gross profit in 2023, we blend, package and market high performance products through our Royal Purple, Bel-Ray, and TruFuel brands. Our fast-growing portfolio of high-performance brands are characterized by strong customer loyalty and stable cash flows. In our Montana/Renewables segment, which accounted for approximately (7.2)% of our continuing operations gross profit in 2023, we expect growth in cash flows as a result of the commissioning of production units at our Montana Renewables facility. Historically, renewable diesel margins have been both significantly higher and more stable than fuel margins. Further, the remaining Great Falls specialty asphalt facility is expected to produce a larger percentage of its products for local retail markets at lower net freight costs.
● Develop and Expand Our Customer Relationships. Due to the specialized nature of certain of our products, the high cost of replacement and the long lead-time associated with the development and production of many of our specialty products, our customers are incentivized to continue their relationships with us. We believe that we offer a more diversified product slate to our customers than competitors do, and we also offer more technical support and bespoke services. In fiscal year 2023, we sold a range of over 1,900 specialty and fuels products to approximately 2,400 customers. We intend to continue to assist our existing customers in their efforts to expand their product offerings, as well as marketing specialty product formulations and services to new customers. By continuing to service our long-term relationships with our broad base of existing customers and by constantly targeting solutions for new customers, we seek to limit our dependence on any one portion of our customer base.
● Disciplined Approach to Strategic and Complementary Acquisitions. We do not expect to focus on large acquisitions in the near term. However, should the right opportunity develop, our senior management team is prepared to consider acquiring low-risk assets where we can enhance operations and improve profitability and product lines that will complement and expand our specialty product offerings. For example, in March 2020, we acquired Paralogics, a producer of candle and industrial wax blends, which expanded our presence in the specialty wax blending and packaging market while adding new capabilities into our existing wax value chain. In the future, we intend to continue pursuing prudent, accretive acquisitions that will deepen our long-term competitive advantages. We intend to reduce our leverage over time and maintain a capital structure that facilitates competitive access to the capital markets.
Competitive Strengths
We believe that we are well positioned to execute our business strategies successfully based on the following competitive strengths:
● We Have Strong Relationships with a Premier Customer Base. We have long-term relationships with many of our customers and we believe that we will continue to benefit from these relationships. Many of these relationships involve lengthy approval processes or certifications that may make switching to a different supplier difficult. In fiscal year 2023, we sold our products to approximately 2,400 customers, and we are continually seeking to deepen those relationships across our broad and diversified customer base. No single customer accounted for more than 10% of our consolidated sales for any of the three years ended December 31, 2023, 2022 and 2021.
● We Offer Our Customers a Diverse Range of Specialty Products. We offer a wide range of over 1,900 specialty products. We believe that our ability to provide our customers with a more diverse selection of products than most of our competitors gives us an advantage in meeting the needs of large, strategic customers and allows us to compete in profitable niches. We believe that we are the only specialty products manufacturer in North America that produces all six of the following products: naphthenic lubricating oils, paraffinic lubricating oils, waxes, solvents, white oils and petrolatums. Our ability to produce numerous specialty products allows us to ship products between our facilities for product upgrading in order to meet customer specifications.
● We are a Leader in North America’s Energy Transition. Our MRL facility is permitted to pretreat and convert 15,000 barrels per stream day of renewable feedstocks into low-emission sustainable alternatives that directly replace fossil fuel products. MRL is a leader in North America’s energy transition and the largest Sustainable Aviation Fuel producer in the western hemisphere. The renewable fuel products produced by MRL are distributed into renewable markets in the western half of North America.
● Our Facilities Have a Unique Combination of Flexibility and Scale. Our facilities are equipped with advanced, flexible technology that allows us to produce high-grade specialty products. For example, our integrated specialty products complex in Northwest Louisiana consists of 27 processing units and 195 million gallons of storage capacity across 400 tanks and has a wide variety of specialized hydroprocessing, dewaxing, emulsifying and distillation capabilities that allow us to meet complex, bespoke customer needs at scale providing an advantaged cost. Our acquisition of Paralogics also added new capabilities into our existing wax business value chain, adding approximately 20 million pounds of annual blending and formulating capabilities. Our facilities also enjoy the value and optionality of integration as many products can be further processed and upgraded at our own facilities.
● We Have Leading, High-Growth Brands. Our Performance Brands segment benefits from well-known high-performance premium brands in consumer, retail and industrial markets. These brands garner a premium and are well positioned for growth. Further, the majority of products in our Specialty Products and Solutions segment are marketed under well-known industrial and consumer-facing brands that are of high value in the market and in many cases were established several decades ago.
● We Have an Experienced Management Team. Our team’s extensive experience within the specialty products, commodities and renewable energy industries provides a strong foundation to build and optimize a diversified, competitively advantaged business that can succeed in various business cycles and environments.
Potential Acquisition and Divestiture Activities
While we evaluate potential acquisitions of strategic and complementary assets that would deepen our competitive advantage, our focus has been and continues to be to de-lever our balance sheet. We evaluate our portfolio on an ongoing basis to allow an objective assessment of potential divestiture candidates that are non-core to our business and/or worth more to a buyer than to us. The combination of acquisition and divestment activities is intended to maximize our return on invested capital by creating and maintaining a portfolio of core assets that optimize our blend of feedstocks, improve our operating efficiency and cash flows, and leverage our competitive strengths. We also intend to monetize all or a portion of our equity in MRL over time.
As we optimize our asset portfolio, which may include the divestiture of certain non-core assets or all or a portion of our equity in MRL, we intend to redeploy capital into projects to develop assets that are better suited to our core specialty products business strategy and de-leverage our balance sheet.
Going forward, we intend to tailor our approach toward owning businesses with stable cash flows and growing end markets. As a result, we may pursue potential arrangements with third parties to divest certain assets to enable us to further reduce the amount of our required capital commitments and potential capital expenditures. We expect that any potential divestitures of assets will also provide us with cash to reinvest in our business and repay debt.
Partnership Structure and Management
Calumet Specialty Products Partners, L.P. is a Delaware limited partnership formed on September 27, 2005. Our general partner is Calumet GP, LLC, a Delaware limited liability company. As of February 28, 2024, we have 80,223,093 common units and 1,637,206 general partner units outstanding. Our general partner owns a 2% general partner interest in our partnership and all incentive distribution rights and has sole responsibility for conducting our business and managing our operations. For more information about our general partner’s board of directors and executive officers, please read Part III, Item 10 “Directors, Executive Officers of Our General Partner and Corporate Governance.”
Our Operating Assets and Contractual Arrangements
General
The following table sets forth information about our continuing operations. Facility production volume differs from sales volume due to changes in inventories and the sale of purchased blendstocks such as ethanol and specialty blendstocks, as well as the resale of crude oil.
Year Ended December 31,
% Change
% Change
(In bpd)
(In bpd)
Total sales volume (1)
79,805
82,946
(3.8)
%
82,946
79,281
4.6
%
Total feedstock runs (2)
77,200
80,447
(4.0)
%
80,447
75,818
6.1
%
Facility production: (3)
Specialty Products and Solutions:
Lubricating oils
10,358
10,951
(5.4)
%
10,951
9,867
11.0
%
Solvents
7,208
7,100
1.5
%
7,100
6,833
3.9
%
Waxes
1,326
1,452
(8.7)
%
1,452
1,335
8.8
%
Fuels, asphalt and other by-products
38,845
40,845
(4.9)
%
40,845
27,869
46.6
%
Total Specialty Products and Solutions
57,737
60,348
(4.3)
%
60,348
45,904
31.5
%
Montana/Renewables:
Gasoline
3,898
3,409
14.3
%
3,409
4,907
(30.5)
%
Diesel
2,941
6,449
(54.4)
%
6,449
9,711
(33.6)
%
Jet fuel
(45.2)
%
(9.0)
%
Asphalt, heavy fuel oils and other
4,483
6,942
(35.4)
%
6,942
10,379
(33.1)
%
Renewable fuels
6,314
-
100.0
%
-
-
100.0
%
Total Montana/Renewables
18,085
17,620
2.6
%
17,620
25,898
(32.0)
%
Performance Brands
1,474
1,434
2.8
%
1,434
1,304
10.0
%
Total facility production (3)
77,296
79,402
(2.7)
%
79,402
73,106
8.6
%
(1) Total sales volume includes sales from the production at our facilities and certain third-party facilities pursuant to supply and/or processing agreements, sales of inventories and the resale of crude oil to third-party customers. Total sales volume includes the sale of purchased blendstocks.
(2) Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements.
(3) The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.
The following table sets forth information about our sales of principal products by segment:
Year Ended December 31,
(In millions)
% of Sales
(In millions)
% of Sales
(In millions)
% of Sales
Specialty Products and Solutions:
Lubricating oils
$
763.8
18.3
%
$
913.7
19.5
%
$
658.7
20.9
%
Solvents
398.5
9.5
%
434.9
9.3
%
303.7
9.7
%
Waxes
163.9
3.9
%
189.3
4.0
%
151.7
4.8
%
Fuels, asphalt and other by-products
1,550.7
37.1
%
1,970.1
42.0
%
997.3
31.7
%
Total
$
2,876.9
68.8
%
$
3,508.0
74.8
%
$
2,111.4
67.1
%
Montana/Renewables:
Gasoline
$
167.2
4.0
%
$
188.1
4.0
%
$
188.3
6.0
%
Diesel
144.8
3.5
%
391.8
8.4
%
324.9
10.3
%
Jet fuel
20.5
0.5
%
41.8
0.9
%
27.5
0.9
%
Asphalt, heavy fuel oils and other
148.1
3.5
%
253.2
5.4
%
243.0
7.7
%
Renewable fuels
513.2
12.3
%
-
-
%
-
-
%
Total
$
993.8
23.8
%
$
874.9
18.7
%
$
783.7
24.9
%
Performance Brands
$
310.3
7.4
%
$
303.4
6.5
%
$
252.9
8.0
%
Consolidated sales
$
4,181.0
100.0
%
$
4,686.3
100.0
%
$
3,148.0
100.0
%
Please read Note 18 - “Segments and Related Information” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” of this Annual Report for additional financial information about each of our segments and the geographic areas in which we conduct business.
Northwest Louisiana Integrated Specialty Complex
The assets in our Northwest Louisiana integrated specialty complex anchor our Specialty Products and Solutions business segment. The assets in the Northwest Louisiana integrated specialty complex, primarily consist of our Shreveport facility, Cotton Valley facility and Princeton facility, which in total, includes 27 processing units and 195 million gallons of storage capacity across 400 tanks and have a wide variety of specialized hydroprocessing, dewaxing, emulsifying and distillation capabilities that allow us to meet complex, bespoke customer needs at scale providing an advantaged cost.
Shreveport Facility
The Shreveport facility (“Shreveport”), located on a 240 acre site in Shreveport, Louisiana, currently has aggregate crude oil throughput capacity of 60,000 bpd and processes paraffinic crude oil and associated feedstocks into fuel products, paraffinic lubricating oils, waxes, asphalt and by-products.
The Shreveport facility consists of 17 major processing units including hydrotreating, catalytic reforming and dewaxing units and approximately 3.3 million barrels of storage capacity in 130 storage tanks and related loading and unloading facilities and utilities. Since our acquisition of the Shreveport facility in 2001, we have expanded the facility’s capabilities by adding additional processing and blending facilities, adding a second reactor to the high pressure hydrotreater, resuming production of gasoline, diesel and other fuel products and adding both 18,000 bpd of crude oil throughput capacity and the capability to run up to 25,000 bpd of sour crude oil.
The following table sets forth historical information about production at our Shreveport facility:
Shreveport Facility
Year Ended December 31,
(In bpd)
Crude oil throughput capacity
60,000
60,000
60,000
Total feedstock runs (1) (2)
38,248
42,453
29,971
Total facility production (2) (3)
40,677
45,525
31,835
(1) Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our Shreveport facility. Total feedstock runs do not include certain interplant feedstocks supplied by our Cotton Valley and Princeton facilities.
(2) Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.
(3) Total facility production includes certain interplant feedstock supplied to our Cotton Valley and Princeton facilities and our Karns City facility.
The Shreveport facility has a flexible operational configuration and operating personnel that facilitates the development of opportunities to enhance profitability. Feedstock and product mix may fluctuate from one period to the next to capture market opportunities.
The Shreveport facility receives crude oil via tank truck, railcar and a common carrier pipeline system that is operated by a subsidiary of Plains All American Pipeline, L.P. (“Plains”) and is connected to Shreveport’s facilities. The Plains pipeline system delivers local supplies of crude oil and condensates from north Louisiana and east Texas. The Plains pipeline also connects to a Plains terminal in Longview, TX, which gives the refinery access to crude oil in west Texas and access to the Cushing, Oklahoma storage hub. Crude oil is also purchased from various suppliers, including local producers, who deliver crude oil to the Shreveport facility via tank truck.
The Shreveport facility also has direct pipeline access to the Enterprise Products Partners L.P. pipeline (“TEPPCO pipeline”), on which it can ship certain grades of gasoline, diesel and jet fuel. Further, the refinery has direct access to the Red River Terminal facility, which provides the facility with barge access, via the Red River, to major feedstock and petroleum products logistics networks on the Mississippi River and Gulf Coast inland waterway system. The Shreveport facility also ships its finished specialty products throughout the U.S. through both truck and railcar service.
Cotton Valley Facility
The Cotton Valley facility (“Cotton Valley”), located on a 77 acre site in Cotton Valley, Louisiana, currently has aggregate crude oil throughput capacity of 13,600 bpd, hydrotreating capacity of 6,500 bpd and processes crude oil into specialty solvents and residual fuel oil. The residual fuel oil is an important feedstock for the production of specialty products at our Shreveport facility. We believe the Cotton Valley facility produces the most complete, single-facility line of paraffinic solvents in the U.S.
The Cotton Valley facility consists of three major processing units that include a crude unit, a hydrotreater and a fractionation train, approximately 625,000 barrels of storage capacity in 74 storage tanks and related loading and unloading facilities and utilities. Since our acquisition of the Cotton Valley facility in 1995, we have expanded the facility’s capabilities by installing a hydrotreater that removes aromatics, increased the crude unit processing capability to 13,600 bpd and reconfigured the facility’s fractionation train to improve product quality, enhance flexibility and lower utility costs.
The following table sets forth historical information about production at our Cotton Valley facility:
Cotton Valley Facility
Year Ended December 31,
(In bpd)
Crude oil throughput capacity
13,600
13,600
13,600
Total feedstock runs (1) (2)
9,125
8,975
8,349
Total facility production (2) (3)
5,520
5,317
4,698
(1) Total feedstock runs do not include certain interplant solvent feedstocks supplied by our Shreveport facility.
(2) Total facility production represents the barrels per day of specialty products yielded from processing crude oil and other feedstocks. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and the production of finished products, intermediates transferred to internal sites for further processing, and volume loss.
(3) Total facility production includes certain interplant feedstocks supplied to our Shreveport facility.
The Cotton Valley facility has a flexible operational configuration and operating personnel that facilitates the development of opportunities to enhance profitability. Feedstock and product mix may fluctuate from one period to the next to capture market opportunities, which allows us to respond to market changes and customer demands by modifying the refinery’s product mix. The reconfigured fractionation train also allows the facility to satisfy demand fluctuations efficiently without large finished product inventory requirements.
The Cotton Valley facility receives crude oil via tank truck. The Cotton Valley facility’s feedstock is primarily low sulfur and paraffinic crude oil originating from north Louisiana and is purchased from various marketers and gatherers. In addition, the Cotton Valley facility receives interplant feedstocks for solvent production from the Shreveport facility. The Cotton Valley facility ships finished products by both truck and railcar service.
Princeton Facility
The Princeton facility (“Princeton”), located on a 208 acre site in Princeton, Louisiana, currently has aggregate crude oil throughput capacity of 10,000 bpd and processes naphthenic crude oil into lubricating oils and asphalt. In addition, feedstock is made for the Shreveport facility for further processing into ultra-low sulfur diesel. The asphalt produced at Princeton may be further processed or blended for coating and roofing product applications at the Princeton facility or transported to the Shreveport facility for further processing into bright stock.
The Princeton facility consists of seven major processing units, approximately 650,000 barrels of storage capacity in 200 storage tanks and related loading and unloading facilities and utilities. Since our acquisition of the Princeton facility in 1990, we have debottlenecked the crude unit to increase production capacity to 10,000 bpd, increased the hydrotreater’s capacity to 7,000 bpd and upgraded the facility’s fractionation unit, which has enabled us to produce higher value specialty products.
The following table sets forth historical information about production at our Princeton facility:
Princeton Facility
Year Ended December 31,
(In bpd)
Crude oil throughput capacity
10,000
10,000
10,000
Total feedstock runs (1)
7,724
7,259
7,266
Total facility production (1) (2)
7,787
5,660
4,881
(1) Total facility production represents the barrels per day of specialty products yielded from processing crude oil and other feedstocks. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and the production of finished products, intermediates transferred to internal sites for further processing, and volume loss.
(2) Total facility production includes certain interplant feedstocks supplied to our Shreveport facility.
The Princeton facility has a hydrotreater and significant fractionation capability enabling the refining of high quality naphthenic lubricating oils at numerous distillation ranges. The Princeton facility’s processing capabilities consist of atmospheric and vacuum distillation, hydrotreating, asphalt oxidation processing and clay/acid treating. In addition, we have the necessary tankage and technology to process our asphalt into higher value product applications such as coatings, road paving and specialty applications.
The Princeton facility receives crude oil via tank truck, railcar and the Plains pipeline system. Its crude oil supply primarily originates from east Texas, south Texas and north Louisiana, purchased directly from third-party suppliers under month-to-month evergreen supply contracts and on the spot market. The Princeton facility ships its finished products throughout the U.S. via truck and railcar service.
Great Falls Specialty Asphalt Facility
The Great Falls specialty asphalt facility (“Great Falls”), located on a 65 acre site in Great Falls, Montana, currently has aggregate crude oil throughput capacity of 15,000 bpd and processes light and heavy crude oil from Canada into fuel and asphalt products. In the fourth quarter of 2022, we converted a significant portion of the Great Falls specialty asphalt facility into a renewable fuels production facility (see below). Upon completion of the conversion project, we continue to own and operate the conventional Great Falls specialty asphalt facility with a reconfigured processing capacity of 15,000 bpd of Canadian crude. The facility is focused on the production of high-quality specialty asphalt, as well as satisfying local demand for conventional fuels.
The Great Falls specialty asphalt facility consists of 15 major processing units including hydrotreating, catalytic reforming, hydrocracking, fluid catalytic cracking and alkylation units, approximately 1.1 million barrels of storage capacity in 75 tanks and related loading and unloading facilities and utilities.
The following table sets forth historical information about production at the Great Falls specialty asphalt facility:
Great Falls Specialty Asphalt Facility
Year Ended December 31,
(In bpd)
Crude oil throughput capacity
15,000
15,000
30,000
Total feedstock runs (1) (2)
11,982
17,599
25,614
Total facility production (2)
11,772
17,619
25,897
(1) Total feedstock runs represent the barrels per day of crude oil processed at our Great Falls specialty asphalt facility.
(2) Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and the production of finished products and volume loss.
Currently, the Great Falls specialty asphalt facility produces liquified petroleum gas, naphtha, gasoline, diesel, jet fuel and asphalt, which are shipped by railcar and truck service. Finished fuel and asphalt sales are primarily made through spot agreements and short-term contracts.
The Great Falls specialty asphalt facility purchases crude oil from various suppliers and receives crude oil through the Interprovincial Bow River South and Rangeland pipeline systems, providing reliable access to high quality conventional crude oil from western Canada.
In the fourth quarter of 2022, we completed the reconfiguration of our 30,000 bpd Great Falls specialty asphalt facility into two unrelated facilities, including a 15,000 bpd specialty asphalt facility and a 15,000 bpd renewable fuels facility. The specialty asphalt facility capitalizes on local access to cost-advantaged Canadian conventional crude oil, while producing additional fuels and refined products for delivery into the regional market while meeting EPA requirements for gasoline and diesel product sulfur limits and reducing air emissions. The renewable fuels facility is described below.
Great Falls Renewable Fuels Facility (“Montana Renewables”)
In the fourth quarter of 2022, Montana Renewables LLC, an unrestricted subsidiary of Calumet, completed the conversion of a significant portion of our Great Falls specialty asphalt facility into a renewable fuels production facility (the “Montana Renewables Facility”). The Montana Renewables Facility has a permitted throughput capacity of 15,000 bpd to pretreat and convert a wide variety of organic waste and vegetable oils into lower emissions, sustainable alternatives to fossil fuels, including renewable hydrogen, renewable natural gas, renewable propane, renewable naphtha, renewable kerosene/sustainable aviation fuel, and renewable diesel.
As part of the conversion project, we also constructed and commissioned an innovative renewable hydrogen unit, which further lowered carbon intensity and increased the throughput of the Montana Renewables facility. Further, a new state of the art feedstock pre-treater, which combined with proximity to advantaged feedstocks and low-carbon product markets provides lasting competitive advantage to Montana Renewables.
Missouri Facility
The Missouri facility (“Missouri”), located on a 22 acre site in Louisiana, Missouri, develops and produces polyol ester synthetic lubricants for use in refrigeration compressors, commercial aviation and polyol ester base stocks. In December 2015, we completed a project to more than double the production capacity of the facility from 35 million pounds to 75 million pounds per year. The facility has approximately 35,000 barrels of storage capacity in 64 tanks and related loading and unloading facilities and utilities. The facility receives its fatty acids and alcohol feedstocks and additives by truck and railcar under supply agreements or spot agreements with various suppliers.
The Missouri facility utilizes the latest batch esterification processes designed to ensure blending accuracy while maintaining production flexibility to meet customer needs.
Calumet Packaging
The Calumet Packaging facility (“Calumet Packaging”), located on a 10 acre site in Shreveport, Louisiana, develops, blends and packages high performance synthetic lubricants, fuels and solvent products for use in industrial, commercial and automotive applications. The Calumet Packaging facility’s processing capability includes state-of-the-art blending and packaging equipment. The facility has approximately 75,000 barrels of storage capacity and related loading and unloading facilities. The facility receives its base oil feedstocks and additives by truck and rail under supply agreements or spot agreements with various suppliers.
Royal Purple
The Royal Purple facility (“Royal Purple”), located on a 20 acre site in Porter, Texas, develops, blends and packages high performance synthetic lubricants and fluid additive products for use in industrial, commercial and automotive applications. The Royal Purple facility’s processing capability includes 10 in-house packaging and production lines. Outsourced packaging services for specific products are also fulfilled. The facility has approximately 30,500 barrels of storage capacity in 91 tanks and related loading and unloading facilities. The facility receives its base oil feedstocks and additives by truck under supply agreements or spot agreements with various suppliers.
Karns City and Dickinson Facilities and Other Processing Agreements
The Karns City facility (“Karns City”), located on a 225 acre site in Karns City, Pennsylvania, has aggregate base oil throughput capacity of 3,000 bpd and produces white mineral oils, solvents, petrolatums, gelled hydrocarbons, cable fillers and natural petroleum sulfonates. The Karns City facility’s processing capability includes hydrotreating, fractionation, acid treating, filtering, blending and packaging. In addition, the facility has approximately 817,000 barrels of storage capacity in 250 tanks and related loading and unloading facilities and utilities.
The Dickinson facility (“Dickinson”), located on a 28 acre site in Dickinson, Texas, has aggregate base oil throughput capacity of 1,300 bpd and produces white mineral oils, compressor lubricants and natural petroleum sulfonates. The Dickinson facility’s processing capability includes acid treating, filtering and blending. The facility has approximately 183,000 barrels of storage capacity in 186 tanks and related loading and unloading facilities and utilities.
These facilities each receive their base oil feedstocks by railcar and truck under supply agreements or spot purchases with various suppliers, the most significant of which is a supply agreement with Phillips 66. Please read “- Our Crude Oil and Feedstock Supply” below for further discussion of the long-term supply agreement with Phillips 66.
The following table sets forth the combined historical information about production at our Karns City, Dickinson and certain other facilities:
Combined Karns City, Dickinson and Other Facilities
Year Ended December 31,
(in bpd)
Feedstock throughput capacity (1)
11,300
11,300
11,300
Total feedstock runs (2) (3)
3,396
3,482
4,368
Total production (3)
3,419
3,582
4,269
(1) Includes Karns City, Dickinson and certain other facilities.
(2) Includes feedstock runs at our Karns City and Dickinson facilities as well as throughput at certain third-party facilities pursuant to supply and/or processing agreements and includes certain interplant feedstocks supplied from our Shreveport facility.
(3) Total production represents the barrels per day of specialty products yielded from processing feedstocks at our Karns City and Dickinson facilities and certain third-party facilities pursuant to supply and/or processing agreements. The difference between total production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and the production of finished products.
Other Logistics Assets
Terminals are complementary to our refineries and play a key role in moving our products to end-user markets by providing services including distribution and blending to achieve specified products and storage and inventory management. In addition to the Burnham terminal, we own and lease additional facilities, primarily related to distribution of finished products, throughout the U.S.
Burnham Terminal: We own and operate a terminal located on an 11 acre site, in Burnham, Illinois. The Burnham terminal receives specialty products from certain of our refineries primarily by railcar and distributes them by truck and railcar to our customers in the Upper Midwest and East Coast regions of the U.S. and in Canada. The terminal includes a tank farm with 90 tanks having aggregate storage capacity of approximately 150,000 barrels, supplying lube base oils, food grade white oils and aliphatic solvents, as well as viscosity index additives and tackifiers.
We use approximately 2,050 railcars leased from various lessors. This fleet of railcars enables us to receive and ship crude oil and distribute various specialty products and fuel products throughout the U.S. and Canada to and from each of our facilities. In addition, we use approximately 450 leased railcars to source renewable feedstocks and distribute renewable fuels products into the western half of North America.
Our Crude Oil and Feedstock Supply
We purchase crude oil and other feedstocks from major oil companies as well as from various crude oil gatherers and marketers in Texas, north Louisiana and Canada. Crude oil supplies at our facilities are as follows:
Facility
Crude Oil / Feedstock Slate
Mode of Transportation
Shreveport
West Texas Intermediate (“WTI”), local crude oils from East Texas, North Louisiana, Arkansas and Light Louisiana Sweet (“LLS”)
Tank truck, railcar and Plains Pipeline
Cotton Valley
Local paraffinic crude oil
Tank truck
Great Falls Specialty Asphalt Facility
Canadian Heavy (e.g. Bow River) and Canadian Light Sour
Front Range Pipeline
Montana Renewables Facility
Organic waste and vegetable oil materials
Railcar
Princeton
Local and imported naphthenic crude oil
Tank truck, railcar and Plains Pipeline
In 2023, BP Products North America Inc. (“BP”) supplied us with approximately 71.7% of our total crude oil supply under term contracts and month-to-month evergreen crude oil supply contracts. In 2023, Macquarie Energy Canada LTD. (“Macquarie”) supplied us with approximately 18.5% of our total crude oil supply under a crude oil supply agreement. Each of our refineries is dependent on one or more key suppliers and the loss of any of these suppliers would adversely affect our financial results to the extent we were unable to find another supplier of this substantial amount of crude oil.
We have short-term and long-term contracts with our crude oil suppliers. For example, a majority of our crude oil supply contracts with Plains are currently month-to-month and terminable upon 90 days’ notice. Additionally, our crude oil supply agreement with BP was amended and restated in December 2016, and automatically renews for successive one-year terms each March unless terminated by either party upon 90 days’ notice (“BP Purchase Agreement”). This agreement has not been terminated by either party. We also purchase foreign crude oil when its spot market price is attractive relative to the price of crude oil from domestic sources.
MRL, an unrestricted subsidiary of the Company, has entered into various term supply agreements for renewable feedstocks that are key to the operations of the Montana Renewables facility.
We have various long-term feedstock supply agreements with Phillips 66, with some agreements operating under the option to continue on a month-to-month basis thereafter, for feedstocks that are key to the operations of our Karns City and Dickinson facilities. In addition, certain products of our refineries can be used as feedstocks by these facilities.
We believe that adequate supplies of crude oil and feedstocks will continue to be available to us.
Our cost to acquire crude oil and feedstocks and the prices for which we ultimately can sell refined products depend on a number of factors beyond our control, including regional and global supply of and demand for crude oil, other feedstocks and specialty and fuel products. These, in turn, are dependent upon, among other things, the availability of imports, overall economic conditions, production levels of domestic and foreign suppliers, U.S. relationships with foreign governments, political affairs and the extent of governmental regulation. We have historically been able to pass on the
costs associated with increased crude oil and feedstock prices to our specialty products customers, although the increase in selling prices for specialty products typically lags the rising cost of crude oil. From time to time, we use a hedging program to manage a portion of our commodity price risk.
Our Products, Markets and Customers
Products
We produce a full line of specialty products, including lubricating oils, solvents, waxes, food grade white oils, pharmaceutical grade petrolatums, and other products, as well as a variety of fuel and fuel related products, including asphalt and heavy fuel oils. We also blend, package and market high performance specialty products through our Royal Purple, Bel-Ray, and TruFuel brands. At our Montana Renewables facility, we produce a variety of renewable fuels products, including renewable diesel, sustainable aviation fuel, renewable hydrogen, renewable natural gas, renewable propane, and renewable naphtha that are distributed into renewable markets in the western half of North America. Our customers purchase specialty products primarily as raw material components for consumer-facing and industrial products. Our customers also purchase renewable fuels, which are consumed to reduce lifecycle carbon emissions.
The following table depicts a representative sample of the diversity of end-use applications for the products we produce:
Representative Sample of End-Use Applications by Product (1)
Lubricating Oils
Solvents
Waxes
Packaged and Synthetic
Specialty Products
Fuels & Fuel Related
Products
Renewable Products
19%
10%
4%
8%
47%
12%
● Hydraulic oils
● Passenger car motor oils
● Railroad engine oils
● Cutting oils
● Compressor oils
● Metalworking fluids
● Transformer oils
● Rubber process oils
● Industrial lubricants
● Gear oils
● Grease
● Automatic transmission fluid
● Animal feed dedusting
● Baby oils
● Bakery pan oils
● Catalyst carriers
● Gelatin capsule lubricants
● Sunscreen
● Waterless hand cleaners
● Alkyd resin diluents
● Automotive products
● Calibration fluids
● Charcoal lighter fluids
● Chemical processing
● Drilling fluids
● Printing inks
● Water treatment
● Paint and coatings
● Stains
● Paraffin waxes
● FDA compliant products
● Candles
● Adhesives
● Crayons
● Floor care
● PVC
● Paint strippers
● Skin & hair care
● Timber treatment
● Waterproofing
● Pharmaceuticals
● Cosmetics
● Refrigeration compressor oils
● Positive displacement and roto-dynamic compressor oils
● Commercial and military jet engine oil
● Lubricating greases
● Gear oils
● Aviation hydraulic oils
● High performance small engine fuels
● Two cycle and four stroke engine oils
● High performance automotive engine oils
● High performance industrial lubricants
● High temperature chain lubricants
● Food contact grade lubricants
● Charcoal lighter fluids and other solvents
● Engine treatment additives
● Gasoline
● Diesel
● Jet fuel
● Marine fuel
● Ethanol free fuels
● Fluid catalytic cracking feedstock
● Asphalt vacuum residuals
● Mixed butanes
● Roofing flux
● Paving asphalt
● Heavy fuel oils
● Renewable hydrogen
● Renewable natural gas
● Renewable propane
● Renewable naphtha
● Renewable kerosene/sustainable aviation fuel
● Renewable diesel
(1) Based on the percentage of total sales for the year ended December 31, 2023. Except for the listed fuel products, renewable products and certain packaged and synthetic specialty products, we do not produce any of these end-use products.
Marketing
Our salespeople regularly visit customers and work in conjunction with our marketing department, the laboratories at our production facilities and our technical services department, to focus on providing additional value to our customers, such as formulation assistance, regulatory insight, and creating specialized blends and packaging that work optimally for our customers.
Markets
Specialty Products. The specialty products market represents a small portion of the overall petroleum refining industry in the U.S. Of the approximately 130 refineries currently in operation in the U.S., only a small number of the refineries are considered specialty products producers and only a few compete with us in terms of the number of products produced.
Our specialty products are utilized in applications across a broad range of industries, including:
● industrial goods such as finished lubricants, batteries, water treatment chemistry, mining lubricants, oilfield drilling, electrical and transformer oils, adhesives, refrigeration compressor oils, aviation fluids, and agriculture applications; and
● consumer goods such as cosmetics, petroleum jelly, lotions, pharmaceuticals, food, candles, paint and coatings, charcoal lighter fluids, and car care products.
We have the capability to ship our specialty products worldwide. In the U.S., we ship our specialty products via railcars, trucks and barges. We use our fleet of leased railcars to ship our specialty products and a majority of our specialty products sales are shipped in trucks owned and operated by several different third-party carriers. For international shipments, which accounted for less than 10% of our consolidated sales in 2023, we ship via railcars and trucks to several ports where the product is loaded onto vessels for shipment to customers abroad.
Fuel Products. The fuel products market represents a large portion of the overall petroleum refining industry in the U.S. Of the approximately 130 refineries currently in operation in the U.S., a large number of the refineries are fuel products producers; however, only a few compete with us in our local markets.
Renewable Fuel Products. The renewable fuel products market represents a small portion of the overall petroleum refining industry in the U.S. MRL is a leading independent producer of renewable transportation fuels in North America and the largest SAF producer in the western hemisphere. The renewable fuels market is in the rapid-growth phase of its life cycle, highlighted by renewable diesel demand growing at an average annualized rate of 96.3% over the past three years, and SAF demand quadrupling in the past year. The U.S. government’s SAF Grand Challenge calls for SAF growth from 4.5 million gallons in 2021 to 3.0 billion gallons annually by 2030. We believe we are well positioned to benefit from these trends.
Gulf Coast Market (PADD 3)
Fuel products produced at our Shreveport facility can be sold locally or to the Midwest region of the U.S. through the TEPPCO pipeline. Local sales are made from the TEPPCO terminal in Bossier City, Louisiana, located approximately 15 miles from the Shreveport facility, as well as from our own Shreveport facility terminal.
Gasoline, diesel and jet fuel from the Shreveport facility are sold primarily into the Louisiana, Texas and Arkansas markets, and any excess volumes are sold to marketers further up the TEPPCO pipeline. Should the appropriate market conditions arise, we have the capability to redirect and sell additional volumes into the Louisiana, Texas and Arkansas markets rather than transport them to the Midwest region via the TEPPCO pipeline.
The Shreveport facility has the capacity to produce approximately 9,000 bpd of commercial jet fuel that can be marketed to the U.S. Department of Defense, sold as Jet-A locally or sold via the TEPPCO pipeline, or transferred to the Cotton Valley facility to be processed further as a feedstock to produce solvents.
Additionally, we produce a number of fuel-related products including fluid catalytic cracking (“FCC”) feedstock, vacuum residuals and mixed butanes. FCC feedstock is sold to other refiners as a feedstock for their FCC units to make fuel products. Vacuum residuals are blended or processed further to make asphalt products. Volumes of vacuum residuals which we cannot process are sold locally into the fuel oil market or sold via railcar to other refiners. Mixed butanes are primarily available in the summer months and are primarily sold to local marketers. If the mixed butanes are not sold, they are blended into our gasoline production.
Northwest Market (PADD 4)
Fuel and asphalt products produced at our Great Falls specialty asphalt facility can be sold locally and in Missouri, Oklahoma, Texas, Arizona, North Dakota, South Dakota, Idaho, Oregon, Utah, Wyoming, Washington, Nevada, California and Canada. Seasonally, fuel products from the Great Falls specialty asphalt facility are transported to terminals in Washington and Utah.
Renewable diesel, sustainable aviation fuel, renewable hydrogen, renewable natural gas, renewable propane, and renewable naphtha produced at our Montana Renewables facility are distributed into renewable markets in the western half of North America.
Customers
Specialty Products. We have a diverse customer base for our specialty products. In fiscal year 2023, we sold our specialty products to approximately 2,200 customers. Many of our customers are long-term customers who use our products in specialty applications, after an approval process ranging from six months to two years.
Fuel Products. We have a diverse customer base for our fuel products. In fiscal year 2023, we sold our fuel products to approximately 200 customers. Our diverse customer base includes wholesale distributors and retail chains. We are able to sell the majority of the fuel products we produce at the Shreveport facility to the local markets of Louisiana, Texas and Arkansas. We also have the ability to ship additional fuel products from the Shreveport facility to the Midwest region through the TEPPCO pipeline. The majority of our fuel products produced at our Great Falls specialty asphalt facility are sold to local markets in Montana and Idaho as well as in Canada. The renewable fuel products produced at our Montana Renewables facility are distributed into renewable markets in the western half of North America.
Renewable Fuels Products. We sell our renewable fuels products to a relatively small number of investment grade counterparties under multiyear offtake agreements for onward distribution into renewable markets in the western half of North America. The robust demand during the placement process for the renewable fuels produced at our Montana Renewables facility allows us to select an established, integrated customer base for our renewable products.
During the years ended December 31, 2023, 2022 and 2021, we had no customer that represented 10% or greater of consolidated sales.
Competition
Competition in our markets is from a combination of large, integrated petroleum companies and independent refiners. Many of our competitors are substantially larger than us and are engaged on a national or international basis in many segments of the petroleum products business, including exploration and production, refining, transportation and marketing. These competitors may have greater flexibility in responding to or absorbing market changes occurring in one or more of these business segments. We distinguish our competitors according to the products that they produce. Set forth below is a description of our significant competitors according to product category.
Naphthenic Lubricating Oils. Our primary competitors in producing naphthenic lubricating oils include Ergon Refining, Inc., Cross Oil Refining and Marketing, Inc. and San Joaquin Refining Co., Inc.
Paraffinic Lubricating Oils. Our primary competitors in producing paraffinic lubricating oils include Exxon Mobil Corporation, Motiva Enterprises, LLC, Phillips 66, HF Sinclair Corporation and Chevron Corporation.
Paraffin Waxes. Our primary competitors in producing paraffin waxes include Exxon Mobil Corporation, HF Sinclair Corporation, The International Group Inc. and Ergon, Inc..
Solvents. Our primary competitors in producing solvents include CITGO Petroleum Corporation, ExxonMobil Chemical Company and Total S.A.
Polyol ester Based Specialty Products. Our primary competitors in producing polyol ester-based specialty products include LANXESS, ExxonMobil Corporation, BASF Corporation, Croda International plc, Nyco Products Corporation and Zschimmer & Schwartz, Inc.
Packaged and Synthetic Specialty Products. Our primary competitors in retail and commercial packaged and synthetic specialty products include Exxon Mobil Corporation (Mobil 1), Valvoline, Inc. and other independent lubricant manufacturers. Our primary competitors in industrial packaged and synthetic specialty products include Exxon Mobil Corporation, Royal Dutch Shell plc, Fuchs and other independent lubricant manufacturers.
Fuel Products and By-Products. Our primary competitors in producing fuel products in the local markets in which we operate include Delek US Holdings, Exxon Mobil Corporation, Phillips 66 and Cenex.
Renewable Fuel Products. Our primary competitor in producing renewable fuel products in the local markets in which we operate is Chevron Corporation.
Our ability to compete effectively depends on our responsiveness to customer needs and our ability to maintain competitive prices and product and service offerings. We believe that our flexibility and customer responsiveness differentiates us from many of our larger competitors. However, it is possible that new or existing competitors could enter the markets in which we operate, which could negatively affect our financial performance.
Governmental Regulation
From time to time, we are a party to certain claims and litigation incidental to our business, including claims made by various taxation and regulatory authorities, such as the IRS, the EPA and the U.S. Occupational Safety and Health Administration (“OSHA”), as well as various state environmental regulatory bodies and state and local departments of revenue, as the result of audits or reviews of our business.
Environmental and Occupational Health and Safety Matters
Environmental
We conduct crude oil and specialty refining, blending and terminal operations, certain activities of which are subject to stringent federal, regional, state and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose legal standards and obligations that are applicable to our operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which we may release materials into the environment, requiring mitigation of pollutant discharges from current operations that may include incurring capital expenditures to limit or prevent unauthorized releases from our equipment and facilities, requiring remedial activities to mitigate pollution from former operations, imposing substantial liabilities for pollution resulting from our operations, and requiring the application of specific health and safety criteria addressing worker protection. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects; and the issuance of injunctive relief limiting or prohibiting our activities in a particular area.
Moreover, certain of these laws impose joint and several liability and strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes or other materials have been disposed of or released and areas where any such contamination has come to be located. In addition, new environmental and worker safety laws and
regulations, amendment of existing laws and regulations, reinterpretation of legal requirements, increased governmental enforcement or other developments could significantly increase our operational or compliance expenditures, including as discussed below in more detail.
Remediation of subsurface contamination continues at certain of our refinery sites and is being overseen by the appropriate governmental agencies. Based on current investigative and remedial activities, we believe that the cost to control or remediate the soil and groundwater contamination at these refineries will not have a material adverse effect on our financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs of these remedial projects will not become material.
Great Falls Refinery
In connection with the acquisition of the Great Falls refinery from Connacher Oil and Gas Limited (“Connacher”), we became a party to an existing 2002 Refinery Initiative Consent Decree (the “Great Falls Consent Decree”) with the EPA and the Montana Department of Environmental Quality (the “MDEQ”). The material obligations imposed by the Great Falls Consent Decree have been completed. On September 27, 2012, Montana Refining Company, Inc., received a final Corrective Action Order on Consent, replacing the refinery’s previously held hazardous waste permit. This Corrective Action Order on Consent governs the investigation and remediation of contamination at the Great Falls refinery.
We believe the majority of the impacts related to such contamination at the Great Falls refinery are covered by a contractual indemnity provided by a subsidiary of HF Sinclair Corporation (“the Seller”), the owner and operator of the Great Falls refinery prior to its acquisition by Connacher, under an asset purchase agreement between the Seller and Connacher, pursuant to which Connacher acquired the Great Falls refinery.
Under this asset purchase agreement, the Seller agreed to indemnify Connacher and Montana Refining Company, Inc., subject to timely notification, certain conditions and certain monetary baskets and caps, for environmental conditions arising under the Seller’s ownership and operation of the Great Falls refinery and existing as of the date of sale to Connacher. During 2014, HF Sinclair Corporation (“Holly”) provided us a notice challenging our position that the Seller is obligated to indemnify our remediation expenses for environmental conditions to the extent arising under Holly’s ownership and operation of the refinery and existing as of the date of sale to Connacher. On September 22, 2015, we initiated a lawsuit against Holly and the Sellers. The court ordered that all of the claims be addressed in arbitration. The arbitration panel confirmed that the sellers of the Great Falls refinery retained the liability for all pre-closing contamination with respect to third-party claims indefinitely and with respect to first party claims for which the sellers received notice within five years after the sale of the refinery, which claims are subject to the requirements otherwise set forth in the asset purchase agreement. Among other things, the panel denied the Company’s demands for reimbursement for costs already incurred by the Company prior to the arbitration but left open the Company’s ability to make future claims. The Company expects that it may incur costs to remediate other environmental conditions at the Great Falls refinery. The Company currently believes that these other costs it may incur will not be material to its financial position or results of operations.
Air Emissions
Our operations are subject to the federal Clean Air Act, as amended (“CAA”), and comparable state and local laws. Amendments made to the CAA in 1990 require most industrial operations in the U.S. to incur capital expenditures to meet the air emission control standards that are developed and implemented by the EPA and state environmental agencies. Under the CAA, facilities that emit regulated air pollutants are subject to stringent regulations, including requirements to install various levels of control technology on sources of pollutants. In addition, in recent years, the petroleum refining sector has become subject to stringent federal regulations that impose maximum achievable control technology (“MACT”) on refinery equipment emitting certain listed hazardous air pollutants. Some of our facilities have been included within the categories of sources regulated by MACT rules. Our refining and terminal operations that emit regulated air pollutants are also subject to air emissions permitting requirements that incorporate stringent control technology requirements for which we may incur significant capital expenditures. Any renewal of those air emissions permits or a need to modify existing or obtain new air emissions permits has the potential to delay the development of our projects. We can provide no assurance that future compliance with existing or any new laws, regulations or permit requirements will not have a material adverse effect on our business, financial position or results of operations. For example, in 2015, the EPA issued a final rule under
the CAA making the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone more stringent. Since that time, the EPA has issued area designations with respect to ground-level ozone and final requirements that apply to state, local and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. States are expected to implement more stringent requirements as a result of this new final rule, which could apply to our operations. EPA retained the 2015 standards for ground-level ozone after a review completed in 2020. In 2021, EPA announced that it would reconsider this standard, and in August 2023, EPA announced it would begin an entirely new review of the NAAQS for ground-level ozone. Also, in 2015, the EPA published a final rule that amended three refinery standards already in effect, imposing additional or, in some cases, new emission control requirements on subject refineries. The final rule requires, among other things, the monitoring of air concentrations of benzene around the refinery fence line perimeter and submittal of the fence line monitoring data to the EPA on a quarterly basis; upgraded emissions controls for storage tanks, including controls for smaller capacity storage vessels and storage vessels storing materials with lower vapor pressures than previously regulated; enhanced performance requirements for flares including the use of a minimum of three pollution prevention measures, continuous monitoring of flares and pressure release devices and analysis and remedy of flare release events; and compliance with emissions standards for delayed coking units. These final rules and any other future air emissions rulemakings could impact us by requiring installation of new emission controls on some of our equipment, resulting in longer permitting timelines, and significantly increasing our capital expenditures and operating costs, which could adversely impact our business.
From time to time the CAA authorizes the EPA to require modifications in the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with the fuel product’s final use. For example, in February 2000, the EPA published regulations limiting the sulfur content allowed in gasoline. These regulations, referred to as “Tier 2 Standards,” required the phase-in of gasoline sulfur standards beginning in 2004, with special provisions for small refiners and for refiners serving those western U.S. states exhibiting lesser air quality problems. Similarly, the EPA published regulations that limit the sulfur content of highway diesel beginning in 2006 from its former level of 500 parts per million (“ppm”) to 15 ppm (the “ultra-low sulfur standard”). Our Shreveport and Great Falls facilities have implemented the sulfur standard with respect to produced gasoline and produced diesel meeting the ultra-low sulfur standard.
In 2014, the EPA published more stringent sulfur standards, referred to as “Tier 3 Standards,” including requiring that motor gasoline will not contain more than 10 ppm of sulfur on an annual average basis by January 1, 2017, except in those instances where refineries received a “small refinery” exemption, in which event the deadline was extended to January 1, 2020. Our Shreveport and Great Falls facilities are fully compliant with the 10 ppm sulfur standard with respect to produced gasoline. In addition, we are required to meet the Mobile Source Air Toxics (“MSAT”) II Standards adopted by the EPA to reduce the benzene content of motor gasoline produced at our facilities and have completed capital projects at our Shreveport and Great Falls facilities to comply with those fuel quality requirements.
The EPA has issued RFS mandates, requiring refiners such as us to blend renewable fuels into the petroleum fuels they produce and sell in the United States. We, and other refiners subject to RFS, may meet the RFS requirements by blending the necessary volumes of renewable transportation fuels produced by us or purchased from third parties. To the extent that refiners are unable to blend renewable fuels into the products they produce in the quantities required to satisfy their obligations under the RFS program, those refiners may purchase renewable credits, referred to as RINs, to maintain compliance. To the extent that we exceed the minimum volumetric requirements for blending of renewable transportation fuels, we generate our own RINs for which we have the option of retaining the RINs for current or future RFS compliance or selling those RINs on the open market. We are unable to blend sufficient quantities of ethanol and biodiesel to meet our requirements and would, therefore, may have to purchase an increasing number of RINs. It is not possible at this time to predict with certainty what those volumes or costs may be. Existing laws and regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum fuels may increase. For more information on the RFS program, our participation in the program and risks associated with the program, see the following risk factor under Part I, Item 1A of this Form 10-K: “The availability and cost of renewable identification numbers and results of litigation related to our SRE petitions could have a material adverse effect on our results of operations and financial condition and our ability to make payments on our debt obligations.”
Climate Change
Climate change continues to attract considerable public, governmental and scientific attention in the U.S. and foreign countries. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHG”) or to control such future emissions. Consequently, it is possible that our operations as well as the operations of our customers may become subject to a series of regulatory, political, litigation and financial risks associated with the processing of fossil fuels and/or emissions of GHGs. The adoption of international, federal, regional or state legislation or regulations or other regulatory initiatives that impose more stringent standards for GHG emissions could require us to incur increased compliance costs or affect the price or availability of certain of our feedstocks or products.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations under existing provisions of the federal CAA that, among other things: establish that Prevention of Significant Deterioration (“PSD”) construction permit programs and Title V operating permit programs will include reviews for GHG emissions from certain large stationary sources that are also potential major sources of criteria pollutant emissions; require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources; implement CAA emission new source performance standards (“NSPS”) directing the reduction of methane from certain new, modified or reconstructed facilities in the oil and natural gas sector; and together with the U.S. Department of Transportation (“DOT”), implement GHG emissions limits on vehicles manufactured for operation in the United States. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored “Paris Agreement,” which calls upon nations to limit their GHG emissions through individually determined reduction goals every five years after 2020.
There are also increasing financial risks for fossil fuel producers, as stockholders and bondholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies are beginning to define sustainable lending practices and there is the possibility that financial institutions will adopt policies that limit funding for fossil fuel energy companies, as governmental and nongovernmental institutions focus on addressing climate-related risks in the financial sector. Although we are not an oil or gas producer, it is possible that limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities which could affect the price or availability of certain of our feedstocks.
It should also be noted that some scientists have concluded that increasing concentrations of GHG in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.
Hazardous Substances and Wastes
The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Such classes of persons include the current and past owners and operators of sites where a hazardous substance was released and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Separately, it is not uncommon for neighboring landowners and other third parties to file claims under relevant state laws for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. In the course of our operations, we generate wastes or handle substances that may be regulated as hazardous substances, and we could become subject to liability under CERCLA and comparable state laws.
We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state laws, which impose requirements related to the handling, storage, treatment and disposal of hazardous and non-hazardous wastes. In the course of our operations, we generate petroleum product wastes and ordinary industrial wastes that may be regulated as hazardous wastes. In addition, our operations also generate non-hazardous solid wastes, which are regulated under RCRA and state laws. Historically, our environmental compliance costs under the existing requirements of RCRA and similar state and local laws have not had a material adverse effect on our results of operations, and the cost involved in complying with these requirements is not material.
We currently own or operate, and have in the past owned or operated, properties that for many years have been used for refining and terminal activities. These properties in the past may have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes were not under our control. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes have been released on or under the properties owned or operated by us. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination or to perform remedial activities to prevent future contamination.
In addition, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements, increased governmental enforcement or other developments could significantly increase our operational or compliance expenditures.
Water Discharges
The Federal Water Pollution Control Act of 1972, as amended, also known as the federal Clean Water Act, and analogous state laws impose restrictions and stringent controls on the discharge of pollutants, including oil, into regulated waters. Such discharges are prohibited, except in accordance with the terms of a permit issued by the EPA or the appropriate state agencies. Any unpermitted release of pollutants, including crude oil or hydrocarbon specialty oils as well as refined products, could result in penalties, as well as significant remedial obligations. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. Historically, our environmental compliance costs under the existing requirements of the federal Clean Water Act and similar state laws have not had a material adverse effect on our results of operations but these laws and their implementing regulations are subject to change and there can be no assurance that such future costs will not be material.
The primary federal law for oil spill liability is the Oil Pollution Act of 1990, as amended (“OPA”), which addresses three principal areas of oil pollution - prevention, containment and cleanup. The OPA applies to vessels, offshore facilities and onshore facilities, including refineries, terminals and associated facilities that may affect waters of the U.S. Under the OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages from oil spills. Historically, our past environmental compliance costs under the existing requirements of the OPA have not had a material adverse effect on our results of operations but this law and its implementing regulations are subject to change and there can be no assurance that such future costs will not be material.
Occupational Health and Safety
We are subject to various laws and regulations relating to occupational health and safety, including the federal Occupational Safety and Health Act, as amended, and comparable state laws. These laws and regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the EPA’s community right-to-know regulations under Title III of CERCLA and similar state statutes require that we maintain information about hazardous materials used or produced in our operations and provide this information to employees, contractors, state and local government authorities and customers. We maintain safety and training programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. We conduct periodic audits of Process Safety Management (“PSM”) systems at each of our locations subject to the PSM standard. Our compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could
result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges.
Other Environmental and Maintenance Items
We perform preventive and normal maintenance on most, if not all, of our refining and terminal assets and make repairs and replacements when necessary or appropriate. We also conduct inspections of these assets as required by law or regulation.
Insurance
Our operations are subject to certain hazards of operations, including fire, explosion and weather-related perils. We maintain insurance policies, including business interruption insurance for each of our facilities, with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, ensure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.
Seasonality
The fuel and fuel related products that we manufacture, including asphalt products, are subject to seasonal demand and trends. Asphalt demand is generally lower in the first and fourth quarters of the year, as compared to the second and third quarters, due to the seasonality of the road construction and roofing industries we supply. Demand for gasoline and diesel is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and agricultural activity. In addition, our natural gas costs can be higher during the winter months, as demand for natural gas as a heating fuel increases during the winter. As a result, our operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year due to seasonality related to these and other products that we produce and sell.
Properties
We own and lease the principal properties listed below. The principal properties which we own, as well as others not listed below, are pledged as collateral under our Collateral Trust Agreement as discussed in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Master Derivative Contracts and Collateral
Trust Agreement.” We believe that all properties are suitable for their intended purpose, are being efficiently utilized and provide adequate capacity to meet demand for the next several years.
Property
Business Segment(s)
Acres
Owned / Leased
Location
Shreveport facility
Specialty Products and Solutions
Owned
Shreveport, Louisiana
Great Falls specialty asphalt facility
Montana/Renewables
Owned
Great Falls, Montana
Montana Renewables facility
Montana/Renewables
Owned / Leased (1)
Great Falls, Montana
Princeton facility
Specialty Products and Solutions
Owned
Princeton, Louisiana
Cotton Valley facility
Specialty Products and Solutions
Owned
Cotton Valley, Louisiana
Burnham terminal
Specialty Products and Solutions
Owned
Burnham, Illinois
Karns City facility
Specialty Products and Solutions
Owned
Karns City, Pennsylvania
Dickinson facility
Specialty Products and Solutions
Owned
Dickinson, Texas
Missouri facility
Specialty Products and Solutions
Owned
Louisiana, Missouri
Calumet Packaging facility
Performance Brands
Leased
Shreveport, Louisiana
Royal Purple facility
Performance Brands
Owned
Porter, Texas
(1) Montana Renewables LLC, an unrestricted subsidiary of the Company, leases certain property from the Company.
In addition to the items listed above, we lease or own a number of storage tanks, railcars, warehouses, equipment, land, crude oil loading facilities and precious metals.
Intellectual Property
Our patents relating to our refining operations are not material to us as a whole. Our patents include composition patents that are integral to certain products in the Specialty Products and Solutions segment. We own, have registered or have applied for registration of a variety of tradenames, service marks and trademarks for use in our business. The trademarks, tradenames and design marks under which we conduct our branded business (including Penreco, Orchex, Royal Purple, Bel-Ray and TruFuel) and other trademarks employed in the marketing of our products are integral to our marketing operations. We also license intellectual property rights from third parties. We are not aware of any facts as of the date of this filing which would negatively impact our continuing use of intellectual property or our licensed intellectual property.
Office Facilities
In addition to our principal properties discussed above, as of December 31, 2023, we were a party to a number of cancelable and noncancelable leases for certain properties, including our corporate headquarters in Indianapolis, Indiana. The corporate headquarters lease is for 58,501 square feet of office space. The lease term expires in August 2024. Please read Note 4 - “Leases” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” of this Annual Report for additional information regarding our leases.
While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future and that additional facilities will be available on commercially reasonable terms as needed.
Human Capital Management
We believe that our employees are significant contributors to our success and the future success of our Company, which depends on our ability to attract, retain and motivate qualified personnel. The skills, experience and industry knowledge of key employees significantly benefit our operations and performance.
As of February 28, 2024, our general partner employed approximately 1,580 people who provide direct support to our operations. Of these employees, approximately 600 are covered by collective bargaining agreements.
Employees at the following locations are covered by the following separate collective bargaining agreements:
Facility
Union
Expiration Date
Cotton Valley
International Union of Operating Engineers
November 19, 2026
Princeton
International Union of Operating Engineers
August 20, 2024
Dickinson
International Union of Operating Engineers
December 12, 2024
Shreveport
United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union
April 30, 2026
Missouri
United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union
April 30, 2025
Karns City
United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union
January 31, 2027
Great Falls
United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union
July 31, 2026
None of the employees at the Calumet Packaging facility, the Royal Purple facility or at the Burnham terminal are covered by collective bargaining agreements. Our general partner considers its employee relations to generally be good, with no history of work stoppages.
Compensation and Benefits
We have demonstrated a history of investing in our workforce by offering competitive salaries, fair wages and comprehensive benefits. To foster a stronger sense of ownership and align the interests of our personnel with unitholders, we provide short-term and long-term incentive programs that include short-term cash bonus awards under our Cash Incentive Plan and phantom unit awards under our Long-Term Incentive Plan. Awards under these incentive programs are subject to individual and company performance factors. Furthermore, we offer comprehensive benefits to our full-time employees working 30 hours or more per week, including long-term disability coverage, comprehensive health insurance, including vision and dental, employee Health Savings Accounts, including contributions to these accounts by us, competitive paid time off and sick leave programs, and student loan repayment matching opportunities. In addition, we provide a 401(k) retirement savings plan to assist our eligible employees in saving for their retirement. To be an employer of choice and maintain the strength of our workforce, we consistently assess the current business environment and labor market to refine our compensation and benefits programs and other resources available to our personnel.
Workforce Health and Safety
The safety of our employees is a core tenet of our values, and our safety goal is zero incidents and zero injuries. A strong safety culture reduces risk, enhances productivity and builds a strong reputation in the communities in which we operate. We have earned a reputation as a safe and an environmentally responsible operator through continuous improvement in our safety performance. This makes us more attractive for current and new employees.
We invest in safety training and coaching, promote risk assessments and encourage visible safety leadership. Employees are empowered and expected to stop or refuse to perform a job if it is not safe or cannot be performed safely. We sponsor emergency preparedness programs, conduct regular audits to assess our performance and celebrate our successes in which we acknowledge employees and contractors alike who have exhibited strong safety leadership during
the course of the year. These many efforts combine to create a culture of safety throughout the company and provide a positive influence on our contractor community.
Diversity, Inclusion and Workplace Culture
We are committed to maintaining a culture where diversity and inclusion are core philosophies across our operations, including, but not limited to, our decisions around recruitment, promotion, transfer, leaves of absence, compensation, opportunities for career support and advancement, job performance and other relevant job-related criteria. We embrace an approach to hiring and advancement that considers the value of diversity, and we are also committed to making opportunities for development and progress available to all employees so their talents can be fully developed to maximize our and their success. We believe that creating an environment that cultivates a sense of belonging requires encouraging employees to continue to educate themselves about each other’s experiences, and we strive to promote the respect and dignity of all persons. We also believe it is important that we foster education, communication and understanding about diversity, inclusion and belonging.
Address, Internet Website and Availability of Public Filings
Our principal executive offices are located at 2780 Waterfront Parkway East Drive, Indianapolis, Indiana, 46214 and our telephone number is (317) 328-5660. Our website is located at www.calumet.com.
Our Securities and Exchange Commission (“SEC”) filings are available on our website as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. We make available, free of charge on our website, our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These documents are located on our website at www.calumet.com by selecting the “Investor Relations” link, and then selecting the “Financial Reporting” link and then selecting the “SEC Filings” link. We also make available, free of charge on our website, our charters for the Audit and Finance Committee, Compensation Committee, and Conflicts Committee, and our Related Party Transactions Policy and Code of Business Conduct and Ethics. We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K relating to amendments to or waivers from any provision of the Code of Business Conduct and Ethics applicable to our executive officers and directors by posting such information on our website. These documents are located on our website at www.calumet.com by selecting the “Investor Relations” link, then selecting the “Governance” link, and then selecting “Governance Documents.” All reports and documents filed with the SEC are also available via the SEC website, www.sec.gov.
The above information is available to anyone who requests it and is free of charge either in print from our website or upon request by contacting Investor Relations using the contact information listed above. Information on our website is not incorporated into this Annual Report or our other securities filings and is not a part of them.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
An investment in our common units involves a significant degree of risk. Before you invest in our common units, you should carefully consider the risk factors discussed or referenced below. If any of the risks discussed below were actually to occur, our business, financial position or results of operations could be materially adversely affected.
Risks Related to our Business
Results of Operations and Financial Condition
Our business depends on supply and demand fundamentals, which can be adversely affected by numerous macroeconomic factors outside of our control and which may in turn impact our operational and financial performance, including our ability to execute our business strategies in the expected time frame.
Such macroeconomic factors include:
● Reduction in the demand for, and the marketability of, our specialty products due to governmental regulations, including travel bans and restrictions, quarantines, shelter in place orders, and shutdowns;
● increased volatility in product margins;
● the ability or willingness of our suppliers to provide raw materials, equipment, services or supplies for our operations or otherwise fulfill their contractual obligations, which could reduce our production levels or otherwise impact our ability to deliver refined or finished lubricant products timely or at all;
● the ability or willingness of our customers to fulfill their contractual obligations or any material reduction in, or loss of, orders or revenue from our customers;
● occurrence of operational hazards, including terrorism, cyberattacks or domestic vandalism, as well as information system failures or communication network disruptions;
● increased cost and reduced availability of capital for growth or maintenance expenditures;
● availability and operability of terminals, tankage and pipelines that store and transport our feedstocks and products;
● the amount of our borrowing base under our revolving credit facility and our ability to issue letters of credit or the requirement that we post substantial amounts of credit support;
● the impairment of our long-lived assets or goodwill, which could reduce our earnings;
● the impact of any economic downturn, recession, inflationary pressures, further increases in interest rates or other disruptions of the U.S. and global economies and financial and commodity markets; and
● political tensions, conflicts and war, such as the ongoing conflicts in Ukraine and the Middle East.
Our business has exposure to some commodities which are volatile, and a reduction in our margins will adversely affect the amount of cash we will have available to operate our business and for payments of our debt obligations.
In many cases, specialty products are produced from intermediates that ultimately originate from crude oil. Typically, we enjoy a cost advantage from processing crude oil into intermediates that are used as specialty feedstocks. This process also creates fuels and other by-products, which carry a margin to crude prices. Typically, the total margin of fuels and other by-products to crude oil is a positive, but in extreme demand scenarios this cost advantage can turn into a short-term disadvantage. When the margin between product sales prices and feedstock costs tightens, our earnings, profitability and cash flows are negatively impacted.
A widely used benchmark to track margins in the fuel products industry is the Gulf Coast 2/1/1 crack spread (“Gulf Coast crack spread”), which represents the gross margin assuming that two barrels of a benchmark crude oil are converted, or cracked, into one barrel of gasoline and one barrel of diesel. The Gulf Coast 2/1/1 crack spread ranged from a high of
$50.05 per barrel to a low of $13.98 per barrel during 2023 and averaged $31.64 per barrel during 2023 compared to an average of $39.96 in 2022.
Our actual fuels product margins may vary from the Gulf Coast crack spread due to the actual crude oil used and products produced, transportation costs, regional differences, and the timing of the purchase of the feedstock and sale of the refined products, but we use the Gulf Coast crack spread as an indicator of the volatility and general levels of fuels refining margins.
Our specialty product margins are influenced by the price of our feedstocks, many of which are commodities. If feedstock prices increase, our margins would fall unless we are able to pass through these price increases to our customers. For example, during fiscal year 2022, higher material and feedstock costs adversely impacted our margins for our Performance Brands segment.
Our hedging activities may not be effective in reducing our exposure to commodity price risk and may reduce our earnings, profitability and cash flows.
From time to time, we utilize derivative financial instruments related to the future price of crude oil, natural gas and refined products to manage expected outcomes involving commodity price risk. We typically do not enter into derivative financial instruments to reduce our exposure to prices of the specialty products we sell as there is no established derivative market for such products.
We limit our derivative transactions to only a portion of the volume of our expected purchase and sales requirements and, as a result, we will continue to have direct commodity price exposure to the unhedged portion of our expected purchase and sales requirements. Thus, we could be exposed to significant increases in commodity prices, which would increase the cost for a portion of our feedstock purchases.
Our actual future purchase and sales requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, which may result in a substantial diminution of our liquidity. As a result, our hedging activities may not be as effective as we intend in reducing our exposure to price risk. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligations under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
Decreases in the price of inventory and products may lead to a reduction in the borrowing base under our revolving credit facility and our ability to issue letters of credit or the requirement that we post substantial amounts of cash collateral for derivative instruments, which could adversely affect our liquidity, financial condition and our ability to make payments on our debt obligations.
We rely on borrowings and letters of credit under our revolving credit facility to purchase feedstocks for our facilities, and to lease certain precious metals for use in our operations. The borrowing base under our revolving credit facility is determined weekly or monthly depending upon availability levels or the existence of a default or event of default. Reductions in the value of our inventories as a result of lower crude oil prices could result in a reduction in our borrowing base, which would reduce the amount of financial resources available to meet our operating requirements. If, under certain circumstances, our available capacity under our revolving credit facility falls below certain threshold amounts, or a default or event of default exists, then our cash balances in a dominion account established with the administrative agent will be applied on a daily basis to our outstanding obligations under our revolving credit facility. In addition, decreases in the price of crude oil or increases in crack spreads may require us to post substantial amounts of cash collateral to our hedging counterparties in order to maintain our derivative instruments. If, due to our financial condition or other reasons, the borrowing base under our revolving credit facility decreases, we are limited in our ability to issue letters of credit or we
are required to post substantial amounts of cash collateral to our hedging counterparties, our liquidity, financial condition and our ability to make payments on our debt obligations could be materially and adversely affected. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Debt and Credit Facilities” for additional information.
We depend on certain third-party pipelines for transportation of feedstocks and products, and if these pipelines become unavailable to us, our revenues and cash available for payment of our debt obligations could decline.
Our Shreveport facility is interconnected to a pipeline that supplies a portion of its crude oil and a pipeline that ships a portion of its refined fuel products to customers, such as pipelines operated by subsidiaries of Enterprise Products Partners L.P. and Plains. Our Great Falls facility receives crude oil through the Front Range pipeline system via the Bow River Pipeline in Canada. Since we do not own or operate any of these pipelines, their continuing operation is not within our control.
The unavailability of any of these third-party pipelines for the transportation of crude oil or our refined fuel products, because of acts of God, accidents, earthquakes or hurricanes, government regulation, terrorism or other third-party events, could lead to disputes or litigation with certain of our suppliers or a decline in our sales, net income and cash available for payments of our debt obligations.
The price volatility of utility services may result in decreases in our earnings, profitability and cash flows.
The volatility in costs of natural gas and other utility services, principally electricity, used by our facilities and other operations affect our net income and cash flows. Natural gas and utility prices are affected by factors outside of our control, such as supply and demand in both local and regional markets. Natural gas prices have historically been volatile.
For example, daily prices for natural gas as reported on the NYMEX ranged between $4.17 and $1.99 per million British thermal unit (“MMBtu”) in 2023, and between $9.68 and $3.72 per MMBtu in 2022. Typically, electricity prices fluctuate with natural gas prices. Future increases in natural gas and utility prices may have a material adverse effect on our results of operations. However, international natural gas prices have been more volatile, and more expensive, than domestic prices, which can provide a competitive advantage to domestic plants. This dynamic means that market product prices may increase more than our utility costs, creating higher margins when natural gas and utility costs increase less than international competitors’ utility prices. Natural gas and utility costs constituted approximately 15.4% and 14.4% of our total operating expenses included in cost of sales for the years ended December 31, 2023 and 2022, respectively. As prices and industry competitive dynamics change, it could adversely affect our profitability and the amount of cash available for payments of our debt obligations.
Our facilities incur operating hazards, and the potential limits on insurance coverage could expose us to potentially significant liability costs.
Our facilities are subject to certain operating hazards, and our cash flow from those operations could decline if any of our facilities experience a major accident, pipeline rupture or spill, explosion or fire, is damaged by severe weather or other natural disaster, or otherwise is forced to curtail its operations or shut down. These operating hazards could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage. One or more of these developments may result in significant curtailment or suspension of our related operations.
Although we maintain insurance policies, including personal and property damage and business interruption insurance for each of our facilities, we cannot ensure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or significant interruption of operations. Our business interruption insurance will not apply unless a business interruption exceeds 60 days. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. In addition, we are not fully insured against all risks incident to our business because certain risks are not fully insurable, coverage is unavailable,
or premium costs, in our judgment, do not justify such expenditures. For example, we are not insured for all environmental liabilities, including, but not limited to, product spills and other releases at all of our facilities. If we were to incur a significant liability for which we are not insured or fully insured, it could affect our financial condition and diminish our ability to make payments of our debt obligations.
Downtime for maintenance at our refineries and facilities will reduce our revenues and could limit our ability to make payments of our debt obligations.
Our facilities consist of many processing units, a number of which have been in operation for extended periods of time. One or more of the units have in the past required, and may in the future require, additional unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for each unit every one to five years. Scheduled and unscheduled maintenance reduce our revenues and increase our operating expenses during the period of time that our processing units are not operating and could limit our ability to make payments of our debt obligations.
An impairment of our long-lived assets or goodwill could reduce our earnings or negatively impact our financial condition and results of operations.
We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset or goodwill may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value based on the ability to generate future cash flows. Our long-lived assets and goodwill impairment analyses are sensitive to changes in key assumptions used in our analysis, such as expected future cash flows, the degree of volatility in equity and debt markets and our unit price. If the assumptions used in our analysis are not realized, it is possible a material impairment charge may need to be recorded in the future.
We cannot accurately predict the amount and timing of any impairment of long-lived assets or goodwill. Further, as we continue to develop our strategy regarding certain of our non-core assets, we will need to continue to evaluate the carrying value of those assets. Any additional impairment charges that we may take in the future could be material to our results of operations and financial condition.
Competition in our industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.
We compete with a broad range of companies within our industry. Because of some of our competitors’ geographic diversity, larger and more complex refineries, integrated operations and greater resources, some of our competitors may be better able to withstand volatile market conditions, to obtain crude oil in time of shortage and to bear the economic risks inherent in all areas of the refining industry.
In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. The more successful these alternatives become as a result of governmental regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the impact on pricing and demand for our products and our profitability. There are presently significant governmental and consumer pressures to increase the use of alternative fuels in the United States. While in some areas of our business these pressures are helpful, in other areas they can pose a significant risk.
We depend on unionized labor for the operation of many of our facilities. Any work stoppages or labor disturbances at these facilities could disrupt our business and negatively impact our financial condition and results of operations.
Substantially all of our operating personnel at our Shreveport, Great Falls, Princeton, Cotton Valley, Karns City, Dickinson and Missouri facilities are employed under collective bargaining agreements. If we are unable to renegotiate these agreements as they expire, any work stoppages or other labor disturbances at these facilities could have an adverse effect on our business and impact our ability to make payments of our debt obligations. In addition, employees who are not currently represented by labor unions may seek union representation in the future, and any renegotiation of current
collective bargaining agreements may result in terms that are less favorable to us. Furthermore, our actions or responses to any such negotiations, labor disputes, strikes or work stoppages could negatively impact how we are perceived and the impact on our reputation could have adverse effects on our business.
Our method of valuing inventory may result in decreases in net income.
The nature of our business requires us to maintain substantial quantities of inventories. Some of our inventory is commodity based, providing us little control over the changing market value of these inventories. Because our inventory is valued at the lower of cost or market (“LCM”) value, if the market value of our inventory were to decline to an amount less than our cost, we would record a write-down of inventory and a non-cash charge to cost of sales. In periods of decreasing crude oil or refined product prices, our inventory valuation methodology has resulted in and may in the future result in decreases in net income.
We depend on key personnel for the success of our business and the loss of those persons could adversely affect our business and our ability to make payments of our debt obligations.
The loss of the services of any member of senior management or key employee could have an adverse effect on our business and reduce our ability to make payments of our debt obligations. Our success in hiring, attracting and retaining senior management and other experienced and highly skilled employees will depend in part on our ability to provide competitive compensation packages and a high-quality work environment and maintain a desirable corporate culture. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available. We do not maintain any key-man life insurance.
We are subject to cybersecurity risks and other cyber incidents resulting in disruption.
Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. We depend on information technology systems to run our business. In addition, our use of the internet, cloud services and other public networks, exposes our business and that of other third parties with whom we do business to cybersecurity threats. Geopolitical tensions or conflicts, such as ongoing conflict in Ukraine and the Middle East, may further heighten the risk of cybersecurity incidents. Such incidents could lead to unauthorized access to data and systems, intentional or inadvertent releases of confidential information, including personally identifiable information, corruption of data and disruption of critical systems and operations. Despite the security measures we have in place and any additional measures we may implement in the future, our facilities and systems, and those of our third-party service providers, could be vulnerable to security breaches, computer viruses, ransomware attacks, phishing attacks, inadvertent data disclosures, programming errors, human errors or malfeasance, acts of vandalism or other events. Moreover, these threats are constantly evolving, thereby making it more difficult to successfully defend against them or to implement adequate preventive measures. We may not have the current capability to detect certain vulnerabilities, or may not detect them in a timely manner, which may allow those vulnerabilities to persist in our systems over long periods of time. During 2021, we experienced a minor cybersecurity incident at one of our operating locations, which was effectively contained. Any disruption of our systems or cybersecurity incident or event resulting in the misappropriation, loss or other unauthorized disclosure of confidential information, whether by us directly or our third-party service providers, could damage our reputation, expose us to the risks of litigation and liability or regulatory fines, penalties or intervention, disrupt our business, require us to incur significant costs to remediate damage resulting from the incident or improve our information technology systems, or otherwise affect our results of operations, which could materially and adversely affect our business, results of operations or financial condition. In addition, as cybersecurity incidents continue to evolve in magnitude and sophistication, and our reliance on digital technologies continues to grow, we have expended and expect to continue to expend additional resources in order to continue to enhance our cybersecurity measures and to investigate and remediate any digital systems, related infrastructure, technologies and network security vulnerabilities. While we carry cyber insurance, we cannot be certain that our coverage will be adequate for liabilities actually incurred, that insurance will continue to be available to us on economically reasonable terms, or at all, or that any insurer will not deny coverage as to any future claim.
We are also subject to an evolving landscape of laws and regulations in a range of jurisdictions governing the handling of information and the operation of information systems, including those relating to privacy, cybersecurity and data
protection. Costs associated with compliance with these laws and regulations may increase over time and failure to comply with these obligations could result in investigations, litigation, fines, penalties, judgments or other proceedings which could have a material impact on our financial results.
We identified a material weakness in our internal control over financial reporting, and if we are unable to remediate this material weakness, or if we experience additional material weaknesses or other deficiencies in the future or otherwise fail to maintain an effective system of internal control, we may not be able to accurately and timely report our financial results.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim consolidated financial statements may not be prevented or detected on a timely basis. In connection with the preparation of the Company’s consolidated financial statements for the fiscal year ended December 31, 2023, we identified a material weakness in the design of our controls within the financial statement close process associated with the subsequent accounting for and measurement of redeemable noncontrolling interests. The material weakness also existed as of December 31, 2022. Additionally, as previously disclosed, we previously identified a material weakness in internal control over financial reporting that pertains to the untimely and insufficient operation of controls in the financial statement close process, including lack of timely account reconciliation, analysis and review related to all financial statement accounts, which was remediated as of December 31, 2021.
Remediation efforts place a significant burden on management and add increased pressure to our financial resources and processes. As a result, we may not be successful in making the improvements necessary to remediate the material weakness identified by management, be able to do so in a timely manner, or be able to identify and remediate additional control deficiencies, including material weaknesses, in the future. Additionally, completion of remediation does not provide assurance that our remediation or other controls will continue to operate properly or remain adequate and we cannot assure you that we will not identify additional material weaknesses in our internal control over financial reporting in the future.
If we are unable to successfully remediate our existing material weakness or any future material weaknesses or other deficiencies in our internal control over financial reporting or disclosure controls and procedures, our ability to record, process and report financial information accurately, and to prepare financial statements within the time periods specified by the rules and forms of the SEC, could be adversely affected. This failure could negatively affect the market price and trading liquidity of our common units, cause investors to lose confidence in our reported financial information, subject us to civil and criminal investigations and penalties and generally materially and adversely impact our business and financial condition.
We reached a determination to restate certain of our previously issued consolidated financial statements, which resulted in unanticipated costs and may affect investor confidence and raise reputational issues.
As discussed in Part II, Item 8 “Financial Statements and Supplementary Data - “Notes to Consolidated Financial Statements,” we reached a determination to restate our consolidated financial statements and related disclosures for the year ended December 31, 2022 and for the periods ended March 31, 2023, June 30, 2023, and September 30, 2023, following the identification of an error in the presentation of net income (loss) to partners arising from the misallocation of net loss from MRHL to noncontrolling interest. The restatement also included other immaterial adjustments to historical periods. As a result, we have incurred unanticipated costs for accounting and legal fees in connection with or related to the restatement, and have become subject to a number of additional risks and uncertainties, which may affect investor confidence in the accuracy of our financial disclosures and may raise reputational issues for our business.
Customers and Suppliers
Our arrangement with J. Aron and Wells Fargo expose us to J. Aron and/or Wells Fargo-related credit and performance risk as well as potential refinancing risks.
In October 2023, MRL and Wells Fargo Commodities, LLC (“Wells Fargo”) entered into (i) an ISDA 2002 Master Agreement (together with a related schedule and credit support annex, the “Master Agreement”) and a Renewable Fuel and Feedstock Repurchase Master Confirmation (together with the Master Agreement, the “MRL Inventory Financing Agreement”). Pursuant to the MRL Inventory Financing Agreement, Wells Fargo agreed to, among other things, (a) purchase from MRL renewable feedstocks and finished products located at MRL’s Great Falls, Montana refinery, subject to MRL’s repurchase obligations with respect thereto, and (b) provide certain financial accommodations to MRL secured by liens on certain renewable feedstocks and finished products owned by MRL.
In January 2024, the Partnership and J. Aron & Company (“J. Aron”) entered into a Monetization Master Agreement (the “Master Agreement”), a related Financing Agreement (the “Financing Agreement”) and Supply and Offtake Agreement (together with the Master Agreement and the Financing Agreement, the “Shreveport Supply and Offtake Agreement”). Pursuant to the Shreveport Supply and Offtake Agreement, J. Aron agreed to, among other things, purchase from the Partnership, or extend to the Partnership, financial accommodations secured by crude oil and finished products located at Calumet Shreveport’s refinery and from time to time, up to maximum volumes specified for crude oil and categories of finished products, subject to the Partnership’s repurchase obligations with respect thereto.
When we executed the Shreveport Supply and Offtake Agreement, the inventories associated with such agreement were taken out of our revolving credit facility borrowing base. The inventories associated with the MRL Inventory Financing Agreement are also not included in our revolving credit facility borrowing base. Should an early termination event occur, pursuant to the terms of the Supply and Offtake Agreement, we would need to seek alternative sources of financing, such as putting the inventory associated with the Shreveport Supply and Offtake Agreement back into our revolving credit facility, to meet our obligation to repurchase the inventory at then current market prices. In addition, upon expiration of the Shreveport Supply and Offtake Agreement, the cost of repurchasing the inventory may be at higher prices than we sold the inventory. If the price of the applicable products is well above the price at which we sold the inventory, we would have to pay more for the inventory than the price we sold the inventory for. If this is the case at the time of termination and we are unable to include the inventory associated with the Shreveport Supply and Offtake Agreement in our borrowing base, we could suffer a significant reduction in liquidity if J. Aron terminates the Shreveport Supply and Offtake Agreement and we have to repurchase the inventories. Similarly, if the MRL Inventory Financing Agreement is terminated and MRL is unable to obtain alternative sources of financing, MRL could suffer significant reductions in liquidity.
Indebtedness; Financing
We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business.
We had approximately $1.9 billion of outstanding indebtedness as of December 31, 2023, and availability for borrowings of approximately $241.9 million under our senior secured revolving credit facilities. We have the ability to incur additional debt, including the ability to borrow up to an aggregate principal amount of $650.0 million at any time, subject to borrowing base limitations, under our revolving credit facility. A tranche of the revolving credit facility includes a $50.0 million senior secured first loaned in and last to be repaid out (“FILO”) revolving credit facility. In addition, as of December 31, 2023, MRL had $13.0 million of outstanding indebtedness under a secured revolving credit facility (the “MRL revolving credit agreement”) that was entered into on November 2, 2022. Our substantial indebtedness could adversely affect our results of operations, business and financial condition, and our ability to meet our debt obligations. In addition, our level of indebtedness could have important consequences to us, including the following:
● our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on favorable terms;
● covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
● we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and payments of our debt obligations;
● our ability to execute our acquisition and divestiture strategy; and
● our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy in general.
Any of these factors could result in a material adverse effect on our business, financial conditions, results of operations, business prospects and ability to satisfy our obligations under our senior notes, revolving credit facility and the MRL revolving credit agreement.
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as continuing the suspension of distributions to our unitholders, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Debt and Credit Facilities” for additional information regarding our indebtedness.
Our financing arrangements contain operating and financial provisions that restrict our business and financing activities.
The operating and financial restrictions and covenants in our financing arrangements, including our revolving credit facility, MRL revolving credit agreement, indentures governing each series of our outstanding senior notes and master derivative contracts, do currently restrict, and any future financing agreements could restrict, our ability to finance future operations or capital needs or to engage, expand or pursue our business activities, including restrictions on our ability to, among other things:
● sell assets, including equity interests in our subsidiaries;
● pay distributions on or redeem or repurchase our units or redeem or repurchase any subordinated debt and, in the case of the 9.25% Senior Secured First Lien Notes due 2024 (the “2024 Secured Notes”), our unsecured notes;
● incur or guarantee additional indebtedness or issue preferred units;
● create or incur certain liens;
● make certain acquisitions and investments;
● redeem or repay other debt or make other restricted payments;
● enter into transactions with affiliates;
● enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
● create unrestricted subsidiaries;
● enter into sale and leaseback transactions;
● enter into a merger, consolidation or transfer or sale of assets, including equity interests in our subsidiaries; and
● engage in certain business activities.
Our revolving credit facility also contains a springing financial covenant which provides that only if the Company’s availability to borrow loans under the revolving credit facility falls below the sum of (a) the greater of (i) (x) 15% of the borrowing base then in effect at any time that the refinery asset borrowing base component is greater than $0 and (y) 10% of the borrowing base then in effect at any time that the refinery asset borrowing base component is equal to $0 and (ii) $45.0 million (which amount is subject to certain increases) plus (b) the amount of FILO Loans outstanding, then we will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the Credit Agreement) of at least 1.0 to 1.0. As of December 31, 2023, the Company was in compliance with all covenants under the revolving credit facility.
Our existing indebtedness imposes, and any future indebtedness may impose, a number of covenants on us regarding collateral maintenance and insurance maintenance. As a result of these covenants and restrictions, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
Our ability to comply with the covenants and restrictions in our revolving credit facility, the MRL revolving credit agreement, our secured hedge agreements and the indentures governing our senior notes may be affected by events beyond our control.
If market or other economic conditions deteriorate, our ability to comply with these covenants and restrictions may be impaired. A failure to comply with the covenants, ratios or tests in our revolving credit facility, the MRL revolving credit agreement, our secured hedge agreements, the indentures governing our senior notes or any future indebtedness could result in an event of default under our revolving credit facility, the MRL revolving credit agreement, our secured hedge agreements, the indentures governing our senior notes or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. Among other things, in the event of any default on our indebtedness, our debt holders and lenders:
● will not be required to lend any additional amounts to us;
● could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;
● could elect to require that all obligations accrue interest at the default rate, if such rate has not already been imposed;
● may have the ability to require us to apply all of our available cash to repay these borrowings;
● may prevent us from making debt service payments under our other agreements, any of which could result in an event of default under our notes; or
● in the event of a default by Calumet or its restricted subsidiaries, could foreclose on the collateral pledged pursuant to the terms of the revolving credit facility or the indenture and security documents governing the 2024 Secured Notes, respectively, or in the event of a default by Montana Renewables Holdings or MRL, could foreclose on the accounts receivables and open blenders tax credit refunds securing the MRL revolving credit agreement.
If our existing indebtedness were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. Even if new financing were available, it may be on terms that are less attractive to us than our then existing credit facilities or it may not be on terms that are acceptable to us. In addition, our obligations under our revolving credit facility are secured by a first priority lien on our accounts receivable, inventory and substantially all of our cash; the obligations under the MRL revolving credit agreement are secured by accounts receivables and open blenders tax credit refunds; our obligations under our secured hedge agreements and the BP Purchase Agreement are secured by a lien on certain of our real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the forgoing (including proceeds of hedge agreements); and the 2024 Secured Notes are secured by a first-priority lien on all of the fixed assets that secure our obligations under our secured hedge agreements, and if we are unable to repay our indebtedness under the revolving credit facility, the MRL revolving credit agreement, the 2024 Secured Notes or satisfy the payment obligations under our secured hedge agreements or the payment obligations under the BP Purchase Agreement or obtain waivers of such defaults, then the lenders under our revolving credit facility and under the MRL revolving credit agreement, the counterparties to such agreements, and the holders of the 2024 Secured Notes could seek to foreclose on these assets. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Debt and Credit Facilities,” “- Short-Term Liquidity,” “- Long-Term Financing” and “- Master Derivative Contracts and Collateral Trust Agreement” for additional information regarding our long-term debt.
An increase in interest rates will cause our debt service obligations to increase.
Borrowings under both our revolving credit facility and the MRL revolving credit agreement bear interest at a rate based on the daily Secured Overnight Financing Rate (“SOFR”). As of December 31, 2023, we had $136.7 million outstanding borrowings under our revolving credit facility, $29.9 million in standby letters of credit were issued under our revolving credit facility, and $13.0 million of outstanding borrowings under the MRL revolving credit agreement. The foregoing interest rates are subject to adjustment based on fluctuations in daily SOFR or the prime rate, as applicable. An increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations. In addition, an increase in interest rates could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.
A change of control could result in us facing substantial repayment obligations under our revolving credit facility, our senior notes, our secured hedge agreements, our Supply and Offtake Agreements, the MRL revolving credit agreement, MRL’s financing arrangements with Stonebriar, and MRL’s term loan credit agreement with I Squared Capital.
There is no restriction in our partnership agreement on the ability of our general partner to enter into a transaction which would trigger the change of control provisions of our revolving credit facility agreement, the indentures governing our senior notes, our Collateral Trust Agreement, our Supply and Offtake Agreements, the MRL revolving credit agreement, MRL’s financing arrangements with Stonebriar, and MRL’s term loan credit agreement with I Squared Capital. Certain events relating to a change of control of our general partner, our partnership and our operating subsidiaries would constitute an event of default under our revolving credit facility, our Collateral Trust Agreement and our Supply and Offtake Agreements. In addition, an event of default under our revolving credit facility would likely constitute an event of default under the indentures governing our senior notes, our master derivatives contracts and the BP Purchase Agreement. As a result, upon a change of control event, we may be required to immediately repay the outstanding principal, any accrued interest on and any other amounts owed by us under our revolving credit facility, the senior notes and Supply and Offtake Agreements and the outstanding payment obligations under our master derivatives contracts and the BP Purchase Agreement. In addition, if a change of control event occurs under the MRL revolving credit agreement, MRL may be required to immediately repay the outstanding principal, any accrued interest on and any other amounts owed by MRL under the MRL revolving credit agreement. The source of funds for these repayments would be our available cash or cash generated from other sources and there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness and other payment obligations in full.
In addition, our obligations under our revolving credit facility are secured by a first-priority lien on our accounts receivable, inventory and substantially all of our cash; the obligations under the MRL revolving credit agreement are
secured by accounts receivables and open blenders tax credit refunds; our 2024 Secured Notes are secured by a first-priority lien on all of the fixed assets that secure our obligations under our secured hedge agreements; and our obligations under our master derivatives contracts and the BP Purchase Agreement are secured by a first-priority lien on our and our subsidiaries’ real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the forgoing (including proceeds of hedge agreements). If we are unable to repay our indebtedness under the revolving credit facility, the 2024 Secured Notes, or satisfy the payment obligations under our master derivative contracts or the payment obligations under the BP Purchase Agreement or obtain waivers of such defaults, then the lenders under our revolving credit facility, the holders of our 2024 Secured Notes, the derivative counterparties under our master derivative contracts and BP, respectively, would have the right to foreclose on those assets, which would have a material adverse effect on us. Additionally, if we are unable to repay our indebtedness under the MRL revolving credit agreement, the lenders thereunder would have the right to foreclose on the accounts receivables and open blenders tax credit refunds securing that facility.
Capital Projects and Future Growth
We make capital expenditures in our facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, results of operations or cash flows could be adversely affected.
Delays or cost increases related to the engineering, procurement and construction of new facilities, or improvements and repairs to our existing facilities and equipment, could have a material adverse effect on our business, financial condition, results of operations or our ability to make payments on our debt obligations. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:
● denial or delay in obtaining regulatory approvals and/or permits;
● changes in government regulations, including environmental and safety regulations;
● unplanned increases in the cost of equipment, materials or labor;
● disruptions in transportation of equipment and materials;
● severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of our vendors and suppliers;
● shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
● market-related increases in a project’s debt or equity financing costs; and/or
● nonperformance or declarations of force majeure by, or disputes with, our vendors, suppliers, contractors or sub-contractors.
Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency.
Any one or more of these occurrences noted above could have a significant impact on our business or subject us to significant cost overruns. If we were unable to make up the delays or to recover the related costs, or if market conditions change, we may not realize the anticipated benefits of our capital projects and it could materially and adversely affect our financial position, results of operations or cash flows and, as a result, our ability to make payments of our debt obligations.
From time to time, we may seek to divest portions of our business, which could materially affect our results of operations and result in disruption to other parts of the business.
We may dispose of portions of our current business or assets, based on a variety of factors and strategic considerations, consistent with our strategy of preserving liquidity and streamlining our business to better focus on the advancement of our core business. We expect that any potential divestitures of assets will also provide us with cash to reinvest in our business and repay indebtedness. These dispositions, together with any other future dispositions we make, may involve risks and uncertainties, including disruption to other parts of our business, potential loss of employees, customers or revenue, exposure to unanticipated liabilities or result in ongoing obligations and liabilities to us following any such divestiture. In addition, any such divestitures may not yield the targeted improvements in our business. Any of the foregoing could adversely affect our financial condition and results of operations or cash flows and, as a result, our ability to make payments of our debt obligations.
Environmental and Regulatory Matters
We may incur significant environmental remediation costs and liabilities in the operation of our refineries, facilities, terminals and related facilities.
The operation of our refineries, blending and packaging sites, terminals, and related facilities subject us to the risk of incurring significant environmental remediation costs and liabilities due to our handling of petroleum hydrocarbons and wastes or hazardous substances or wastes, because of air emissions and water discharges related to our operations and activities, and as a result of historical operations and waste disposal practices at our facilities or in connection with our activities, some of which may have been conducted by prior owners or operators. We could incur significant remedial costs in the cleanup of any petroleum hydrocarbons or wastes or hazardous substances or wastes that may have been released on, under or from the properties owned or operated by us. While we believe we have adequately reserved for these possibilities, such costs and liabilities are difficult to predict and could exceed the amount reserved.
Some environmental laws may impose joint and several, strict liability for releases of petroleum hydrocarbons and wastes or hazardous substances or wastes, which means in some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Private parties, including the owners of properties adjacent to our operations and facilities where our petroleum hydrocarbons or wastes or hazardous substances or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. We may not be able to recover some or any of these costs from insurance or other sources of indemnity. To the extent that the costs associated with meeting any or all of these requirements are significant and not adequately secured or indemnified for, there could be a material adverse effect on our business, financial condition and results of operations or cash flows and, as a result, our ability to make payments of our debt obligations.
We are subject to operational compliance with stringent environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.
Our refining, blending and packaging site, terminal and related facility operations are subject to stringent federal, regional, state and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose legal requirements that are applicable to our operations, including the obligation to obtain permits to conduct regulated activities, the incurrence of significant capital expenditures for air pollution control equipment to limit or prevent releases of pollutants from our facilities, the expenditure of significant monies in the application of specific health and safety criteria addressing worker protection, the requirement to maintain information about hazardous materials used or produced in our operations and to provide this information to required parties, and the incurrence of significant costs and liabilities for pollution resulting from our operations or from those of prior owners or operators of our facilities. Numerous federal and state governmental authorities, such as the U.S. EPA, OSHA and the Louisiana Department of Environmental Quality (“LDEQ”), have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring challenging and costly actions. From time to time, we receive notices of violation, other enforcement proceedings and regulatory inquiries
from governmental agencies alleging non-compliance with applicable environmental and occupational health and safety laws and regulations. Failure to comply with such laws and regulations as well as any issued permits and orders may result in the assessment of administrative, civil, and criminal sanctions, including monetary penalties, the imposition of remedial or corrective action obligations or the incurrence of capital expenditures, the occurrence of delays or cancellations in the permitting, development or expansion of projects, litigation, and the issuance of injunctions limiting or preventing some or all of our operations.
New worker safety and environmental laws and regulations, revised interpretations of such existing laws and regulations, increased governmental enforcement or other developments could require us to make additional, unforeseen expenditures. The adoption of more stringent environmental laws or regulations could impact us by requiring installation of new emission controls on some of our equipment, resulting in longer permitting timelines, and significantly increasing our capital expenditures and operating costs, which could adversely impact our business, cash flows and results of operation. Please read Items 1 and 2 “Business and Properties - Environmental and Occupational Health and Safety Matters” for additional information.
The availability and cost of renewable identification numbers and results of litigation related to our SRE petitions could have a material adverse effect on our results of operations and financial condition and our ability to make payments on our debt obligations.
Under the RFS provisions of the Clean Air Act, the EPA sets or adjusts volume mandates for the percentages of four compliance categories-cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel-to be blended into gasoline and diesel produced or imported during each calendar year. Most recently, the EPA has established these volume mandates for RFS program years 2023, 2024 and 2025 under final rules published in June 2023. We, and other refiners subject to RFS requirements, may meet those requirements by blending the necessary volumes of renewable transportation fuels into our production. To the extent that refiners cannot blend renewable fuels in the quantities required, those refiners may purchase renewable credits, referred to as RINs, which are created by blending done by others.
Our Shreveport and Great Falls refineries are normally subject to compliance with the RFS volume mandates. Our annual RINs Obligation, which includes RINs that are required to be secured through either our own blending or through the purchase of RINs in the open market, is approximately 65 million RINs across the four compliance categories. However, the EPA granted certain of our refineries the small refinery exemption (“SRE”) provided by the RFS in past years including, most recently, for the 2018 program year. Refineries that receive a SRE are not subject to the RFS renewable blending requirements for the corresponding calendar year. We have submitted SRE petitions for our Shreveport and Great Falls refineries for program years 2018, 2019, 2020, 2021, 2022 and 2023. All of these SRE petitions are in various stages of litigation. For 2018, EPA granted our SREs then later reversed (along with other SRE petitions from other small refineries) under a “blanket denial” issued in April 2022. The blanket denial included an alternate compliance approach under which the refineries, in essence, were deemed to have met their 2018 compliance obligations without tendering additional RINs. EPA’s 2018 alternate compliance approach is being challenged by Growth Energy, which in turn caused us to appeal the 2018 blanket denial. For 2019 and 2020 our SRE petitions were subject to a separate “blanket denial” in June 2022 (along with all other SRE petitions from all small refineries for those years) which we have appealed. For 2021 and 2022 our petitions were denied in July 2023 on the same grounds that EPA applied to our 2019 and 2020 petitions which we have appealed. For 2023 the EPA has not yet acted on our SRE petitions.
Status of Appeals. The U.S. Court of Appeals for the Fifth Circuit in November 2023 found venue to properly reside in the regional circuit and vacated EPA’s denial of Shreveport refinery’s 2018, 2019 and 2020 SRE petitions on the basis that EPA’s actions were impermissibly retroactive and arbitrary and capricious and remanded the decision to EPA. Shreveport refinery’s 2021 and 2022 compliance obligations were stayed on September 14, 2023 while that appeal is pending. The D.C. Circuit granted a stay relating to the Montana refinery’s 2018, 2019 and 2020 compliance obligations in March 2023, and a stay of the 2021 and 2022 obligations on October 23, 2023, indicating that the Montana refinery is likely to be successful on the merits of its appeals which are pending.
We cannot predict the final outcome of these matters or whether they may result in increased RFS program compliance costs. Moreover, the price of RINs remains subject to extreme volatility, with the potential for significant increases in price driven by political decisions rather than fundamentals. There also continues to be a shortage of advanced biofuel
production resulting in increased difficulties meeting the original RFS program mandates. Our refineries produce a higher ratio of diesel than national averages, and since ethanol cannot be blended into diesel we therefore have a more difficult “compliance pathway” than average. The inability to receive an exemption under the RFS program for one or more of our refineries; any increase in the final minimum volumes of renewable fuels that must be blended with refined petroleum fuels; and/or any increase in the cost to acquire RINs may, individually or in the aggregate, have the potential to result in significant costs in connection with RIN compliance, which costs could be material.
Refer to Note 2 - “Summary of Significant Accounting Policies” under Part II, Item 8 “Financial Statements - Notes to Consolidated Financial Statements” for further information. Our involvement in such litigation may strain our resources, increase our costs and distract management, even if we are successful at certain stages. As long as the final outcome of our SRE petitions remains uncertain, we expect to carry a RINs liability on our consolidated balance sheets and any changes to such liability will be recognized as a charge or credit to net income (loss). As a result of such charges, investors may have a negative outlook on our financial position regardless of the actual impact these charges have on our business. In addition, on January 27, 2022, EPA extended the compliance reporting deadlines and attestation engagement reporting deadlines for program years 2019, 2020 and 2021, calculated based on the future effective dates of other EPA RFS rulemakings. Nonetheless, we may in the future become subject to civil penalties if we are not in compliance with the RFS by such extended compliance deadlines.
Our and our customers’ operations are subject to risks arising out of the threat of climate change, including regulatory, political, litigation and financial risks, which could result in increased operating and capital costs for our customers and reduced demand for the products and services we provide.
The threat of climate change continues to attract considerable attention in the United States and foreign countries. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs as well as to eliminate such future emissions. As a result, our operations and potentially the operations of our customers are subject to a series of regulatory, political, physical, litigation and financial risks associated with the production and processing of fossil fuels and emissions of GHGs. Please see Items 1 and 2 “Business and Properties - Environmental and Occupational Health and Safety Matters” for more discussion on the threat of climate change and restriction of GHG emissions.
The adoption and implementation of any international, federal, regional or state executive actions, legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions or put a price on GHG emissions could result in increased compliance costs, additional operating restrictions or reduced demand for some of our services and products. Additionally, regulators in Europe and the U.S. have also focused efforts on increased disclosure related to climate change and mitigation efforts, which may significantly increase compliance burdens and associated regulatory costs and complexity. Further, increasing concentrations of GHGs in the Earth’s atmosphere may produce climatic changes that have significant physical effects, such as increased frequency and severity of storms, floods, wildfires and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations or the operations of our suppliers and customers and result in more frequent and severe disruptions to our business and those of our suppliers and customers, increased costs to repair damaged facilities or maintain or resume operations, and increased insurance costs. Increasing attention to the risks of climate change has also resulted in an increased possibility of lawsuits or investigations brought by public and private entities against companies in the oil and natural gas sector in connection with their greenhouse gas emissions. While we do not produce oil or natural gas, if we were to be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contributions to the asserted damage, or to mitigating factors.
There are also increasing financial risks if stockholders and bondholders concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Additionally, the lending and investment practices of institutional lenders have been the subject of intensive lobbying efforts in recent years pressuring such lenders to not to provide funding for oil and natural gas producers. While we do not produce oil or natural gas, such developments could affect our cost and access to capital. Similarly, political, physical, financial and litigation risks may result in certain companies engaged in the oil and natural gas production business restricting, delaying or canceling production activities, incurring liability for infrastructure damages as a result of climatic
changes, or impairing the ability to continue to operate in an economic manner, which also could reduce demand for our products and services.
The occurrence of one or more of these developments could have a material adverse effect on our business, financial condition, results of operations and cash flows. Moreover, the increased competitiveness of alternative energy sources (such as wind, solar, geothermal and tidal), as well as any regulatory or other incentives to conserve energy, could reduce demand for hydrocarbons and therefore for our products, which could lead to a reduction in our revenues and cash flow available for payments on our debt obligations. For example, the Inflation Reduction Act of 2022 contains tax inducements and other provisions that incentivize investment, development, and deployment of alternative energy sources and technologies.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with occupational, environmental and other laws and regulations.
Our operations require numerous permits and authorizations under various occupational, environmental and other laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or the health or safety of workers. New policy objectives and regulatory initiatives pursued under the Biden Administration as well as changes in leadership or priorities at the state level may result in more stringent conditions with respect to the acquisition of these authorizations and permits. Additionally, a violation of an authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or facility shutdowns. Any or all of these matters could have a negative effect on our business, results of operations and cash flow available for payments on our debt obligations.
Subsidiaries
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets and our ability to resume distributions to our unitholders and make payments of our debt obligations depends on the performance of our subsidiaries and their ability to distribute funds to us.
We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the equity interests in our subsidiaries. As a result, our ability to make payments of debt obligations depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us is restricted by our revolving credit facility and the indentures governing our senior notes and may be restricted by, among other things, applicable state laws and other laws and regulations. If we are unable to obtain the funds necessary to distribute cash to our unitholders or make payments of debt obligations, we may be required to adopt one or more alternatives, such as a refinancing our indebtedness or incurring borrowings under our revolving credit facility. We cannot assure unitholders that we would be able to refinance our indebtedness or that the terms on which we could refinance our indebtedness would be favorable.
Risks Related to Montana Renewables
If there is not sufficient demand for renewable energy, if renewable energy projects do not develop or take longer to develop than we anticipate, or if we do not realize the expected SAF premium, we may be unable to achieve our investment objectives for MRL, which could have a material adverse impact on our results of operations and financial condition.
If demand for renewable energy fails to grow sufficiently, we may be unable to achieve our business objectives for MRL. Many factors will influence the widespread adoption of renewable energy and demand for renewable energy projects, including:
● cost-effectiveness of renewable energy technologies as compared with conventional and competitive technologies;
● performance and reliability of renewable energy products as compared with conventional and non-renewable products;
● fluctuations in economic and market conditions that impact the viability of conventional and competitive alternative energy sources;
● increases or decreases in the prices of oil, coal and natural gas; and
● availability or effectiveness of government subsidies and incentives.
We also face the risks that SAF cannot generate the premium we currently expect, that a market for SAF does not evolve as expected and that alternate technologies supersede the expected demand for SAF. Any of these factors may preclude us from achieving our investment objectives for MRL and, by extension, could have a material adverse impact on our results of operations and financial condition.
Montana Renewables is subject to numerous operating risks, which could materially adversely impact our results of operations and financial conditions.
Montana Renewables was formed in 2021 and has a limited operating history, as Montana Renewables has only been producing renewable fuels since December 2022. The Company is experienced in operating facilities, such as the Montana Renewables facility, and expects to continue to leverage the Company’s operating experience, as well as its experience in selling and distributing renewable fuels.
As with any facilities of similar size and nature, the operations of Montana Renewables could be affected by many factors, including start-up problems, the breakdown or failure of equipment or processes, the performance of Montana Renewables below expected levels of output or efficiency, renewable feedstock or utility supply disruptions, environmental proceedings or other litigation that compel cessation of all or a portion of the operations, cyber-security considerations, increased stringent environmental operating, storage and transportation regulations, and/or, labor disputes. Additionally, the operations of Montana Renewables could be affected by both natural or man-made catastrophic events beyond our control, such as fires, earthquakes, floods, severe storms, extreme temperatures, explosions, major accidents, armed conflict, hostilities, acts of terrorism, health emergencies, cyber and physical attacks and/or similar events.
The occurrence of such events could significantly reduce or eliminate revenues generated by Montana Renewables and significantly increase the expenses of Montana Renewables, thereby jeopardizing the ability of Montana Renewables to generate revenues sufficient to pay its outstanding debt obligations. While MRHL will maintain insurance to protect against certain of these operating risks, the proceeds of such insurance may not be adequate to cover Montana Renewable’s lost revenues or increased costs. Under such circumstances, no assurance can be given concerning the ability of Montana Renewables to generate sufficient revenues to make timely payments of its debt obligations.
MRHL may also face civil liabilities or fines in the ordinary course of its business as a result of damages to third parties. These liabilities may result in MRHL making indemnification payments in accordance with applicable laws to the extent and in the amount that such indemnification payments are not covered by MRHL’s insurance policies.
MRHL may be unable to attract and retain qualified managers and skilled employees to operate Montana Renewable facilities efficiently which could adversely affect the operations, cash flows and liquidity of Montana Renewables. The renewable fuels business requires a highly specialized workforce, and accordingly, it can be difficult to find qualified and affordable personnel. Additionally, labor expenses may increase as a result of a shortage in the supply of skilled personnel and MRHL may be forced to incur significant training expenses if unable to hire employees with the requisite skills.
Substantially all operating personnel at Montana Renewables are employed under a collective bargaining agreement. If MRHL is unable to renegotiate this agreement as it expires, any work stoppages or other labor disturbances could have an adverse effect on the operations of Montana Renewables and MRHL’s ability to pay outstanding debt obligations.
During the start-up of operation, new facilities like Montana Renewables could be susceptible to operational failures which may result in temporary maintenance shutdowns. Although the initial commissioning of the facility was successful, any significant curtailing of production at Montana Renewables may result in materially lower levels of revenues or cash flows and materially increased expenses for the duration of any downtime and may materially adversely impact the Company’s results of operations, financial conditions and ability to pay the principal of, redemption premium, if any, and/or interest on outstanding debt obligations.
Montana Renewables is subject to a number of statutes and regulations that could have an adverse effect on Montana Renewables’ operations.
We are required to comply with a number of statutes and regulations relating to the environment and the safety and health of our employees and the public during the operation of our Montana Renewables facility, such as: limits on noise emissions from the Montana Renewables facility; safety and health standards, practices and procedures applicable to the operation of the Montana Renewables facility; environmental protection requirements, including standards and limits relating to the discharge of pollutants and waste to the air, water and land; and employment, hiring and anti-discrimination requirements relating to the operation of the Montana Renewables facility.
Federal, state, and local laws and regulations protecting the environment require us to obtain permits and other authorizations to operate the Montana Renewables facility. Changes in such laws could materially and adversely affect our costs. Permits that have been obtained or will be obtained may be subject to challenge in public proceedings, including the filing of administrative or judicial appeals contesting the validity or the terms of the permits. If such permits are challenged, the operation of the Montana Renewables facility may be delayed or prohibited, and elements of our Montana Renewables facility may need to be removed, redesigned or replaced.
All permits and approvals issued by governmental agencies expire and must be renewed if the permitted activity is not complete. Renewals of operating permits require ongoing compliance and may result in new requirements being imposed by governmental agencies. There is no assurance that required renewals will be obtained when required to continue operation or that the Montana Renewables facility will be able to satisfy the requirements for renewal or continued operation. The inability to maintain required permits in force and effect, and their amendment, suspension or revocation would have adverse effects on the Montana Renewables facility’s operations and our financial performance.
A significant component of our product margin consists of a variety of government subsidies and incentives, and any changes in law that eliminate or reduce these subsidies and incentives would have a material adverse impact on our results of operations and financial condition.
As with many producers, our margins are supported by federal, state and provincial government programs that incentivize the production, blending and use of renewable and low-carbon fuels. While the general trend over time has been for these programs to expand both in number and scope, such continued growth is not guaranteed and is subject to potential changes in political and public support. For example, since the enactment of the U.S. blender’s tax credit (Section 40A of the IRC) in 2004 with specified sunset dates, there have been several occasions where the renewal and extension of the credit has been in doubt, only for it to be renewed and extended close to (and in some cases, after) expiration. Many factors affect political and public support, which cannot be fully evaluated or predicted at this time.
In addition, programs that enjoy political and public support may nonetheless evolve over time in ways that may limit opportunities for our renewable transportation fuel. For example, in September 2020, California Governor Gavin Newsom issued Executive Order N-79-20, establishing goals of 100% of new passenger vehicle sales in-state to be zero-emission by 2035, and all heavy-duty truck sales to be zero-emission by 2045. The order further directs the California Air Resources Board to develop regulations to achieve these goals. While the precise nature of future regulations cannot be predicted, it is possible that incentives for renewable fuel products may be scaled back or more stringent emission reduction standards may be adopted to facilitate the transition to zero-emission vehicles. These and similar initiatives reflect an ever evolving legal and regulatory landscape, which introduces uncertainty in evaluating future governmental support for our products.
Certain regulatory programs feature a periodic update process. The U.S. Renewable Fuel Standard program, for example, has historically required EPA to set RVOs each year, in light of volumes of four categories of renewable fuels
established by Congress in the Clean Air Act. More recently, EPA promulgated regulations setting RVOs for a three-year period (2023, 2024 and 2025). The periodic update process featured in the RFS and similar programs nonetheless introduces a degree of uncertainty in demand for our products on a yearly basis.
Transactions between the Company and MRL present possible conflicts of interest that could have an adverse effect on the Company if they are not managed appropriately.
MRHL has no assets other than its equity interests in MRL. Several of the Company’s affiliates have been or are expected to be involved with the operation of Montana Renewables, including the sales and marketing of the renewable fuels produced by Montana Renewables. The support and experience of the Company’s affiliates are expected to be important to the success of Montana Renewables. However, no affiliates of the Company are obligated to make any payments with respect to outstanding debt obligations of MRHL or MRL and any such transactions between the Company and MRHL or MRL present possible conflicts of interest that could have an adverse effect on the Company if they are not managed appropriately.
Montana Renewables depends on the Company to provide MRL with services necessary to operate its business. If the Company were unable or unwilling to provide these services, it would result in a disruption in MRL’s business that could have an adverse effect on its financial position, financial results and cash flow.
MRL does not directly employ directors, officers or employees. Pursuant to the master services agreement (the “MSA”) with a wholly-owned subsidiary of the Company, all of MRL’s executive management personnel are employees of our general partner, and MRL uses a significant number of the Company’s employees to operate the Montana Renewables facility and provide MRL with general and administrative services as well as services related to information technology, cybersecurity and data privacy. The failure of the Company to provide accurate and timely service may adversely impact MRL’s business operations. In addition, if the Company were to become unable or unwilling to provide such services, MRL would need to develop these services internally or arrange for the services from another service provider, which may not be possible and which could take time and cause MRL to experience significant interruptions or incur additional costs. Developing the capabilities internally or by retaining another service provider could have an adverse effect on MRL’s business, and the services, when developed or retained, may not be of the same quality as provided to us by the Company. For example, if MRL is not able to obtain adequate information technology and cybersecurity services, MRL may be at a higher risk for cyberattacks and other interruptions or failures. Additionally, if the MSA were to terminate, MRL would lose its key personnel.
Increases to the cost of transportation services or equipment related to our feedstock materials and renewable transportation fuels could materially and adversely affect our sales revenues and cost of operations.
We rely on railroad and trucking companies to transport renewable feedstock materials to the Montana Renewables facility, and to deliver renewable transportation fuels to our customers. These transportation services are subject to various hazards, including extreme weather conditions, floods, droughts, work stoppages, delays, accidents such as spills and derailments and other accidents and other operating hazards. Increasing climate risk may exacerbate weather conditions so as to materially affect the economics of traditional transportation methods. These transportation operations, equipment and services are also subject to environmental, safety, and regulatory oversight. Due to concerns related to accidents, local and national governments could implement new regulations affecting the transportation of our renewable feedstock materials or renewable transportation fuels. We may be unable to ship the renewable transportation fuels or obtain renewable feedstock materials as a result of these transportation companies’ failure to operate properly, or if new and more stringent regulatory requirements are implemented affecting transportation operations or equipment. If there are significant increases in the cost of such transportation services or equipment, or changes in such costs relative to transportation costs incurred by competitors, our sales revenues and/or cost of operations could be materially and adversely affected.
Montana Renewable’s operations are dependent on the use of intellectual property licensed to MRL by third parties, and if MRL fails to comply with our obligations under such license agreements, we may be required to pay damages, and we could lose license rights that are critical to our business.
Montana Renewable’s operations are dependent upon the use of intellectual property licensed to us by third parties, and in the future, MRL may enter into additional agreements for certain other intellectual property or technologies. If MRL fails to comply with terms of its license agreements related to such intellectual property or other technologies, the applicable licensor may have the right to terminate its license or MRL may be required to pay damages. Termination by the licensor may cause MRL to lose valuable rights and could prevent MRL from operating the Montana Renewables facility or otherwise operating its business. Our business may suffer if any current or future licenses terminate, if the licensors fail to abide by the terms of the license, if the licensors fail to enforce licensed patents against infringing third parties, if the licensed intellectual property rights are found to be invalid or unenforceable, or if we are unable to enter into necessary licenses on acceptable terms. In addition, our rights to the licensed intellectual property are licensed to us on a non-exclusive basis. The owners of these non-exclusively licensed technologies are therefore free to license them to third parties, including our competitors, on terms that may be superior to those offered to us, which could place us at a competitive disadvantage. Moreover, our licensors may own or control intellectual property that has not been licensed to us and, as a result, we may be subject to claims, regardless of their merit, that we are infringing, misappropriating or otherwise violating the licensor’s rights. In addition, the agreements under which we license intellectual property or technology from third parties are generally complex, and certain provisions in such agreements may be susceptible to multiple interpretations. The resolution of any contract interpretation disagreement that may arise could narrow what we believe to be the scope of our rights to the relevant licensed intellectual property or technology or increase what we believe to be our financial or other obligations under the relevant agreement. Failure to obtain, maintain or renew these licenses, along with any of the foregoing, could have a material adverse effect on our ability to operate the Montana Renewables facility.
The production of renewable fuels is a growing industry and we are expected to encounter significant competition in the marketplace.
The production of renewable fuels is a growing industry and we are expected to encounter significant competition in the marketplace. Emerging trends that develop as industry production of renewable fuels increases may adversely affect our business, financial condition, results of operations and prospects. We have encountered and will continue to encounter risks and difficulties frequently experienced by growing companies in rapidly changing industries, including unpredictable and volatile revenues and increased expenses as our business continues to grow. In addition, new technologies or methods of operation may be developed that improve the quality of the fuel, increase production, or decrease the costs of production.
Risks Related to the Corporate Conversion
The Corporate Conversion is subject to conditions, including some conditions that may not be satisfied on a timely basis, if at all. Failure to complete the Corporate Conversion, or significant delays in completing the Corporate Conversion, could negatively affect our business and financial results and the price of our common units or, following the consummation of the Corporate Conversion, future business and financial results and the price of the common stock.
The consummation of the Corporate Conversion is subject to a number of conditions. The consummation of the Corporate Conversion is not assured and is subject to risks, including the risk that the unitholder approval of the transaction is not obtained. Further, the Corporate Conversion may not be consummated even if such unitholder approval is obtained. The Restructuring Agreement contains conditions, some of which are beyond the parties’ control, that, if not satisfied or waived, may prevent, delay or otherwise result in the Corporate Conversion not being consummated.
If the Corporate Conversion is not completed, or if there are significant delays in completing the Corporate Conversion, our future business and financial results and the trading price of our common units could be negatively affected or, following the consummation of the Corporation Reorganization, our future business and financial results and the price of the common stock could be negatively affected, and the parties will be subject to several risks, including the following (i) there may be negative reactions from the financial markets due to the fact that the current price of the common
units may reflect a market assumption that the Corporate Conversion will be completed and (ii) the attention of management will have been diverted to the Corporate Conversion rather than our own operations and pursuit of other opportunities that could have been beneficial to our business.
Risks Related to Our Partnership Structure
Cash Distributions to Unitholders
We may not have sufficient cash from operations, following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to resume paying distributions to our unitholders or restore distributions to previous levels.
In April 2016, we announced suspension of our quarterly cash distribution to unitholders and have not paid any quarterly distributions since. We may not have sufficient available cash from operations in the future to enable us to resume payment of a distribution to unitholders. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
● overall demand for specialty products;
● the level of foreign and domestic production of crude oil and refined products;
● our ability to produce fuel products and specialty products that meet our customers’ unique and precise specifications;
● the marketing of alternative and competing products;
● the extent of government regulation;
● results of our hedging activities;
● global or national health concerns; and
● overall economic and local market conditions.
In addition, the actual amount of cash we have available for distribution will depend on other factors, some of which are beyond our control, including:
● the level of capital expenditures we make, including those for acquisitions, if any;
● our debt service requirements;
● fluctuations in our working capital needs;
● our ability to borrow funds and access capital markets;
● restrictions on distributions and on our ability to make working capital borrowings for distributions contained in our debt instruments; and
● the amount of cash reserves established by our general partner for the proper conduct of our business.
If we generate insufficient cash from our operations for a sustained period of time and/or forecasts demonstrate expectations of continued future insufficiencies, the board of directors of our general partner may determine not to reinstate
our distribution to unitholders. Any such continued suspension or elimination of distributions may cause the trading price of our units to decline.
The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.
Unitholders should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow from operating activities, cash on hand and working capital borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses and may not make cash distributions during periods when we record net income.
General Partner, The Heritage Group and Partnership Agreement
At February 28, 2024, The Heritage Group and certain of their affiliates own an approximate 20.4% limited partner interest in us and own and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to other unitholders’ detriment.
At February 28, 2024, The Heritage Group and certain of their affiliates own an approximate 20.4% limited partner interest in us. In addition, The Heritage Group and certain of their affiliates control our general partner.
Conflicts of interest may arise between our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
● our general partner is allowed to take into account the interests of parties other than us, such as its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
● our general partner has limited its liability and reduced its fiduciary duties under our partnership agreement and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under Delaware law;
● our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to unitholders;
● our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
● our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or a capital expenditure for acquisitions or capital improvements, which does not. This determination can affect the amount of cash that is available for distribution to our unitholders;
● our general partner has the flexibility to cause us to enter into a broad variety of derivative transactions covering different time periods, the net cash receipts or payments from which will increase or decrease operating surplus and adjusted operating surplus, with the result that our general partner may be able to shift the recognition of operating surplus and adjusted operating surplus between periods to increase the distributions it and its affiliates receive on their incentive distribution rights; and
● in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.
The Heritage Group and certain of its affiliates may engage in limited competition with us.
Pursuant to the omnibus agreement we entered into in connection with our initial public offering, The Heritage Group and its controlled affiliates have agreed not to engage in, whether by acquisition or otherwise, the business of refining or marketing specialty lubricating oils, solvents and wax products as well as gasoline, diesel and jet fuel products in the continental U.S. for so long as it controls us. This restriction does not apply to certain assets and businesses which are more fully described under Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence - Omnibus Agreement.”
The owners of our general partner, other than The Heritage Group, are not prohibited from competing with us, except to the extent described above. Currently, The Heritage Group is an active marketer of asphalt products and has been engaged in this business for much longer than us. In certain geographical areas, there can be overlap where both The Heritage Group and we market asphalt.
Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
● permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of our partnership or amendment of our partnership agreement;
● provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
● generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
● provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal.
By purchasing a common unit, a unitholder agrees to be bound by the provisions in the partnership agreement, including the provisions discussed above.
Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders do not elect our general partner or its board of directors, and have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, the vote of
the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. At February 28, 2024, the owners of our general partner and certain of their affiliates own approximately 20.4% of our common units. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Our partnership agreement restricts the voting rights of those unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Our general partner interest or control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner from transferring their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby control the decisions taken by the board of directors.
We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs.
We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs. We can provide no assurance that our general partner will continue to provide us the officers and employees that are necessary for the conduct of our business nor that such provision will be on terms that are acceptable to us. If our general partner fails to provide us with adequate personnel, our operations could be adversely impacted and our cash available for payments of our debt obligations could be reduced.
We may issue additional common units without unitholder approval, which would dilute our current unitholders’ existing ownership interests.
We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of common units or equity securities ranking junior to the common units at any time. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units. The issuance of additional common units or other equity securities of equal or senior rank to the common units will have the following effects:
● our unitholders’ proportionate ownership interest in us may decrease;
● the amount of cash available for distribution on each unit may decrease;
● the relative voting strength of each previously outstanding unit may be diminished;
● the market price of the common units may decline; and
● the ratio of taxable income to distributions, if any may increase.
Our general partner’s determination of the level of cash reserves may reduce the amount of available cash for distribution to unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our partnership agreement also permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These reserves will affect the amount of cash available for distribution to unitholders.
Cost reimbursements due to our general partner and its affiliates will reduce cash available for payments of our debt obligations.
Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Any such reimbursement will be determined by our general partner and will reduce the cash available for payments of our debt obligations. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. Please read Part III, Item 13 “Certain Relationships and Related Transactions and Director Independence.”
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the issued and outstanding common units, our general partner will have the right, but not the obligation, which right it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units to our general partner, its affiliates or us at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their common units. At February 28, 2024, our general partner and its affiliates own approximately 20.4% of our common units.
Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Unitholders could be liable for any and all of our obligations as if they were a general partner if:
● a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
● unitholders’ right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, which we call the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser
of the units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as not being subject to a material amount of entity-level taxation by individual states or local entities. If the IRS were to treat us as a corporation or we became subject to a material amount of entity-level taxation for state or local tax purposes, our cash available to make payments of our debt obligations could be substantially reduced.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. We requested and obtained a favorable private letter ruling from the IRS to the effect that, based on facts presented in the private letter ruling request, our income from refining, blending, processing, packaging, marketing and distribution of lubricants will constitute “qualifying income” within the meaning of Section 7704 of the Code. Based upon our current operations and private letter rulings we have received with respect to certain aspects of our business, we believe we satisfy the qualifying income requirement. However, no ruling has been requested regarding our treatment as a partnership for U.S. Federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate. Because a tax would be imposed upon us as a corporation, our cash available for payment of our other debt obligations could be substantially reduced.
From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly-traded partnerships including the elimination of partnership tax treatment for certain publicly traded partnerships. The enactment of such a law or the modification or interpretation of an existing law could subject us to taxation as a corporation or otherwise subjects us to a material amount of entity-level taxation for federal, state or local income tax purposes. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. For example, we are required to pay the Texas Margin Tax each year at a maximum effective rate of 0.75% for our “margin,” as defined in the law, apportioned to Texas in the prior year. Imposition of these or similar types of federal and state taxes on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for payment of principal and interest on our senior notes and our other debt obligations.
Our tax treatment or the tax treatment of our unitholders could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. From time to time the U.S. government considers substantive changes to the existing federal income tax laws that affect publicly traded partnerships. We are unable to predict whether any such additional legislation or any other tax-related proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could materially adversely impact a unitholder’s investment in our common units.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders or to make payments of our debt obligations.
We have not requested a ruling from the IRS, and the IRS has not otherwise made any determination, regarding our status as a partnership for federal income tax purposes The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to attempt to sustain some or all of the positions we take, and a court may not ultimately agree with some or all of our positions. Any contest with the IRS may materially and
adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders as the costs will reduce our cash available for distribution and for payments of our debt obligations.
The IRS may challenge aspects of our proration method, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of Treasury and the IRS issued Treasury Regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of our common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
Our unitholders may be required to pay taxes on their share of our income even if they do not receive any distributions from us.
Our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no distributions from us. Our unitholders may not receive distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
We may engage in transactions to de-lever the Partnership and manage our liquidity that may result in income and gain to our unitholders. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, our unitholders may be allocated taxable income and gain resulting from the sale. The ultimate effect of any such allocations will depend on the unitholder’s individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences of potential transactions that may result in income and gain to unitholders.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of nonrecourse liabilities, if our unitholders sell their common units, they may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale of our units will generally be considered “effectively connected income.” As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Upon the sale, exchange or other disposition of a common unit by a foreign person, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have recently issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Distributions to foreign persons may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. The U.S. Department of the Treasury and the IRS have provided that these rules will generally not apply to transfers of, or distributions on, our common units occurring before January 1, 2023.
Our unitholders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.
In addition to federal income taxes, our unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders may be required to file tax returns and pay taxes in some or all of these various jurisdictions or be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in 32 states, most of which impose a personal income tax.
If the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders or to make payments of our debt obligations might be substantially reduced.
If the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be made, or applicable, in all circumstances. If we are unable to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the economic burden resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders and for payments of our debt obligations might be substantially reduced.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from lending their common units.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
We are not a party to, and our property is not the subject of, any pending legal proceedings other than ordinary routine litigation incidental to our business. Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. Please read Items 1 and 2 “Business and Properties - Environmental and Occupational Health and Safety Matters” for a description of our current regulatory matters related to the environment, health and safety. Additionally, the information provided under Note 6 - “Commitments and Contingencies” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” is incorporated herein by reference.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common units are quoted and traded on the Nasdaq Global Select Market (“Nasdaq”) under the symbol “CLMT.” As of February 28, 2024, there were approximately 23 unitholders of record of our common units. As of February 28, 2024, there were 80,223,093 common units outstanding.
Cash Distribution Policy
General. Within 45 days after the end of each quarter, we distribute our available cash (as defined in our partnership agreement), if any, to unitholders of record on the applicable record date.
Available Cash. Available cash generally means, for any quarter, all cash on hand at the end of the quarter:
● less the amount of cash reserves established by our general partner to:
● provide for the proper conduct of our business;
● comply with applicable law, any of our debt instruments or other agreements; and
● provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.
● plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
Cash Distribution Policy. We distribute to the holders of common units on a quarterly basis at least the minimum quarterly distribution of $0.45 per unit, or $1.80 in aggregate per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, since April 2016, we have not paid, and there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Please read “- Distribution Suspension.” Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under our debt instruments, including our Credit Agreement and the indentures governing our 2024 Secured Notes, 11.00% Senior Notes due 2025 (the “2025 Notes”), 8.125% Senior Notes due 2027 (the “2027 Notes”), and 9.75% Senior Notes due 2028 (the “2028 Notes”). Please read Note 8 - “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data” for a discussion of the restrictions in our debt instruments that restrict our ability to make distributions.
General Partner Interest and Incentive Distribution Rights. Our general partner is entitled to 2% of all quarterly distributions since inception that we make prior to our liquidation. As of February 28, 2024, this general partner interest is represented by 1,637,206 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of $0.495 per unit. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest, and assumes that
our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on units that it owns. Our general partner earned no incentive distribution rights for the years ended December 31, 2023 and 2022.
Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:
Total Quarterly
Distribution
Marginal Percentage
Target Amount
Interest in Distributions
Per Common Unit
Unitholders
General Partner
Minimum Quarterly Distribution
$0.45
%
%
First Target Distribution
up to $0.495
%
%
Second Target Distribution
above $0.495 up to $0.563
%
%
Third Target Distribution
above $0.563 up to $0.675
%
%
Thereafter
above $0.675
%
%
Distribution Suspension
In April 2016 and effective beginning the first quarter 2016, the board of directors of our general partner suspended payment of our quarterly cash distribution. We currently are not permitted to resume cash distributions pursuant to the terms of the indentures governing our senior notes.
Equity Compensation Plans
The equity compensation plan information required by Item 201(d) of Regulation S-K in response to this Item 5 is incorporated by reference from Part III, Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” of this Annual Report.
Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
None.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Reserved

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The historical consolidated financial statements included in this Annual Report reflect all of the assets, liabilities and results of operations of Calumet Specialty Products Partners, L.P. and its consolidated subsidiaries (“Calumet,” the “Company,” “we,” “our,” or “us”). The following discussion analyzes the financial condition and results of operations of the Company for the years ended December 31, 2023, 2022 and 2021. Unitholders should read the following discussion and analysis of the financial condition and results of operations of the Company in conjunction with the historical consolidated financial statements and notes included elsewhere in this Annual Report.
Overview
We manufacture, formulate and market a diversified slate of specialty branded products and renewable fuels to customers across a broad range of consumer-facing and industrial markets. We are headquartered in Indianapolis, Indiana and operate twelve facilities throughout North America.
Our operations are managed using the following reportable segments: Specialty Products and Solutions; Performance Brands; Montana/Renewables; and Corporate. For additional information, see Note 18 - “Segments and Related Information” under Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements.” In our Specialty Products and Solutions segment, we manufacture and market a wide variety of solvents, waxes, customized lubricating oils, white oils, petrolatums, gels, esters, and other products. Our specialty products are sold to domestic and international customers who purchase them primarily as raw material components for consumer-facing and industrial products. In our Performance Brands segment, we blend, package and market high performance products through our Royal Purple, Bel-Ray, and TruFuel brands. Our Montana/Renewables segment is comprised of two facilities - renewable fuels and specialty asphalt. At our Great Falls renewable fuels facility, we process a variety of geographically advantaged renewable feedstocks into renewable diesel, sustainable aviation fuel, renewable hydrogen, renewable natural gas, renewable propane, and renewable naphtha that are distributed into renewable markets in the western half of North America. At our Montana specialty asphalt facility, we process Canadian crude oil into conventional gasoline, diesel, jet fuel and specialty grades of asphalt, with production sized to serve local markets. Our Corporate segment primarily consists of general and administrative expenses not allocated to the Specialty Products and Solutions, Performance Brands or Montana/Renewables segments.
Restatement of Previously Issued Financial Statements:
We have restated our previously issued financial statements contained in this Annual Report on Form 10-K. Refer to the “Explanatory Note” preceding Items 1 and 2. Business and Properties, for background on the restatement, the fiscal periods impacted, control considerations, and other information. See Note 21 - “Restatement of Prior Period” and Note 22 - “Quarterly Financial Data (Unaudited)” under Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements,” for additional information related to the restatement, including descriptions of the misstatements and the impacts on our financial statements.
Recent Developments
Corporate Conversion
On November 9, 2023, we entered into a Partnership Restructuring Agreement (as amended, the “Restructuring Agreement”) with our general partner, The Heritage Group and the other owners of our general partner (the “Sponsor Parties”) to effectuate a corporate transition of the Company to Calumet, Inc., a newly formed Delaware corporation (“New Calumet”).
Pursuant to the Restructuring Agreement and the transaction documents to be entered into in connection therewith, at the closing of the transactions contemplated by the Restructuring Agreement (the “Corporate Conversion”), among other things:
●each common unit representing a limited partnership interest in the Company will be exchanged for one share of New Calumet’s common stock (“Common Stock”);
●all equity interests in our general partner (which currently owns all of our incentive distribution rights and our 2.0% General Partner interest in the Company) will be exchanged for 5.5 million shares of Common Stock and warrants to purchase 2.0 million shares of Common Stock, each exercisable for one share of Common Stock at an exercise price of $20.00 per share and expiring three years from the date of issuance, which shares and warrants will be issued to the owners of our general partner;
●as a result of the Corporate Conversion, our general partner will become a wholly owned subsidiary of New Calumet, and its incentive distribution rights and 2.0% General Partner interest will be cancelled, and the Company will become a wholly owned subsidiary of New Calumet; the New Calumet Common Stock will continue to trade on Nasdaq.
On February 9, 2024, we entered into the First Amendment to the Partnership Restructuring Agreement (the “Restructuring Agreement Amendment”) with our general partner and the Sponsor Parties. Pursuant to the Restructuring Agreement Amendment, as of the date of the closing of the Corporate Conversion (the “Closing”), New Calumet will be governed by a board of directors (the “New Calumet Board”) of 10 directors, classified into three classes. The initial directors of New Calumet will be appointed by The Heritage Group, together with its affiliates, related trusts, trustees, family members, successors and assigns (“THG”), and following the Closing, (i) for so long as THG owns at least 16.7% of the outstanding shares of New Calumet’s common stock, par value $0.01 per share (“Common Stock”), THG will have the right to nominate two directors; (ii) for so long as THG owns less than 16.7% but 5% or more of the outstanding shares of Common Stock, THG will have the right to nominate one director; and (iii) at such time as THG ceases to own at least 5% of the outstanding shares of Common Stock, THG will not have the right to nominate any directors. In addition, the Restructuring Agreement Amendment sets forth certain Partnership unitholder approvals that are conditions to the Closing and provides that our general partner will make an election to be taxed as an association taxable as a corporation for U.S. federal income tax purposes prior to the Closing.
On February 9, 2024, we entered into a Conversion Agreement (the “Conversion Agreement”) with New Calumet, Calumet Merger Sub I LLC, a wholly owned subsidiary of New Calumet, Calumet Merger Sub II LLC, a wholly owned subsidiary of New Calumet, our general partner and the Sponsor Parties to effectuate the Corporate Conversion.
The Board has unanimously approved the terms of the Conversion Agreement and the transactions contemplated thereby and has resolved to recommend that the Partnership’s unitholders approve the Conversion Agreement. The Board approved the Conversion Agreement following the recommendation and special approval of the Conflicts Committee.
The consummation of the Corporate Conversion is subject to certain customary conditions, including, among others: (i) approval of the Conversion Agreement and certain related matters specified in the Restructuring Agreement by the holders of a majority of our outstanding common units; (ii) the absence of any law or injunction prohibiting the consummation of the transactions contemplated by the Conversion Agreement; (iii) the effectiveness of a registration statement on Form S-4 to be filed by New Calumet with respect to the registration of the shares of Common Stock to be issued in the Corporate Conversion; (iv) approval for listing of the Common Stock on the Nasdaq Stock Market LLC; (v) expiration or termination of applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (vi) the election by our general partner to be taxed as an association taxable as a corporation for U.S. federal income tax purposes; (vii) subject to specified materiality standards, the accuracy of certain representations and warranties of the other party; and (viii) compliance by the other party in all material respects with its covenants.
The Conversion Agreement may be terminated: (i) by the mutual written consent of the Partnership and the Sponsor Parties; (ii) if, upon the conclusion of the meeting of our unitholders called to approve the Corporate Conversion, the required unitholder approvals have not been obtained; (iii) if the Closing has not occurred on or before August 7, 2024; or (iv) upon the occurrence of certain other events specified in the Conversion Agreement.
For additional information, please read our Current Reports on Form 8-K filed with the Securities and Exchange Commission on November 9, 2023 and February 12, 2024. Please also read Part I, Item 1A “Risk Factors - The Corporate Conversion is subject to conditions, including some conditions that may not be satisfied on a timely basis, if at all. Failure to complete the Corporate Conversion, or significant delays in completing the Corporate Conversion, could negatively affect our business and financial results and the price of our common units or, following the consummation of the Corporate Conversion, future business and financial results and the price of the common stock.”
Note Purchase Agreement
On February 23, 2024, we entered into a Note Purchase Agreement (the “Note Purchase Agreement”) with certain qualified institutional buyers and institutional accredited investors, pursuant to which we agreed to sell $200.0 million aggregate principal amount of a new series of our 9.25% Senior Secured First Lien Notes due 2029 (the “2029 Secured Notes”) in a private placement transaction in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act. The 2029 Secured Notes will mature on July 15, 2029 and will be issued at par. The closing of the issuance of the 2029 Secured Notes is expected to occur on March 7, 2024, subject to customary closing conditions.
We intend to use the net proceeds from the private placement of the 2029 Secured Notes, together with cash on hand, to redeem all of the outstanding 2024 Secured Notes and $50.0 million aggregate principal amount of the outstanding 2025 Notes.
2023 Update
Outlook and Trends
During the fourth quarter of 2023, our business continued to benefit from a healthy margin environment. Demand for our products remained healthy across most of the enterprise, and we expect margins to continue to remain strong. We believe low unemployment, stabilizing raw material and packaging costs, and lower than normal industry inventories point to a continuation of this trend. While the risk of recession and inflation continue to be monitored, our plants and the industry are expected to operate at high rates to meet market demand.
Our Specialty Products and Solutions segment continues to perform well. Market demand is relatively high compared to historical averages, and we continue to leverage the benefits of our fully integrated specialty business in this market. As expected, margins continued to slowly normalize relative to record highs experienced in the second half of 2022. Our Montana Renewables facility returned to normal operations in early December 2023 following the successful completion of the steam drum replacement and turnaround. During the months of August, September and October, the Montana Renewables facility operated at 50% utilization and the plant was in turnaround nearly the entire month of November. The market price of feedstocks has decreased dramatically, and the business consumed old feed from inventory, which is significantly more expensive than the current market, upon return to normal operations in December. Results in our Performance Brands segment continued to trend better versus the prior year as input and packaging costs have stabilized, price increases from previous periods have largely held, and industrial volume demand continues to grow.
As we have experienced in the past several years, our integrated business model and diversified product portfolio provides an advantaged response to changing market conditions. While we are not immune to the impacts of an economic downturn, we believe our specialty business is well positioned to withstand one.
Contingencies
For a summary of litigation and other contingencies, please read Note 6 - “Commitments and Contingencies” under Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements.” Based on information available to us at the present time, we do not believe that any liabilities beyond the amounts already accrued, which may result from these contingencies, will have a material adverse effect on our liquidity, financial condition or results of operations.
Financial Results
We reported net income of $48.1 million in 2023, versus a net loss of $173.3 million in 2022. We reported Adjusted EBITDA (as defined in Item 7 “Management’s Discussion and Analysis - Non-GAAP Financial Measures”) of $260.5 million in 2023, versus $390.0 million in 2022. We used cash from operating activities of $14.9 million in 2023, versus generating cash from operating activities of $100.6 million in 2022.
Please read Item 7 “Management’s Discussion and Analysis - Non-GAAP Financial Measures” for a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to Net income (loss), our most directly comparable financial performance measure calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”).
Specialty Products and Solutions segment Adjusted EBITDA was $251.2 million in 2023 compared to $379.4 million in the prior year. Compared to the prior year, Specialty Products and Solutions 2023 segment Adjusted EBITDA was unfavorably impacted by lower throughput volumes as a result of the planned turnarounds completed at our Cotton Valley, Shreveport and Princeton facilities during the current year coupled with the impact of unplanned outages as a result of the severe weather experienced in Northwest Louisiana during the current year. The specialties and fuels margin environments continue to slowly regress from record highs, but remain strong compared to historical averages and continue to benefit our business.
Montana/Renewables segment Adjusted EBITDA was $30.2 million in 2023 compared to $75.8 million in 2022. Compared to the prior year, Montana/Renewables 2023 segment Adjusted EBITDA was unfavorably impacted by lower throughput volumes as a result of throughput constraints caused by the ruptured steam drum and a turnaround at our Montana Renewables facility during the current year period, coupled with the impact of lower production volumes as a result of modifying our legacy Great Falls specialty asphalt facility to operate at a new and reduced nameplate capacity as part of the conversion to renewable fuel production. In addition to this, current year results were unfavorably impacted by higher material costs, primarily as it related to higher priced pre-treated feedstocks to support the start-up of the feedstock pre-treatment and SAF units.
Performance Brands segment Adjusted EBITDA was $47.9 million in 2023 compared to $20.2 million in 2022. Compared to the prior year, Performance Brands segment Adjusted EBITDA was favorably impacted by an increase in net unit margins as a result of input costs stabilizing in our branded and consumer markets and an increase in industrial volumes. The segment also benefited from a partial payout of our ongoing business interruption claims and received $8.2 million of insurance payments during the current year.
Corporate segment Adjusted EBITDA was negative $68.8 million in 2023 versus negative $85.4 million in 2022 primarily due to lower labor and benefits related expenses.
Liquidity Update
As of December 31, 2023, we had total liquidity of $249.8 million comprised of $7.9 million of unrestricted cash and $241.9 million of availability under our revolving credit facilities. As of December 31, 2023, our revolving credit facilities had a $421.5 million borrowing base, $149.7 million in outstanding borrowings and $29.9 million of outstanding standby letters of credit. We believe we will continue to have sufficient liquidity from cash on hand, projected cash flow from operations, borrowing capacity and other means by which to meet our financial commitments, debt service obligations, contingencies, and anticipated capital expenditures for at least the next 12 months. Please read Item 7 “Management’s Discussion and Analysis - Liquidity and Capital Resources” and Part I, Item 1A. “Risk Factors” for additional information.
Renewable Fuel Standard Update
Along with the broader refining industry, we remain subject to compliance costs under the RFS unless or until we receive a small refinery exemption from the EPA, which we have historically received. Administered by the EPA, the RFS provides annual requirements for the total volume of renewable transportation fuels that are mandated to be blended into
finished transportation fuels. If a refiner does not meet its required annual Renewable Volume Obligation, the refiner can purchase blending credits in the open market, referred to as RINs. For more information, see Part I, Item 1A, “Risk Factors - The availability and cost of renewable identification numbers and results of litigation related to our SRE petitions could have a material adverse effect on our results of operations and financial condition and our ability to make payments on our debt obligations.”
For the year ended December 31, 2023, we recorded a gain of $231.2 million for RINs, as compared to an expense of $197.5 million for RINs for the year ended December 31, 2022. Our gross RINs Obligation, which includes RINs that are required to be secured through either our own blending or through the purchase of RINs in the open market, is spread across four compliance categories (D3, D4, D5 and D6). The gross RINs obligations may be satisfied by our own renewables blending, RIN purchases, or receipt of small refinery exemptions.
Expenses related to RFS compliance have the potential to remain a significant expense for our two segments containing fuels products. If legal or regulatory changes occur that have the effect of increasing our RINs Obligation or eliminating or narrowing the availability of the small refinery exemption under the RFS program, we could be required to purchase additional RINs in the open market, which may materially increase our costs related to RFS compliance and could have a material adverse effect on our results of operations and liquidity.
See Note 2 - “Summary of Significant Accounting Policies” under Part II, Item 8 “Financial Statements - Notes to Consolidated Financial Statements” for further information on the Company’s RINs obligation.
Unrestricted Subsidiaries
See Note 19 - “Unrestricted Subsidiaries” under Part II, Item 8 “Financial Statements - Notes to Consolidated Financial Statements” for further information regarding certain financial information of our unrestricted subsidiaries.
Key Performance Measures
Our sales and results of operations are principally affected by demand for specialty products, fuel and renewable fuel product demand, global fuel crack spreads, the price of natural gas used as fuel in our operations, our ability to operate our production facilities at high utilization, and our results from derivative instrument activities.
Our primary raw materials are crude oil, renewable feedstocks and other specialty feedstocks, and our primary outputs are specialty consumer facing and industrial products, specialty branded products, and fuel and renewable fuel products. The prices of crude oil, specialty products and fuel and renewable fuel products are subject to fluctuations in response to changes in supply, demand, market uncertainties and a variety of factors beyond our control. We monitor these risks and from time-to-time enter into derivative instruments designed to help mitigate the impact of commodity price fluctuations on our business. The primary purpose of our commodity risk management activities is to economically hedge our cash flow exposure to commodity price risk. We may also hedge when market conditions exist that we believe to be out of the ordinary and particularly supportive of our financial goals. We enter into derivative contracts for future periods in quantities that do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. Please read Note 9 - “Derivatives” under Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements.”
Our management uses several financial and operational measurements to analyze our performance. These measurements include the following:
● sales volumes;
● segment gross profit;
● segment Adjusted gross profit;
● segment Adjusted EBITDA; and
● selling, general and administrative expenses.
Sales volumes. We view the volumes of Specialty Products and Solutions products, Montana/Renewables products and Performance Brands products sold as an important measure of our ability to effectively utilize our operating assets. Our ability to meet the demands of our customers is driven by the volumes of feedstocks that we run at our facilities. Higher volumes typically improve profitability both through the spreading of fixed costs over greater volumes and the additional gross profit achieved on the incremental volumes.
Segment gross profit. Specialty Products and Solutions, Montana/Renewables and Performance Brands products’ gross profit are important measures of profitability of our segments. We define gross profit as sales less the cost of crude oil and other feedstocks, LCM/LIFO adjustments, and other production-related expenses, the most significant portion of which includes labor, plant fuel, utilities, contract services, maintenance, transportation, RINs, depreciation and amortization and processing materials. We use gross profit as an indicator of our ability to manage margins in our business over the long-term. The increase or decrease in selling prices typically lags behind the rising or falling costs, respectively, of feedstocks throughout our business. Other than plant fuel, RINs mark-to-market adjustments, and LCM/LIFO adjustments, production related expenses generally remain stable across broad ranges but can fluctuate depending on maintenance activities performed during a specific period.
Segment Adjusted gross profit. Specialty Products and Solutions, Montana/Renewables and Performance Brands products segment Adjusted gross profit measures are useful as they exclude transactions not related to our core cash operating activities and provide metrics to analyze the profitability of the core cash operations of our segments. We define segment Adjusted gross profit as segment gross profit excluding the impact of (a) LCM inventory adjustments; (b) the impact of liquidation of inventory layers calculated using the LIFO method; (c) RINs mark-to-market adjustments; and (d) depreciation and amortization.
Segment Adjusted EBITDA. We believe that Specialty Products and Solutions, Montana/Renewables and Performance Brands segment Adjusted EBITDA measures are useful as they exclude transactions not related to our core cash operating activities and provide metrics to analyze our ability to pay interest to our noteholders. Adjusted EBITDA allows us to meaningfully analyze the trends and performance of our core cash operations as well as to make decisions regarding the allocation of resources to segments. Corporate Adjusted EBITDA primarily reflects general and administrative costs.
Results of Operations
Production Volume. The following table sets forth information about our continuing operations. Facility production volume differs from sales volume due to changes in inventories and the sale of purchased blendstocks such as ethanol and specialty blendstocks, as well as the resale of crude oil.
Year Ended December 31,
(In bpd)
Total sales volume (1)
79,805
82,946
79,281
Total feedstock runs (2)
77,200
80,447
75,818
Facility production: (3)
Specialty Products and Solutions:
Lubricating oils
10,358
10,951
9,867
Solvents
7,208
7,100
6,833
Waxes
1,326
1,452
1,335
Fuels, asphalt and other by-products
38,845
40,845
27,869
Total Specialty Products and Solutions
57,737
60,348
45,904
Montana/Renewables:
Gasoline
3,898
3,409
4,907
Diesel
2,941
6,449
9,711
Jet fuel
Asphalt, heavy fuel oils and other
4,483
6,942
10,379
Renewable fuels
6,314
-
-
Total Montana/Renewables
18,085
17,620
25,898
Performance Brands
1,474
1,434
1,304
Total facility production (3)
77,296
79,402
73,106
(1) Total sales volume includes sales from the production at our facilities and certain third-party facilities pursuant to supply and/or processing agreements, sales of inventories and the resale of crude oil to third-party customers. Total sales volume includes the sale of purchased blendstocks.
(2) Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements.
(3) The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.
The following table reflects our consolidated results of operations and includes the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. For a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to Net income (loss), our most directly comparable financial performance measure calculated and presented in accordance with GAAP, please read “Non-GAAP Financial Measures.”
Year Ended December 31,
(In millions)
Sales
$
4,181.0
$
4,686.3
$
3,148.0
Cost of sales
3,729.3
4,334.6
3,005.1
Gross profit
451.7
351.7
142.9
Operating costs and expenses:
Selling
54.9
53.9
52.8
General and administrative
133.0
143.4
151.1
Taxes other than income taxes
21.5
13.7
12.5
Loss on impairment and disposal of assets
3.5
0.7
4.1
Other operating (income) expense
(28.4)
8.1
8.0
Operating income (expense)
267.2
131.9
(85.6)
Other income (expense):
Interest expense
(221.7)
(175.9)
(149.5)
Debt extinguishment costs
(5.9)
(41.4)
(0.5)
Gain (loss) on derivative instruments
9.9
(81.7)
(23.3)
Other income (expense):
0.2
(2.8)
0.3
Total other expense
(217.5)
(301.8)
(173.0)
Net income (loss) before income taxes
49.7
(169.9)
(258.6)
Income tax expense
1.6
3.4
1.5
Net income (loss)
$
48.1
$
(173.3)
$
(260.1)
EBITDA
$
418.3
$
104.3
$
(1.4)
Adjusted EBITDA
$
260.5
$
390.0
$
110.3
Distributable Cash Flow
$
(86.2)
$
87.8
$
(120.1)
Non-GAAP Financial Measures
We include in this Annual Report the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. We provide reconciliations of EBITDA, Adjusted EBITDA and Distributable Cash Flow to Net income (loss), our most directly comparable financial performance measure calculated and presented in accordance with GAAP.
EBITDA, Adjusted EBITDA and Distributable Cash Flow are used as supplemental financial measures by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:
● the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
● the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;
● our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and
● the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
We believe that these non-GAAP measures are useful to analysts and investors as they exclude transactions not related to our core cash operating activities and provide metrics to analyze our ability to pay interest to our noteholders. However, the indentures governing our senior notes contain covenants that, among other things, restrict our ability to pay distributions. We believe that excluding these transactions allows investors to meaningfully analyze trends and performance of our core cash operations.
We define EBITDA for any period as net income (loss) plus interest expense (including amortization of debt issuance costs), income taxes and depreciation and amortization. Historically, we considered net income (loss) to be the most directly comparable GAAP measure to EBITDA. We believe net income (loss) is the most directly comparable GAAP measure to EBITDA.
We define Adjusted EBITDA for any period as EBITDA adjusted for (a) impairment; (b) unrealized gains and losses from mark-to-market accounting for hedging activities; (c) realized gains and losses under derivative instruments excluded from the determination of net income (loss); (d) non-cash equity-based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (e) debt refinancing fees, extinguishment costs, premiums and penalties; (f) any net gain or loss realized in connection with an asset sale that was deducted in computing net income (loss); (g) amortization of turnaround costs; (h) LCM inventory adjustments; (i) the impact of liquidation of inventory layers calculated using the LIFO method; (j) RINs mark-to-market adjustments; and (k) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense.
We define Distributable Cash Flow for any period as Adjusted EBITDA less replacement and environmental capital expenditures, turnaround costs, cash interest expense (consolidated interest expense less non-cash interest expense), gain (loss) from unconsolidated affiliates, net of cash distributions and income tax expense (benefit).
We define Adjusted EBITDA Margin as Adjusted EBITDA divided by sales.
The definition of Adjusted EBITDA presented in this Annual Report is similar to the calculation of “Consolidated Cash Flow” contained in the indentures governing our senior notes. We are required to report Consolidated Cash Flow to the holders of our senior notes and Adjusted EBITDA to the lenders under our revolving credit facility, and these measures are used by them to determine our compliance with certain covenants governing those debt instruments. Please read
“Liquidity and Capital Resources - Debt and Credit Facilities” for additional details regarding the covenants governing our debt instruments.
EBITDA, Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to Net income (loss) or Operating income (loss) or any other measure of financial performance presented in accordance with GAAP. In evaluating our performance as measured by EBITDA, Adjusted EBITDA and Distributable Cash Flow, management recognizes and considers the limitations of these measurements. EBITDA and Adjusted EBITDA do not reflect our liabilities for the payment of income taxes, interest expense or other obligations such as capital expenditures. Accordingly, EBITDA, Adjusted EBITDA and Distributable Cash Flow are only three of several measurements that management utilizes. Moreover, our EBITDA, Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA, Adjusted EBITDA and Distributable Cash Flow in the same manner.
The following tables present a reconciliation of Net income (loss), our most directly comparable GAAP financial performance measure to EBITDA, Adjusted EBITDA and Distributable Cash Flow, for each of the periods indicated.
Year Ended December 31,
(In millions)
Reconciliation of Net income (loss) to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net income (loss)
$
48.1
$
(173.3)
$
(260.1)
Add:
Interest expense
221.7
175.9
149.5
Depreciation and amortization
146.9
98.3
107.7
Income tax expense
1.6
3.4
1.5
EBITDA
$
418.3
$
104.3
$
(1.4)
Add:
LCM / LIFO (gain) loss
$
35.6
$
6.6
$
(50.3)
Unrealized (gain) loss on derivative instruments
(33.0)
45.9
$
24.4
Debt extinguishment costs
5.9
41.4
0.5
Amortization of turnaround costs
36.1
23.1
17.0
Loss on impairment and disposal of assets
3.5
0.7
4.1
RINs mark-to-market (gain) loss
(290.2)
115.7
57.7
Equity-based compensation and other items
20.2
34.4
50.7
Other non-recurring expenses (1)
60.9
15.6
7.6
Noncontrolling interest adjustments
3.2
2.3
-
Adjusted EBITDA
$
260.5
$
390.0
$
110.3
Less:
Replacement and environmental capital expenditures (2)
$
81.2
$
77.9
$
29.0
Cash interest expense (3)
216.0
158.3
138.9
Turnaround costs
47.9
62.6
61.0
Income tax expense
1.6
3.4
1.5
Distributable Cash Flow
$
(86.2)
$
87.8
$
(120.1)
(1) For the year ended December 31, 2023, other non-recurring expenses included a $50.6 million charge to cost of sales for losses under firm purchase commitments. For the year ended December 31, 2022, other non-recurring expenses included a $13.0 million charge to cost of sales for losses under firm purchase commitments.
(2) Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs. Environmental capital expenditures include asset additions to meet or exceed environmental and operating regulations.
(3) Represents consolidated interest expense less non-cash interest expense.
Year Ended December 31, 2023, Compared to Year Ended December 31, 2022
Sales. Sales decreased $505.3 million, or 10.8%, to $4,181.0 million in 2023 from $4,686.3 million in 2022. Sales for each of our principal product categories in these periods were as follows:
Year Ended December 31,
% Change
(Dollars in millions, except barrel and per barrel data)
Sales by segment:
Specialty Products and Solutions:
Lubricating oils
$
763.8
$
913.7
(16.4)
%
Solvents
398.5
434.9
(8.4)
%
Waxes
163.9
189.3
(13.4)
%
Fuels, asphalt and other by-products (1)
1,550.7
1,970.1
(21.3)
%
Total Specialty Products and Solutions
$
2,876.9
$
3,508.0
(18.0)
%
Total Specialty Products and Solutions sales volume (in barrels)
21,468,000
22,461,000
(4.4)
%
Average Specialty Products and Solutions sales price per barrel
$
134.01
$
156.18
(14.2)
%
Montana/Renewables:
Gasoline
$
167.2
$
188.1
(11.1)
%
Diesel
144.8
391.8
(63.0)
%
Jet Fuel
20.5
41.8
(51.0)
%
Asphalt, heavy fuel oils and other (2)
148.1
253.2
(41.5)
%
Renewable fuels
513.2
-
100.0
%
Total Montana/Renewables
$
993.8
$
874.9
13.6
%
Total Montana/Renewables sales volume (in barrels)
7,149,000
7,298,000
(2.0)
%
Average Montana/Renewables sales price per barrel
$
139.01
$
119.88
16.0
%
Performance Brands:
Total Performance Brands (3)
$
310.3
$
303.4
2.3
%
Total Performance Brands sales volume (in barrels)
512,000
517,000
(1.0)
%
Average Performance Brands sales price per barrel
$
606.05
$
586.85
3.3
%
Total sales
$
4,181.0
$
4,686.3
(10.8)
%
Total Specialty Products and Solutions, Montana/Renewables, and Performance Brands sales volume (in barrels)
29,129,000
30,276,000
(3.8)
%
(1) Represents (a) by-products, including fuels and asphalt, produced in connection with the production of specialty products at the Princeton and Cotton Valley facilities and Dickinson and Karns City facilities, (b) polyol ester synthetic lubricants produced at the Missouri facility, and (c) fuels products produced at the Shreveport facility.
(2) Represents asphalt, heavy fuel oils and other products produced in connection with the production of fuels at the Great Falls specialty asphalt facility.
(3) Represents packaged and synthetic specialty products at our Royal Purple, Bel-Ray and Calumet Packaging facilities.
The components of the $631.1 million decrease in Specialty Products and Solutions segment sales in 2023, as compared to 2022, were as follows:
Dollar Change
(In millions)
Volume
$
(155.3)
Sales price
(475.8)
Total Specialty Products and Solutions segment sales decrease
$
(631.1)
Specialty Products and Solutions segment sales decreased period over period, primarily due to the weaker price environment in the current year period and lower throughput. The unfavorable volumes impact was due to planned turnarounds at our Shreveport, Cotton Valley, and Princeton facilities in the current year period and unplanned outages as a result of the severe weather experienced in Northwest Louisiana during the current year.
The components of the $118.9 million increase in Montana/Renewables segment sales in 2023, as compared to 2022, were as follows:
Dollar Change
(In millions)
Sales price
$
136.6
Volume
(17.7)
Total Montana/Renewables segment sales increase
$
118.9
Montana/Renewables segment sales increased primarily due to higher sales prices resulting from sales of higher priced renewable fuels in the current year period. Lower volumes were the result of throughput constraints caused by the ruptured steam drum and a turnaround at our Montana Renewables facility, coupled with the unfavorable impact as a result of modifying our legacy Great Falls asphalt plant to operate at a new and lower nameplate capacity.
The components of the $6.9 million increase in Performance Brands segment sales in 2023, as compared to 2022, were as follows:
Dollar Change
(In millions)
Sales price
$
9.6
Volume
(2.7)
Total Performance Brands segment sales increase
$
6.9
Performance Brands segment sales increased primarily due to increases in product prices.
Gross Profit. Gross profit increased $100.0 million, or 28.4%, to $451.7 million in 2023 from $351.7 million in 2022. Gross profit for our business segments were as follows:
Year Ended December 31,
% Change
(Dollars in millions, except per barrel data)
Gross profit by segment:
Specialty Products and Solutions:
Gross profit
$
402.2
$
325.5
23.6
%
Percentage of sales
14.0
%
9.3
%
4.7
%
Specialty Products and Solutions gross profit per barrel
$
18.73
$
14.49
29.3
%
Montana/Renewables:
Gross profit (loss)
$
(32.6)
$
(29.4)
10.9
%
Percentage of sales
(3.3)
%
(3.4)
%
0.1
%
Montana/Renewables gross profit (loss) per barrel
$
(4.56)
$
(4.03)
13.2
%
Performance Brands:
Gross profit
$
82.1
$
55.6
47.7
%
Percentage of sales
26.5
%
18.3
%
8.2
%
Performance Brands gross profit per barrel
$
160.35
$
107.54
49.1
%
Total gross profit
$
451.7
$
351.7
28.4
%
Percentage of sales
10.8
%
7.5
%
3.3
%
The components of the $76.7 million increase in Specialty Products and Solutions segment gross profit in 2023, as compared to 2022, were as follows:
Dollar Change
(In millions)
Year ended December 31, 2022 reported gross profit
$
325.5
Cost of materials
360.3
Operating costs
(18.5)
LCM / LIFO inventory adjustments
(12.1)
Volumes
(36.7)
Sales price
(475.8)
RINs expense
259.5
Year ended December 31, 2023 reported gross profit
$
402.2
The increase in Specialty Products and Solutions segment gross profit for the year ended December 31, 2023, as compared to the same period in 2022, was primarily due to the significant decline in RINs prices in the current year. This impact was partially off-set by lower specialties and fuels unit margins as a result of the weaker margin environment experienced during the current year period. Also, current year results were unfavorably impacted by higher operating expenses and lower volumes as a result of planned turnarounds completed at our Shreveport, Cotton Valley, and Princeton facilities and unplanned outages as a result of severe weather experienced in Northwest Louisiana during the current year period.
The components of the $3.2 million decrease in Montana/Renewables segment gross profit (loss) in 2023, as compared to 2022, were as follows:
Dollar Change
(In millions)
Year ended December 31, 2022 reported gross profit (loss)
$
(29.4)
Cost of materials
(110.3)
Loss on firm purchase commitments
(37.6)
LCM / LIFO inventory adjustments
(14.6)
Volumes
(3.7)
RINs expense
136.1
Operating costs
(109.8)
Sales price
136.7
Year ended December 31, 2023 reported gross profit (loss)
$
(32.6)
The increase in Montana/Renewables segment gross profit for the year ended December 31, 2023, as compared to the same period in 2022, was primarily due to the significant decline in RINs prices in the current year. This impact was coupled with the favorable impact of higher margins associated with sales of renewable fuels products at our Montana Renewables facility in the current year period. The unfavorable impact for lower production volumes and higher operating costs were associated with the start-up of the Montana Renewables facility and the modification of our legacy Great Falls specialty asphalt facility. Also, volumes were unfavorably impacted due to throughput constraints caused by the ruptured steam drum and a turnaround completed at our Montana Renewables during the current year period. These impacts were coupled with the unfavorable impact of a charge for losses under firm purchase commitments recorded in the current year period.
The components of the $26.5 million increase in Performance Brands segment gross profit in 2023, as compared to 2022, were as follows:
Dollar Change
(In millions)
Year ended December 31, 2022 reported gross profit
$
55.6
Sales price
9.6
Operating costs
6.3
LCM / LIFO inventory adjustments
(2.3)
Volume
(0.7)
Cost of materials
13.6
Year ended December 31, 2023 reported gross profit
$
82.1
The increase in Performance Brands segment gross profit for the year ended December 31, 2023, as compared to the same period in 2022, was primarily driven by higher unit margins as a result of input costs stabilizing in our branded and consumer markets. The favorable impact for operating costs was the result of partial receipt of proceeds from the Company’s business interruption insurance policy recorded in the current year period.
General and administrative. General and administrative expenses decreased $10.4 million, or 7.3%, to $133.0 million in 2023 from $143.4 million in 2022. The decrease was due primarily to a $5.4 million decrease in labor and benefits expenses.
Interest expense. Interest expense increased $45.8 million, or 26.0%, to $221.7 million in 2023 from $175.9 million in 2022. The increase was primarily due to interest expense incurred for our 2028 Notes and the MRL Term Loan Credit Agreement in the current year period, which was absent the prior year comparative period. The increase in interest expense in the current year period was partially offset by the absence of interest expense incurred in the prior year comparative period for outstanding borrowings under the MRL credit facility, which were repaid in August 2022.
Gain (loss) on derivative instruments. There was a $9.9 million gain on derivative instruments in 2023, compared to a $81.7 million loss in the same period in 2022. The $23.1 million realized loss on derivative instruments in the current year period was primarily due to the settlement of our crack spread swaps positions during the period. The unrealized gain on derivative instruments was primarily the result of a $42.9 million unrealized gain on crack spread swaps positions, partially offset by the unrealized loss on the inventory financing embedded derivative of $9.9 million in the current year period, compared to an unrealized loss of $14.6 million in the prior year comparative period.
Debt extinguishment costs. There was a $5.9 million loss for debt extinguishment costs in 2023, compared to a $41.4 million loss for debt extinguishment costs in 2022. Debt extinguishment costs in the prior year period comprised of $2.1 million in conjunction with the repurchase of $36.5 million aggregate principal amount of the 2025 Notes and $38.3 million in conjunction with the repayment of all borrowings under the MRL credit facility. Please refer to Note 8 “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
Year Ended December 31, 2022, Compared to Year Ended December 31, 2021
Refer to Item 7 “Management’s Discussion and Analysis - Year Ended December 31, 2022, Compared to Year Ended December 31, 2021” of our 2022 Annual Report for a description of the factors impacting our results of operations for the year ended December 31, 2022 in comparison to the year ended December 31, 2021.
Liquidity and Capital Resources
Our principal sources of cash have historically included cash flow from operations, proceeds from public equity offerings, proceeds from notes offerings, bank borrowings and other financial arrangements. Principal uses of cash have included capital expenditures, acquisitions, distributions to our limited partners and general partner and debt service. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions, tender offers or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
In general, we expect that our short-term liquidity needs, including debt service, working capital, replacement and environmental capital expenditures and capital expenditures related to internal growth projects, will be met primarily through cash on hand, projected cash flow from operations, borrowing capacity under our revolving credit facilities and asset sales.
On June 27, 2023, the Company issued and sold $325.0 million in aggregate principal amount of 2028 Notes, in a private placement pursuant to Section 4(a)(2) of the Securities Act to eligible purchasers at par. The Company received net proceeds of $319.1 million, after deducting the initial purchasers’ discount and offering expenses. On June 28, 2023, the Company used approximately $125.5 million (excluding accrued and unpaid interest and related expenses) of the proceeds from the offering of the 2028 Notes to fund the repurchase of (i) approximately $21.0 million in aggregate principal amount of 2024 Secured Notes and (ii) $100.0 million in aggregate principal amount of the 2025 Notes and pay related premiums, in each case, in connection with the completion of the Company’s tender offers. Please refer to Note 8 - “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
On April 19, 2023, MRL and MRHL entered into the MRL Term Loan Credit Agreement, that provides for a $75.0 million term loan facility with a maturity date of April 19, 2028. Please refer to Note 8 - “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
On January 17, 2024, the Company entered into the Fourth Amendment to its revolving credit facility (the “Credit Agreement”) governing its senior secured revolving credit facility maturing in January 2027, which provides maximum availability of credit under the revolving credit facility of $650.0 million, including a FILO tranche, subject to borrowing base limitations, and includes a $500.0 million incremental uncommitted expansion feature. Lenders under the revolving credit facility have a first priority lien on, among other things, the Company’s accounts receivable and inventory and substantially all of its cash (collectively, the “Credit Agreement Collateral”). Please refer to Note 8 - “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
On February 23, 2024, the Company announced that it delivered (i) a notice of conditional redemption for all of the 2024 Secured Notes at a redemption price of par, plus accrued and unpaid interest to but not including the redemption date of March 9, 2024, and (ii) a notice of conditional redemption for $50.0 million aggregate principal amount of the 2025 Notes at a redemption price of par, plus accrued and unpaid interest to but not including the redemption date of April 15, 2024.
The Company’s obligation to redeem all of the 2024 Secured Notes and $50.0 million aggregate principal amount of the 2025 Notes, in each case, is conditioned upon, on or before March 9, 2024, the completion of a private placement of at least $200.0 million aggregate principal amount of the Company’s senior debt securities. The Company will publicly announce and notify the holders of the 2024 Secured Notes, the holders of the 2025 Notes and Wilmington Trust, National Association, as trustee, if the foregoing condition is not satisfied or waived, whereupon the redemptions will be revoked and the 2024 Secured Notes and the 2025 Notes called for redemption will remain outstanding. Please refer to Note 23 - “Subsequent Events” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
On January 17, 2024 (the “Effective Date”), the Company and J. Aron entered into a Monetization Master Agreement (the “Master Agreement”), a related Financing Agreement (the “Financing Agreement”) and Supply and Offtake Agreement (together with the Master Agreement and the Financing Agreement, the “Shreveport Supply and Offtake Agreement”). Pursuant to the Shreveport Supply and Offtake Agreement, J. Aron agreed to, among other things, purchase from the Company, or extend to the Company, financial accommodations secured by crude oil and finished products located at the Company’s Shreveport facility on the Effective Date and from time to time, up to maximum volumes specified for crude oil and categories of finished products, subject to the Company’s repurchase obligations with respect thereto. The Shreveport Supply and Offtake Agreement replaced the Company’s previous inventory financing agreement with Macquarie, which terminated on January 17, 2024. Please refer to Note 7 - “Inventory Financing Agreements” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
On October 3, 2023, Montana Renewables, LLC (“MRL”) and Wells Fargo Commodities, LLC (“Wells Fargo”) entered into (a) an ISDA 2002 Master Agreement (the “Master Agreement), (ii) a Schedule to the ISDA 2002 Master Agreement (the “Schedule”), (iii) a Credit Support Annex to the ISDA 2002 Master Agreement (the “Credit Support Annex”), and (iv) a Renewable Fuel and Feedstock Repurchase Master Confirmation (together with the Master Agreement, the Schedule and the Credit Support Annex, collectively the “MRL Supply and Offtake Agreement” and, together with the Shreveport Supply and Offtake Agreement, the “Supply and Offtake Agreements”). Pursuant to the MRL Supply and Offtake Agreement, Wells Fargo agreed to, among other things, (a) purchase from MRL renewable feedstocks and finished products located at MRL’s Great Falls facility, subject to MRL’s repurchase obligations with respect thereto, and (b) provide certain financial accommodations to MRL secured by liens on certain renewable feedstocks and finished products owned by MRL. The MRL Supply and Offtake Agreement replaced MRL’s previous inventory financing agreement with Macquarie, which terminated on October 3, 2023. Please refer to Note 7 - “Inventory Financing Agreements” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
We expect to fund planned capital expenditures in 2024 of approximately $110 million to $140 million primarily with cash on hand, and cash flows from operations. Future internal growth projects or acquisitions may require expenditures in excess of our then-current cash flow from operations and borrowing availability under our revolving credit facilities and may require us to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs. We continue to anticipate that capital improvement expenditure requirements will be funded from borrowings under our revolving credit facilities or by funding accessed through capital markets.
The borrowing base on our revolving credit facilities decreased from approximately $477.4 million as of December 31, 2022, to approximately $421.5 million at December 31, 2023, resulting in a corresponding decrease in our borrowing availability from approximately $337.6 million at December 31, 2022, to approximately $241.9 million at December 31, 2023. Total liquidity, consisting of cash and available funds under our revolving credit facilities, decreased from $372.8 million at December 31, 2022 to $249.8 million at December 31, 2023.
Cash Flows from Operating, Investing and Financing Activities
We believe that we have sufficient liquid assets, cash flow from operations, borrowing capacity and adequate access to capital markets to meet our financial commitments, debt service obligations and anticipated capital expenditures for at least the next 12 months. We continue to seek to lower our operating costs, selling expenses and general and administrative expenses as a means to further improve our cash flow from operations with the objective of having our cash flow from operations support all of our capital expenditures and interest payments. However, we are subject to business and operational risks that could materially adversely affect our cash flows. A material decrease in our cash flow from operations including a significant, sudden decrease in crude oil prices would likely produce a corollary effect on our borrowing capacity under our revolving credit facility and potentially our ability to comply with the covenants under our revolving credit facility. A significant, sudden increase in crude oil prices, if sustained, would likely result in increased working capital requirements which would be funded by borrowings under our revolving credit facility. In addition, our cash flow from operations may be impacted by the timing of settlement of our derivative activities. Gains and losses from derivative
instruments that do not qualify as cash flow hedges are recorded in unrealized gain (loss) on derivative instruments until settlement and will impact operating cash flow in the period settled.
The following table summarizes our primary sources and uses of cash in each of the most recent two years:
Year Ended December 31,
(In millions)
Net cash provided by (used) in operating activities
$
(14.9)
$
100.6
$
(44.0)
Net cash used in investing activities
(271.8)
(536.0)
(82.8)
Net cash provided by financing activities
266.2
348.7
139.3
Net increase (decrease) in cash, cash equivalents and restricted cash
$
(20.5)
$
(86.7)
$
12.5
Operating Activities. Operating activities used cash of $14.9 million in 2023 compared to providing cash of $100.6 million in 2022. The change was primarily driven by a decrease in net unit margins as a result of the weaker margin environment experienced during the current year period.
Investing Activities. Investing activities used cash of $271.8 million in 2023 compared to a use of cash of $536.0 million in 2022. The change is related to a decrease in cash expenditures for additions to property, plant and equipment in the current year period in comparison to the prior year. The cash expenditures for additions to property, plant and equipment in both periods were mainly related to our Montana Renewables project.
Financing Activities. Financing activities provided cash of $266.2 million in 2023 compared to providing cash of $348.7 million in 2022. The change is primarily due to the borrowings we received from the issuance of the 2028 Notes and the MRL Term Loan Credit Agreement, partially offset by repayments of our 2024 Secured Notes, 2025 Notes and the payments made to terminate the Great Falls Supply and Offtake Agreement (as defined below). In addition to this, cash provided by financing activities in the prior year comparative period included $372.9 million of proceeds for other financing activities, mostly related to our MRL asset financing arrangements, and $250.0 million of proceeds received for the sale of preferred units in MRHL. Please refer to Note 20 - “Redeemable Noncontrolling Interest” for additional information regarding the issuance and sale of preferred units and Note 8 - “Long-Term Debt - MRL Asset Financing Arrangements” under Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information regarding the MRL asset financing arrangements.
Capital Expenditures
Our property, plant and equipment capital expenditure requirements consist of capital improvement expenditures, replacement capital expenditures, environmental capital expenditures and turnaround capital expenditures. Capital improvement expenditures include the acquisition of assets to grow our business, facility expansions, or capital initiatives that reduce operating costs. Replacement capital expenditures replace worn out or obsolete equipment or parts. Environmental capital expenditures include asset additions to meet or exceed environmental and operating regulations. Turnaround capital expenditures represent capitalized costs associated with our periodic major maintenance and repairs.
The following table sets forth our capital improvement expenditures, replacement capital expenditures, environmental capital expenditures and turnaround capital expenditures in each of the periods shown (including capitalized interest):
Year Ended December 31,
(In millions)
Capital improvement expenditures
$
190.6
$
458.3
$
53.9
Replacement capital expenditures
69.9
69.2
24.0
Environmental capital expenditures
11.3
8.7
5.0
Turnaround capital expenditures
47.9
62.6
61.0
Total
$
319.7
$
598.8
$
143.9
2024 Capital Spending Forecast
We are forecasting total capital expenditures of approximately $110 million to $140 million in 2024. Our forecasted capital expenditures are primarily related to growth and sustainability projects. We anticipate that capital expenditure requirements will be provided primarily through cash flow from operations, cash on hand, available borrowings under our revolving credit facilities and by accessing capital markets as necessary. Further, we continue to anticipate that capital improvement expenditure requirements will be funded from borrowings under our revolving credit facilities or by funding accessed through capital markets. If future capital expenditures require expenditures in excess of our then-current cash flow from operations and borrowing availability under our revolving credit facilities, we may be required to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs.
Debt and Credit Facilities
As of December 31, 2023, our primary debt and credit instruments consisted of:
● $650.0 million senior secured revolving credit facility maturing in January 2027 (after giving effect to the Fourth Amendment to our revolving credit facility (the “Credit Facility Amendment”)), subject to borrowing base limitations, with a maximum letter of credit sub-limit equal to $255.0 million, which amount may be increased to 90% of revolver commitments in effect with the consent of the Agent (as defined in the Credit Agreement) (“revolving credit facility”);
● $90.0 million senior secured revolving credit facility, with the option to request additional commitments of up to $15.0 million, maturing in November 2027 (the “MRL Revolving Credit Agreement”);
● $179.0 million of 9.25% Senior Secured First Lien Notes due 2024;
● $413.5 million of 11.00% Senior Notes due 2025;
● $325.0 million of 8.125% Senior Notes due 2027;
● $325.0 million of 9.25% Senior Notes due 2028 (“2028 Notes”);
● $74.4 million of borrowings under our MRL Term Loan Credit Agreement; and
● $384.6 million of financing through our MRL asset financing arrangements.
We were in compliance with all covenants under our debt instruments in place as of December 31, 2023, and believe we have adequate liquidity to conduct our business.
On June 27, 2023, the Company issued and sold $325.0 million in aggregate principal amount of 2028 Notes, in a private placement pursuant to Section 4(a)(2) of the Securities Act to eligible purchasers at par. The Company received net proceeds of $319.1 million, after deducting the initial purchasers’ discount and offering expenses. On June 28, 2023, the Company used approximately $125.5 million (excluding accrued and unpaid interest and related expenses) of the proceeds from the offering of the 2028 Notes to fund the repurchase of (i) approximately $21.0 million in aggregate principal amount of 2024 Secured Notes and (ii) $100.0 million in aggregate principal amount of the 2025 Notes and pay related premiums, in each case, in connection with the completion of the Company’s tender offers. Please refer to Note 8 - “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
On April 19, 2023, MRL and MRHL entered into the MRL Term Loan Credit Agreement, that provides for a $75.0 million term loan facility with a maturity date of April 19, 2028. Please refer to Note 8 - “Long-Term Debt” in Part II,
Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
On January 17, 2024, the Company entered into the Fourth Amendment to its revolving credit facility (the “Credit Agreement”) governing its senior secured revolving credit facility maturing in January 2027, which provides maximum availability of credit under the revolving credit facility of $650.0 million, including a FILO tranche, subject to borrowing base limitations, and includes a $500.0 million incremental uncommitted expansion feature. Lenders under the revolving credit facility have a first priority lien on, among other things, the Company’s accounts receivable and inventory and substantially all of its cash (collectively, the “Credit Agreement Collateral”). Please refer to Note 8 - “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
On February 23, 2024, the Company announced that it delivered (i) a notice of conditional redemption for all of the 2024 Secured Notes at a redemption price of par, plus accrued and unpaid interest to but not including the redemption date of March 9, 2024, and (ii) a notice of conditional redemption for $50.0 million aggregate principal amount of the 2025 Notes at a redemption price of par, plus accrued and unpaid interest to but not including the redemption date of April 15, 2024.
The Company’s obligation to redeem all of the 2024 Secured Notes and $50.0 million aggregate principal amount of the 2025 Notes, in each case, is conditioned upon, on or before March 9, 2024, the completion of a private placement of at least $200.0 million aggregate principal amount of the Company’s senior debt securities. The Company will publicly announce and notify the holders of the 2024 Secured Notes, the holders of the 2025 Notes and Wilmington Trust, National Association, as trustee, if the foregoing condition is not satisfied or waived, whereupon the redemptions will be revoked and the 2024 Secured Notes and the 2025 Notes called for redemption will remain outstanding. Please refer to Note 23 - “Subsequent Events” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
Inventory Financing
On January 17, 2024 (the “Effective Date”), the Company and J. Aron entered into a Monetization Master Agreement (the “Master Agreement”), a related Financing Agreement (the “Financing Agreement”) and Supply and Offtake Agreement (together with the Master Agreement and the Financing Agreement, the “Shreveport Supply and Offtake Agreement”). Pursuant to the Shreveport Supply and Offtake Agreement, J. Aron agreed to, among other things, purchase from the Company, or extend to the Company, financial accommodations secured by crude oil and finished products located at the Company’s Shreveport facility on the Effective Date and from time to time, up to maximum volumes specified for crude oil and categories of finished products, subject to the Company’s repurchase obligations with respect thereto. The Shreveport Supply and Offtake Agreement replaced the Company’s previous inventory financing agreement with Macquarie, which terminated on January 17, 2024. Please refer to Note 7 - “Inventory Financing Agreements” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
On October 3, 2023, Montana Renewables, LLC (“MRL”) and Wells Fargo Commodities, LLC (“Wells Fargo”) entered into (a) an ISDA 2002 Master Agreement (the “Master Agreement), (ii) a Schedule to the ISDA 2002 Master Agreement (the “Schedule”), (iii) a Credit Support Annex to the ISDA 2002 Master Agreement (the “Credit Support Annex”), and (iv) a Renewable Fuel and Feedstock Repurchase Master Confirmation (together with the Master Agreement, the Schedule and the Credit Support Annex, collectively the “MRL Supply and Offtake Agreement” and, together with the Shreveport Supply and Offtake Agreement, the “Supply and Offtake Agreements”). Pursuant to the MRL Supply and Offtake Agreement, Wells Fargo agreed to, among other things, (a) purchase from MRL renewable feedstocks and finished products located at MRL’s Great Falls facility, subject to MRL’s repurchase obligations with respect thereto, and (b) provide certain financial accommodations to MRL secured by liens on certain renewable feedstocks and finished products owned by MRL. The MRL Supply and Offtake Agreement replaced MRL’s previous inventory financing agreement with Macquarie, which terminated on October 3, 2023. Please refer to Note 7 - “Inventory Financing Agreements” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information.
Please refer to Note 7 - “Inventory Financing Agreements” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for additional information regarding our Supply and Offtake Agreements.
Short-Term Liquidity
As of December 31, 2023, our principal sources of short-term liquidity were (i) approximately $241.9 million of availability under our revolving credit facilities, (ii) inventory financing agreements related to our Shreveport facility and Montana Renewables facility and (iii) $7.9 million of unrestricted cash on hand. Borrowings under our revolving credit facility can be used for, among other things, working capital, capital expenditures, and other lawful partnership purposes including acquisitions. For additional information regarding our revolving credit facility, please read Note 8 - “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements.”
Long-Term Financing
In addition to our principal sources of short-term liquidity listed above, subject to market conditions, we may meet our cash requirements (other than distributions of Available Cash (as defined in our partnership agreement) to our common unitholders) through the issuance of long-term notes or additional common units.
From time to time, we issue long-term debt securities referred to as our senior notes. All of our outstanding senior notes, other than the 2024 Secured Notes, are unsecured obligations that rank equally with all of our other senior debt obligations to the extent they are unsecured. As of December 31, 2023, we had $179.0 million in 2024 Secured Notes, $413.5 million in 2025 Notes, $325.0 million in 2027 Notes, and $325.0 million in 2028 Notes outstanding. The 2024 Secured Notes and the related guarantees are secured by a first priority lien (subject to certain exceptions) on all the fixed assets that secure our obligations under the secured hedge agreements, as governed by the Collateral Trust Agreement, which governs how secured hedging counterparties and holders of the 2024 Secured Notes share collateral pledged as security for the payment obligations owed by us to the secured hedging counterparties under their respective master derivatives contracts and the holders of the 2024 Secured Notes. In addition, as of December 31, 2023, we had $384.6 million of debt outstanding for our MRL asset financing arrangements and $50.8 million of other debt outstanding for the Shreveport terminal asset financing arrangement. Borrowings under the MRL asset financing arrangements are obligations of our unrestricted subsidiaries MRL and MRHL solely, and are non-recourse to the Company and its restricted subsidiaries. For additional information regarding our MRL asset financing arrangements, see Note 8 - “Long-Term Debt” under Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” in this Annual Report.
To date, our debt balances have not adversely affected our operations, our ability to repay or refinance our indebtedness. Based on our historical record, we believe that our capital structure will continue to allow us to achieve our business objectives.
For more information regarding our senior notes, please read Note 8 - “Long-Term Debt” under Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” in this Annual Report.
Master Derivative Contracts and Collateral Trust Agreement
Under our credit support arrangements, our payment obligations under all of our master derivatives contracts for commodity hedging generally are secured by a first priority lien on our and our subsidiaries’ real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). We had no additional letters of credit or cash margin posted with any hedging counterparty as of December 31, 2023. Our master derivatives contracts and Collateral Trust Agreement (as defined below) continue to impose a number of covenant limitations on our operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements. For financial reporting purposes, we do not offset the
collateral provided to a counterparty against the fair value of our obligation to that counterparty. Any outstanding collateral is released to us upon settlement of the related derivative instrument liability.
Our various hedging agreements contain language allowing our hedge counterparties to request additional collateral if a specified credit support threshold is exceeded. However, these credit support thresholds are set at levels that would require a substantial increase in hedge exposure to require us to post additional collateral. As a result, we do not expect further increases in fuel products crack spreads or interest rates to significantly impact our liquidity due to requirements to post additional collateral.
Additionally, we have a collateral trust agreement (the “Collateral Trust Agreement”) which governs how secured hedging counterparties and holders of the 2024 Secured Notes share collateral pledged as security for the payment obligations owed by us to the secured hedging counterparties under their respective master derivatives contracts and the holders of the 2024 Secured Notes. The Collateral Trust Agreement limits to $150.0 million the extent to which forward purchase contracts for physical commodities are covered by, and secured under, the Collateral Trust Agreement and the Parity Lien Security Documents (as defined in the Collateral Trust Agreement). There is no such limit on financially settled derivative instruments used for commodity hedging. Subject to certain conditions set forth in the Collateral Trust Agreement, we have the ability to add secured hedging counterparties from time to time.
Credit Ratings
In October 2023, S&P reaffirmed a rating of B- on our senior unsecured notes and revised our outlook to stable. In January 2022, Moody’s reaffirmed a rating of Caa1 on our senior unsecured notes and a Company rating of B3, with the stable outlook maintained. Our 2024 Secured Notes issued in 2020 are rated B+ by S&P and B1 by Moody’s.
Equity Transactions
In April 2016, the board of directors of our general partner suspended payment of our quarterly cash distribution.
Seasonality Impacts on Liquidity
The fuel and fuel related products that we manufacture, including asphalt products, are subject to seasonal demand and trends. Asphalt demand is generally lower in the first and fourth quarters of the year, as compared to the second and third quarters, due to the seasonality of the road construction and roofing industries we supply. Demand for gasoline and diesel is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and agricultural activity. In addition, our natural gas costs can be higher during the winter months, as demand for natural gas as a heating fuel increases during the winter. As a result, our operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year due to seasonality related to these and other products that we produce and sell.
Critical Accounting Estimates
The preparation of our consolidated financial statements in accordance with GAAP requires us to use estimates and make judgements and assumptions about future events that affect the reported amounts of assets, liabilities, revenue, expenses, and the related disclosures. Considerable judgement is often involved in making these determinations. Critical estimates are those that require the most difficult, subjective or complex judgements in the preparation of the financial statements and the accompanying notes. We evaluate these estimates and judgements on a regular basis. We believe our assumptions and estimates are reasonable and appropriate. However, the use of different assumptions could result in significantly different results and actual results could differ from those estimates. The following discussion of accounting estimates is intended to supplement the Summary of Significant Accounting Policies presented in Note 2 to our consolidated financial statements in Part II, Item 8.
We consider an accounting estimate to be critical if:
● The accounting estimate requires us to make assumptions about matters that are highly uncertain at the time the accounting estimate is made; and
● We reasonably could have used different estimates in the current period, or changes in these estimates are reasonably likely to occur from period to period as new information becomes available, and a change in these estimates would have a material impact on our financial condition or results from operations.
Valuation of Goodwill
We assess goodwill for impairment annually and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The Company tests goodwill either quantitatively or qualitatively for impairment. The Company assessed goodwill for impairment qualitatively during the year ended December 31, 2023 and qualitatively and quantitatively during the year ended December 31, 2022.
In assessing the qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, we assess relevant events and circumstances that may impact the fair value and the carrying amount of the reporting unit. The identification of relevant events and circumstances and how these may impact a reporting unit’s fair value or carrying amount involve significant judgment and assumptions. The judgment and assumptions include the identification of macroeconomic conditions, industry and market considerations, cost factors, overall financial performance and Company specific events and the assessment on whether each relevant factor will impact the impairment test positively or negatively and the magnitude of any such impact.
In the first step of the quantitative assessment, our assets and liabilities, including existing goodwill and other intangible assets, are assigned to the identified reporting units to determine the carrying value of the reporting units. If the carrying value of a reporting unit is in excess of its fair value, an impairment may exist, and we must perform an impairment analysis, in which the implied fair value of the goodwill is compared to its carrying value to determine the impairment charge, if any.
When performing the quantitative assessment, as required in the impairment test, the fair value of the reporting unit is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation, and risks associated with the reporting unit. If the carrying value of a reporting unit is in excess of its fair value, an impairment would be recognized in an amount equal to the excess that the carrying value exceeded the estimated fair value, limited to the carrying value of goodwill.
Inputs used to estimate the fair value of the Company’s reporting units are considered Level 3 inputs of the fair value hierarchy and include the following:
● The Company’s financial projections for its reporting units are based on its analysis of various supply and demand factors which include, among other things, industry-wide capacity, planned utilization rates, end-user demand, crack spreads, capital expenditures and economic conditions. Such estimates are consistent with those used in the Company’s planning and capital investment reviews and include recent historical prices and published forward prices.
● The discount rate used to measure the present value of the projected future cash flows is based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible.
For Level 3 measurements, significant increases or decreases in long-term growth rates or discount rates in isolation or in combination could result in a significantly lower or higher fair value measurement.
Fair values calculated for the purpose of testing our goodwill for impairment are estimated using the expected present value of future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions.
Meaningful factors that would significantly impact our financial projections are changes in customer demand levels or loss of significant portions of our business. We believe that the assumptions and estimates used in the assessment of our goodwill as of October 1, 2023 were reasonable.
Valuation of Finite Long-Lived Assets
Property, plant and equipment and intangible assets with finite lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. If the estimated undiscounted future cash flows related to the asset are less than the carrying value, we recognize a loss equal to the difference between the carrying value and the estimated fair value, usually determined by the estimated discounted future cash flows of the asset. When a decision has been made to dispose of property, plant and equipment prior to the end of the previously estimated useful life, depreciation estimates are revised to reflect the use of the asset over the shortened estimated useful life.
Estimated undiscounted future cash flows are used for the purpose of testing our finite long-lived assets for impairment. Fair values calculated for the purpose of measuring impairments on finite long-lived assets are estimated using the expected present value of future cash flows method and comparative market prices when appropriate. Significant judgment is involved in estimating undiscounted future cash flows and performing these fair value estimates since the results are based on forecasted assumptions.
We base our estimated undiscounted future cash flows and fair value estimates on projected financial information which we believe to be reasonable. However, actual results may differ from these projections.
Valuation of Renewable Identification Numbers (“RINs”) Obligation
The Company’s RINs volume obligation (“RVO” or “RINs Obligation”) is an estimated provision if future purchase of RINs were to be required in order to satisfy the U.S. Environmental Protection Agency’s (“EPA”) requirement to blend renewable fuels into certain transportation fuel products pursuant to the Renewable Fuel Standard (“RFS”) of the Clean Air Act (“CAA”). A RIN is a 38-character number assigned to each physical gallon of renewable fuel produced in or imported into the United States. The EPA sets annual volume obligations for the percentage of renewable fuels that must be blended into transportation fuels consumed in the U.S. Compliance is demonstrated by tendering RINs to the EPA documenting that blending has been accomplished or by obtaining a Small Refinery Exemption as provided in the Clean Air Act. Prior to 2018, the Company historically received the Small Refinery Exemption after qualifying on the merits and has historically not been obligated to make these purchases during these years. The Company’s petitions for the Small Refinery Exemption for compliance years 2018-2022 ultimately were denied by the EPA. EPA’s denials of those petitions is subject to litigation, as described in Note 2 - “Summary of Significant Accounting Policies.” Future exemptions are the subject of future annual applications. The RIN obligation is a non-financial instrument representing a quantity that cannot be settled financially.
The Company accounts for its current period RVO by multiplying the quantity of RINs shortage (based on actual results) by the period end RINs spot price, which is recorded as both a current and long-term liability in the consolidated balance sheets. These liabilities are revalued at the end of each subsequent accounting period, which produce non-cash mark-to-market adjustments that are reflected in cost of sales in the consolidated statements of operations (with the exception of RINs for compliance year 2019 related to the San Antonio refinery, which amount is reflected in other operating expense in the consolidated statements of operations). RINs generated by blending may be sold or held to offset future RVO. Any gains or losses from RINs sales are recorded in cost of sales in the consolidated statements of operations.
Our RINs Obligation is measured at the RINs spot prices obtained from an independent pricing service as of each balance sheet date. However, certain vintage RINs are very thinly traded, and the period end spot prices might not be an accurate reflection of the actual amount that we could purchase RINs in the open market in the quantities that would be
required to satisfy our RINs volume obligation. Please read Note 2 - “Summary of Significant Accounting Policies” for further information on our RINs obligation.
We believe that our small refineries (“the refineries”) qualify for SREs on the merits and we have asked EPA to approve our petitions. The Company has previously applied for and received SREs through 2018, following a structure procedure administered by the EPA. According to documentation we have received from the EPA, the analysis prepared by the Department of Energy (“DOE”) under this procedure showed that the Company’s refineries met the criteria for disproportionate economic hardship for the 2018, 2019 and 2020 compliance years. The reversal of our previously approved 2018 SRE in April 2022, the blanket denial in June 2022 by EPA of our 2019 and 2020 petitions, and the blanket denial in July 2023 by EPA of our 2021 and 2022 petitions were based on EPA’s retroactive across-the-board determination despite the affirmative findings from the DOE that the refineries met the criteria for disproportionate economic hardship.
Management believes that we have viable legal arguments to challenge the denials, including that the denials are inconsistent with the CAA, the Administrative Procedure Act, EPA’s regulations, the DOE’s analysis and/or the factual record, and are unlawful retroactive applications of a new standard. In November 2023, the Fifth Circuit ruled in the Partnership’s favor on the merits of its challenge as it relates to the Shreveport refinery’s 2019 and 2020 SRE petitions, vacated EPA’s denial and remanded it to the EPA, and held that EPA’s denial was impermissibly retroactive and also violated federal law. In January 2024, the Fifth Circuit denied a request to rehear the case. The court’s mandate issued in January 2024, and these SRE petitions are before EPA once again for further consideration consistent with the court’s opinion. The challenge before the D.C. Circuit remains pending. As with any legal action, a challenge to an EPA decision denying the refineries’ SRE petitions may ultimately be unsuccessful. This would present a number of uncertainties and complexities caused primarily by the passage of time since we first submitted the SRE petitions, including for example the potential expiration and/or unavailability or limited availability in the market of vintage 2019, 2020, 2021 and 2022 RINs, the specifics of other potential forthcoming EPA actions, the results of other parties’ potential litigation avenues and outcomes, and post-litigation uncertainties around the timing and magnitude of any resolution.
Based on current information we believe the most likely outcome is either successful appellate litigation or reaching an alternative resolution. If we are ultimately successful in obtaining the refineries’ SREs (or a non-enforcement equivalent), the value of the liability would be zero. If we are ultimately unsuccessful in our appeals, the timing, amount and form our actual liability may depend upon the resolution obtained, potentially as part of subsequent, additional litigation. For example, if resolution for the 2019 and 2020 compliance years used the market price of RINs on the day the EPA was obligated to rule on the refineries’ 2019 SRE petitions, the value of the liability would be approximately $50.7 million.
Recent Accounting Pronouncements
For a summary of recently issued and adopted accounting standards applicable to us, please read Note 2 - “Summary of Significant Accounting Policies” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements.”

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks from adverse changes in commodity prices, the price of credits needed to comply with governmental programs, interest rates and foreign currency exchange rates. Information relating to quantitative and qualitative disclosures about material market risk is set forth below.
Commodity Price Risk
Derivative Instruments
We are exposed to price risks due to fluctuations in the price of crude oil, refined products, natural gas and precious metals. We use various strategies to reduce our exposure to commodity price risk. We do not attempt to eliminate all of our risk as the costs of such actions are believed to be too high in relation to the risk posed to our future cash flows, earnings and liquidity. The strategies we use to reduce our risk utilize both physical forward contracts and financially
settled derivative instruments, such as swaps, collars, options and futures, to attempt to reduce our exposure with respect to:
● crude oil purchases and sales;
● refined product sales and purchases;
● natural gas purchases;
● precious metals; and
● fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as NYMEX WTI, Light Louisiana Sweet, WCS, WTI Midland, Mixed Sweet Blend, Magellan East Houston and ICE Brent.
We manage our exposure to commodity markets, credit, volumetric and liquidity risks to manage our costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability and anticipated future transactions and the changes in fair value of our derivative instruments will affect our earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. We do not speculate with derivative instruments or other contractual arrangements that are not associated with our business objectives. Speculation is defined as increasing our natural position above the maximum position of our physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with our business activities and objectives. Our positions are monitored routinely by a risk management committee and discussed with the board of directors of our general partner quarterly to ensure compliance with our stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by our risk management committee, which will add, remove or revise strategies in anticipation of changes in market conditions and/or in risk profiles. These changes in strategies are to position us in relation to our risk exposures in an attempt to capture market opportunities as they arise.
Please read Note 9 - “Derivatives” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements” for a discussion of the accounting treatment for the various types of derivative instruments, for a further discussion of our hedging policies and for more information relating to our implied crack spreads of crude oil, diesel, and gasoline derivative instruments.
Our derivative instruments and overall hedging positions are monitored regularly by our risk management committee, which includes executive officers. The risk management committee reviews market information and our hedging positions regularly to determine if additional derivatives activity is advised. A summary of derivative positions and a summary of hedging strategy are presented to our general partner’s Board of Directors quarterly.
Compliance Price Risk
Renewable Identification Numbers
We are exposed to market risks related to the volatility in the price of credits needed to comply with governmental programs. The EPA sets annual volume obligations for the percentage of renewable fuels that must be blended into transportation fuels consumed in the U.S., and as a producer of transportation fuels from petroleum, we are subject to those obligations. To the extent we are unable to physically blend renewable fuels to satisfy the EPA requirement, we may purchase RINs in the open market to satisfy the annual obligations. We have not entered into any derivative instruments to manage this risk.
Holding other variables related to RINs obligations constant, a $1.00 increase in the price of RINs would be expected to have a negative impact on Net income (loss) of approximately $65.0 million per year.
Interest Rate Risk
Our exposure to interest rate changes on fixed and variable rate debt is limited to the fair value of the debt issued, which would not have a material impact on our earnings or cash flows. The following table provides information about the fair value of our fixed and variable rate debt obligations as of December 31, 2023 and December 31, 2022, which we disclose in Note 8 - “Long-Term Debt” and Note 10 - “Fair Value Measurements” under Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements.”
December 31, 2023
December 31, 2022
Fair Value
Carrying Value
Fair Value
Carrying Value
(In millions)
Financial Instrument:
2024 Secured Notes
$
179.7
$
178.8
$
203.7
$
199.3
2025 Notes
$
421.1
$
411.5
$
536.1
$
509.2
2027 Notes
$
320.7
$
322.3
$
305.4
$
321.5
2028 Notes
$
325.7
$
319.7
$
-
$
-
Revolving credit facility
$
136.7
$
134.4
$
104.0
$
100.9
MRL revolving credit facility
$
13.0
$
12.4
$
-
$
(0.6)
MRL Term Loan Credit Agreement
$
74.4
$
71.6
$
-
$
-
Shreveport terminal asset financing arrangement
$
50.8
$
50.1
$
58.2
$
57.2
MRL asset financing arrangements
$
384.6
$
381.6
$
370.1
$
368.8
For our variable rate debt, if any, changes in interest rates generally do not impact the fair value of the debt instrument but may impact our future earnings and cash flows. We had a $500.0 million revolving credit facility as of December 31, 2023, with borrowings bearing interest at the prime rate or SOFR, at our option, plus the applicable margin. We had $149.7 million of outstanding variable rate debt as of December 31, 2023 and $104.0 million of outstanding variable rate debt as of December 31, 2022. Holding other variables constant (such as debt levels), a 100 basis point change in interest rates on our variable rate debt as of December 31, 2023, would be expected to have an impact on Net income (loss) of approximately $1.5 million per year.
Foreign Currency Risk
We have minimal exposure to foreign currency risk and as such the cost of hedging this risk is viewed to be in excess of the benefit of further reductions in our exposure to foreign currency exchange rate fluctuations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Board of Directors of Calumet GP, LLC
General Partner and the Partners of Calumet Specialty Products Partners, L.P.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Calumet Specialty Products Partners, L.P. (“the Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income (loss), partners' capital (deficit) and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 29, 2024, expressed an adverse opinion thereon.
Restatement of 2022 Financial Statements
As discussed in Note 21 to the consolidated financial statements, the 2022 consolidated financial statements have been restated to correct a misstatement.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Renewable Identification Numbers (“RINs”) Obligation
Description of the Matter
As of December 31, 2023, the Company’s RINs obligation was $277.3 million. As described in Note 2 to the consolidated financial statements, the RINs obligation is an estimated provision for the future purchase of RINs in order to satisfy the U.S. Environmental Protection Agency’s (“EPA”) annual requirement to blend renewable fuels into certain transportation fuel products pursuant to the Renewable Fuel Standard.
Auditing management’s RINs obligation was complex and judgmental due to estimation uncertainty in the Company’s determination of the RINs obligation under the Renewable Fuel Standard. The complexity and estimation uncertainty was primarily due to the calculation of the RINs shortage and the pricing assumptions, respectively.
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over the RINs obligation estimation process. For example, we tested controls over management’s review of the methodology used to calculate the obligation and the RINs shortage and pricing assumptions, as noted above.
To audit the Company’s RINs obligation, our audit procedures included, among others, evaluating the appropriateness of management’s methodology to calculate the RINs obligation under the Renewable Fuel Standard including testing the completeness and accuracy of the underlying data used by management in estimating the amount of the obligation. We involved our specialists to assist in our evaluation of management’s methodology. Additionally, we compared the prices utilized by the Company in their estimate of the RINs obligation to a third-party pricing source.
We have served as the Company’s auditor since 2002.
/s/ Ernst & Young LLP (PCAOB ID 42)
Indianapolis, Indiana
February 29, 2024
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
Year Ended December 31,
(In millions, except unit data)
ASSETS
(As Restated)
Current assets:
Cash and cash equivalents
$
7.9
$
35.2
Accounts receivable, net:
Trade, less allowance for credit losses of $1.2 million and $1.3 million, respectively
252.4
244.7
Other
33.8
22.4
286.2
267.1
Inventories
439.4
497.7
Derivative assets
9.6
-
Prepaid expenses and other current assets
51.6
19.6
Total current assets
794.7
819.6
Property, plant and equipment, net
1,506.3
1,482.0
Goodwill
173.0
173.0
Other intangible assets, net
28.5
36.3
Operating lease right-of-use assets
114.4
107.5
Other noncurrent assets, net
134.4
122.6
Total assets
$
2,751.3
$
2,741.0
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Accounts payable
$
322.0
$
442.0
Accrued interest payable
48.7
34.6
Accrued salaries, wages and benefits
87.1
93.0
Other taxes payable
13.5
9.5
Obligations under inventory financing agreements
190.4
221.8
Current portion of RINs obligation
277.3
398.9
Derivative liabilities
-
26.5
Current portion of operating lease liabilities
75.6
70.7
Other current liabilities
42.4
34.3
Current portion of long-term debt
55.7
19.6
Total current liabilities
1,112.7
1,350.9
Pension and postretirement benefit obligations
4.2
4.8
Other long-term liabilities
10.4
18.3
Long-term operating lease liabilities
39.0
37.1
Long-term RINs obligation, less current portion
-
77.5
Long-term debt, less current portion
1,829.7
1,540.1
Total liabilities
$
2,996.0
$
3,028.7
Commitments and contingencies
Redeemable noncontrolling interest
$
245.6
$
245.6
Partners’ capital (deficit):
Limited partners’ interest (79,967,363 units and 79,189,583 units, issued and outstanding at December 31, 2023 and December 31, 2022, respectively)
$
(484.4)
$
(525.3)
General partner’s interest
1.3
0.3
Accumulated other comprehensive loss
(7.2)
(8.3)
Total partners’ capital (deficit)
(490.3)
(533.3)
Total liabilities and partners’ capital (deficit)
$
2,751.3
$
2,741.0
See accompanying notes to consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
(In millions, except unit and per unit data)
(As Restated)
Sales
$
4,181.0
$
4,686.3
$
3,148.0
Cost of sales
3,729.3
4,334.6
3,005.1
Gross profit
451.7
351.7
142.9
Operating costs and expenses:
Selling
54.9
53.9
52.8
General and administrative
133.0
143.4
151.1
Taxes other than income taxes
21.5
13.7
12.5
Loss on impairment and disposal of assets
3.5
0.7
4.1
Other operating (income) expense
(28.4)
8.1
8.0
Operating income (loss)
267.2
131.9
(85.6)
Other income (expense):
Interest expense
(221.7)
(175.9)
(149.5)
Debt extinguishment costs
(5.9)
(41.4)
(0.5)
Gain (loss) on derivative instruments
9.9
(81.7)
(23.3)
Other income (expense)
0.2
(2.8)
0.3
Total other expense
(217.5)
(301.8)
(173.0)
Net income (loss) before income taxes
49.7
(169.9)
(258.6)
Income tax expense
1.6
3.4
1.5
Net income (loss)
$
48.1
$
(173.3)
$
(260.1)
Allocation of net income (loss) to partners:
Net income (loss) attributable to partners
$
48.1
$
(173.3)
$
(260.1)
Less:
General partners’ interest in net income (loss)
1.0
(3.5)
(5.2)
Net income (loss) available to limited partners
$
47.1
$
(169.8)
$
(254.9)
Weighted average limited partner units outstanding:
Basic and diluted
80,075,530
79,336,283
78,980,839
Limited partners’ interest basic and diluted net income (loss) per unit:
Limited partners’ interest
$
0.59
$
(2.14)
$
(3.23)
See accompanying notes to consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Year Ended December 31,
(In millions)
(As Restated)
Net income (loss)
$
48.1
$
(173.3)
$
(260.1)
Other comprehensive income:
Defined benefit pension and retiree health benefit plans
1.1
1.8
2.2
Total other comprehensive income
1.1
1.8
2.2
Comprehensive income (loss) attributable to partners’ capital (deficit)
$
49.2
$
(171.5)
$
(257.9)
See accompanying notes to consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (DEFICIT)
Accumulated
Partners’ Capital (Deficit)
Other
Comprehensive
General
Limited
Loss
Partner
Partners
Total
(In millions)
Balance at December 31, 2020
$
(12.3)
$
9.0
$
(125.3)
$
(128.6)
Other comprehensive income
2.2
-
-
2.2
Net loss
-
(5.2)
(254.9)
(260.1)
Settlement of tax withholdings on equity-based incentive compensation
-
-
(0.6)
(0.6)
Amortization of phantom units
-
-
2.0
2.0
Balance at December 31, 2021
$
(10.1)
$
3.8
$
(378.8)
$
(385.1)
Other comprehensive income
1.8
-
-
1.8
Net loss
-
(3.5)
(169.8)
(173.3)
Settlement of phantom units
-
-
8.2
8.2
Settlement of tax withholdings on equity-based incentive compensation
-
-
(4.1)
(4.1)
Modification of phantom units
-
-
13.5
13.5
Amortization of phantom units
-
-
5.7
5.7
Balance at December 31, 2022 (As Restated)
$
(8.3)
$
0.3
$
(525.3)
$
(533.3)
Other comprehensive income
1.1
-
-
1.1
Net income
-
1.0
47.1
48.1
Settlement of phantom units
-
-
2.8
2.8
Settlement of tax withholdings on equity-based incentive compensation
-
-
(9.7)
(9.7)
Amortization of phantom units
-
-
0.7
0.7
Balance at December 31, 2023
$
(7.2)
$
1.3
$
(484.4)
$
(490.3)
See accompanying notes to consolidated financial statements.
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(In millions)
Operating activities
(As Restated)
Net income (loss)
$
48.1
$
(173.3)
$
(260.1)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization
146.8
98.3
107.7
Amortization of turnaround costs
36.1
23.1
17.0
Non-cash interest expense
5.7
17.6
10.6
Debt extinguishment costs
1.6
41.4
0.5
Non-cash RINs (gain) expense
(199.1)
197.5
149.5
Unrealized (gain) loss on derivative instruments
(33.0)
45.9
24.4
Loss on impairment and disposal of assets
3.5
0.7
4.1
Equity based compensation
14.7
17.3
50.7
Lower of cost or market inventory adjustment
33.2
19.4
(44.7)
Other non-cash activities
0.5
2.2
2.4
Changes in assets and liabilities
Accounts receivable
(19.2)
(14.1)
(91.4)
Inventories
25.1
(190.5)
(27.0)
Prepaid expenses and other current assets
(25.9)
(5.6)
(3.7)
Turnaround costs
(47.9)
(62.6)
(61.0)
Other assets
(10.2)
-
-
Accounts payable
(12.4)
56.9
71.0
Accrued interest payable
15.3
8.4
(3.2)
Accrued salaries, wages and benefits
(17.1)
9.5
17.1
Other taxes payable
4.0
(2.1)
2.1
Other liabilities
15.3
10.6
(10.0)
Net cash provided by (used in) operating activities
(14.9)
100.6
(44.0)
Investing activities
Additions to property, plant and equipment
(271.8)
(536.2)
(82.9)
Proceeds from sale of property, plant and equipment
-
0.2
0.1
Net cash used in investing activities
(271.8)
(536.0)
(82.8)
Financing activities
Proceeds from borrowings - revolving credit facility
2,185.0
1,695.1
1,122.1
Repayments of borrowings - revolving credit facility
(2,152.3)
(1,591.1)
(1,230.1)
Proceeds from borrowings - MRL revolving credit agreement
93.2
-
-
Repayments of borrowings - MRL revolving credit agreement
(80.2)
-
-
Proceeds from borrowings - senior notes
325.0
325.0
-
Repayments of borrowings - senior notes
(121.0)
(363.1)
(150.0)
Payments on finance lease obligations
(1.0)
(0.9)
(0.6)
Proceeds from inventory financing
1,712.0
2,166.0
1,046.7
Payments on inventory financing
(1,753.9)
(2,132.6)
(999.2)
Proceeds from sale of redeemable noncontrolling interest in subsidiary
-
250.0
-
Payments for issuance of Preferred Units
-
(4.4)
-
Proceeds from MRL Credit Facility
-
-
300.0
Repayments of borrowings - MRL Credit Facility
-
(347.3)
-
Proceeds from other financing obligations
102.0
372.9
70.0
Payments on other financing obligations
(30.1)
(15.6)
(7.6)
Debt issuance costs
(12.5)
(5.3)
(12.0)
Net cash provided by financing activities
266.2
348.7
139.3
Net increase (decrease) in cash, cash equivalents and restricted cash
(20.5)
(86.7)
12.5
Cash, cash equivalents and restricted cash at beginning of period
35.2
121.9
109.4
Cash, cash equivalents and restricted cash at end of period
$
14.7
$
35.2
$
121.9
Cash and cash equivalents
$
7.9
$
35.2
$
38.1
Restricted cash
$
6.8
$
-
$
83.8
Supplemental disclosure of cash flow information
Interest paid, net of capitalized interest
$
201.9
$
151.4
$
142.9
Supplemental disclosure of non-cash investing activities
Non-cash property, plant and equipment additions
$
31.3
$
136.9
$
51.4
See accompanying notes to consolidated financial statements.
1. Description of the Business
Calumet Specialty Products Partners, L.P. (the “Company”) is a publicly-traded Delaware limited partnership listed on the Nasdaq Global Select Market (“Nasdaq”) under the ticker symbol “CLMT.” The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of December 31, 2023, the Company had 79,967,363 limited partner common units and 1,631,987 general partner equivalent units outstanding. The general partner owns 2% of the Company and all of the incentive distribution rights (as defined in the Company’s partnership agreement, “IDRs”), while the remaining 98% is owned by limited partners.
The Company manufactures, formulates, and markets a diversified slate of specialty branded products and renewable fuels to customers across a broad range of consumer-facing and industrial markets. Calumet is headquartered in Indianapolis, Indiana and operates twelve facilities throughout North America.
2. Summary of Significant Accounting Policies
Consolidation
The consolidated financial statements and related notes reflect the accounts of the Company, its wholly-owned subsidiaries, and its majority-owned subsidiaries. All intercompany profits, transactions and balances have been eliminated.
Reclassifications
Certain amounts in the prior years’ consolidated financial statements have been reclassified to conform to the current year presentation.
Use of Estimates
The Company’s consolidated financial statements are prepared in conformity with U.S. generally accepted accounting principles (“GAAP”) which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash, Cash Equivalents and Restricted Cash
Cash, cash equivalents and restricted cash include all highly liquid investments with a maturity of three months or less at the time of purchase.
Restricted cash as of December 31, 2023 represents cash that is legally restricted under the MRL Term Loan Credit Agreement, and it is included in prepaid expenses and other current assets in the consolidated balance sheets. Restricted cash as of December 31, 2021 represents cash that was legally restricted under the MRL Credit Facility because it was only available for capital additions related to the renewable diesel project.
Accounts Receivable
The Company performs periodic credit evaluations of customers’ financial condition and generally does not require collateral. Accounts receivable are carried at their face amounts. The Company maintains an allowance for credit losses for estimated losses in the collection of accounts receivable. The Company makes estimates regarding the future ability of its customers to make required payments based on historical experience, the age of the accounts receivable balances, credit quality of its customers, current economic conditions, expected future trends and other factors that may affect customers’ ability to pay. Individual accounts are written off against the allowance for credit losses after all reasonable collection efforts have been exhausted.
The activity in the allowance for credit losses was as follows (in millions):
December 31,
Beginning balance
$
1.3
$
2.0
$
0.8
Provision
(0.1)
(0.7)
1.2
Write-offs, net
-
-
-
Ending balance
$
1.2
$
1.3
$
2.0
Inventories
The cost of inventory is recorded using the last-in, first-out (“LIFO”) method. Costs include crude oil and other feedstocks, labor, processing costs and refining overhead costs. Inventories are valued at the lower of cost or market value. The replacement cost of these inventories, based on current market values, would have been $67.8 million and $99.9 million higher than the carrying value of inventory as of December 31, 2023 and 2022, respectively.
For the years ended December 31, 2023 and 2022, the Company sold inventory comprised of crude oil, refined products and renewable feedstocks under Supply and Offtake Agreements as described in Note 7 - “Inventory Financing Agreements” related to the Great Falls, Shreveport and Montana Renewables facilities.
Inventories consist of the following (in millions):
December 31, 2023
December 31, 2022 (As Restated)
Supply and
Supply and
Titled
Offtake
Titled
Offtake
Inventory
Agreements (1)
Total
Inventory
Agreements (1)
Total
Raw materials
$
61.6
$
27.6
$
89.2
$
99.3
$
22.5
$
121.8
Work in process
72.3
36.7
109.0
62.5
95.7
158.2
Finished goods
162.1
79.1
241.2
137.3
80.4
217.7
$
296.0
$
143.4
$
439.4
$
299.1
$
198.6
$
497.7
(1) Amounts represent LIFO value and do not necessarily represent the value at which the inventory was sold. Please read Note 7 - “Inventory Financing Agreements” for further information.
Under the LIFO inventory method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs, resulting in a better matching of costs and revenues. For the year ended December 31, 2023, the Company recorded an increase (exclusive of lower of cost or market (“LCM”) adjustments) of $2.4 million in cost of sales in the consolidated statements of operations due to the liquidation of inventory layers. For the years ended December 31, 2022 and 2021, the Company recorded decreases (exclusive of LCM adjustments) of $12.8 million and $5.6 million, respectively, in cost of sales in the consolidated statements of operations due to the liquidation of inventory layers.
In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. During the years ended December 31, 2023 and 2022, the Company recorded an increase in cost of sales in the consolidated financial statements of operations of $33.2 million and $19.4 million, respectively, substantially all of which was the result of declining market prices for renewable feedstocks at our Montana Renewables facility. During the year ended December 31, 2021, the Company recorded a decrease in cost of sales in the consolidated statements of operations of $44.7 million due to the sale of inventory previously adjusted through the LCM valuation.
Derivatives
The Company is exposed to fluctuations in the price of numerous commodities, such as crude oil (its principal raw material), as well as the sales prices of gasoline, diesel, natural gas and jet fuel. Given the historical volatility of commodity prices, these fluctuations can significantly impact sales, gross profit and net income. Therefore, the Company utilizes derivative instruments primarily to minimize its price risk and volatility of cash flows associated with the purchase of crude oil, natural gas, and the sale of fuel products. The Company employs various hedging strategies and does not hold or issue derivative instruments for trading purposes. For further information, please read Note 9 - “Derivatives.”
On a regular basis, the Company enters into commodity contracts with counterparties for the purchase or sale of crude oil, blendstocks and various finished products. These contracts usually qualify for the normal purchase / normal sale exemption under ASC 815 and, as such, are not measured at fair value.
Property, Plant and Equipment
Property, plant and equipment are stated on the basis of cost. Depreciation is calculated using the straight-line method over the estimated useful lives. Assets under finance leases are amortized over the lesser of the useful life of the asset or the term of the lease.
Property, plant and equipment, including depreciable lives, consisted of the following (in millions):
December 31,
Land
$
8.9
$
8.9
Buildings and improvements (10 to 40 years)
40.4
35.6
Machinery and equipment (10 to 20 years)
2,460.0
2,153.7
Furniture, fixtures and software (5 to 10 years)
47.1
48.7
Assets under finance leases (1 to 14 years) (1)
7.4
6.9
Construction-in-progress
39.5
222.5
2,603.3
2,476.3
Less accumulated depreciation
(1,097.0)
(994.3)
$
1,506.3
$
1,482.0
(1) Assets under finance leases consist of buildings and machinery and equipment. As of December 31, 2023 and 2022, finance lease assets are recorded net of accumulated amortization of $5.0 million and $4.1 million, respectively.
Under the composite depreciation method, the cost of partial retirements of a group is charged to accumulated depreciation. However, when there are dispositions of complete groups or significant portions of groups, the cost and related accumulated depreciation are retired, and any gain or loss is reflected in earnings.
During 2023, 2022 and 2021, the Company incurred $225.1 million, $194.5 million and $151.1 million, respectively, of interest expense of which $3.4 million, $18.6 million and $1.6 million, respectively, was capitalized as a component of property, plant and equipment.
The Company periodically assesses its operations and legal requirements to determine if recognition of an asset retirement obligation is necessary. The Company has not recorded an asset retirement obligation as of December 31, 2023 or 2022 given the timing of any retirement and related costs are currently indeterminable.
During the years ended December 31, 2023, 2022 and 2021, the Company recorded $138.6 million, $88.7 million and $95.9 million, respectively, of depreciation expense on its property, plant and equipment. Depreciation expense included $0.9 million, $0.7 million and $0.7 million for the years ended 2023, 2022 and 2021, respectively, related to the Company’s finance lease assets.
The Company capitalizes the cost of computer software developed or obtained for internal use. Capitalized software is amortized using the straight-line method over five years. As of December 31, 2023 and 2022, the Company had $41.9 million and $43.5 million, respectively, of capitalized software costs. As of December 31, 2023 and 2022, the Company had $40.5 million and $41.4 million, respectively, of accumulated depreciation related to the capitalized software costs. During the years ended December 31, 2023, 2022 and 2021, the Company recorded $0.7 million, $5.4 million and $7.8 million, respectively, of amortization expense on capitalized computer software.
Goodwill
Goodwill represents the excess of purchase price over fair value of the net assets acquired in various acquisitions. Please read Note 5 - “Goodwill and Other Intangible Assets” for more information. The Company assesses goodwill for impairment annually and whenever events or changes in circumstances indicate its carrying value may not be recoverable in accordance with ASC 350, Intangibles - Goodwill and Other (Topic 350) and ASU 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. Under ASC 350, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the impairment test is unnecessary. The Company tests goodwill either quantitatively or qualitatively for impairment. The Company assessed goodwill for impairment qualitatively for the year ended December 31, 2023 and qualitatively and quantitatively for the year ended December 31, 2022.
In assessing the qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company assesses relevant events and circumstances that may impact the fair value and the carrying amount of the reporting unit. The identification of relevant events and circumstances and how these may impact a reporting unit’s fair value or carrying amount involve significant judgment and assumptions. The judgment and assumptions include the identification of macroeconomic conditions, industry and market considerations, cost factors, overall financial performance and Company specific events and making the assessment on whether each relevant factor will impact the impairment test positively or negatively and the magnitude of any such impact.
In the first step of the quantitative assessment, the Company’s assets and liabilities, including existing goodwill and other intangible assets, are assigned to the identified reporting units to determine the carrying value of the reporting units. Under ASU 2017-04, goodwill impairment testing is done by comparing the fair value of the reporting unit to its carrying value. If the carrying amount exceeds the fair value, the Company would recognize an impairment charge for the amount that the reporting unit’s carrying value exceeds the fair value, not to exceed the total amount of goodwill allocated to that reporting unit.
When performing the quantitative assessment, the fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of the reporting unit, measuring the current value of the reporting unit by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation, and risks associated with the reporting unit. For more information, please read Note 5 - “Goodwill and Other Intangible Assets.”
Finite-Lived Intangible Assets
Finite-lived intangible assets consist of intangible assets associated with customer relationships, tradenames, trade secrets, patents and royalty agreements that were acquired in various acquisitions. The majority of these assets are being amortized using undiscounted estimated future cash flows over the term of the related agreements. Intangible assets associated with customer relationships are being amortized using the undiscounted estimated future cash flows method based upon assumed rates of annual customer attrition. For more information, please read Note 5 - “Goodwill and Other Intangible Assets.”
Other Noncurrent Assets
Other noncurrent assets include turnaround costs. Turnaround costs represent capitalized costs associated with the Company’s periodic major maintenance and repairs and the net carrying value of turnaround costs included in other noncurrent assets in the consolidated balance sheets were $129.3 million and $119.7 million as of December 31, 2023 and 2022, respectively. The Company capitalizes these costs and amortizes the costs on a straight-line basis over the lives of the turnaround assets which is generally two to five years. These amounts are net of accumulated amortization of $68.9 million and $54.0 million at December 31, 2023 and 2022, respectively.
Renewable Identification Numbers (“RINs”) Obligation
The Company’s RINs volume obligation (“RVO” or “RINs Obligation”) is an estimated provision if future purchase of RINs were to be required in order to satisfy the U.S. Environmental Protection Agency’s (“EPA”) requirement to blend renewable fuels into certain transportation fuel products pursuant to the Renewable Fuel Standard (“RFS”) of the Clean Air Act (“CAA”). The Company has historically not been obligated to make these purchases. A RIN is a 38-character number assigned to each physical gallon of renewable fuel produced in or imported into the United States. The EPA sets annual volume obligations for the percentage of renewable fuels that must be blended into transportation fuels consumed in the U.S. Compliance is demonstrated by tendering RINs to the EPA documenting that blending has been accomplished or by obtaining a Small Refinery Exemption as provided in the Clean Air Act. Prior to 2018, the Company historically received the Small Refinery Exemption after qualifying on the merits. The Company’s petitions for the Small Refinery Exemption for compliance years 2018-2022 ultimately were denied by the EPA. EPA’s denials of those petitions is subject to litigation, as described below. Future exemptions are the subject of future annual applications. The RIN obligation is a non-financial instrument representing a quantity that cannot be settled financially.
The Company accounts for its current period RVO by multiplying the quantity of RINs shortage (based on actual results) by the period end RINs spot price, which is recorded as both a current and long-term liability in the consolidated balance sheets. These liabilities are revalued at the end of each subsequent accounting period, which produce non-cash mark-to-market adjustments that are reflected in cost of sales in the consolidated statements of operations (with the exception of RINs for compliance year 2019 related to the San Antonio refinery, which amount is reflected in other operating expense in the consolidated statements of operations). RINs generated by blending may be sold or held to offset future RVO. Any gains or losses from RINs sales are recorded in cost of sales in the consolidated statements of operations.
The RFS provision of the CAA allows small refineries to apply at any time for a Small Refinery Exemption (“SRE”) from the renewable blending requirements, and we have applied in respect of compliance years 2019, 2020, 2021, 2022 and 2023.
2018 RVO. In April 2022, EPA issued new decisions denying 36 petitions from small refineries seeking SREs for program year 2018 that had been remanded by the U.S. Court of Appeals for the D.C. Circuit to EPA. EPA had previously granted 31 of these 36 petitions in August 2019, including petitions from the Company. Concurrent with the April 2022 denial action, EPA provided an alternate compliance approach to allow these 31 small refineries to meet their 2018 compliance obligations without purchasing or redeeming additional RINs. In April 2022, the Company filed a petition for review of EPA’s denial of the 2018 SRE petition for the Shreveport refinery in the U.S. Court of Appeals for the Fifth Circuit. In June 2022, the Company filed a petition for review of EPA’s denial of the 2018 SRE petition for the Montana refinery in the U.S. Court of Appeals for the Ninth Circuit and filed a protective petition for review in the U.S. Court of Appeals for the D.C. Circuit challenging the EPA’s denials of both the Shreveport and Montana refineries’ petitions. Upon a motion made by EPA, the Ninth Circuit dismissed the Company’s appeal of the denial of the Montana refinery’s 2018 SRE petition for improper venue in favor of the D.C. Circuit appeal. EPA filed a similar motion to dismiss or transfer in the Fifth Circuit; however, the Fifth Circuit denied EPA’s motion and ordered the merits panel to consider both the merits of the appeal and the venue question raised by EPA. These 2018 RVO appeals were consolidated with the 2019-2020 RVO appeals described below.
2019-2020 RVO. In June 2022, EPA issued final decisions denying 69 pending petitions from small refineries seeking SREs for compliance years 2016 to 2021, including petitions submitted by the Company seeking exemptions for program years 2019 and 2020, based on an across-the-board determination that no small refinery suffers disproportionate
economic hardship from the RFS program, a contention which was subsequently rejected by the Government Accountability Office. In September 2022, EPA finalized an alternative RIN retirement schedule for small refineries. The alternative RIN retirement schedule allows the use of RINs generated in post-2020 compliance years to meet the 2020 RFS obligations. The Company’s small refineries are eligible to use this alternative schedule. In August 2022, the Company filed a petition for review of EPA’s denial of the 2019 and 2020 SRE petitions for the Shreveport refinery in the U.S. Court of Appeals for the Fifth Circuit, and a petition for review of EPA’s denial of the 2019 and 2020 SRE petitions for the Montana refinery in the U.S. Court of Appeals for the Ninth Circuit. The Company again filed a protective petition for review in the U.S. Court of Appeals for the D.C. Circuit challenging both of the EPA’s denials. These appeals have been consolidated with the applicable program year 2018 appeals. Upon a motion made by EPA, the Ninth Circuit transferred the Company’s Montana appeal, which is now pending in the D.C. Circuit. The Fifth Circuit denied EPA’s request to dismiss or transfer the appeal, ruling that merits panel will also consider EPA’s argument that the Shreveport refinery appeals should be transferred to the D.C. Circuit. The Company filed motions in both appeals asking the circuit courts to stay the Company’s 2019 and 2020 RFS obligations while the merits appeals are pending. In January 2023, the Fifth Circuit granted the Company’s motion for stay relating to the Shreveport refinery, and in March 2023, the D.C. Circuit granted the Company’s motion for stay relating to the Montana refinery. The stays granted by each of the respective circuits hold that the Company is likely to be successful on the merits of its appeals. In November 2023, the Fifth Circuit issued its decision and found that venue for the appeal is proper in the Fifth Circuit and that EPA’s denial of the Shreveport refinery’s petitions for program years 2018-2020 was improper. The Fifth Circuit vacated the EPA’s denials of those petitions and remanded the petitions to EPA.
2021-2022 RVO. In October 2022, Calumet applied for SREs for 2021 and 2022 compliance years. In April 2023, the Company filed for injunctive relief in both the District Court of Montana and the Western District Court of Louisiana to force EPA to make a decision on the Montana and Shreveport refineries’ joint 2021 and 2022 SRE applications. In July 2023, EPA issued final decisions denying 26 pending petitions from small refineries seeking SREs for compliance years 2016 to 2023, including petitions submitted by the Company seeking exemptions for program years 2021 and 2022, based on the same approach and analysis described in the June 2022 denials. EPA’s denial decision renders the district court actions moot, and the Company voluntarily dismissed those actions. The Company then filed appeals of the denials with the Fifth Circuit and D.C. Circuit. In September 2023, the Fifth Circuit granted the Company’s motion for stay relating to the Shreveport refinery for its appeal of the denial for program years 2021 and 2022, and in October 2023, the D.C. Circuit granted the Company’s motion for stay relating to the Montana refinery’s appeal of the denial for program years 2021 and 2022. The Company’s appeals of the denial of the Shreveport and Great Falls refinery petitions for program years 2021 and 2022 remain pending in the Fifth Circuit and D.C. Circuit, respectively.
Expenses related to RFS compliance have the potential to remain a significant expense for the Specialty Products and Solutions and Montana/Renewables segments. If legal or regulatory changes occur that have the effect of increasing the RINs Obligation, increasing the market price of RINs, or eliminating or narrowing the availability of SREs, the Company could be required to purchase additional RINs in the open market, which may materially increase the costs related to RFS compliance and could have a material adverse effect on the results of operations and liquidity.
As of December 31, 2023 and 2022, as restated, the Company had a RINs Obligation recorded on the consolidated balance sheets of $277.3 million and $476.4 million, respectively.
Impairment of Long-Lived Assets
The Company periodically evaluates the carrying value of long-lived assets to be held and used, including finite-lived intangible assets, when events or circumstances warrant such a review. The carrying value of a long-lived asset to be held and used is considered impaired when the anticipated separately identifiable undiscounted cash flows from such an asset are less than the carrying value of the asset. In such an event, a write-down of the asset would be recorded through a charge to operations, based on the amount by which the carrying value exceeds the fair value of the long-lived asset. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved. Long-lived assets to be disposed of other than by sale are considered held and used until disposal.
During the years ended December 31, 2023 and 2022, the Company did not identify any impairment indicators that suggested the carrying values of its long-lived assets are not recoverable at the asset groups within the Specialty Products
and Solutions, Montana/Renewables, Performance Brands and Corporate segments. As a result of the long-lived asset impairment assessment performed, no impairment charges were recorded for the years ended December 31, 2023, 2022 and 2021.
Revenue Recognition
The Company recognizes revenue in accordance with ASC 606, Revenue Recognition, which states that revenue is recognized when control of the promised goods are transferred to the customer, in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods. Please read Note 3 - “Revenue Recognition” for additional information on our revenue recognition accounting policies and elections.
Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into “in contemplation” of one another, are combined and reported as a net purchase in cost of sales in the consolidated statements of operations.
Concentrations of Credit Risk
The Company performs periodic credit evaluations of its customers’ financial condition and in some instances requires cash in advance or letters of credit prior to shipment for domestic orders. For international orders, letters of credit are generally required, and the Company maintains insurance policies which cover certain export orders. The Company maintains an allowance for credit losses for estimated losses resulting from the inability of its customers to make required payments. The allowance for credit losses is developed based on several factors including historical experience, the age of the accounts receivable balances, credit quality of the Company’s customers, current economic conditions, expected future trends and other factors that may affect customers’ ability to pay, which exist as of the balance sheet dates. If the financial condition of the Company’s customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. The Company has derivative positions with a limited number of counterparties. The evaluation of these counterparties is performed quarterly in connection with the Company’s ASC 820-10, Fair Value Measurements and Disclosures, valuations to determine the impact of the counterparty credit risk on the valuation of its derivative instruments.
Earnings per Unit
The Company calculates earnings per unit under ASC 260-10, Earnings per Share. The Company treats incentive distribution rights (“IDRs”) as participating securities for the purposes of computing earnings per unit in the period that the general partner becomes contractually entitled to receive IDRs. Also, the undistributed earnings are allocated to the partnership interests based on the allocation of earnings to the Company’s partners’ capital accounts as specified in the Company’s partnership agreement.
Unit-Based Compensation
For unit-based compensation equity awards, compensation expense is recognized in the Company’s consolidated financial statements on a straight-line basis over the awards’ vesting periods based on their fair values on the dates of grant. The unit-based compensation awards vest over a period not exceeding four years. The amount of compensation expense recognized at any date is at least equal to the portion of the grant date value of the award that is vested at that date. For more information, please read Note 12 - “Unit-Based Compensation.”
Unit-based compensation liability awards are awards that are currently expected to be settled in cash on their vesting dates rather than in units (“Liability Awards”). Liability Awards are recorded in accrued salaries, wages and benefits based on the vested portion of the fair value of the awards on the balance sheet date. The fair value of Liability Awards is updated at each balance sheet date and changes in the fair value of the vested portions of the Liability Awards are recorded as increases or decreases to compensation expense. The Company recognizes forfeitures as they occur. Please read Note 12 - “Unit-Based Compensation” for more information on Liability Awards.
Advertising Expenses
The Company expenses advertising costs as incurred which totaled $10.6 million, $9.1 million and $7.4 million for the years ended December 31, 2023, 2022, and 2021, respectively. Advertising expenses are reported as selling expenses in the consolidated statements of operations.
3. Revenue Recognition
The following is a description of principal activities from which the Company generates revenue. Revenues are recognized when control of the promised goods are transferred to the customer, in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods. To determine revenue recognition for arrangements that an entity determines are within the scope of ASC 606, the Company performs the following five steps: (i) identify the contract(s) with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the entity satisfies a performance obligation. At contract inception, once the contract is determined to be within the scope of ASC 606, the Company assesses the goods promised within each contract and determines the performance obligations and assesses whether each promised good is distinct. The Company then recognizes as revenue the amount of the transaction price that is allocated to the respective performance obligation when (or as) the performance obligation is satisfied.
Products
The Company manufactures, formulates, and markets a diversified slate of specialty branded products to customers in various consumer-facing and industrial markets. In addition, the Company produces fuel and fuel related products, including gasoline, diesel, jet fuel, asphalt, and other fuels products. At our Montana Renewables facility, we process a variety of geographically advantaged renewable feedstocks into renewable fuels, including: renewable diesel, sustainable aviation fuel, renewable hydrogen, renewable natural gas, renewable propane, and renewable naphtha. These renewable fuels are distributed into renewable markets in the western half of North America. The Company also blends, packages and markets high-performance branded specialty products through its Royal Purple, Bel-Ray, and TruFuel brands.
The Company considers customer purchase orders, which in some cases are governed by master sales agreements, to be the contracts with a customer. For each contract, the Company considers the promise to transfer products, each of which are distinct, to be the identified performance obligations. In determining the transaction price, the Company evaluates whether the price is subject to variable consideration such as product returns, rebates or other discounts to determine the net consideration to which the Company expects to be entitled. The Company transfers control and recognizes revenue upon shipment to the customer or, in certain cases, upon receipt by the customer in accordance with contractual terms.
Revenue is recognized when obligations under the terms of a contract with a customer are satisfied and control of the promised goods are transferred to the customer. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. For fuel products, payment is typically due in full between 2 to 30 days of delivery or the start of the contract term, such that payment is typically collected 2 to 30 days subsequent to the satisfaction of performance obligations. For renewable fuel products, payment is typically due in full between 7 to 14 days of delivery or the start of the contract term, such that payment is typically collected 7 to 14 days subsequent to the satisfaction of performance obligations. For specialty products, payment is typically due in full between 30 to 90 days of delivery or the start of the contract term, such that payment is typically collected 30 to 90 days subsequent to the satisfaction of performance obligations. In the normal course of business, the Company does not accept product returns unless the item is defective as manufactured. The expected costs associated with a product assurance warranty continues to be recognized as expense when products are sold. The Company does not offer promised services that could be considered warranties that are sold separately or provide a service in addition to assurance that the related product complies with agreed upon specifications. The Company establishes provisions based on the methods described in ASC 606 for estimated returns and warranties as variable consideration when determining the transaction price.
Excise and Sales Taxes
The Company assesses, collects and remits excise taxes associated with the sale of certain of its fuel products. Furthermore, the Company collects and remits sales taxes associated with certain sales of its products to non-exempt customers. The Company excludes excise taxes and sales taxes that are collected from customers from the transaction price in its contracts with customers. Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers and remitted to taxing authorities.
Shipping and Handling Costs
Shipping and handling costs are deemed to be fulfillment activities rather than a separate distinct performance obligation.
Cost of Obtaining Contracts
The Company may incur incremental costs to obtain a sales contract, which under ASC 606 should be capitalized and amortized over the life of the contract. The Company has elected to apply the practical expedient in ASC 340-40-50-5 allowing the Company to expense these costs since the contracts are short-term in nature with a contract term of one year or less.
Contract Balances
Under product sales contracts, the Company invoices customers for performance obligations that have been satisfied, at which point payment is unconditional. Accordingly, a product sales contract does not give rise to contract assets or liabilities under ASC 606. The Company’s receivables, net of allowance for expected credit losses from contracts with customers as of December 31, 2023 and 2022, as restated, was $252.4 million and $244.7 million, respectively.
Transaction Price Allocated to Remaining Performance Obligations
The Company’s product sales are short-term in nature with a contract term of one year or less. The Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Additionally, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
4. Leases
The Company has various operating and finance leases primarily for the use of land, storage tanks, railcars, equipment, precious metals and office facilities that have remaining lease terms of greater than one year to sixteen years, some of which include options to extend the lease for up to 32 years, and some of which include options to terminate the lease within one year.
Supplemental balance sheet information related to the Company’s leases for the periods presented were as follows (in millions):
December 31,
December 31,
Assets:
Classification:
Operating lease assets
Other noncurrent assets, net
$
114.4
$
107.5
Finance lease assets
Property, plant and equipment, net (1)
2.4
2.8
Total leased assets
$
116.8
$
110.3
Liabilities:
Current
Operating
Other current liabilities
$
75.6
$
70.7
Finance
Current portion of long-term debt
1.1
0.9
Non-current
Operating
Other long-term liabilities
39.0
37.1
Finance
Long-term debt, less current portion
1.9
2.5
Total lease liabilities
$
117.6
$
111.2
(1) As of December 31, 2023 and 2022, finance lease assets are recorded net of accumulated amortization of $5.0 million and $4.1 million, respectively.
Lease expense for lease payments is recognized on a straight-line basis over the lease term. The components of lease expense related to the Company’s leases for the periods presented were as follows (in millions):
December 31,
Lease Costs:
Classification:
Fixed operating lease cost
Cost of Sales; SG&A Expenses
$
75.6
$
75.4
$
51.5
Short-term operating lease cost (1)
Cost of Sales; SG&A Expenses
9.5
8.2
7.8
Variable operating lease cost (2)
Cost of Sales; SG&A Expenses
3.6
19.2
13.8
Finance lease cost:
Amortization of finance lease assets
Cost of Sales
0.9
0.7
0.7
Interest on lease liabilities
Interest expense
0.2
1.3
0.4
Total lease cost
$
89.8
$
104.8
$
74.2
(1) The Company’s leases with an initial term of 12 months or less are not recorded on the consolidated balance sheets.
(2) The Company’s railcar leases typically include a mileage limit the railcar can travel over the life of the lease. For any mileage incurred over this limit, the Company is obligated to pay an agreed upon dollar value for each mile that is traveled over the limit.
Operating lease expense included in the consolidated statements of operations was $88.7 million, $102.8 million and $73.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. Cash paid related to operating lease obligations approximated lease expense for 2023, 2022 and 2021, respectively.
As of December 31, 2023, the Company had estimated minimum commitments for the payment of rentals under leases which, at inception, had a noncancelable term of more than one year, as follows (in millions):
Operating
Finance
Maturity of Lease Liabilities
Leases (1)
Leases (2)
Total
$
81.8
$
1.2
$
83.0
18.8
0.9
19.7
9.8
0.8
10.6
7.1
0.3
7.4
4.3
0.1
4.4
Thereafter
4.9
-
4.9
Total
$
126.7
$
3.3
$
130.0
Less: Interest
12.1
0.3
12.4
Present value of lease liabilities
$
114.6
$
3.0
$
117.6
Less obligations due within one year
75.6
1.1
76.7
Long-term lease obligation
$
39.0
$
1.9
$
40.9
(1) As of December 31, 2023, the Company’s operating lease payments included no material options to extend lease terms that are reasonably certain of being exercised. The Company has no legally binding minimum lease payments for leases signed but not yet commenced as of December 31, 2023.
(2) As of December 31, 2023, the Company’s finance lease payments included no material options to extend lease terms that are reasonably certain of being exercised. In addition, the Company has no legally binding minimum lease payments for leases that have been signed but not yet commenced as of December 31, 2023.
Weighted-Average Lease Term and Discount Rate
The weighted-average remaining lease term and weighted-average discount rate for the Company’s operating and finance leases for the periods presented were as follows:
December 31,
December 31,
Lease Term and Discount Rate:
Weighted-average remaining lease term (years):
Operating leases
2.6
2.7
Finance leases
3.1
3.9
Weighted-average discount rate:
Operating leases
8.6
%
6.9
%
Finance leases
7.3
%
7.1
%
5. Goodwill and Other Intangible Assets
For the years ended December 31, 2023 and 2022, the Company performed its annual goodwill assessment for each of the years then ended, and determined that the fair value of each of its reporting units with goodwill exceeded its carrying value. Thus, no impairment charge for goodwill related to the Specialty Products and Solutions segment or Performance Brands segment was recorded in the consolidated statements of operations for the years ended December 31, 2023 and 2022, respectively. There is no goodwill within the reporting units for the Montana/Renewables segment or the Corporate segment.
Inputs used to estimate the fair value of the Company’s reporting units are considered Level 3 inputs of the fair value hierarchy and include the following:
● The Company’s financial projections for its reporting units are based on its analysis of various supply and demand factors which include, among other things, industry-wide capacity, its planned utilization rate, end-user demand, crack spreads, capital expenditures and economic conditions. Such estimates are consistent with those used in the
Company’s planning and capital investment reviews and include recent historical prices and published forward prices.
● The discount rate used to measure the present value of the projected future cash flows is based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible.
For Level 3 measurements, significant increases or decreases in long-term growth rates or discount rates in isolation or in combination could result in a significantly lower or higher fair value measurement.
Changes in goodwill balances for the periods indicated below are as follows (in millions):
Specialty
Products and
Performance
Consolidated
Solutions
Brands
Total
Net balance as of December 31, 2021
$
49.3
$
123.7
$
173.0
Additions
-
-
-
Impairment (1)
-
-
-
Net balance as of December 31, 2022
$
49.3
$
123.7
$
173.0
Additions
-
-
-
Impairment (1)
-
-
-
Net balance as of December 31, 2023
$
49.3
$
123.7
$
173.0
(1) Total accumulated goodwill impairment as of December 31, 2023 and 2022, is $35.5 million.
Other intangible assets consist of the following (in millions):
Weighted
December 31, 2023
December 31, 2022
Average Life
Accumulated
Accumulated
(Years)
Gross Amount
Amortization
Gross Amount
Amortization
Customer relationships
$
181.8
$
(158.8)
$
181.8
$
(153.6)
Tradenames
26.8
(24.9)
26.8
(23.7)
Trade secrets
52.9
(51.2)
52.9
(50.1)
Patents
1.6
(1.6)
1.6
(1.6)
Royalty agreements
6.1
(4.2)
6.1
(3.9)
$
269.2
$
(240.7)
$
269.2
$
(232.9)
Tradenames, trade secrets, patents and royalty agreements are being amortized to properly match expenses with the undiscounted estimated future cash flows over the terms of the related agreements or the period expected to be benefited. The costs of agreements with terms allowing for the potential extension of such agreements are being amortized based on the initial term only. Customer relationships are being amortized to properly match expenses with the undiscounted estimated future cash flows based upon assumed rates of annual customer attrition. For the years ended December 31, 2023, 2022 and 2021, the Company recorded amortization expense of intangible assets of $7.8 million, $9.5 million and $11.8 million, respectively.
As of December 31, 2023, the Company estimates that amortization of intangible assets for the next five years will be as follows (in millions):
Amortization
Year
Amount
$
6.5
$
4.9
$
3.8
$
3.2
$
2.3
6. Commitments and Contingencies
Contingencies
From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various taxation and regulatory authorities, such as the Internal Revenue Service, the EPA and the U.S. Occupational Safety and Health Administration (“OSHA”), as well as various state environmental regulatory bodies and state and local departments of revenue, as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company.
Environmental
The Company conducts crude oil and specialty refining, blending and terminal operations and such activities are subject to stringent federal, regional, state and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose obligations that are applicable to the Company’s operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities for pollution resulting from its operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects and the issuance of injunctive relief limiting or prohibiting Company activities. Moreover, certain of these laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes or other materials have been released or disposed. In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments, some of which legal requirements are discussed below, could significantly increase the Company’s operational or compliance expenditures.
Remediation of subsurface contamination is in process at certain of the Company’s refinery sites and is being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the soil and groundwater contamination at these refineries can be controlled or remediated without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material.
Occupational Health and Safety
The Company is subject to various laws and regulations relating to occupational health and safety, including the federal Occupational Safety and Health Act, as amended, and comparable state laws. These laws and regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the EPA’s community right-to-know regulations under Title III of the federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and similar state statutes require the Company to maintain information about hazardous materials used or produced in the Company’s operations and provide this information to employees, contractors,
state and local government authorities and customers. The Company maintains safety and training programs as part of its ongoing efforts to promote compliance with applicable laws and regulations. The Company conducts periodic audits of process safety management systems at each of its locations subject to this standard. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges.
Labor Matters
The Company has approximately 600 employees covered by various collective bargaining agreements, or approximately 38% of its total workforce of approximately 1,580 employees. These agreements have expiration dates of April 30, 2026, July 31, 2026, November 19, 2026, January 31, 2027, April 30, 2025, August 20, 2024 and December 12, 2024. The Company has approximately 93 employees, or 6% of its total workforce, who are covered by a collective bargaining agreement which will expire in less than one year and does not expect any work stoppages.
Other Matters, Claims and Legal Proceedings
The Company is subject to other matters, claims and litigation incidental to its business. The Company has recorded accruals with respect to certain of its matters, claims and litigation where appropriate, that are reflected in the audited consolidated financial statements but are not individually considered material. For other matters, claims and litigation, the Company has not recorded accruals because it has not yet determined that a loss is probable or because the amount of loss cannot be reasonably estimated. While the ultimate outcome of matters, claims and litigation currently pending cannot be determined, the Company currently does not expect these outcomes, individually or in the aggregate (including matters for which the Company has recorded accruals), to have a material adverse effect on its financial position, results of operations or cash flows. The outcome of any matter, claim or litigation is inherently uncertain, however, and if decided adversely to the Company, or if the Company determines that settlement of particular litigation is appropriate, the Company may be subject to liability that could have a material adverse effect on its financial position, results of operations or cash flows.
Standby Letters of Credit
The Company has agreements with various financial institutions for standby letters of credit which have been issued primarily to vendors. As of December 31, 2023 and 2022, the Company had outstanding standby letters of credit of $29.9 million and $35.8 million, respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Please read Note 8 - “Long-Term Debt” for additional information regarding the Company’s revolving credit facility. At December 31, 2023 and 2022, the maximum amount of letters of credit the Company could issue under its revolving credit facility was subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $255.0 million, which may be increased with consent of the Agent (as defined in the Credit Agreement) to 90% of revolver commitments then in effect ($500.0 million at December 31, 2023 and 2022).
As of December 31, 2023 and 2022, the Company had availability to issue letters of credit of approximately $238.2 million and approximately $337.6 million, respectively, under its revolving credit facility.
Crude Oil Supply, Other Feedstocks and Finished Products
Purchase commitments consist primarily of obligations to purchase fixed volumes of crude oil, other feedstocks and finished products for resale from various suppliers based on current market prices at the time of delivery. The Company is currently purchasing a majority of its crude oil under month-to-month evergreen contracts or on a spot basis. Certain other feedstocks are purchased under various term supply agreements.
As of December 31, 2023, the estimated minimum purchase commitments under the Company’s crude oil, other feedstock supply and finished product agreements were as follows (in millions):
Year
Commitment
2024 (1)
$
181.9
28.2
28.2
13.7
-
Thereafter
-
Total
$
252.0
(1) For the year ended December 31, 2023, the Company recorded a $50.6 million charge to cost of sales for expected future losses under firm purchase commitments.
Throughput Contract
Prior to 2020, the Company entered into a long-term agreement to transport crude oil at a minimum of 5,000 bpd through a pipeline, which commenced service in the second quarter of 2020. The agreement also contains a capital recovery charge that increases 2% per annum. The agreement is for seven years.
As of December 31, 2023, the estimated minimum unconditional purchase commitments, including the capital recovery charge, under the agreement were as follows (in millions):
Year
Commitment
$
4.0
4.0
4.0
2.4
-
Thereafter
-
Total (1)
$
14.4
(1) As of December 31, 2023, the estimated minimum payments for the unconditional purchase commitments have been accrued and are included in other current liabilities and other long-term liabilities in the consolidated balance sheets. This liability was accrued due to the fact that the contract was entered into to supply crude to a divested facility.
7. Inventory Financing Agreements
On January 17, 2024 (the “Effective Date”), the Company and J. Aron entered into a Monetization Master Agreement (the “Master Agreement”), a related Financing Agreement (the “Financing Agreement”) and Supply and Offtake Agreement (together with the Master Agreement and the Financing Agreement, the “Shreveport Supply and Offtake Agreement”). Pursuant to the Shreveport Supply and Offtake Agreement, J. Aron agreed to, among other things, purchase from the Company, or extend to the Company, financial accommodations secured by crude oil and finished products located at the Company’s Shreveport facility on the Effective Date and from time to time, up to maximum volumes specified for crude oil and categories of finished products, subject to the Company’s repurchase obligations with respect thereto. The Shreveport Supply and Offtake Agreement replaced the Company’s previous inventory financing agreement with Macquarie, which terminated on January 17, 2024.
In March 2017, the Company entered into an agreement with Macquarie to support the operations of the Great Falls refinery (as amended, the “Great Falls Supply and Offtake Agreement”). The Great Falls Supply and Offtake Agreement terminated on December 13, 2023. The inventories that were previously associated with the Great Falls Supply and Offtake Agreement were added back to our revolving credit facility borrowing base. Upon termination of the Great Falls Supply and Offtake Agreement, the Company recognized a $17.9 million realized loss on derivative instruments, which was
included in gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2023.
On October 3, 2023, Montana Renewables, LLC (“MRL”) and Wells Fargo Commodities, LLC (“Wells Fargo”) entered into (a) an ISDA 2002 Master Agreement (the “Master Agreement”), (ii) a Schedule to the ISDA 2002 Master Agreement (the “Schedule”), (iii) a Credit Support Annex to the ISDA 2002 Master Agreement (the “Credit Support Annex”), and (iv) a Renewable Fuel and Feedstock Repurchase Master Confirmation (together with the Master Agreement, the Schedule and the Credit Support Annex, collectively the “MRL Supply and Offtake Agreement” and, together with the Shreveport Supply and Offtake Agreement, the “Supply and Offtake Agreements”). Pursuant to the MRL Supply and Offtake Agreement, Wells Fargo agreed to, among other things, (a) purchase from MRL renewable feedstocks and finished products located at MRL’s Great Falls facility, subject to MRL’s repurchase obligations with respect thereto, and (b) provide certain financial accommodations to MRL secured by liens on certain renewable feedstocks and finished products owned by MRL. The MRL Supply and Offtake Agreement replaced MRL’s previous inventory financing agreement with Macquarie, which terminated on October 3, 2023. Upon termination of the inventory financing agreement with Macquarie, the Company recognized a $7.7 million realized gain on derivative instruments, which was included in gain (loss) on derivative instruments in the consolidated statements of operations for the year ended December 31, 2023.
While title to certain inventories will reside with the counterparties to the arrangements, the Supply and Offtake Agreements are accounted for by the Company similar to a product financing arrangement; therefore, the inventories sold to the counterparties will continue to be included in the Company’s consolidated balance sheets until processed and sold to a third party.
For the years ended December 31, 2023, 2022 and 2021, the Company incurred an expense of $32.0 million, $30.6 million, and $15.4 million, respectively, for financing costs related to the Supply and Offtake Agreements, which are included in interest expense in the Company’s consolidated statements of operations.
The Company’s inventory financing arrangements with Macquarie in effect as of December 31, 2023, as it related to the Company’s Shreveport facility, and in effect as of December 31, 2022, as it related to the Company’s Shreveport and Great Falls facilities, included a deferred payment arrangement (the “Deferred Payment Arrangement”) whereby the Company could defer payments on just-in-time crude oil purchases from Macquarie owed under the agreements up to the value of the collateral provided (90% of the collateral was inventory). The deferred amounts under the Deferred Payment Arrangement bore interest at a rate equal to the SOFR plus 3.25% per annum. Amounts outstanding under the Deferred Payment Arrangement were included in obligations under inventory financing agreements in the Company’s consolidated balance sheets. Changes in the amount outstanding under the Deferred Payment Arrangement were included within cash flows from financing activities in the consolidated statements of cash flows. As of December 31, 2022 and December 31, 2021, the Company had $14.1 million and $36.0 million of deferred payments outstanding, for the inventory financing arrangements with Macquarie then in effect, respectively.
8. Long-Term Debt
Long-term debt consisted of the following (in millions):
December 31,
December 31,
2022 (As Restated)
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due January 2027, weighted average interest rates of 7.4% and 4.7% for the year ended December 31, 2023 and the year ended December 31, 2022, respectively.
$
136.7
$
104.0
Borrowings under amended secured MRL revolving credit agreement with third-party lender, interest payments quarterly, borrowings due November 2027, weighted average interest rate of 11.2% for the year ended December 31, 2023.
13.0
-
Borrowings under the 2024 Secured Notes, interest at a fixed rate of 9.25%, interest payments semiannually, borrowings due July 2024, effective interest rate of 9.5% for the years ended December 31, 2023 and December 31, 2022. (1)
179.0
200.0
Borrowings under the 2025 Notes, interest at a fixed rate of 11.0%, interest payments semiannually, borrowings due April 2025, effective interest rate of 11.4% for the years ended December 31, 2023 and December 31, 2022.
413.5
513.5
Borrowings under the 2027 Notes, interest at a fixed rate of 8.125%, interest payments semiannually, borrowings due July 2027, effective interest rate of 8.3% for the years ended December 31, 2023 and December 31, 2022.
325.0
325.0
Borrowings under the 2028 Notes, interest at a fixed rate of 9.75%, interest payments semiannually, borrowings due July 2028, effective interest rate of 10.0% for the year ended December 31, 2023.
325.0
-
MRL Term Loan Credit Agreement
74.4
-
Shreveport terminal asset financing arrangement
50.8
58.2
MRL asset financing arrangements
384.6
370.1
Finance lease obligations, at various interest rates, interest and principal payments monthly through June 2028
3.0
3.4
Less unamortized debt issuance costs (2)
(16.1)
(12.1)
Less unamortized discounts
(3.5)
(2.4)
Total debt
$
1,885.4
$
1,559.7
Less current portion of long-term debt
55.7
19.6
Total long-term debt
$
1,829.7
$
1,540.1
(1) As of December 31, 2023, $149.0 million of outstanding borrowings under the 2024 Secured Notes have been excluded from current liabilities, as the outstanding borrowings are obligated to be redeemed, conditioned upon, on or before March 9, 2024, the completion of a private placement of at least $200.0 million aggregate principal amount of the Company’s senior debt securities. Refer to Note 23 - “Subsequent Events” for additional information.
(2) Deferred debt issuance costs are being amortized by the effective interest rate method over the lives of the related debt instruments. These amounts are net of accumulated amortization of $26.6 million and $22.3 million at December 31, 2023 and 2022, respectively.
Senior Notes
9.75% Senior Notes due 2028 (the “2028 Notes”)
On June 27, 2023, the Company issued and sold $325.0 million in aggregate principal amount of 2028 Notes, in a private placement pursuant to Section 4(a)(2) of the Securities Act to eligible purchasers at par. The Company received net proceeds of $319.1 million, after deducting the initial purchasers’ discount and offering expenses, which the Company used a portion of the net proceeds to fund offers (collectively, the “Tender Offers”) to purchase (i) any and all of its outstanding $200.0 million in aggregate principal amount of 2024 Secured Notes (as defined below) and (ii) up to $100.0
million in aggregate principal amount of its outstanding 2025 Notes (as defined below) and pay related premiums and expenses, with the remaining net proceeds to be used for general partnership purposes, including debt repayment. On June 28, 2023, in connection with the early settlement of the Tender Offers, the Company used approximately $125.5 million (excluding accrued and unpaid interest and related expenses) of the proceeds from the offering of the 2028 Notes to fund the repurchase of (i) approximately $21.0 million in aggregate principal amount of 2024 Secured Notes and (ii) $100.0 million in aggregate principal amount of the 2025 Notes and pay related premiums. Interest on the 2028 Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2024.
8.125% Senior Notes due 2027 (the “2027 Notes”)
On January 20, 2022, the Company issued and sold $325.0 million in aggregate principal amount of 2027 Notes, in a private placement pursuant to Section 4(a)(2) of the Securities Act to eligible purchasers at par. The Company received net proceeds of $319.1 million, after deducting the initial purchasers’ discount and offering expenses, which the Company used, along with cash on hand, to fund the redemption of $325.0 million aggregate principal amount of its 2023 Senior Notes at a redemption price of par, plus accrued and unpaid interest to the redemption date of February 11, 2022. In conjunction with the redemption of the 2023 Senior Notes, the Company recorded a loss from debt extinguishment of $1.0 million, which is reflected in loss from debt extinguishment in the consolidated statements of operations for the year ended December 31, 2022. Interest on the 2027 Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2022.
11.00% Senior Notes due 2025 (the “2025 Notes”)
On October 11, 2019, the Company issued and sold $550.0 million in aggregate principal amount of 11.00% Senior Notes due April 15, 2025, in a private placement pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”), to eligible purchasers at par. The Company received net proceeds of $539.9 million net of initial purchasers’ fees and estimated expenses, which it used, along with revolver borrowings and cash on hand, to fund the redemption of $761.2 million in aggregate principal amount of outstanding 6.50% Notes due 2021. Interest on the 2025 Notes is paid semiannually in arrears on April 15 and October 15 of each year.
On July 6, 2020, the Company commenced a consent solicitation to holders of the 2025 Notes for amendments to the indenture governing the 2025 Notes to allow for the consummation of the 2024 Notes Exchange Transaction. On August 5, 2020, the Company executed the First Supplemental Indenture to the indenture governing the 2025 Notes to allow the 2024 Notes Exchange Transaction.
During the year ended December 31, 2022, the Company repurchased $36.5 million aggregate principal amount of its 2025 Notes at an average price of 104.3% of par value, plus accrued and unpaid interest thereon up to, but not including the respective transaction dates. In conjunction with the repurchases of the 2025 Notes during the year ended December 31, 2022, the Company recorded a loss from debt extinguishment of $2.1 million, which is reflected in loss from debt extinguishment in the consolidated statements of operations.
9.25% Senior Secured First Lien Notes due 2024 (the “2024 Secured Notes”)
On August 5, 2020, we consummated a transaction whereby we exchanged approximately $200.0 million aggregate principal amount of our outstanding 2022 Notes for $200.0 million aggregate principal amount of newly issued 2024 Secured Notes, approximately at par (the “2024 Notes Exchange Transaction”). Interest on the 2024 Secured Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2021. The 2024 Secured Notes are secured by a first priority lien (subject to certain exceptions) on all the fixed assets that secure the Company’s obligations under their secured hedge agreements, as governed by the Collateral Trust Agreement.
7.75% Senior Notes due 2023 (the “2023 Notes”)
On March 27, 2015, the Company issued and sold $325.0 million in aggregate principal amount of 7.75% Senior Notes due April 15, 2023 in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at a discounted price of 99.257 percent of par. The Company received net proceeds of approximately $317.0 million net of
discount, initial purchasers’ fees and expenses, which the Company used to fund the redemption of $178.8 million in aggregate principal amount of outstanding 9.625% Senior Notes due 2020 on April 28, 2015, to repay borrowings outstanding under its revolving credit facility and for general partnership purposes, including planned capital expenditures at the Company’s facilities and working capital. Interest on the 2023 Notes was paid semiannually in arrears on April 15 and October 15 of each year.
On February 11, 2022, the Company redeemed $325.0 million in aggregate principal amount of the 2023 Notes at a redemption price of par, plus accrued and unpaid interest. In conjunction with the redemption of the 2023 Senior Notes, the Company recorded a loss from debt extinguishment of $1.0 million, which is reflected in loss from debt extinguishment in the consolidated statements of operations for the year ended December 31, 2022.
Senior Notes
The 2024 Secured Notes, 2025 Notes, 2027 Notes and 2028 Notes (collectively, the “Senior Notes”) are subject to certain automatic customary releases, including the sale, disposition, or transfer of capital stock or substantially all of the assets of a subsidiary guarantor, designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture, exercise of legal defeasance option or covenant defeasance option, liquidation or dissolution of the subsidiary guarantor and a subsidiary guarantor ceases to both guarantee other Company debt and to be an obligor under the revolving credit facility. The Company’s operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into, another company if such a sale would cause a default under the indentures governing the Senior Notes.
The indentures governing the Senior Notes contain covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the Senior Notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or S&P Global Ratings (“S&P”) and no Default or Event of Default, each as defined in the indentures governing the Senior Notes, has occurred and is continuing, many of these covenants will be suspended. As of December 31, 2023, the Company was in compliance with all covenants under the indentures governing the Senior Notes.
MRL Asset Financing Arrangements
On August 5, 2022, Montana Renewables, LLC (“MRL”), a wholly owned subsidiary of the Company, entered into Equipment Schedule No. 2 (the “Equipment Schedule”) and an Interim Funding Agreement (the “Funding Agreement”) with Stonebriar Commercial Finance LLC (“Stonebriar”). The Equipment Schedule and the Funding Agreement each constitute a schedule under the Master Lease Agreement (the “Lease Agreement”) dated as of December 31, 2021 between MRL and Stonebriar. The Equipment Schedule provides that Stonebriar will purchase from and lease back to MRL a hydrocracker, intended to produce renewable diesel and related products, for a purchase price of $250.0 million. The Funding Agreement provides $100.0 million in financing for the design and construction of a feedstock pre-treater facility. The transactions with Stonebriar described in this paragraph are referred to herein as the “MRL Asset Financing Arrangements.” The Company has recorded the MRL asset financing arrangements as a financial liability in the consolidated balance sheets.
Fourth Amendment to Third Amended and Restated Senior Secured Revolving Credit Facility
On January 17, 2024, the Company entered into the Fourth Amendment to its revolving credit facility (the “Credit Agreement”) governing its senior secured revolving credit facility maturing in January 2027, which provides maximum availability of credit under the revolving credit facility of $650.0 million, including a FILO tranche, subject to borrowing base limitations, and includes a $500.0 million incremental uncommitted expansion feature. Lenders under the revolving
credit facility have a first priority lien on, among other things, the Company’s accounts receivable and inventory and substantially all of its cash (collectively, the “Credit Agreement Collateral”).
The borrowing capacity at December 31, 2023, under the revolving credit facility was approximately $404.8 million. As of December 31, 2023, the Company had $136.7 million of outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $29.9 million, leaving approximately $238.2 million of unused capacity.
The revolving credit facility contains various covenants that limit, among other things, the Company’s ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates; and enter into a merger, consolidation or sale of assets. Further, the revolving credit facility contains a springing financial covenant which provides that only if the Company’s availability to borrow loans under the revolving credit facility falls below the sum of (a) the greater of (i) (x) 15% of the borrowing base then in effect at any time that the refinery asset borrowing base component is greater than $0 and (y) 10% of the borrowing base then in effect at any time that the refinery asset borrowing base component is equal to $0 and (ii) $45.0 million (which amount is subject to certain increases) plus (b) the amount of FILO Loans outstanding, then we will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the Credit Agreement) of at least 1.0 to 1.0. As of December 31, 2023, the Company was in compliance with all covenants under the revolving credit facility.
MRL Revolving Credit Agreement
On November 2, 2022 (the “Effective Date”), MRL entered into, as borrower, a Credit Agreement (the “MRL Revolving Credit Agreement”) with Montana Renewables Holdings LLC (“MRHL”), the parent company of MRL, and Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent and lender, which MRL Revolving Credit Agreement provides for a secured revolving credit facility in the maximum amount of $90.0 million outstanding, with the option to request additional commitments of up to $15.0 million, and with a maturity date of November 2, 2027. The borrowing capacity at December 31, 2023, under the MRL Revolving Credit Agreement was approximately $16.7 million. As of December 31, 2023, MRL had $13.0 million of outstanding borrowings under the MRL Revolving Credit Agreement and no outstanding standby letters of credit, leaving approximately $3.7 million of unused capacity.
MRL Credit Facility
On November 18, 2021 (the “Closing Date”), MRL, Montana Renewables Holdings LLC (“Montana Renewables Holdings”), the parent of MRL and an unrestricted, non-guarantor subsidiary of the Partnership for purposes of the agreements governing the Partnership’s indebtedness, Oaktree Fund Administration, LLC and the lenders from time to time party thereto (the “Oaktree Lenders”) entered into a Credit Agreement, which provides for a $300.0 million senior secured term loan facility (the “MRL Credit Facility”). On the Closing Date, $300.0 million was drawn under the MRL Credit Facility to finance the transfer for value of various assets at the Great Falls refinery, including the hydrocracker, a hydrogen plant, and several products tanks to MRL. The MRL Credit Facility is not subject to amortization and matures on November 18, 2024. The MRL Credit Facility is secured by substantially all of the assets of MRL and a pledge of 100% of the equity interest in MRL held by Montana Renewables Holdings.
The interest rate per annum applicable to the MRL Credit Facility is 8.00%. If interest on the MRL Credit Facility is not paid when due on any quarterly interest payment date (each, a “Quarterly Date”), then interest for the immediately preceding quarterly period shall be deemed to have accrued in an amount equal to the product of (i) the percentage of the interest amount that was not paid in cash on the relevant Quarterly Date multiplied by (ii) 2.00% per annum above the interest rate otherwise applicable thereto, which amount, in each case, shall be added to the principal balance of the loans then outstanding under the MRL Credit Facility.
On August 5, 2022, the Company repaid all borrowings outstanding under the MRL credit facility with a combination of proceeds from the issuance and sale of preferred units in MRHL and the Stonebriar Transactions (as defined herein). In conjunction with the redemption of the MRL credit facility, the Company recorded a loss from debt extinguishment of $38.3 million, which is reflected in loss from debt extinguishment in the consolidated statements of operations for the year ended December 31, 2022. Please refer to Note 20 - “Redeemable Noncontrolling Interest” for additional information
regarding the issuance and sale of preferred units in MRHL and Note 8 - “Long-Term Debt - MRL Asset Financing Arrangements” for additional information regarding the Stonebriar Transactions.
MRL Term Loan Credit Agreement
On April 19, 2023, MRL and MRHL entered into a Credit Agreement (the “MRL Term Loan Credit Agreement”) with a group of financial institutions, including I Squared Capital and Delaware Trust Company, as administrative agent, that provides for a $75.0 million term loan facility with a maturity date of April 19, 2028 (the “Maturity Date”). The MRL Term Loan Credit Agreement provides for a variable interest rate based on the SOFR plus 6.0% to 7.3% per annum. The borrowings under the MRL Term Loan Credit Agreement are repayable in quarterly installments commencing on June 30, 2023, in an amount equal to 0.25% of the outstanding principal amount under the MRL Term Loan Credit Agreement as of each quarterly payment date, plus additional principal payments to the extent MRL has excess cash flows, pursuant to the terms of the MRL Term Loan Credit Agreement. The remaining borrowings under the MRL Term Loan Credit Agreement are repayable on the Maturity Date.
Master Derivative Contracts
The Company’s payment obligations under all of the Company’s master derivatives contracts for commodity hedging generally are secured by a first priority lien on the Company’s real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). The Company had no additional letters of credit or cash margin posted with any hedging counterparty as of December 31, 2023. The Company’s master derivatives contracts and Collateral Trust Agreement (as defined below) continue to impose a number of covenant limitations on the Company’s operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements.
Collateral Trust Agreement
The Company has a collateral trust agreement (“The Collateral Trust Agreement”) which governs how various secured Company creditors, including secured hedging counterparties, our creditor on a forward purchase contract for physical commodities, and holders of our 2024 Secured Notes share collateral pledged as security for the payment of respective payment obligations to them. The Collateral Trust Agreement limits to $150.0 million the extent to which forward purchase contracts for physical commodities are covered by, and secured under, the Collateral Trust Agreement and the Parity Lien Security Documents (as defined in the Collateral Trust Agreement). There is no such limit on financially settled derivative instruments used for commodity hedging. Subject to certain conditions set forth in the Collateral Trust Agreement, the Company has the ability to add secured parties from time to time.
Maturities of Long-Term Debt
As of December 31, 2023, principal payments on debt obligations and future minimum rentals on finance lease obligations are as follows (in millions):
Year
Maturity
2024 (1)
$
205.3
442.4
31.9
524.1
423.3
Thereafter
278.0
Total
$
1,905.0
(1) As of December 31, 2023, $149.0 million of outstanding borrowings under the 2024 Secured Notes have been excluded from current liabilities, as the outstanding borrowings are obligated to be redeemed, conditioned upon, on or before March 9, 2024, the completion of a private placement of at least $200.0 million aggregate principal amount of the Company’s senior debt securities. Refer to Note 23 - “Subsequent Events” for additional information.
9. Derivatives
The Company is exposed to price risks due to fluctuations in the price of crude oil, refined products, natural gas and precious metals. The Company uses various strategies to reduce its exposure to commodity price risk. The strategies to reduce the Company’s risk utilize both physical forward contracts and financially settled derivative instruments, such as swaps, collars, options and futures, to attempt to reduce the Company’s exposure with respect to:
● crude oil purchases and sales;
● fuel product sales and purchases;
● natural gas purchases;
● precious metals purchases; and
● fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”), Light Louisiana Sweet, Western Canadian Select (“WCS”), WTI Midland, Mixed Sweet Blend, Magellan East Houston and ICE Brent.
The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability and anticipated future transactions and the changes in fair value of the Company’s derivative instruments will affect its earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. The Company does not speculate with derivative instruments or other contractual arrangements that are not associated with its business objectives.
Speculation is defined as increasing the Company’s natural position above the maximum position of its physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with the Company’s business activities and objectives. The Company’s positions are monitored routinely by a risk management committee to ensure compliance with its stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by the Company’s risk management committee, which will add, remove or revise strategies in
anticipation of changes in market conditions and/or its risk profiles. Such changes in strategies are to position the Company in relation to its risk exposures in an attempt to capture market opportunities as they arise.
As of December 31, 2023 and 2022, the Company was obligated to repurchase crude oil and refined products from its counterparties, then in effect, at the termination of the Supply and Offtake Agreements in certain scenarios. The Company has determined that the redemption feature on the initially recognized liability related to the Supply and Offtake Agreements is an embedded derivative indexed to commodity prices. As such, the Company has accounted for this embedded derivative at fair value with changes in the fair value, if any, recorded in gain (loss) on derivative instruments in the Company’s consolidated statements of operations please read Note 7 - “Inventory Financing Agreements" for additional information. The Company recognizes all derivative instruments at their fair values as either current assets or current liabilities in the consolidated balance sheets (please read Note 10 - “Fair Value Measurements”). Fair value includes any premiums paid or received and unrealized gains and losses. Fair value does not include any amounts receivable from or payable to counterparties, or collateral provided to counterparties. Derivative asset and liability amounts with the same counterparty are netted against each other for financial reporting purposes in accordance with the provisions of our master netting arrangements.
The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets in the Company’s consolidated balance sheets (in millions):
December 31, 2023
December 31, 2022
Gross
Net Amounts
Gross
Net Amounts
Amounts
of Assets
Amounts
of Assets
Offset in the
Presented
Offset in the
Presented
Gross
Condensed
in the
Gross
Condensed
in the
Amounts of
Consolidated
Condensed
Amounts of
Consolidated
Condensed
Balance Sheet
Recognized
Balance
Consolidated
Recognized
Balance
Consolidated
Location
Assets
Sheets
Balance Sheets
Assets
Sheets
Balance Sheets
Derivative instruments not designated as hedges:
Specialty Products and Solutions segment:
Crack spread swaps
Derivative assets / Other noncurrent assets, net
$
11.6
$
-
$
11.6
$
-
$
-
$
-
Total derivative instruments
$
11.6
$
-
$
11.6
$
-
$
-
$
-
The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative liabilities in the Company’s consolidated balance sheets (in millions):
December 31, 2023
December 31, 2022
Net Amounts
Gross
of Liabilities
Gross
Net Amounts
Amounts
Presented in
Amounts
of Liabilities
Offset in the
the
Offset in the
Presented in
Gross
Condensed
Condensed
Gross
Condensed
the
Amounts of
Consolidated
Consolidated
Amounts of
Consolidated
Condensed
Balance Sheet
Recognized
Balance
Balance
Recognized
Balance
Consolidated
Location
Liabilities
Sheets
Sheets
Liabilities
Sheets
Balance Sheets
Derivative instruments not designated as hedges:
Specialty Products and Solutions segment:
Inventory financing obligation
Obligations under inventory financing agreements
$
(52.5)
$
-
$
(52.5)
$
(38.0)
$
-
$
(38.0)
Crack spread swaps
Derivative liabilities / Other long-term liabilities
-
-
-
(50.6)
19.3
(31.3)
Montana/Renewables segment:
Inventory financing obligation
Obligations under inventory financing agreements
-
-
-
(15.8)
11.3
(4.5)
Total derivative instruments
$
(52.5)
$
-
$
(52.5)
$
(104.4)
$
30.6
$
(73.8)
Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. The majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business. The cash flow impact of the Company’s derivative activities are included within cash flows from operating activities in the consolidated statements of cash flows.
Derivative Instruments Not Designated as Hedges
For derivative instruments not designated as hedges, the change in fair value of the asset or liability for the period is recorded to gain (loss) on derivative instruments in the consolidated statements of operations. Upon the settlement of a derivative not designated as a hedge, the gain or loss at settlement is recorded to gain (loss) on derivative instruments in the consolidated statements of operations. The Company has entered into crack spread swaps and crude oil basis swaps that are not designated as cash flow hedges for accounting purposes. However, these instruments provide economic hedges of the purchases and sales of the Company’s natural gas, crude oil, gasoline and refined products.
The Company recorded the following gains (losses) in its consolidated statements of operations related to its derivative instruments not designated as hedges (in millions):
Amount of Realized
Loss Recognized in Gain (Loss) on
Amount of Unrealized Gain (Loss)
Derivative
Recognized in Gain (Loss) on Derivative
Instruments
Instruments
Year Ended December 31,
Year Ended December 31,
Type of Derivative
Specialty Products and Solutions segment:
Inventory financing obligation
$
-
$
-
$
(14.5)
$
(20.6)
Crack spread swaps
(21.8)
(35.0)
42.9
(31.3)
Crude oil swaps
-
(0.8)
-
-
Montana/Renewables segment:
Inventory financing obligation
(1.3)
-
4.6
6.0
Total
$
(23.1)
$
(35.8)
$
33.0
$
(45.9)
Derivative Positions
At December 31, 2023, the Company had the following notional contract volumes related to outstanding derivative instruments:
Notional Contract Volumes by
Year of Maturity
Total
Outstanding
Notional
Unit of Measure
Derivative instruments not designated as hedges:
Crack spread swaps - sales
2,928,000
2,928,000
Barrels
10. Fair Value Measurements
The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. Observable inputs are from sources independent of the Company. Unobservable inputs reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. These tiers include the following:
● Level 1 - inputs include observable unadjusted quoted prices in active markets for identical assets or liabilities
● Level 2 - inputs include other than quoted prices in active markets that are either directly or indirectly observable
● Level 3 - inputs include unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions
In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment.
Recurring Fair Value Measurements
Derivative Assets and Liabilities
Derivative instruments are reported in the accompanying consolidated financial statements at fair value. The Company’s derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s derivative instruments are with counterparties that have long-term credit ratings of at least A3 and BBB+ by Moody’s and S&P, respectively.
To estimate the fair values of the Company’s commodity derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. Various analytical tests are performed to validate the counterparty data. The fair values of the Company’s derivative instruments are adjusted for nonperformance risk and creditworthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the counterparty level utilizing the fair value exposure at each payment date and applying a weighted probability of the appropriate survival and marginal default percentages. The Company uses the counterparty’s marginal default rate and the Company’s survival rate when the Company is in a net asset position at the payment date and uses the Company’s marginal default rate and the counterparty’s survival rate when the Company is in a net liability position at the payment date.
Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were based primarily on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Based on the use of various unobservable inputs, principally non-performance risk, creditworthiness of the hedging entities and unobservable inputs in the forward rate, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company believes it has obtained the most accurate information available for the types of derivative instruments it holds. Please read Note 9 - “Derivatives” for further information on derivative instruments.
Pension Assets
Pension assets are reported at fair value in the accompanying consolidated financial statements. At December 31, 2023 and 2022, the Company’s investments associated with its Pension Plan (as such term is hereinafter defined) consisted of (i) cash and cash equivalents, (ii) fixed income bond funds, (iii) mutual equity funds, and (iv) mutual balanced funds. The fixed income bond funds, mutual equity funds, and mutual balanced funds that are measured at fair value using a market approach based on quoted prices from national securities exchanges are categorized in Level 1 of the fair value hierarchy. The fixed income bond funds, mutual equity funds, and mutual balanced funds that are measured at fair value using a market approach based on prices obtained from an independent pricing service are categorized in Level 2 of the fair value hierarchy.
Liability Awards
Unit-based compensation Liability Awards are awards that are currently expected to be settled in cash on their vesting dates, rather than in equity units. The Liability Awards are categorized as Level 1 because the fair value of the Liability Awards is based on the Company’s quoted closing unit price as of each balance sheet date.
Precious Metals Obligations
The fair value of precious metals obligations is based upon unadjusted exchange-quoted prices and is, therefore, classified within Level 1 of the fair value hierarchy.
Hierarchy of Recurring Fair Value Measurements
The Company’s recurring assets and liabilities measured at fair value were as follows (in millions):
December 31, 2023
December 31, 2022 (As Restated)
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets:
Derivative assets:
Crack spread swaps
$
-
$
-
$
11.6
$
11.6
$
-
$
-
$
-
$
-
Total derivative assets
$
-
$
-
$
11.6
$
11.6
$
-
$
-
$
-
$
-
Pension plan investments
$
3.5
$
23.5
$
-
$
27.0
$
3.4
$
23.0
$
-
$
26.4
Total recurring assets at fair value
$
3.5
$
23.5
$
11.6
$
38.6
$
3.4
$
23.0
$
-
$
26.4
Liabilities:
Derivative liabilities:
Inventory financing obligation
$
-
$
-
$
(52.5)
$
(52.5)
$
-
$
-
$
(42.5)
$
(42.5)
Crack spread swaps
-
-
-
-
-
-
(31.3)
(31.3)
Total derivative liabilities
$
-
$
-
$
(52.5)
$
(52.5)
$
-
$
-
$
(73.8)
$
(73.8)
Precious metals obligations
(6.9)
-
-
(6.9)
(7.5)
-
-
(7.5)
Liability awards
(64.2)
-
-
(64.2)
(52.9)
-
-
(52.9)
Total recurring liabilities at fair value
$
(71.1)
$
-
$
(52.5)
$
(123.6)
$
(60.4)
$
-
$
(73.8)
$
(134.2)
The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities (in millions):
For the Year Ended December 31,
Fair value at January 1,
$
(73.8)
$
(27.9)
Realized loss on derivative instruments
(23.1)
(35.8)
Unrealized gain (loss) on derivative instruments
33.0
(45.9)
Settlements
23.1
35.8
Fair value at December 31,
$
(40.8)
$
(73.8)
Total gain (loss) included in net income (loss) attributable to changes in unrealized gain (loss) relating to financial assets and liabilities held as of December 31,
$
33.0
$
(45.9)
Nonrecurring Fair Value Measurements
Certain non-financial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment.
The Company assesses goodwill for impairment annually and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the reporting unit. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its consolidated financial statements. Please read Note 5 - “Goodwill and Other Intangible Assets” for further information on goodwill impairment.
The Company periodically evaluates the carrying value of long-lived assets to be held and used, including finite-lived intangible assets and property plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, in the event that the Company was
required to measure and record such assets at fair value within its consolidated financial statements. Please read Note 2 - “Summary of Significant Accounting Policies” for further information on long-lived asset impairment.
Estimated Fair Value of Financial Instruments
Cash, cash equivalents and restricted cash
The carrying value of cash, cash equivalents and restricted cash are each considered to be representative of their fair value.
Debt
The estimated fair value of long-term debt at December 31, 2023 and 2022, consists primarily of senior notes. The estimated aggregate fair value of the Company’s 2024 Secured Notes and 2025, 2027 and 2028 Senior Notes defined as Level 2 was based upon quoted prices for identical or similar liabilities in markets that are not active. The carrying value of borrowings, if any, under the Company’s revolving credit facility, MRL Revolving Credit Agreement, MRL asset financing arrangements, MRL term loan credit agreement, finance lease obligations and other obligations are classified as Level 3. Please read Note 8 - “Long-Term Debt” for further information on long-term debt.
The Company’s carrying value and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, were as follows (in millions):
December 31, 2023
December 31, 2022
Level
Fair Value
Carrying Value
Fair Value
Carrying Value
Financial Instrument:
2024 Secured Notes, 2025 Notes, 2027 Notes, and 2028 Notes
$
1,247.2
$
1,232.3
$
1,045.2
$
1,030.0
Revolving credit facility
$
136.7
$
134.4
$
104.0
$
100.9
MRL revolving credit agreement
$
13.0
$
12.4
$
-
$
(0.6)
MRL term loan credit agreement
$
74.4
$
71.6
$
-
-
Shreveport terminal asset financing arrangement
$
50.8
$
50.1
$
58.2
$
57.2
MRL asset financing arrangements
$
384.6
$
381.6
$
370.1
$
368.8
Finance leases and other obligations
$
3.0
$
3.0
$
3.4
$
3.4
11. Partners’ Capital (Deficit)
Units Authorized
As of December 31, 2023 and 2022, the Company has 92,473,023 of common units authorized for issuance.
Units Outstanding
Of the 79,967,363 common units outstanding at December 31, 2023, 63,271,967 common units were held by the public, with the remaining 16,695,396 common units held by the Company’s affiliates (including members of the Company’s general partner and their families).
Significant information regarding rights of the limited partners includes the following:
● Rights to receive distributions of available cash within 45 days after the end of each quarter, to the extent the Company has sufficient cash from operations after the establishment of cash reserves.
● Limited partners have limited voting rights on matters affecting the Company’s business. The general partner may consider only the interests and factors that it desires and has no duty or obligation to give any consideration of any interests of the Company’s limited partners. Limited partners have no right to elect the board of directors of the Company’s general partner.
● The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. Any holder, other than the general partner or the general partner’s affiliates, that owns 20% or more of any class of units outstanding cannot vote on any matter.
● The Company may issue an unlimited number of limited partner interests without the approval of the limited partners.
● Limited partners may be required to sell their units to the general partner if at any time the general partner owns more than 80% of the issued and outstanding common units.
Distributions and Incentive Distribution Rights
The Company’s general partner is entitled to incentive distributions if the amount it distributes to unitholders with respect to any quarter exceeds specified target levels shown below:
Total Quarterly
Marginal Percentage
Distribution Per Common Unit
Interest in Distributions
Target Amount
Unitholders
General Partner
Minimum Quarterly Distribution
$0.45
%
%
First Target Distribution
up to $0.495
%
%
Second Target Distribution
above $0.495 up to $0.563
%
%
Third Target Distribution
above $0.563 up to $0.675
%
%
Thereafter
above $0.675
%
%
The Company’s ability to make distributions is limited by its debt instruments. The revolving credit facility generally permits the Company to make cash distributions to unitholders as long as immediately after giving effect to such a cash distribution the Company has availability under the revolving credit facility at least the greater of (i) 15% of the Aggregate Borrowing Base (as defined in the credit agreement) then in effect, and (ii) $60.0 million (which amount is subject to increase in proportion to revolving commitment increases). Further, the revolving credit facility contains a springing financial covenant which provides that only if the Company’s availability to borrow loans under the revolving credit facility falls below the sum of (a) the greater of (i) (x) 15% of the borrowing base then in effect at any time that the refinery asset borrowing base component is greater than $0 and (y) 10% of the borrowing base then in effect at any time that the refinery asset borrowing base component is equal to $0 and (ii) $45.0 million (which amount is subject to certain increases) plus (b) the amount of FILO Loans outstanding, then we will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the Credit Agreement) of at least 1.0 to 1.0. The indentures governing the Company’s various senior notes restrict the Company’s ability to make cash distributions. Under the indenture governing the 2024 Secured Notes and 2025 Senior Notes, the Company may pay distributions to its unitholders in an amount equal to available cash from operating surplus (as defined in the Company’s partnership agreement) with respect to its preceding fiscal quarter, subject to certain customary adjustments described in the indentures, if the Company’s fixed charge coverage ratio (as defined in the indentures) for the most recently ended four full fiscal quarters is not less than 3.0 to 1.0. If the Company’s fixed charge coverage ratio is less than 3.0 to 1.0, the Company will be able to pay distributions to its unitholders up to an amount equal to a $25.0 million basket, subject to certain customary adjustments described in the indentures. The indentures governing the 2027 Senior Notes reduces this minimum fixed charge coverage ratio to 2.5 to 1.0.
The Company’s distribution policy is as defined in its partnership agreement. In April 2016, the board of directors of the Company’s general partner determined to suspend payment of the Company’s quarterly cash distribution to unitholders and the Company is not currently permitted to resume cash distributions pursuant to the terms of the indentures governing the Company’s outstanding senior notes. The Company made no distributions to its partners for the years ended December 31, 2023 and 2022. For the years ended December 31, 2023 and 2022, the general partner was allocated no incentive distribution rights.
12. Unit-Based Compensation
The Company’s general partner originally adopted a Long-Term Incentive Plan on January 24, 2006, which was amended and restated effective December 10, 2015 and further amended effective December 9, 2021 (the “LTIP”), for its employees, consultants and directors and its affiliates who perform services for the Company. The LTIP provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights (“DERs”). Following unitholder approval of the December 9, 2021 amendment to the LTIP, which was obtained on February 16, 2022, an aggregate of 5,283,960 common units may be delivered pursuant to awards under the LTIP. Units withheld to satisfy the Company’s general partner’s tax withholding obligations are available for delivery pursuant to other awards. The LTIP is administered by the compensation committee of the Company’s general partner’s board of directors.
Liability Awards are awards that are currently expected to be settled in cash on their vesting dates, rather than in equity units. Phantom unit Liability Awards are recorded in accrued salaries, wages and benefits in the consolidated balance sheets based on the vested portion of the fair value of the awards on the balance sheet date. The fair value of Liability Awards is updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense within general and administrative expense in the consolidated statements of operations.
Phantom Units
Non-employee directors and certain management level employees of the Company’s general partner have been granted phantom units under the terms of the LTIP as part of their respective compensation packages related to fiscal years 2023 and 2022. The phantom units granted to non-employee directors and employees related to fiscal years 2023 and 2022 vest in full on the third anniversary following the grant date. Although ownership of common units related to the vesting of such LTIP phantom units does not transfer to the recipients until the phantom units vest, the recipients have DERs on these phantom units from the date of grant.
Non-employee directors and certain senior management level employees of the Company’s general partner are eligible to defer their earned director fees or earned annual cash incentive amounts, respectively, into the Deferred Compensation Plan. When such individuals elect to defer any portion of their compensation into the plans, these deferred amounts are credited to the participant in the form of phantom units. The compensation committee may recommend a matching contribution for the deferred amounts at its discretion.
For unit-based compensation equity awards, the Company uses the market price of its common units on the grant date to calculate the fair value and related compensation cost of the phantom units. The Company amortizes this compensation cost to partners’ capital (deficit) and general and administrative expense in the consolidated statements of operations using the straight-line method over the service period, as it expects these units to fully vest.
A summary of the Company’s non-vested phantom units as of December 31, 2023, and the changes during the years ended December 31, 2023 and 2022, are presented below:
Weighted-
Number of
Average
Phantom Units
Grant Date Fair Value
Non-vested at January 1, 2021
2,370,868
$
2.21
Granted
821,964
4.71
Vested
(1,002,338)
3.34
Forfeited
(61,933)
3.68
Non-vested at December 31, 2021
2,128,561
$
2.31
Granted
931,926
15.02
Vested
(1,706,783)
5.61
Forfeited
(39,322)
6.62
Non-vested at December 31, 2022
1,314,382
$
6.58
Granted
1,216,817
17.53
Vested
(1,144,542)
11.08
Forfeited
(159,080)
11.89
Non-vested at December 31, 2023
1,227,577
$
9.83
For the year ended December 31, 2023, compensation expense of $21.8 million was recognized in the consolidated statements of operations related to phantom unit grants. For the year ended December 31, 2022, compensation expense of $32.9 million was recognized in the consolidated statements of operations related to phantom unit grants. As of December 31, 2023, there was a total of $14.8 million of unrecognized compensation costs related to non-vested phantom unit grants, all of which was attributable to Liability Awards. These costs are expected to be recognized over a weighted-average period of approximately two years. The total fair value of phantom units vested during the years ended December 31, 2023 and 2022, was $19.8 million and $26.1 million, respectively.
13. Employee Benefit Plans
Defined Contribution Plan
The Company has a domestic defined contribution plan administered by its general partner for (i) all full-time employees that are eligible to participate in the plan (the “401(k) Plan”). Participants in the 401(k) Plan are allowed to contribute 1% to 70% of their pre-tax earnings to the plan, subject to government imposed limitations. The Company matches 100% of each 1% of eligible compensation contributed by the participant up to 4% and 50% of each additional 1% of eligible compensation contributed up to 6%, for a maximum contribution by the Company of 5% of eligible compensation contributed per participant. The 401(k) Plan also includes a profit-sharing component for eligible employees. Contributions under the profit-sharing component are determined by the board of directors of the Company’s general partner and are discretionary. The funding policy is consistent with funding requirements of applicable laws and regulations.
The Company recorded the following 401(k) Plan matching contribution expense in the consolidated statements of operations (in millions):
Year Ended December 31,
401(k) Plan matching contribution expense
$
7.0
$
6.9
$
5.9
Defined Benefit Pension Plan
The Company has domestic noncontributory defined benefit plans for those salaried employees as well as those employees represented by either the United Steelworkers (the “USW”) or the International Union of Operating Engineers (the “IUOE”); who (i) were formerly employees of Penreco and became employees of the Company as a result of the
acquisition of Penreco on January 3, 2008 (the “Penreco Pension Plan”) or (ii) were formerly employees of Montana Refining Company, Inc. and who became employees of the Company as a result of the acquisition of the Great Falls refinery on October 1, 2012 (the “Great Falls Pension Plan” and together with the Penreco Pension Plan, the “Pension Plan”).
Both the Penreco Pension Plan and the Great Falls Pension Plans were last amended in 2009 and 2015 respectively, which curtailed employees covered by the plans from accumulating additional benefits in subsequent years following the amendment date.
During 2023, the Company made an immaterial amount of contributions to its Pension Plan and expects to contribute less than $0.1 million to its Pension Plan in 2024.
The accumulated and projected benefit obligations for the Pension Plan were $31.2 million as of each of December 31, 2023 and 2022. For the years ended December 31, 2023 and 2022, the discount rate used to determine the benefit obligations was 4.97% and 5.19%, respectively, for the Penreco Pension Plan and 5.05% and 5.16%, respectively, for the Great Falls Pension Plan. For the years ended December 31, 2023 and 2022, the expected rate of return on plan assets was 5.25% and 4.50%, respectively, for the Penreco Pension Plan and 6.00% and 4.50%, respectively, for the Great Falls Pension Plan. The fair value of plan assets was $27.0 million and $26.4 million as of December 31, 2023 and 2022, respectively. The estimated benefit payments for the Pension Plan, which reflect expected future service, as appropriate, are expected to be less than $2.6 million in each of the next five years.
14. Accumulated Other Comprehensive Loss
The table below sets forth a summary of changes in accumulated other comprehensive loss by component for the years ended December 31, 2023 and 2022 (in millions):
Defined Benefit
Pension And
Retiree Health
Benefit Plans
Total
Accumulated other comprehensive loss at December 31, 2021
$
(10.1)
$
(10.1)
Other comprehensive income before reclassifications
1.8
1.8
Net current period other comprehensive income
1.8
1.8
Accumulated other comprehensive loss at December 31, 2022
$
(8.3)
$
(8.3)
Other comprehensive income before reclassifications
1.1
1.1
Net current period other comprehensive income
1.1
1.1
Accumulated other comprehensive loss at December 31, 2023
$
(7.2)
$
(7.2)
15. Income Taxes
The Company, as a partnership, is generally not liable for federal and state income taxes on the earnings of Calumet Specialty Products Partners, L.P., its wholly-owned subsidiaries, and its majority owned subsidiaries. However, the Company conducts certain activities through immaterial, wholly-owned subsidiaries that are corporations, which in certain circumstances are subject to federal, state and local income taxes. Additionally, the Company is subject to franchise taxes in certain states. Income taxes on the earnings of the Company, with the exception of the above-mentioned taxes, are the responsibility of its partners, with earnings of the Company included in partners’ earnings.
For the years ended December 31, 2023, 2022, and 2021, the Company recognized income tax expense of $1.6 million, $3.4 million, and $1.5 million, respectively.
As a result of the Company’s analysis, management has determined that the Company does not have any material uncertain tax positions.
16. Earnings per Unit
The following table sets forth the computation of basic and diluted earnings per limited partner unit (in millions, except unit and per unit data):
Year Ended December 31,
2022 (As Restated)
Numerator for basic and diluted earnings per limited partner unit:
Net income (loss)
$
48.1
$
(173.3)
$
(260.1)
Less:
General partner’s interest in net income (loss)
1.0
(3.5)
(5.2)
Net income (loss) attributable to limited partners
$
47.1
$
(169.8)
$
(254.9)
Denominator for earnings per limited partner unit:
Basic weighted average limited partner units outstanding
80,075,530
79,336,283
78,980,839
Effect of dilutive securities:
Incremental units (1)
-
-
-
Diluted weighted average limited partner units outstanding (2)
80,075,530
79,336,283
78,980,839
Limited partners’ interest basic net income (loss) per unit:
Limited partners’ interest
$
0.59
$
(2.14)
$
(3.23)
Limited partners’ interest diluted net income (loss) per unit:
Limited partners’ interest
$
0.59
$
(2.14)
$
(3.23)
(1) There were no incremental units that would have been dilutive in the computation of earnings per limited partner unit for the year ended December 31, 2023.
(2) Total diluted weighted average limited partner units outstanding excludes a de-minimis amount of potentially dilutive phantom units which would have been anti-dilutive for the years ended December 31, 2022, and 2021.
17. Transactions with Related Parties
During the years ended December 31, 2023, 2022, and 2021, the Company had product sales to related parties of $8.4 million, $16.5 million, and $19.9 million, respectively. Trade accounts and other receivables from related parties at December 31, 2023 and 2022 were $1.7 million and $1.9 million, respectively. The Company also had purchases from related parties during the years ended December 31, 2023, 2022, and 2021 of $16.5 million, $11.7 million, and $9.7 million, respectively. Accounts payable to related parties were $5.9 million and $1.5 million, at December 31, 2023 and 2022, respectively.
The general partner employs all of the Company’s employees and the Company reimburses the general partner for certain of its expenses.
18. Segments and Related Information
Segment Reporting
The Company determines its reportable segments based on how the business is managed internally for the products sold to customers, including how results are reviewed and resources are allocated by the chief operating decision makers (“CODM”). The Company’s operations are managed by the CODM using the following reportable segments:
● Specialty Products and Solutions. The Specialty Products and Solutions segment consists of our customer-focused solutions and formulations businesses, covering multiple specialty product lines, anchored by our unique integrated complex in Northwest Louisiana. In this segment, we manufacture and market a wide variety of solvents, waxes, customized lubricating oils, white oils, petrolatums, gels, esters, and other products. Our
specialty products are sold to domestic and international customers who purchase them primarily as raw material components for consumer-facing and industrial products.
● Montana/Renewables. The Montana/Renewables segment is composed of our Great Falls specialty asphalt facility and our Montana Renewables facility. At our Montana Renewables facility, we process a variety of geographically advantaged renewable feedstocks into renewable diesel, sustainable aviation fuel, renewable hydrogen, renewable natural gas, renewable propane, and renewable naphtha that are distributed into renewable markets in the western half of North America. At our Montana specialty asphalt facility, we process Canadian crude oil into conventional gasoline, diesel, jet fuel and specialty grades of asphalt, with production sized to serve local markets.
● Performance Brands. The Performance Brands segment includes our fast-growing portfolio of high-quality, high-performing brands. In this segment, we blend, package, and market high performance products through our Royal Purple, Bel-Ray, and TruFuel brands.
● Corporate. The Corporate segment primarily consists of general and administrative expenses not allocated to the Montana/Renewables, Specialty Products and Solutions, or Performance Brands segments.
The accounting policies of the reporting segments are the same as those described in the summary of significant accounting policies as disclosed in Note 2 - “Summary of Significant Accounting Policies,” except that the disaggregated financial results for the reporting segments have been prepared using a management approach, which is consistent with the basis and manner in which management internally disaggregates financial information for the purposes of assisting internal operating decisions. The Company accounts for inter-segment sales and transfers using market-based transfer pricing. The Company will periodically refine its expense allocation methodology for its segment reporting as more specific information becomes available and the industry or market changes. The Company evaluates performance based upon Adjusted EBITDA (a non-GAAP financial measure). The Company defines Adjusted EBITDA for any period as EBITDA adjusted for (a) impairment; (b) unrealized gains and losses from mark-to-market accounting for hedging activities; (c) realized gains and losses under derivative instruments excluded from the determination of net income (loss); (d) non-cash equity-based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (e) debt refinancing fees, extinguishment costs, premiums and penalties; (f) any net gain or loss realized in connection with an asset sale that was deducted in computing net income (loss); (g) amortization of turnaround costs; (h) LCM inventory adjustments; (i) the impact of liquidation of inventory layers calculated using the LIFO method; (j) RINs mark-to-market adjustments; and (k) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense.
Reportable segment information is as follows (in millions):
Specialty
Products and
Performance
Montana/
Consolidated
Year Ended December 31, 2023
Solutions (1)
Brands (2)
Renewables (3)
Corporate
Eliminations
Total
Sales:
External customers
$
2,876.9
$
310.3
$
993.8
$
-
$
-
$
4,181.0
Inter-segment sales
17.2
0.3
-
-
(17.5)
-
Total sales
$
2,894.1
$
310.6
$
993.8
$
-
$
(17.5)
$
4,181.0
Adjusted EBITDA
$
251.2
$
47.9
$
30.2
$
(68.8)
$
-
$
260.5
Reconciling items to net income:
Depreciation and amortization
76.8
9.9
95.2
1.1
-
183.0
LCM / LIFO (gain) loss
(2.1)
2.0
35.7
-
-
35.6
Loss on impairment and disposal of assets
-
-
3.5
-
-
3.5
Interest expense
27.9
0.1
65.4
128.3
-
221.7
Debt extinguishment costs
-
-
0.4
5.5
-
5.9
Unrealized gain on derivatives
(28.4)
-
(4.6)
-
-
(33.0)
RINs mark-to-market gain
(201.1)
-
(89.1)
-
-
(290.2)
Other non-recurring expenses
60.9
Equity-based compensation and other items
20.2
Income tax expense
1.6
Noncontrolling interest adjustments
3.2
Net income
$
48.1
Capital expenditures
$
82.2
$
2.3
$
234.6
$
0.6
$
-
$
319.7
PP&E, net
$
373.0
$
33.4
$
1,097.9
$
2.0
$
-
$
1,506.3
Specialty
Products and
Performance
Montana/
Consolidated
Year Ended December 31, 2022 (As Restated)
Solutions (4) (5)
Brands
Renewables (3)
Corporate
Eliminations
Total
Sales:
External customers
$
3,508.0
$
303.4
$
874.9
$
-
$
-
$
4,686.3
Inter-segment sales
24.7
-
-
-
(24.7)
-
Total sales
$
3,532.7
$
303.4
$
874.9
$
-
$
(24.7)
$
4,686.3
Adjusted EBITDA
$
379.4
$
20.2
$
75.8
$
(85.4)
$
-
$
390.0
Reconciling items to net loss:
Depreciation and amortization
63.0
11.3
41.1
6.0
-
121.4
LCM / LIFO (gain) loss
(14.2)
(0.3)
21.1
-
-
6.6
Loss on impairment and disposal of assets
-
-
0.7
-
-
0.7
Interest expense
32.3
1.2
29.8
112.6
-
175.9
Debt extinguishment costs
-
-
38.3
3.1
-
41.4
Unrealized (gain) loss on derivatives
51.9
-
(6.0)
-
-
45.9
RINs mark-to-market loss
75.0
-
40.7
-
-
115.7
Other non-recurring expenses
15.6
Equity-based compensation and other items
34.4
Income tax expense
3.4
Noncontrolling interest adjustments
2.3
Net loss
$
(173.3)
Capital expenditures
$
68.4
$
2.0
$
528.1
$
0.3
$
-
$
598.8
PP&E, net
$
382.4
$
34.1
$
1,062.7
$
2.8
$
-
$
1,482.0
Specialty
Products and
Performance
Montana/
Consolidated
Year Ended December 31, 2021
Solutions
Brands
Renewables
Corporate
Eliminations
Total
Sales:
External customers
$
2,111.4
$
252.9
$
783.7
$
-
$
-
$
3,148.0
Inter-segment sales
16.1
-
-
-
(16.1)
-
Total sales
$
2,127.5
$
252.9
$
783.7
$
-
$
(16.1)
$
3,148.0
Adjusted EBITDA
$
104.6
$
33.8
$
44.4
$
(72.5)
$
-
$
110.3
Reconciling items to net loss:
Depreciation and amortization
68.5
13.6
34.6
8.0
-
124.7
LCM / LIFO gain
(35.1)
(3.8)
(11.4)
-
-
(50.3)
Loss on impairment and disposal of assets
3.1
0.1
0.8
0.1
-
4.1
Interest expense
18.5
0.3
8.3
122.4
-
149.5
Unrealized loss on derivatives
16.3
-
8.1
-
-
24.4
RINs mark-to-market loss
40.9
-
16.8
-
-
57.7
Other non-recurring expenses
8.1
Equity-based compensation and other items
50.7
Income tax expense
1.5
Net loss
$
(260.1)
Capital expenditures
$
57.6
$
3.3
$
83.0
$
-
$
-
$
143.9
PP&E, net
$
375.5
$
34.3
$
531.3
$
8.6
$
-
$
949.7
(1) For the year ended December 31, 2023, Adjusted EBITDA for the Specialty Products and Solutions segment included a $9.5 million gain recorded in cost of sales in the consolidated statements of operations for proceeds received under the Company’s property damage insurance policy.
(2) For the year ended December 31, 2023, Adjusted EBITDA for the Performance Brands segment included a $8.2 million gain recorded in cost of sales in the consolidated statements of operations for proceeds received under the Company’s business interruption insurance policy.
(3) For the year ended December 31, 2023, Adjusted EBITDA for the Montana/Renewables segment excluded a $50.6 million charge to cost of sales in the consolidated statements of operations for losses under firm purchase commitments. For the year ended December 31, 2022, Adjusted EBITDA for the Montana/Renewables segment excluded a $13.0 million charge to cost of sales in the consolidated statements of operations for losses under firm purchase commitments.
(4) For the year ended December 31, 2022, Adjusted EBITDA for the Specialty Products and Solutions segment included a $13.9 million gain recorded in cost of sales in the consolidated statements of operations for proceeds received under the Company’s business interruption insurance policy. The Company incurred business losses due to increased costs arising from a polar vortex that occurred in 2021 in northwest Louisiana. As a result, the Company filed a contingent business interruption claim. Specifically, the losses included a loss of throughput at the Shreveport refinery and additional transportation related expenses.
(5) For the year ended December 31, 2022, Adjusted EBITDA for the Specialty Products and Solutions segment included a $4.4 million gain recorded in cost of sales in the consolidated statements of operations for proceeds received under the Company’s property damage insurance policy as a result of damages caused by a polar vortex that occurred in 2021.
Geographic Information
International sales accounted for less than ten percent of consolidated sales in each of the years ended December 31, 2023, 2022, and 2021 respectively.
Product Information
The Company offers specialty, fuels, renewable fuels and packaged products primarily in categories consisting of lubricating oils, solvents, waxes, gasoline, diesel, jet fuel, asphalt, heavy fuel oils, renewable fuels, high-performance branded specialty products, and other specialty and fuels products. The following table sets forth the major product category sales for each segment (dollars in millions):
Year Ended December 31,
2022 (As Restated)
Specialty Products and Solutions:
Lubricating oils
$
763.8
18.3
%
$
913.7
19.5
%
$
658.7
20.9
%
Solvents
398.5
9.5
%
434.9
9.3
%
303.7
9.7
%
Waxes
163.9
3.9
%
189.3
4.0
%
151.7
4.8
%
Fuels, asphalt and other by-products
1,550.7
37.2
%
1,970.1
42.0
%
997.3
31.7
%
Total
$
2,876.9
68.9
%
$
3,508.0
74.8
%
$
2,111.4
67.1
%
Montana/Renewables:
Gasoline
$
167.2
4.0
%
$
188.1
4.0
%
$
188.3
6.0
%
Diesel
144.8
3.5
%
391.8
8.4
%
324.9
10.3
%
Jet fuel
20.5
0.5
%
41.8
0.9
%
27.5
0.9
%
Asphalt, heavy fuel oils and other
148.1
3.5
%
253.2
5.4
%
243.0
7.7
%
Renewable fuels
513.2
12.3
%
-
-
-
-
%
Total
$
993.8
23.8
%
$
874.9
18.7
%
$
783.7
24.9
%
Performance Brands:
$
310.3
7.4
%
$
303.4
6.5
%
$
252.9
8.0
%
Consolidated sales
$
4,181.0
100.0
%
$
4,686.3
100.0
%
$
3,148.0
100.0
%
Major Customers
During the years ended December 31, 2023, 2022, and 2021 the Company had no customer that represented 10% or greater of consolidated sales.
Major Suppliers
During the years ended December 31, 2023, 2022, and 2021 the Company had two counterparties that supplied approximately 90.2%, 86.2%, and 90.2%, respectively, of its crude oil supply.
19. Unrestricted Subsidiaries
As defined in the indentures governing the Company’s outstanding senior notes, an unrestricted subsidiary means Montana Renewables Holdings, MRL and any other subsidiary of the Company, other than Calumet Finance Corp., that is designated by the Company’s general partner’s board of directors as an unrestricted subsidiary, but only to the extent that such subsidiary:
● has no indebtedness other than non-recourse debt owing to any person other than the Company or any of its restricted subsidiaries, except to the extent permitted by the indentures of the senior notes;
● is not party to any agreement, contract, arrangement or understanding with the Company or any restricted subsidiary of the Company unless the terms of any such agreement, contract, arrangement or other understanding are no less favorable to the Company or such restricted subsidiary than those that might be obtained at the time from persons who are not affiliates of the Company, except to the extent permitted by the indentures of the senior notes;
● is a person with respect to which neither the Company nor any of its restricted subsidiaries has any direct or indirect obligation (a) to subscribe for additional equity interests or (b) to maintain or preserve such person’s financial condition or to cause such person to achieve any specified levels of operating results, except to the extent permitted by the indentures of the senior notes; and
● has not guaranteed or otherwise directly or indirectly provided credit support for any indebtedness of the Company or any of its restricted subsidiaries.
For the years ended December 31, 2023 and December 31, 2022, respectively, Montana Renewables Holdings and MRL were the only unrestricted subsidiaries of the Company. In accordance with the indentures governing the Company’s outstanding senior notes, the following table sets forth certain financial information of (i) the Company and its restricted subsidiaries, on a combined basis, (ii) the Company’s unrestricted subsidiaries, on a combined basis, and (iii) the Company and its subsidiaries, on a consolidated basis, in each case, as of December 31, 2023 and December 31, 2022, respectively.
Parent
Company and
Restricted
Unrestricted
Consolidated
December 31, 2023
Subsidiaries
Subsidiaries
Eliminations
Total
Cash and cash equivalents
$
7.3
$
0.6
$
-
$
7.9
Accounts receivable - trade
$
230.7
$
21.7
$
-
$
252.4
Accounts receivable - other
$
24.8
$
9.0
$
-
$
33.8
Inventory
$
353.1
$
86.3
$
-
$
439.4
Prepaid expenses and other current assets
$
14.6
$
37.0
$
-
$
51.6
Property, plant and equipment, net
$
731.7
$
774.6
$
-
$
1,506.3
Operating lease right-of-use assets
$
108.1
$
6.3
$
-
$
114.4
Other noncurrent assets, net
$
127.3
$
7.1
$
-
$
134.4
Accounts payable
$
282.4
$
333.3
$
(293.7)
$
322.0
Accrued interest payable
$
47.8
$
0.9
$
-
$
48.7
Other taxes payable
$
11.9
$
1.6
$
-
$
13.5
Obligations under inventory financing agreements
$
126.0
$
64.4
$
-
$
190.4
Other current liabilities
$
20.4
$
22.0
$
-
$
42.4
Current portion of operating lease liabilities
$
72.2
$
3.4
$
-
$
75.6
Current portion of long-term debt
$
38.8
$
16.9
$
-
$
55.7
Long-term operating lease liabilities
$
36.0
$
3.0
$
-
$
39.0
Long-term debt
$
1,381.0
$
548.7
$
(100.0)
$
1,829.7
Redeemable noncontrolling interest
$
-
$
245.6
$
-
$
245.6
Partners’ capital (deficit)
$
(174.3)
$
(297.2)
$
(18.8)
$
(490.3)
Parent
Company and
Restricted
Unrestricted
Consolidated
December 31, 2022 (As Restated)
Subsidiaries
Subsidiaries
Eliminations
Total
Cash and cash equivalents
$
9.4
$
25.8
$
-
$
35.2
Accounts receivable - trade
$
238.4
$
6.3
$
-
$
244.7
Accounts receivable - other
$
20.5
$
1.9
$
-
$
22.4
Inventory
$
369.8
$
127.9
$
-
$
497.7
Prepaid expenses and other current assets
$
13.6
$
6.0
$
-
$
19.6
Property, plant and equipment, net
$
760.7
$
721.3
$
-
$
1,482.0
Operating lease right-of-use assets
$
105.7
$
1.8
$
-
$
107.5
Other noncurrent assets, net
$
113.8
$
8.8
$
-
$
122.6
Accounts payable
$
307.2
$
265.6
$
(130.8)
$
442.0
Obligations under inventory financing agreements
$
158.2
$
63.6
$
-
$
221.8
Other current liabilities
$
21.2
$
13.1
$
-
$
34.3
Current portion of operating lease liabilities
$
70.1
$
0.6
$
-
$
70.7
Current portion of long-term debt
$
7.9
$
11.7
$
-
$
19.6
Long-term operating lease liabilities
$
35.9
$
1.2
$
-
$
37.1
Long-term debt
$
1,183.5
$
356.6
$
-
$
1,540.1
Redeemable noncontrolling interest
$
-
$
245.6
$
-
$
245.6
Partners’ capital (deficit)
$
(456.3)
$
(58.2)
$
(18.8)
$
(533.3)
The following table sets forth certain financial information of the Company’s unrestricted subsidiaries, on a combined basis, as of December 31, 2023, 2022 and 2021, respectively.
Year Ended December 31,
2022 (As Restated)
(In millions, except unit and per unit data)
Sales
$
513.2
$
65.9
$
6.9
Cost of sales
651.0
77.8
5.0
Gross profit (loss)
(137.8)
(11.9)
1.9
Operating costs and expenses:
General and administrative
22.1
2.0
2.1
Taxes other than income taxes
4.3
-
-
Loss on impairment and disposal of assets
3.4
-
-
Operating loss
(167.6)
(13.9)
(0.2)
Other income (expense):
Interest expense
(77.8)
(32.8)
(5.2)
Debt extinguishment costs
-
(38.3)
-
Gain on derivative instruments
5.3
11.3
-
Other income
1.1
0.4
-
Total other expense
(71.4)
(59.4)
(5.2)
Net loss
$
(239.0)
$
(73.3)
$
(5.4)
20. Redeemable Noncontrolling Interest
On August 5, 2022 (the “Closing Date”), MRHL issued and sold 12,500,000 preferred units (“Preferred Units”) in MRHL to an affiliate of Warburg Pincus LLC for $250.0 million for an immediate cash payment of $200.0 million and the agreement to pay the remaining $50.0 million in cash not later than October 3, 2022 (the “Deferred Purchase Price”) in exchange for a 14.2045% Percentage Interest in MRHL. The Company received the cash payment for the Deferred Purchase Price on October 3, 2022. The Preferred Units are not interest bearing and carry certain minimum return thresholds.
Holders of the Preferred Units are entitled to receive a preferred return equal to the greater of (i) an internal rate of return, or IRR, as defined in the Second Amended and Restated Limited Liability Company Agreement of MRHL (the “Second A&R LLC Agreement”), equal to 8.0% and (ii) a multiple on invested capital, or MOIC (as defined in the Second A&R LLC Agreement), initially equal to 1.35 and increasing by 0.01 each anniversary of the Closing Date up to a maximum MOIC equal to 1.40 on or after the fifth anniversary of the Closing Date (the “Preferred Return”). Pursuant to the Second A&R LLC Agreement, MRHL is required to distribute all Available Cash (as defined in the Second A&R LLC Agreement), to the members of MRHL (the “Members”) in the following priority: (i) 37.5% to the holders of the Preferred Units and 62.5% to all other Members pro rata based on their Percentage Interests (as defined in the Second A&R LLC Agreement) until the holders of the Preferred Units receive the Preferred Return and (ii) thereafter, 100.0% to the Members pro rata based on their Percentage Interests. Additionally, pursuant to the Second A&R LLC Agreement the Company is required to make distributions to the Members sufficient to enable them to pay, on a quarterly basis, federal, state and local taxes arising from the allocations made to such members. Further, such distributions are determined by the Company and shall be made within thirty (30) days after the close of each applicable quarter. Any tax liability distributions shall be treated as an advance against, and shall reduce the amount of, the next distribution that the members would otherwise receive pursuant to the agreement.
At any time following the fifth anniversary of the Closing Date, if MRHL has not had an Initial Public Offering or Change of Control (each as defined in the Second A&R LLC Agreement), Warburg has the right to initiate an Initial Public Offering or Change of Control transaction pursuant to the terms of the Second A&R LLC Agreement. Upon the closing of a Qualified Initial Public Offering (as defined in the Second A&R LLC Agreement), each of MRHL and Warburg have the right to elect to convert all (but not less than all) of the Preferred Units (i) first by MRHL paying each holder of Preferred Units an amount in cash equal to such holder’s Preferred Return (to the extent not already paid) and (ii) thereafter, the Preferred Units automatically convert into the same number of common units of MRHL and will be entitled to participate in any distributions of Available Cash to the Members in proportion to their respective Percentage Interests. The Second A&R LLC Agreement also provides certain drag-along rights in connection with a Change of Control, subject to a minimum preferred return requirement for certain transactions that are consummated before the third anniversary of the Closing Date.
The redeemable noncontrolling interest in MRHL is reflected as temporary equity in the consolidated balance sheets due to the redemption features described above and included a balance of $245.6 million as of December 31, 2023 and 2022, as restated, respectively, which reflects the amount recorded for the Preferred Units at their issuance date fair value, net of issuance costs. As of the reporting date, there are no triggering, change of control, early redemption or monetization events that are probable that would require us to revalue the Preferred Units.
21. Restatement of Prior Period
The Company has restated its consolidated financial statements as of and for the year ended December 31, 2022. This restatement corrects the error related to the attribution of net loss from MRHL to noncontrolling interest for the year ended December 31, 2022. The Company previously allocated its net loss to noncontrolling interest based on the relative ownership interest of the equity holders in MRHL, which was approximately 14% for the noncontrolling interest. The Partnership has subsequently determined that, under applicable accounting standards, no portion of the net loss from MRHL should have been allocated to noncontrolling interest. In addition to the restatement error described above, the Company has corrected certain items that were concluded as immaterial, individually and in the aggregate, to the financial statements for the year ended December 31, 2022.
The effects of the restatement on the consolidated balance sheet as of December 31, 2022 are summarized in the following table:
December 31, 2022
(In millions, except unit data)
As Previously
Reported
Effect of
Restatement
As Restated
ASSETS
Current assets:
Cash and cash equivalents
$
35.2
$
-
$
35.2
Accounts receivable, net:
Trade, less allowance for credit losses of $1.3 million
245.7
(1.0)
244.7
Other
22.3
0.1
22.4
268.0
(0.9)
267.1
Inventories
498.0
(0.3)
497.7
Prepaid expenses and other current assets
19.2
0.4
19.6
Total current assets
820.4
(0.8)
819.6
Property, plant and equipment, net
1,482.0
-
1,482.0
Goodwill
173.0
-
173.0
Other intangible assets, net
36.3
-
36.3
Operating lease right-of-use assets
107.5
-
107.5
Other noncurrent assets, net
122.6
-
122.6
Total assets
$
2,741.8
$
(0.8)
$
2,741.0
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Accounts payable
$
442.4
$
(0.4)
$
442.0
Accrued interest payable
34.6
-
34.6
Accrued salaries, wages and benefits
93.0
-
93.0
Other taxes payable
9.5
-
9.5
Obligations under inventory financing agreements
221.8
-
221.8
Current portion of RINs obligation
399.3
(0.4)
398.9
Other current liabilities
34.3
-
34.3
Current portion of operating lease liabilities
70.7
-
70.7
Current portion of long-term debt
20.0
(0.4)
19.6
Derivative liabilities
26.5
-
26.5
Total current liabilities
1,352.1
(1.2)
1,350.9
Pension and postretirement benefit obligations
4.8
-
4.8
Other long-term liabilities
18.3
-
18.3
Long-term operating lease liabilities
37.1
-
37.1
Long-term RINs obligation, less current portion
77.5
-
77.5
Long-term debt, less current portion
1,539.7
0.4
1,540.1
Total liabilities
$
3,029.5
$
(0.8)
$
3,028.7
Commitments and contingencies
Redeemable noncontrolling interest
$
250.0
$
(4.4)
$
245.6
Partners’ capital (deficit):
Limited partners’ interest (79,189,583 units issued and outstanding at December 31, 2022)
$
(529.9)
$
4.6
$
(525.3)
General partner’s interest
0.5
(0.2)
0.3
Accumulated other comprehensive loss
(8.3)
-
(8.3)
Total partners’ capital (deficit)
(537.7)
4.4
(533.3)
Total liabilities and partners’ capital (deficit)
$
2,741.8
$
(0.8)
$
2,741.0
The effects of the restatement on the consolidated statement of operations for the year ended December 31, 2022 are summarized in the following table:
Year Ended December 31, 2022
As Previously
Effect of
Reported
Restatement
As Restated
(In millions, except unit and per unit data)
Sales
$
4,686.7
$
(0.4)
$
4,686.3
Cost of sales
4,335.9
(1.3)
4,334.6
Gross profit
350.8
0.9
351.7
Operating costs and expenses:
Selling
53.9
-
53.9
General and administrative
141.0
2.4
143.4
Taxes other than income taxes
13.7
-
13.7
Loss on impairment and disposal of assets
0.7
-
0.7
Other operating expense
8.1
-
8.1
Operating income
133.4
(1.5)
131.9
Other expense:
Interest expense
(175.9)
-
(175.9)
Debt extinguishment costs
(41.4)
-
(41.4)
Loss on derivative instruments
(81.7)
-
(81.7)
Other expense
(2.8)
-
(2.8)
Total other expense
(301.8)
-
(301.8)
Net loss before income taxes
(168.4)
(1.5)
(169.9)
Income tax expense
3.4
-
3.4
Net loss
$
(171.8)
$
(1.5)
$
(173.3)
Net loss attributable to noncontrolling interest
(6.7)
6.7
-
Net loss attributable to partners
$
(165.1)
$
(8.2)
$
(173.3)
Allocation of net loss to partners:
Net loss attributable to partners
$
(165.1)
$
(8.2)
$
(173.3)
Less:
General partners’ interest in net loss
(3.3)
(0.2)
(3.5)
Net loss available to limited partners
$
(161.8)
$
(8.0)
$
(169.8)
Weighted average limited partner units outstanding:
Basic and diluted
79,336,283
-
79,336,283
Limited partners’ interest basic and diluted net loss per unit:
Limited partners’ interest
$
(2.04)
$
(0.10)
$
(2.14)
The effects of the restatement on the consolidated statement of comprehensive income (loss) for the year ended December 31, 2022 are summarized in the following table:
Year Ended December 31, 2022
As Previously
Effect of
Reported
Restatement
As Restated
(In millions)
Net loss
$
(171.8)
$
(1.5)
$
(173.3)
Other comprehensive income:
Defined benefit pension and retiree health benefit plans
1.8
-
1.8
Total other comprehensive income
1.8
-
1.8
Comprehensive loss
$
(170.0)
$
(1.5)
$
(171.5)
Less: Comprehensive loss attributable to noncontrolling interest
(6.7)
6.7
-
Comprehensive loss attributable to partners’ capital (deficit)
$
(163.3)
$
(8.2)
$
(171.5)
The effects of the restatement on the consolidated statement of partners’ capital (deficit) for the year ended December 31, 2022 are summarized in the following table:
Accumulated
Other
Partners’ Capital (Deficit)
Comprehensive
General
Limited
Loss
Partner
Partners
Total
(In millions)
Balance at December 31, 2021 (as previously reported)
$
(10.1)
$
3.8
$
(378.8)
$
(385.1)
Other comprehensive income
1.8
-
-
1.8
Net loss attributable to partners
-
(3.3)
(161.8)
(165.1)
Settlement of phantom units
-
-
6.7
6.7
Settlement of tax withholdings on equity-based incentive compensation
-
-
(4.1)
(4.1)
Modification of phantom units
-
-
13.5
13.5
Amortization of phantom units
-
-
5.7
5.7
Adjustment to ASC 480 redemption value
-
-
(11.1)
(11.1)
Balance at December 31, 2022
$
(8.3)
$
0.5
$
(529.9)
$
(537.7)
Restatement Impacts
Net loss attributable to partners
-
(0.2)
(8.0)
(8.2)
Settlement of phantom units
-
-
1.5
1.5
Adjustment to ASC 480 redemption value
-
-
11.1
11.1
Balance at December 31, 2022 (restatement impacts)
$
-
$
(0.2)
$
4.6
$
4.4
Balance at December 31, 2021 (as previously reported)
$
(10.1)
$
3.8
$
(378.8)
$
(385.1)
Other comprehensive income
1.8
-
-
1.8
Net loss attributable to partners
-
(3.5)
(169.8)
(173.3)
Settlement of phantom units
-
-
8.2
8.2
Settlement of tax withholdings on equity-based incentive compensation
-
-
(4.1)
(4.1)
Modification of phantom units
-
-
13.5
13.5
Amortization of phantom units
-
-
5.7
5.7
Balance at December 31, 2022 (as restated)
$
(8.3)
$
0.3
$
(525.3)
$
(533.3)
The effects of the restatement on the consolidated statement of cash flows for the year ended December 31, 2022 are summarized in the following table:
Year Ended December 31, 2022
As Previously
Reported
Effect of
Restatement
As Restated
(In millions)
Operating activities
Net loss
$
(171.8)
$
(1.5)
$
(173.3)
Adjustments to reconcile net loss to net cash provided by operating activities:
-
Depreciation and amortization
98.3
-
98.3
Amortization of turnaround costs
23.1
-
23.1
Non-cash interest expense
17.6
-
17.6
Debt extinguishment costs
41.4
-
41.4
Non-cash RINs expense
197.9
(0.4)
197.5
Unrealized loss on derivative instruments
45.9
-
45.9
Loss on impairment and disposal of assets
0.7
-
0.7
Equity based compensation
15.8
1.5
17.3
Lower of cost or market inventory adjustment
19.4
-
19.4
Other non-cash activities
2.2
-
2.2
Changes in assets and liabilities
Accounts receivable
(15.0)
0.9
(14.1)
Inventories
(190.8)
0.3
(190.5)
Prepaid expenses and other current assets
(5.2)
(0.4)
(5.6)
Turnaround costs
(62.6)
-
(62.6)
Accounts payable
57.3
(0.4)
56.9
Accrued interest payable
8.4
-
8.4
Accrued salaries, wages and benefits
9.5
-
9.5
Other taxes payable
(2.1)
-
(2.1)
Other liabilities
10.6
-
10.6
Net cash provided by operating activities
100.6
-
100.6
Investing activities
Additions to property, plant and equipment
(536.2)
-
(536.2)
Proceeds from sale of property, plant and equipment
0.2
-
0.2
Net cash used in investing activities
(536.0)
-
(536.0)
Financing activities
Proceeds from borrowings - revolving credit facility
1,695.1
-
1,695.1
Repayments of borrowings - revolving credit facility
(1,591.1)
-
(1,591.1)
Proceeds from borrowings - senior notes
325.0
-
325.0
Repayments of borrowings - senior notes
(363.1)
-
(363.1)
Payments on finance lease obligations
(0.9)
-
(0.9)
Proceeds from inventory financing
2,166.0
-
2,166.0
Payments on inventory financing
(2,132.6)
-
(2,132.6)
Proceeds from sale of redeemable noncontrolling interest in subsidiary
250.0
-
250.0
Payments for issuance of Preferred Units
(4.4)
-
(4.4)
Repayments of borrowings - MRL Credit Facility
(347.3)
-
(347.3)
Proceeds from other financing obligations
372.9
-
372.9
Payments on other financing obligations
(15.6)
-
(15.6)
Debt issuance costs
(5.3)
-
(5.3)
Net cash provided by financing activities
348.7
-
348.7
Net decrease in cash, cash equivalents and restricted cash
(86.7)
-
(86.7)
Cash, cash equivalents and restricted cash at beginning of period
121.9
-
121.9
Cash, cash equivalents and restricted cash at end of period
$
35.2
$
-
$
35.2
Cash and cash equivalents
$
35.2
$
-
$
35.2
Restricted cash
$
-
$
-
$
-
Supplemental disclosure of non-cash investing activities
Non-cash property, plant and equipment additions
$
151.4
$
-
$
151.4
Supplemental disclosure of non-cash investing activities
Non-cash property, plant and equipment additions
$
136.9
$
-
$
136.9
22. Quarterly Financial Data (Unaudited)
The Company has restated its unaudited interim condensed consolidated financial statements for the periods ended March 31, 2023, June 30, 2023, and September 30, 2023. This restatement corrects the error related to the attribution of net loss from MRHL to noncontrolling interest for all restated periods. The Company previously allocated its net loss to noncontrolling interest based on the relative ownership interest of the equity holders in MRHL, which was approximately 14% for the noncontrolling interest. The Partnership has subsequently determined that, under applicable accounting standards, no portion of the net loss from MRHL should have been allocated to noncontrolling interest. In addition to the restatement error described above, the Company has corrected certain items that were concluded as immaterial, individually and in the aggregate, to the unaudited interim condensed consolidated financial statements for the periods ended March 31, 2023, June 30, 2023, and September 30, 2023.
As of and for the Three Months Ended March 31, 2023
The effects of the restatement on the condensed consolidated balance sheet as of March 31, 2023 are summarized in the following table:
March 31, 2023
(In millions, except unit data)
As Previously
Reported
Effect of
Restatement
As Restated
ASSETS
Current assets:
Cash and cash equivalents
$
11.2
$
-
$
11.2
Accounts receivable, net:
Trade, less allowance for credit losses of $1.5 million
262.2
-
262.2
Other
34.7
-
34.7
296.9
-
296.9
Inventories
454.8
-
454.8
Derivative assets
7.1
-
7.1
Prepaid expenses and other current assets
29.9
-
29.9
Total current assets
799.9
-
799.9
Property, plant and equipment, net
1,543.2
-
1,543.2
Other noncurrent assets, net
421.4
-
421.4
Total assets
$
2,764.5
$
-
$
2,764.5
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Accounts payable
$
394.3
$
-
$
394.3
Accrued interest payable
39.5
-
39.5
Accrued salaries, wages and benefits
75.1
1.6
76.7
Obligations under inventory financing agreements
204.0
-
204.0
Current portion of RINs obligation
419.5
-
419.5
Other current liabilities
112.7
-
112.7
Current portion of long-term debt
20.6
-
20.6
Total current liabilities
1,265.7
1.6
1,267.3
Other long-term liabilities
52.9
-
52.9
Long-term RINs obligation, less current portion
25.2
-
25.2
Long-term debt, less current portion
1,696.8
-
1,696.8
Total liabilities
$
3,040.6
$
1.6
$
3,042.2
Commitments and contingencies
Redeemable noncontrolling interest
$
250.0
$
(4.4)
$
245.6
Partners’ capital (deficit):
Limited partners’ interest (79,835,801 units issued and outstanding at March 31, 2023)
$
(518.9)
$
3.2
$
(515.7)
General partner’s interest
1.1
(0.4)
0.7
Accumulated other comprehensive loss
(8.3)
-
(8.3)
Total partners’ capital (deficit)
(526.1)
2.8
(523.3)
Total liabilities and partners’ capital (deficit)
$
2,764.5
$
-
$
2,764.5
The effects of the restatement on the condensed consolidated statement of operations for the three months ended March 31, 2023 are summarized in the following table:
Three Months Ended March 31, 2023
As Previously
Reported
Effect of
Restatement
As Restated
(In millions, except unit and per unit data)
Sales
$
1,036.9
$
0.4
$
1,037.3
Cost of sales
940.2
0.5
940.7
Gross profit
96.7
(0.1)
96.6
Operating costs and expenses:
Selling
13.5
-
13.5
General and administrative
37.0
0.1
37.1
Other operating expense
3.0
-
3.0
Operating income
43.2
(0.2)
43.0
Other income (expense):
Interest expense
(49.2)
-
(49.2)
Gain on derivative instruments
25.5
-
25.5
Other expense
(0.2)
-
(0.2)
Total other expense
(23.9)
-
(23.9)
Net income before income taxes
19.3
(0.2)
19.1
Income tax expense
0.5
-
0.5
Net income
$
18.8
$
(0.2)
$
18.6
Net loss attributable to noncontrolling interest
(9.9)
9.9
-
Net income attributable to partners
$
28.7
$
(10.1)
$
18.6
Allocation of net income to partners:
Net income attributable to partners
$
28.7
$
(10.1)
$
18.6
Less:
General partners’ interest in net income
0.6
(0.2)
0.4
Net income available to limited partners
$
28.1
$
(9.9)
$
18.2
Weighted average limited partner units outstanding:
Basic
79,830,671
-
79,830,671
Diluted
79,939,985
-
79,939,985
Limited partners’ interest basic and diluted net income per unit:
Limited partners’ interest
$
0.35
$
(0.12)
$
0.23
Limited partners’ interest diluted net income per unit:
Limited partners’ interest
$
0.35
$
(0.12)
$
0.23
The effects of the restatement on the condensed consolidated statement of comprehensive income (loss) for the three months ended March 31, 2023 are summarized in the following table:
Three Months Ended March 31, 2023
As Previously
Effect of
Reported
Restatement
As Restated
(In millions)
Net income
$
18.8
$
(0.2)
$
18.6
Other comprehensive income:
Defined benefit pension and retiree health benefit plans
-
-
-
Total other comprehensive income
-
-
-
Comprehensive income attributable to partners’ capital (deficit)
$
18.8
$
(0.2)
$
18.6
Less: Comprehensive loss attributable to noncontrolling interest
(9.9)
9.9
-
Comprehensive income attributable to partners’ capital (deficit)
$
28.7
$
(10.1)
$
18.6
The effects of the restatement on the condensed consolidated statement of cash flow for the three months ended March 31, 2023 are summarized in the following table:
Three Months Ended March 31, 2023
As Previously
Reported
Effect of
Restatement
As Restated
(In millions)
Operating activities
Net income
$
18.8
$
(0.2)
$
18.6
Non-cash RINs gain
(32.1)
-
(32.1)
Unrealized gain on derivative instruments
(41.0)
-
(41.0)
Other non-cash activities
67.8
(1.5)
66.3
Changes in assets and liabilities
(40.2)
1.7
(38.5)
Net cash used in operating activities
(26.7)
-
(26.7)
Investing activities
Additions to property, plant and equipment
(130.4)
-
(130.4)
Net cash used in investing activities
(130.4)
-
(130.4)
Financing activities
Proceeds from borrowings - revolving credit facility
559.0
-
559.0
Repayments of borrowings - revolving credit facility
(437.0)
-
(437.0)
Proceeds from borrowings - MRL revolving credit agreement
18.7
-
18.7
Proceeds from inventory financing
388.5
-
388.5
Payments on inventory financing
(404.1)
-
(404.1)
Proceeds from other financing obligations
20.8
-
20.8
Payments on other financing obligations
(12.8)
-
(12.8)
Net cash provided by financing activities
133.1
-
133.1
Net decrease in cash, cash equivalents and restricted cash
(24.0)
-
(24.0)
Cash, cash equivalents and restricted cash at beginning of period
35.2
-
35.2
Cash, cash equivalents and restricted cash at end of period
$
11.2
$
-
$
11.2
Cash and cash equivalents
$
11.2
$
-
$
11.2
Restricted cash
$
-
$
-
$
-
Supplemental disclosure of non-cash investing activities
Non-cash property, plant and equipment additions
$
95.1
$
-
$
95.1
As of and for the Three and Six Months Ended June 30, 2023
The effects of the restatement on the condensed consolidated balance sheet as of June 30, 2023 are summarized in the following table:
June 30, 2023
(In millions, except unit data)
As Previously
Reported
Effect of
Restatement
As Restated
ASSETS
Current assets:
Cash and cash equivalents
$
36.0
$
-
$
36.0
Accounts receivable, net:
Trade, less allowance for credit losses of $1.2 million
252.8
-
252.8
Other
62.5
-
62.5
315.3
-
315.3
Inventories
439.9
0.4
440.3
Derivative assets
14.7
-
14.7
Prepaid expenses and other current assets
41.5
-
41.5
Total current assets
847.4
0.4
847.8
Property, plant and equipment, net
1,536.4
-
1,536.4
Other noncurrent assets, net
420.4
-
420.4
Total assets
$
2,804.2
$
0.4
$
2,804.6
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Accounts payable
$
278.2
$
0.4
$
278.6
Accrued interest payable
35.7
-
35.7
Accrued salaries, wages and benefits
74.4
-
74.4
Obligations under inventory financing agreements
213.1
-
213.1
Current portion of RINs obligation
475.1
-
475.1
Other current liabilities
99.8
-
99.8
Current portion of long-term debt
21.9
-
21.9
Total current liabilities
1,198.2
0.4
1,198.6
Other long-term liabilities
54.4
-
54.4
Long-term RINs obligation, less current portion
25.1
-
25.1
Long-term debt, less current portion
1,824.3
-
1,824.3
Total liabilities
$
3,102.0
$
0.4
$
3,102.4
Commitments and contingencies
Redeemable noncontrolling interest
$
250.0
$
(4.4)
$
245.6
Partners’ capital (deficit):
Limited partners’ interest (79,958,262 units issued and outstanding at June 30, 2023)
$
(540.3)
$
4.9
$
(535.4)
General partner’s interest
0.7
(0.5)
0.2
Accumulated other comprehensive loss
(8.2)
-
(8.2)
Total partners’ capital (deficit)
(547.8)
4.4
(543.4)
Total liabilities and partners’ capital (deficit)
$
2,804.2
$
0.4
$
2,804.6
The effects of the restatement on the condensed consolidated statement of operations for the three and six months ended June 30, 2023 are summarized in the following table:
Three Months Ended June 30, 2023
Six Months Ended June 30, 2023
As Previously
Effect of
As Previously
Effect of
Reported
Restatement
As Restated
Reported
Restatement
As Restated
(In millions, except unit and per unit data)
Sales
$
1,017.8
$
-
$
1,017.8
$
2,054.7
$
0.4
$
2,055.1
Cost of sales
946.4
(0.1)
946.3
1,886.6
0.4
1,887.0
Gross profit
71.4
0.1
71.5
168.1
-
168.1
Operating costs and expenses:
Selling
15.5
-
15.5
29.0
-
29.0
General and administrative
27.3
(1.6)
25.7
64.3
(1.5)
62.8
Other operating expense
5.2
-
5.2
8.2
-
8.2
Operating income
23.4
1.7
25.1
66.6
1.5
68.1
Other income (expense):
Interest expense
(55.8)
-
(55.8)
(105.0)
-
(105.0)
Gain on derivative instruments
14.3
-
14.3
39.8
-
39.8
Other expense
(5.5)
-
(5.5)
(5.7)
-
(5.7)
Total other expense
(47.0)
-
(47.0)
(70.9)
-
(70.9)
Net loss before income taxes
(23.6)
1.7
(21.9)
(4.3)
1.5
(2.8)
Income tax expense
0.4
0.4
0.9
0.9
Net loss
$
(24.0)
$
1.7
$
(22.3)
$
(5.2)
$
1.5
$
(3.7)
Net loss attributable to noncontrolling interest
(5.5)
5.5
-
(15.4)
15.4
-
Net loss attributable to partners
$
(18.5)
$
(3.8)
$
(22.3)
$
10.2
$
(13.9)
$
(3.7)
Allocation of net loss to partners:
Net loss attributable to partners
$
(18.5)
$
(3.8)
$
(22.3)
$
10.2
$
(13.9)
$
(3.7)
Less:
General partners’ interest in net loss
(0.4)
(0.1)
(0.5)
0.2
(0.3)
(0.1)
Net loss available to limited partners
$
(18.1)
$
(3.7)
$
(21.8)
$
10.0
$
(13.6)
$
(3.6)
Weighted average limited partner units outstanding:
Basic
80,152,648
-
80,152,648
79,992,637
-
79,992,637
Diluted
80,152,648
-
80,152,648
80,102,432
(109,795)
79,992,637
Limited partners’ interest basic net loss per unit:
Limited partners’ interest
$
(0.23)
$
(0.04)
$
(0.27)
$
0.13
$
(0.18)
$
(0.05)
Limited partners’ interest diluted net loss per unit:
Limited partners’ interest
$
(0.23)
$
(0.04)
$
(0.27)
$
0.12
$
(0.17)
$
(0.05)
The effects of the restatement on the condensed consolidated statement of comprehensive income (loss) for the three and six months ended June 30, 2023 are summarized in the following table:
Three Months Ended June 30, 2023
Six Months Ended June 30, 2023
As Previously
Effect of
As Previously
Effect of
Reported
Restatement
As Restated
Reported
Restatement
As Restated
(In millions)
Net loss
$
(24.0)
$
1.7
$
(22.3)
$
(5.2)
$
1.5
$
(3.7)
Other comprehensive income:
Defined benefit pension and retiree health benefit plans
0.1
-
0.1
0.1
-
0.1
Total other comprehensive income
0.1
-
0.1
0.1
-
0.1
Comprehensive loss attributable to partners’ capital (deficit)
$
(23.9)
$
1.7
$
(22.2)
$
(5.1)
$
1.5
$
(3.6)
Less: Comprehensive loss attributable to noncontrolling interest
(5.5)
5.5
-
(15.4)
15.4
-
Comprehensive loss attributable to partners’ capital (deficit)
$
(18.4)
$
(3.8)
$
(22.2)
$
10.3
$
(13.9)
$
(3.6)
The effects of the restatement on the condensed consolidated statement of cash flow for the six months ended June 30, 2023 are summarized in the following table:
Six Months Ended June 30, 2023
As Previously
Reported
Effect of
Restatement
As Restated
(In millions)
Operating activities
Net loss
$
(5.2)
$
1.5
$
(3.7)
Non-cash RINs expense
23.4
-
23.4
Unrealized gain on derivative instruments
(55.1)
-
(55.1)
Other non-cash activities
102.2
(1.5)
100.7
Changes in assets and liabilities
(117.9)
-
(117.9)
Net cash used in operating activities
(52.6)
-
(52.6)
Investing activities
Additions to property, plant and equipment
(208.2)
-
(208.2)
Net cash used in investing activities
(208.2)
-
(208.2)
Financing activities
Proceeds from borrowings - revolving credit facility
1,084.8
-
1,084.8
Repayments of borrowings - revolving credit facility
(1,101.0)
-
(1,101.0)
Proceeds from borrowings - MRL revolving credit agreement
37.2
-
37.2
Repayments of borrowings - MRL revolving credit agreement
(18.7)
-
(18.7)
Proceeds from borrowings - senior notes
325.0
-
325.0
Repayments of borrowings - senior notes
(121.0)
-
(121.0)
Proceeds from inventory financing
791.2
-
791.2
Payments on inventory financing
(796.6)
-
(796.6)
Proceeds from other financing obligations
95.8
-
95.8
Payments on other financing obligations
(28.5)
-
(28.5)
Net cash provided by financing activities
268.2
-
268.2
Net increase in cash, cash equivalents and restricted cash
7.4
-
7.4
Cash, cash equivalents and restricted cash at beginning of period
35.2
-
35.2
Cash, cash equivalents and restricted cash at end of period
$
42.6
$
-
$
42.6
Cash and cash equivalents
$
36.0
$
-
$
36.0
Restricted cash
$
6.6
$
-
$
6.6
Supplemental disclosure of non-cash investing activities
Non-cash property, plant and equipment additions
$
41.7
$
-
$
41.7
As of and for the Three and Nine Months Ended September 30, 2023
The effects of the restatement on the condensed consolidated balance sheet as of September 30, 2023 are summarized in the following table:
September 30, 2023
(In millions, except unit data)
As Previously
Reported
Effect of
Restatement
As Restated
ASSETS
Current assets:
Cash and cash equivalents
$
13.7
$
-
$
13.7
Accounts receivable, net:
Trade, less allowance for credit losses of $1.3 million
285.0
-
285.0
Other
62.8
-
62.8
347.8
-
347.8
Inventories
447.7
-
447.7
Derivative assets
5.2
-
5.2
Prepaid expenses and other current assets
49.0
-
49.0
Total current assets
863.4
-
863.4
Property, plant and equipment, net
1,526.9
-
1,526.9
Other noncurrent assets, net
414.5
-
414.5
Total assets
$
2,804.8
$
-
$
2,804.8
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Accounts payable
$
342.1
$
-
$
342.1
Accrued interest payable
41.2
-
41.2
Accrued salaries, wages and benefits
82.9
-
82.9
Obligations under inventory financing agreements
237.9
-
237.9
Current portion of RINs obligation
326.3
-
326.3
Other current liabilities
85.2
-
85.2
Current portion of long-term debt
204.6
-
204.6
Total current liabilities
1,320.2
-
1,320.2
Other long-term liabilities
57.5
-
57.5
Long-term RINs obligation, less current portion
16.5
-
16.5
Long-term debt, less current portion
1,608.2
-
1,608.2
Total liabilities
$
3,002.4
$
-
$
3,002.4
Commitments and contingencies
Redeemable noncontrolling interest
$
250.0
$
(4.4)
$
245.6
Partners’ capital (deficit):
Limited partners’ interest (79,964,002 units issued and outstanding at September 30, 2023)
$
(442.3)
$
5.0
$
(437.3)
General partner’s interest
2.8
(0.6)
2.2
Accumulated other comprehensive loss
(8.1)
-
(8.1)
Total partners’ capital (deficit)
(447.6)
4.4
(443.2)
Total liabilities and partners’ capital (deficit)
$
2,804.8
$
-
$
2,804.8
The effects of the restatement on the condensed consolidated statement of operations for the three and nine months ended September 30, 2023 are summarized in the following table:
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2023
As Previously
Effect of
As Previously
Effect of
Reported
Restatement
As Restated
Reported
Restatement
As Restated
(In millions, except unit and per unit data)
Sales
$
1,149.4
$
-
$
1,149.4
$
3,204.1
$
0.4
$
3,204.5
Cost of sales
887.8
0.1
887.9
2,774.4
0.5
2,774.9
Gross profit
261.6
(0.1)
261.5
429.7
(0.1)
429.6
Operating costs and expenses:
Selling
12.4
-
12.4
41.4
-
41.4
General and administrative
40.2
-
40.2
104.5
(1.5)
103.0
Other operating (income) expense
(4.1)
-
(4.1)
4.1
-
4.1
Operating income
213.1
(0.1)
213.0
279.7
1.4
281.1
Other income (expense):
Interest expense
(58.7)
-
(58.7)
(163.7)
-
(163.7)
Debt extinguishment costs
(0.3)
-
(0.3)
(5.5)
-
(5.5)
Loss on derivative instruments
(54.3)
-
(54.3)
(14.5)
-
(14.5)
Other income
0.6
-
0.6
0.1
-
0.1
Total other expense
(112.7)
-
(112.7)
(183.6)
-
(183.6)
Net income before income taxes
100.4
(0.1)
100.3
96.1
1.4
97.5
Income tax expense
0.5
-
0.5
1.4
1.4
Net income
$
99.9
$
(0.1)
$
99.8
$
94.7
$
1.4
$
96.1
Net loss attributable to noncontrolling interest
(3.1)
3.1
-
(18.5)
18.5
-
Net income attributable to partners
$
103.0
$
(3.2)
$
99.8
$
113.2
$
(17.1)
$
96.1
Allocation of net income to partners:
Net income attributable to partners
$
103.0
$
(3.2)
$
99.8
$
113.2
$
(17.1)
$
96.1
Less:
General partners’ interest in net income
2.1
(0.1)
2.0
2.3
(0.4)
1.9
Non-vested share based payments
0.1
-
0.1
0.1
-
0.1
Net income available to limited partners
$
100.8
$
(3.1)
$
97.7
$
110.8
$
(16.7)
$
94.1
Weighted average limited partner units outstanding:
Basic
80,172,810
-
80,172,810
80,046,930
-
80,046,930
Diluted
80,277,483
109,795
80,387,278
80,148,519
-
80,148,519
Limited partners’ interest basic net income per unit:
Limited partners’ interest
$
1.26
$
(0.04)
$
1.22
$
1.38
$
(0.20)
$
1.18
Limited partners’ interest diluted net income per unit:
Limited partners’ interest
$
1.26
$
(0.04)
$
1.22
$
1.38
$
(0.21)
$
1.17
The effects of the restatement on the condensed consolidated statement of comprehensive income (loss) for the three and nine months ended September 30, 2023 are summarized in the following table:
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2023
As Previously
Effect of
As Previously
Effect of
Reported
Restatement
As Restated
Reported
Restatement
As Restated
(In millions)
Net income
$
99.9
$
(0.1)
$
99.8
$
94.7
$
1.4
$
96.1
Other comprehensive income:
Defined benefit pension and retiree health benefit plans
0.1
-
0.1
0.2
-
0.2
Total other comprehensive income
0.1
-
0.1
0.2
-
0.2
Comprehensive income attributable to partners’ capital (deficit)
$
100.0
$
(0.1)
$
99.9
$
94.9
$
1.4
$
96.3
Less: Comprehensive loss attributable to noncontrolling interest
(3.1)
3.1
-
(18.5)
18.5
-
Comprehensive income attributable to partners’ capital (deficit)
$
103.1
$
(3.2)
$
99.9
$
113.4
$
(17.1)
$
96.3
The effects of the restatement on the condensed consolidated statement of cash flows for the nine months ended September 30, 2023 are summarized in the following table:
Nine Months Ended September 30, 2023
As Previously
Reported
Effect of
Restatement
As Restated
(In millions)
Operating activities
Net income
$
94.7
$
1.4
$
96.1
Non-cash RINs gain
(134.0)
-
(134.0)
Unrealized gain on derivative instruments
(18.8)
-
(18.8)
Other non-cash activities
147.4
(1.5)
145.9
Changes in assets and liabilities
(96.7)
0.1
(96.6)
Net cash used in operating activities
(7.4)
-
(7.4)
Investing activities
Additions to property, plant and equipment
(240.3)
-
(240.3)
Net cash used in investing activities
(240.3)
-
(240.3)
Financing activities
Proceeds from borrowings - revolving credit facility
1,585.6
-
1,585.6
Repayments of borrowings - revolving credit facility
(1,618.5)
-
(1,618.5)
Proceeds from borrowings - MRL revolving credit agreement
79.0
-
79.0
Repayments of borrowings - MRL revolving credit agreement
(79.0)
-
(79.0)
Proceeds from borrowings - senior notes
325.0
-
325.0
Repayments of borrowings - senior notes
(121.0)
-
(121.0)
Proceeds from inventory financing
1,229.3
-
1,229.3
Payments on inventory financing
(1,235.2)
-
(1,235.2)
Proceeds from other financing obligations
101.5
-
101.5
Payments on other financing obligations
(33.8)
-
(33.8)
Net cash provided by financing activities
232.9
-
232.9
Net decrease in cash, cash equivalents and restricted cash
(14.8)
-
(14.8)
Cash, cash equivalents and restricted cash at beginning of period
35.2
-
35.2
Cash, cash equivalents and restricted cash at end of period
$
20.4
$
-
$
20.4
Cash and cash equivalents
$
13.7
$
-
$
13.7
Restricted cash
$
6.7
$
-
$
6.7
Supplemental disclosure of non-cash investing activities
Non-cash property, plant and equipment additions
$
31.7
$
-
$
31.7
Effect of Restatement on the Condensed Consolidated Statement of Partners’ Capital (Deficit)
The effects of the restatement on the condensed consolidated statement of partners’ capital (deficit) for each of the three months period ended March 31, 2023, June 30, 2023, and September 30, 2023 and for the nine months period ended September 30, 2023 are summarized in the following table:
Accumulated
Other
Partners’ Capital (Deficit)
Comprehensive
General
Limited
Loss
Partner
Partners
Total
(In millions)
Balance at December 31, 2022 (as reported)
$
(8.3)
$
0.5
$
(529.9)
$
(537.7)
Net income attributable to partners
-
0.6
28.1
28.7
Settlement of tax withholdings on equity-based incentive compensation
-
-
(7.9)
(7.9)
Settlement of phantom units
-
-
0.5
0.5
Amortization of phantom units
-
-
0.2
0.2
Adjustment to ASC 480 redemption value
-
-
(9.9)
(9.9)
Balance at March 31, 2023
$
(8.3)
$
1.1
$
(518.9)
$
(526.1)
Restatement Impacts
Net loss attributable to partners
-
(0.2)
(9.9)
(10.1)
Settlement of phantom units
-
-
(1.5)
(1.5)
Adjustment to ASC 480 redemption value
-
-
9.9
9.9
Balance at March 31, 2023 (restatement impacts)
$
-
$
(0.2)
$
(1.5)
$
(1.7)
Balance at December 31, 2022 (as restated)
$
(8.3)
$
0.3
$
(525.3)
$
(533.3)
Net income attributable to partners
-
0.4
18.2
18.6
Settlement of tax withholdings on equity-based incentive compensation
-
-
(7.9)
(7.9)
Settlement of phantom units
-
-
(1.0)
(1.0)
Amortization of phantom units
-
-
0.3
0.3
Balance at March 31, 2023 (as restated)
$
(8.3)
$
0.7
$
(515.7)
$
(523.3)
Balance at March 31, 2023 (as reported)
$
(8.3)
$
1.1
$
(518.9)
$
(526.1)
Other comprehensive income
0.1
-
-
0.1
Net loss attributable to partners
-
(0.4)
(18.1)
(18.5)
Settlement of tax withholdings on equity-based incentive compensation
-
-
(1.7)
(1.7)
Settlement of phantom units
-
-
3.7
3.7
Amortization of phantom units
-
-
0.2
0.2
Adjustment to ASC 480 redemption value
-
-
(5.5)
(5.5)
Balance at June 30, 2023 (as reported)
$
(8.2)
$
0.7
$
(540.3)
$
(547.8)
Restatement Impacts
Net loss attributable to partners
-
(0.1)
(3.7)
(3.8)
Adjustment to ASC 480 redemption value
-
-
5.5
5.5
Balance at June 30, 2023 (restatement impacts)
$
-
$
(0.1)
$
1.8
$
1.7
Balance at March 31, 2023 (as restated)
$
(8.3)
$
0.7
$
(515.7)
$
(523.3)
Other comprehensive income
0.1
-
-
0.1
Net loss attributable to partners
-
(0.5)
(21.8)
(22.3)
Settlement of tax withholdings on equity-based incentive compensation
-
-
(1.7)
(1.7)
Settlement of phantom units
-
-
3.7
3.7
Amortization of phantom units
-
-
0.1
0.1
Balance at June 30, 2023 (as restated)
$
(8.2)
$
0.2
$
(535.4)
$
(543.4)
Balance at June 30, 2023 (as reported)
$
(8.2)
$
0.7
$
(540.3)
$
(547.8)
Other comprehensive income
0.1
-
-
0.1
Net income attributable to partners
-
2.1
100.9
103.0
Amortization of phantom units
-
-
0.2
0.2
Adjustment to ASC 480 redemption value
-
-
(3.1)
(3.1)
Balance at September 30, 2023 (as reported)
$
(8.1)
$
2.8
$
(442.3)
$
(447.6)
Restatement Impacts
Net loss attributable to partners
-
(0.1)
(3.1)
(3.2)
Adjustment to ASC 480 redemption value
-
-
3.1
3.1
Balance at September 30, 2023 (restatement impacts)
$
-
$
(0.1)
$
-
$
(0.1)
Balance at June 30, 2023 (as restated)
$
(8.2)
$
0.2
$
(535.4)
$
(543.4)
Other comprehensive income
0.1
-
-
0.1
Net income attributable to partners
-
2.0
97.8
99.8
Amortization of phantom units
-
-
0.3
0.3
Balance at September 30, 2023 (as restated)
$
(8.1)
$
2.2
$
(437.3)
$
(443.2)
Accumulated
Other
Partners’ Capital (Deficit)
Comprehensive
General
Limited
Loss
Partner
Partners
Total
(In millions)
Balance at December 31, 2022 (as restated)
$
(8.3)
$
0.3
$
(525.3)
$
(533.3)
Other comprehensive income
0.2
-
-
0.2
Net income attributable to partners
-
2.3
110.9
113.2
Settlement of tax withholdings on equity-based incentive compensation
-
-
(9.6)
(9.6)
Settlement of phantom units
-
-
4.2
4.2
Amortization of phantom units
-
-
0.7
0.7
Adjustment to ASC 480 redemption value
-
-
(18.5)
(18.5)
Balance at September 30, 2023
$
(8.1)
$
2.6
$
(437.6)
$
(443.1)
Restatement Impacts
Net loss attributable to partners
-
(0.4)
(16.7)
(17.1)
Settlement of phantom units
-
-
(1.5)
(1.5)
Adjustment to ASC 480 redemption value
-
-
18.5
18.5
Balance at September 30, 2023 (restatement impacts)
$
-
$
(0.4)
$
0.3
$
(0.1)
Balance at December 31, 2022 (as restated)
$
(8.3)
$
0.3
$
(525.3)
$
(533.3)
Other comprehensive income
0.2
-
-
0.2
Net income attributable to partners
-
1.9
94.2
96.1
Settlement of phantom units
-
-
2.7
2.7
Settlement of tax withholdings on equity-based incentive compensation
-
-
(9.6)
(9.6)
Amortization of phantom units
-
-
0.7
0.7
Balance at September 30, 2023 (as restated)
$
(8.1)
$
2.2
$
(437.3)
$
(443.2)
23. Subsequent Events
As of February 23, 2024, the fair value of the Company’s derivative instruments has changed by approximately $5.6 million subsequent to December 31, 2023.
On February 23, 2024, the Company announced that it delivered (i) a notice of conditional redemption for all of the 2024 Secured Notes at a redemption price of par, plus accrued and unpaid interest to but not including the redemption date of March 9, 2024, and (ii) a notice of conditional redemption for $50.0 million aggregate principal amount of the 2025 Notes at a redemption price of par, plus accrued and unpaid interest to but not including the redemption date of April 15, 2024.
The Company’s obligation to redeem all of the 2024 Secured Notes and $50.0 million aggregate principal amount of the 2025 Notes, in each case, is conditioned upon, on or before March 9, 2024, the completion of a private placement of at least $200.0 million aggregate principal amount of the Company’s senior debt securities. The Company will publicly announce and notify the holders of the 2024 Secured Notes, the holders of the 2025 Notes and Wilmington Trust, National Association, as trustee, if the foregoing condition is not satisfied or waived, whereupon the redemptions will be revoked and the 2024 Secured Notes and the 2025 Notes called for redemption will remain outstanding.

---

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Conclusion Regarding Effectiveness of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Based upon that evaluation and in connection with the restatement of our 2022 consolidated financial statements, our principal executive officer and principal financial officer have concluded that as of December 31, 2023, due to the material weakness in our internal control over financial reporting as described below, our disclosure controls and procedures were not effective as of December 31, 2023. In addition, our disclosure controls and procedures were not effective as of December 31, 2022.
Our disclosure controls and procedures were not effective to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.
Management’s Report on Internal Control Over Financial Reporting
The management of Calumet Specialty Products Partners, L.P. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and board of directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2023, based on criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (“COSO”). Based on this evaluation, management concluded that we did not maintain effective internal control over financial reporting as of December 31, 2023, due to the material weakness described below.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.
In connection with the preparation of the Company’s consolidated financial statements for the fiscal year ended December 31, 2023, we identified a material weakness in the design of our controls within the financial statement close process associated with the subsequent accounting for and measurement of redeemable noncontrolling interests. The material weakness also existed as of December 31, 2022.
This material weakness resulted in material errors in the attribution of Net losses to redeemable noncontrolling interest and the Net losses attributable to partners, which resulted in a restatement of the previously issued financial statements as of and for the year ended December 31, 2022 and as of and for each interim period during the year ended December 31, 2023, as more fully described in Note 21 - Restatement of Prior Period and Note 22 - Quarterly Financial Data (Unaudited) to the consolidated financial statements included herein. In addition to the restatement errors described above, the Company has corrected certain items that were concluded as immaterial, individually and in the aggregate, to the financial statements for the restated periods. These immaterial adjustments to the restated periods are being corrected as a part of the restatement.
Remediation of Material Weakness
We have evaluated the material weakness and have implemented and continue to implement a plan of remediation to strengthen our internal controls over financial reporting which includes implementing new controls and increased rigor of financial reporting controls that will address subsequent measurement of redeemable noncontrolling interests, including consideration of attribution of income and loss to redeemable noncontrolling interests. Consistent with past practice, preparation and reviews of technical accounting memos will operate for all material non-routine transactions. Management will engage third party resources with technical accounting expertise to assist in evaluating the appropriate accounting treatment of subsequent measurement of redeemable noncontrolling interests, and to ensure that appropriate controls are in place to evaluate the ongoing accounting for redeemable noncontrolling interests. The remediation efforts are intended to address the deficiencies and enhance our overall internal control environment.
We believe the measures described above along with other elements of our remediation plan will remediate the material weakness identified and strengthen our internal control over financial reporting. While we believe that these efforts will improve our internal control over financial reporting, the implementation of our remediation is currently ongoing and will require validation and testing of the design and operating effectiveness of our internal controls over a sustained period of financial reporting cycles.
We are committed to continuing to improve our internal control processes and have implemented the steps described above. We will also continue to review, optimize and enhance our financial reporting controls and procedures. As we continue to evaluate and work to improve our internal control over financial reporting, we may take additional measures to address control deficiencies or we may modify certain of the remediation measures described above.
Changes in Internal Control over Financial Reporting
Other than the actions to remediate the material weakness in our internal control over financial reporting as described above, both of which were ongoing as of the date of issuance of this Annual Report on Form 10-K, and the material weakness noted above, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Report of Independent Registered Public Accounting Firm
To the Board of Directors of Calumet GP, LLC
General Partner and the Partners of Calumet Specialty Products Partners, L.P.
Opinion on Internal Control Over Financial Reporting
We have audited Calumet Specialty Products Partners, L.P.’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, because of the effect of the material weakness described below on the achievement of the objective of the control criteria, Calumet Specialty Products Partners, L.P. (the Company) has not maintained effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment. Management has identified a material weakness in design of controls in the financial statement close process related to the Company’s accounting for and subsequent measurement of the redeemable noncontrolling interest.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income (loss), partners' capital (deficit) and cash flows for each of the three years in the period ended December 31, 2023, and the related notes. This material weakness was considered in determining the nature, timing and extent of audit tests applied in our audit of the 2023 consolidated financial statements, and this report does not affect our report dated February 29, 2024, which expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Indianapolis, Indiana
February 29, 2024

---

ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
During the three months ended December 31, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

---

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers of Our General Partner and Corporate Governance
Management of Calumet Specialty Products Partners, L.P. and Director Independence
Our general partner, Calumet GP, LLC, manages our operations and activities. Unitholders are limited partners and are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. Our general partner owes certain contractual duties to our unitholders pursuant to various provisions of our partnership agreement as well as fiduciary duties to its owners.
The directors of our general partner oversee our operations. The owners of our general partner have appointed nine members to our general partner’s board of directors. The directors of our general partner are generally elected by a majority vote of the owners of our general partner on an annual basis. However, as long as trusts established for the benefit of our former executive vice chairman of our general partner, F. William Grube, his family members or Permitted Transferees (as defined in our partnership agreement), continue to own at least 30% of the membership interests in our general partner, the Grube Family Group (as defined in our partnership agreement) has the right to appoint a member of Mr. Grube’s family to serve as a director of our general partner. The directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified.
Pursuant to Section 5615 of the Nasdaq Stock Market, LLC Marketplace Rules (“Nasdaq Rules”), a listed limited partnership like us is not required to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/governance committee. However, four of our general partner’s nine directors are “independent” as that term is defined in the Nasdaq Rules and Rule 10A-3 of the Exchange Act. In determining the independence of each director, our general partner has adopted standards that incorporate the Nasdaq Rules and Exchange Act standards. Our general partner’s independent directors as determined in accordance with those standards are: James S. Carter, Daniel L. Sheets, John (“Jack”) G. Boss, and Karen A. Twitchell. The board of directors held four meetings during 2023.
The officers of our general partner manage the day-to-day affairs of our business. Officers serve at the discretion of the board of directors.
Directors and Executive Officers
The following table shows information regarding the directors and executive officers of Calumet GP, LLC as of February 28, 2024:
Name
Age
Position with Calumet GP, LLC
Stephen P. Mawer
Chairman of the Board
Todd Borgmann
Chief Executive Officer
Bruce Fleming
Executive Vice President - Montana Renewables & Corporate Development
Scott Obermeier
Executive Vice President - Specialties
David Lunin
Executive Vice President - Chief Financial Officer
Gregory Morical
Senior Vice President, General Counsel & Secretary
James S. Carter
Director
Daniel J. Sajkowski
Director
Amy M. Schumacher
Director
Daniel L. Sheets
Director
Paul C. Raymond III
Director
Jennifer G. Straumins
Director
John (“Jack”) G. Boss
Director
Karen A. Twitchell
Director
Each director’s biographical information set forth below includes the particular experience and qualifications that led the board of directors to conclude that the director is qualified to serve in such capacity.
Stephen P. Mawer has served as chairman of the board of our general partners since January 2023 and has served as a board member of our general partner since March 2016. From May 2022 until December 2022, Mr. Mawer served in the role of Executive Chairman of our general partner. From April 2020 until May 2022, Mr. Mawer served as the Chief Executive Officer of our general partner. He retired as president of Koch Supply & Trading in 2014 following a 27-year career in commodities trading, risk management and refining operations. While at Koch, Mr. Mawer led global commodities trading and served as a senior member of the Koch Industries management team. Mr. Mawer holds Bachelor’s and Master’s degrees in chemical engineering from the University of Cambridge, England. Currently, he serves as a member of the Board of Directors at Zenith Energy Management and Howard Energy Partners, both of which are midstream company, as well as chairman of ClimeCo Corporation, an environmental commodities development and management company. He previously served as a member of the advisory board of Heritage Environmental Services.
Mr. Mawer brings extensive knowledge of petroleum markets, refining economics, supply/marketing optimization, sustainability and renewable fuels, and risk management.
Todd Borgmann has served as Chief Executive Officer of our general partner since May 2022. From February 2021 until the appointment to his current position, Mr. Borgmann served as Executive Vice President - Chief Financial Officer of our general partner. Mr. Borgmann has over fifteen years of experience with Calumet, serving the Company across a diverse set of management roles. For the five years preceding his appointment to Executive Vice President - Chief Financial Officer, Mr. Borgmann served as Senior Vice President - Chief Financial Officer, Senior Vice President - Interim Chief Financial Officer, and Vice President of Supply & Trading, developing extensive knowledge of petroleum markets, refining operations and risk management. Mr. Borgmann has also served as Calumet’s Vice President of Business Development and Director of the Partnership’s White Oils and Petroleum sales. Mr. Borgmann earned a Bachelor of Science in Industrial Engineering from Purdue University and a Masters of Business Administration from the University of Notre Dame.
Bruce Fleming has served as Executive Vice President - Montana Renewables & Corporate Development of our general partner since February 2021. From March 2016 until the appointment to his current position, Mr. Fleming served as Executive Vice President - Strategy & Growth of our general partner. From 2004 until joining the Company, Mr. Fleming served as the vice president of mergers & acquisitions at Tesoro Corporation and as an officer of Tesoro Companies Inc. From 1997 through 2004, Mr. Fleming served as managing director of Hong Kong-based Orient Refining Ltd., and from 1981 through 1996 he held senior operations, business development and planning roles with Amoco Oil and Amoco Corporation where he was most recently vice president of China business development. Mr. Fleming earned a Ph.D. in chemical engineering from Princeton University and a B.S. in chemical engineering from the University of Delaware. He is a member of the Board of M&A Standards.
Scott Obermeier was named Executive Vice President - Specialties of our general partner in January 2023. Prior to the appointment to his current position, Mr. Obermeier served as Executive Vice President - Specialty Products & Solutions and Executive Vice President - Commercial. Mr. Obermeier has been a Vice President with the Company since November 2017 and has more than 20 years of experience in sales and marketing as well as general management roles focused on the specialty chemicals market. Prior to his work with Calumet, he spent 10 years with Univar Solutions Inc., most recently serving as vice president where he managed the global chemical distributor’s organic chemicals business. Mr. Obermeier is a graduate of the University of Northern Iowa, with a degree in chemistry marketing.
David Lunin assumed the role of Executive Vice President - Chief Financial Officer of our general partner effective January 1, 2024. Prior to joining the Company, Mr. Lunin served in progressive roles with Goldman Sachs & Co. LLC (“Goldman Sachs”) from July 2010 to May 2023, most recently serving in the position of Managing Director, Financial Institutions Group from January 2022 to May 2023. Prior to this position, Mr. Lunin served as Vice President, Mergers and Acquisitions Group from September 2020 to July 2021 and as Investment Banking Vice President, Global Natural Resources, from 2014 to September 2020. Prior to Goldman Sachs, he served as Research Associate with Cornerstone Research and Associate with LECG, LLC. Mr. Lunin earned a Bachelor of Business Administration degree from George Washington University, a Master of Arts degree from Johns Hopkins University, and a Masters of Business Administration degree from Columbia Business School.
Gregory Morical is the Senior Vice President, General Counsel & Secretary of our general partner and has served as our General Counsel since April 2012. Prior to joining the Company, Mr. Morical served as the General Counsel of Dormir, Inc. and U.S. Biopsy, LLC, as an in-house counsel in other companies, as associate at Ice Miller LLP and as a judicial clerk for the U.S. Court of Appeals for the Seventh Circuit and the Supreme Court of Ohio. Mr. Morical has a J.D. from Indiana University School of Law-Bloomington and a B.A. in political science from DePauw University.
James S. Carter has served as a member of the board of directors of our general partner since January 2006. Mr. Carter worked in various operations, commercial and business analysis capacities at ExxonMobil including vice president of U.S. marketing and sales of fuels and specialty products, manager of U.S. refining and marketing planning and analysis, manager of U.S. distribution activities, analysis manager of ExxonMobil International, and advisor to ExxonMobil headquarters for European refining and marketing until his retirement in 2003. Mr. Carter was previously a board member of the Association of Audit Committee Members, Inc. He received his B.S. in mechanical engineering from Clemson University and his M.B.A. in finance and accounting from Tulane University.
Mr. Carter brings extensive managerial experience with one of the largest integrated energy companies in the world. He possesses a broad background in petroleum products marketing, with specific experience in the marketing of fuel products.
Daniel J. Sajkowski has served as a member of the board of directors of our general partner since September 2014. Mr. Sajkowski has served as executive vice president, Growth and New Ventures of The Heritage Group since 2013. Prior to joining The Heritage Group, Mr. Sajkowski was the senior director - downstream technology at Sapphire Energy from 2010 until 2013. From 2004 to 2010, Mr. Sajkowski served as business unit leader at BP’s Whiting, Indiana refinery. During his career with BP/Amoco, Mr. Sajkowski also held positions as the manager of integrated supply and trading from 2002 until 2004 and vice president of refining technology from 2000 until 2002. Mr. Sajkowski earned his B.S. and M.S. degrees in chemical engineering from the University of Michigan and a Ph.D. in chemical engineering from Stanford University. He also completed The General Manager Program at Harvard University.
Mr. Sajkowski has extensive refining industry experience including planning, operations and managerial roles for a large multinational refining company. His broad background of experience provides helpful insight to the Company in its implementation of strategic initiatives and its refinery operations in general.
Amy M. Schumacher has served as a member of the board of directors of our general partner since September 2014. Ms. Schumacher has been part of The Heritage Group family of businesses since 2003, working in various capacities and leading a variety of growth projects along the way. In 2008, Ms. Schumacher founded Monument Chemical and served as President and CEO for eight years. In 2016, Ms. Schumacher transitioned to President of The Heritage Group and was appointed Chief Executive Officer in 2020. From 1998 to 2003, Ms. Schumacher served as a consultant with Accenture. Ms. Schumacher received her B.S. in civil engineering from Purdue University and her M.S. in management from the Massachusetts Institute of Technology Sloan School. Ms. Schumacher currently serves as CEO and a trustee for The Heritage Group and sits on a number of private subsidiary boards. Ms. Schumacher is the daughter of Fred M. Fehsenfeld, Jr., the former chairman of the board of our general partner.
Ms. Schumacher has extensive managerial experience including planning and strategy. She possesses a broad background within the chemicals industry, with specific experience in strategic growth projects.
Daniel L. Sheets has served as a member of the board of directors of our general partner since October 2018. Mr. Sheets previously served as president of Lubrizol Additives and corporate senior vice president of The Lubrizol Corporation, a global company providing specialty chemicals for transportation, industrial and consumer markets, from 2008 until his retirement in 2018. Mr. Sheets joined Lubrizol in 1984 and served in a variety of roles including vice president of sales, vice president of engine additives, global business manager fuels, refinery and oilfield products and business development roles which led to multiple acquisitions and an assignment in Germany. Mr. Sheets received his B.S. in electrical engineering from Pennsylvania State University.
Mr. Sheets has extensive global management experience in specialty chemicals including strategy, commercial excellence, business development and acquisitions. He possesses a broad background in petroleum products marketing, with specific experience in the marketing of lubricants, lubricant additives and specialty chemicals.
Paul C. Raymond III has served as a member of the board of directors of our general partner since November 2020. Mr. Raymond brings over three decades of industry experience, which includes serving in his current role of chief executive officer of Monument Chemical and previously as president and chief executive officer of Sonneborn, LLC. Mr. Raymond holds a B.S in chemical engineering from Rice University and earned his Ph.D. in chemical engineering from the University of Texas at Austin.
Mr. Raymond brings extensive specialty chemicals knowledge and strategic insights, and his impressive track record leading and growing similar businesses makes him a terrific asset and provides helpful insight to the Partnership’s board of directors.
Jennifer G. Straumins has served as a member of the board of directors of our general partner since February 2021. Ms. Straumins is the Chairman of Maverick Performance Products’ Board of Directors and a Board member for Wincoram Asset Management. Prior to founding Maverick Performance Product’s, Jennifer was an employee of Calumet Specialty Products Partners for 13 years holding various positions. Prior to joining Calumet, Jennifer held financial planning positions with Great Lakes Chemical Company and Exxon Chemical Company. Jennifer received her B.E. in Chemical Engineering from Vanderbilt University and her MBA from the University of Kansas.
Ms. Straumins brings extensive specialty chemicals knowledge and strategic insights. Her background provides helpful insight to the Company in its implementation of strategic initiatives and operations in general.
John (“Jack”) G. Boss has served as a member of the board of directors of our general partner since August 2022. Mr. Boss brings over 40 years of experience to the Board of Calumet. He currently serves on the Board of Directors of Cooper-Standard (NYSE: CPS), Wabash National (NYSE: WNC) and Libbey, Inc. Most recently, he was the President and Chief Executive Officer of Momentive Performance Materials, a specialty chemicals and materials business from 2014 until 2020. Prior to this role, Mr. Boss served in the role of President of Honeywell Safety Products from 2012 to 2014. Mr. Boss held various managerial roles within Honeywell’s Specialty and Chemicals businesses from 2003 through 2014. Prior to Honeywell, Mr. Boss served as Vice President at Great Lakes Chemical Corporation. Mr. Boss holds a B.S. in Mechanical Engineering from West Virginia University and an MBA from Rutgers University.
Mr. Boss brings extensive specialty chemicals and materials knowledge. In addition, he brings to the board of directors of our general partner a broad range of experiences and skills as a result of his service as a director of other public and private companies.
Karen A. Twitchell has served as a member of the board of directors of our general partner since August 2022. Ms. Twitchell brings more than a dozen years of Board experience and 30 years of executive experience to the Board of Calumet. Ms. Twitchell was Chair of the Board of Trecora Resources (NYSE: TREC), a petrochemical and specialty wax manufacturer, until the sale of the company in June 2022. In addition, she serves on the Board of Kraton Corp and HMTX Industries. Previously, she served on KMG Chemicals’ (NYSE: KMG) Board. From 2010 to 2013, Ms. Twitchell was Executive Vice President and Chief Financial Officer of Landmark Aviation, a private equity-backed fixed base operator for the aviation industry. Prior to 2010, Ms. Twitchell was Vice President and Treasurer of LyondellBasell Industries/Lyondell Chemical Company. Ms. Twitchell has also held senior management positions in the aluminum and cement manufacturing industries. Ms. Twitchell has a B.A. in Economics from Wellesley College and an MBA degree from Harvard Business School.
Ms. Twitchell brings extensive leadership experience in the chemicals industry. Her background provides helpful insight to the Company in its implementation of strategic initiatives and operations in general.
Board of Directors Committees
Conflicts Committee
Four members of the board of directors of our general partner serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be owners, officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by Nasdaq and the Exchange Act to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The four independent board members who serve on the conflicts committee are Messrs. James S. Carter, Daniel L. Sheets, John (“Jack”) G. Boss and Ms. Karen A. Twitchell. Ms. Twitchell serves as the chair of the conflicts committee. The conflicts committee held seventeen meetings during 2023.
Compensation Committee
The board of directors of our general partner also has a compensation committee which, among other responsibilities, has overall responsibility for evaluating and recommending to the board of directors chief executive officer compensation and for evaluating and approving the compensation arrangements for the other senior executives. Nasdaq does not require a limited partnership like us to have a compensation committee comprised entirely of independent directors. Accordingly, Mr. Daniel L. Sheets, Ms. Amy M. Schumacher, and Ms. Karen A. Twitchell serve as members of our compensation committee. Mr. Sheets serves as the chair of the compensation committee. Ms. Schumacher is not an independent member of the compensation committee. The compensation committee held four meetings during 2023.
The board of directors has adopted a written charter for the compensation committee which defines the scope of the committee’s authority. The committee may form and delegate some or all its authority to subcommittees comprised of committee members when it deems appropriate. The committee is responsible for reviewing and recommending to the board of directors for its approval the annual salary and other compensation components for the chief executive officer. The committee reviews and makes recommendations to the board of directors for its approval of any of the Company’s equity compensation-based plans, including the Long-Term Incentive Plan, or any cash bonus or incentive compensation plans or programs. Also, the committee reviews and approves all annual salary and other compensation arrangements and components for other senior executives of the Company. Further, the compensation committee periodically reviews and makes a recommendation to the board of directors regarding any changes in the compensation of all directors. The committee has the authority to retain or terminate any compensation consultant that assists it in the evaluation of director and senior executive compensation and to obtain independent advice and assistance from internal and external legal, accounting and other advisors. The committee did not engage a compensation consultant for 2023.
Audit and Finance Committee
The board of directors of our general partner has an audit and finance committee comprised of four directors, Messrs. James S. Carter, Daniel L. Sheets, John (“Jack”) G. Boss, and Ms. Karen A. Twitchell, each of whom the board of directors of our general partner has determined meets the independence and experience standards established by Nasdaq and the SEC. In addition, the board of directors of our general partner has determined that Mr. Carter is an “audit committee financial expert” as defined by the SEC. Mr. Carter serves as the chair of the audit and finance committee. The audit and finance committee held five meetings during 2023.
The board of directors has adopted a written charter for the audit and finance committee. The audit and finance committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit and finance committee has the sole authority to retain and terminate our independent registered public accounting firm, approves all auditing services and related fees and the terms thereof and pre-approves any non-audit services to be rendered by our independent registered public accounting firm. The audit and finance committee is also responsible for confirming the independence and
objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit and finance committee.
Risk Committee
The board of directors of our general partner has established a risk committee which, among other responsibilities, oversees the Company’s risk assessment practices. Messrs. Daniel J. Sajkowski, Paul C. Raymond III, Stephen P. Mawer, and Ms. Jennifer G. Straumins serve as members of our risk committee. Mr. Sajkowski serves as the chair of the risk committee. The board of directors has adopted a written charter for the risk committee which defines the scope of the committee’s authority. The risk committee held four meetings during 2023.
Strategy and Growth Committee
The board of directors of our general partner has established a strategy and growth committee which, among other responsibilities, oversees our (i) long-term strategy, (ii) risks and opportunities relating to such strategy, (iii) strategic decisions regarding investments, mergers, acquisitions and divestitures, (iv) capitalization, (v) ownership structure and (vi) distribution policy. Messrs. Paul C. Raymond III, Stephen P. Mawer, John (“Jack”) G. Boss, and Ms. Jennifer G. Straumins serve as members of the strategy and growth committee. Mr. Raymond serves as the chair of the strategy and growth committee. The board of directors has adopted a written charter for the strategy and growth committee which defines the scope of the committee’s authority. The strategy and growth committee held four meetings during 2023.
Leadership and Talent Development Committee
The board of directors of our general partner has established a leadership and talent development committee which, among other responsibilities, monitors our strategic, long-term, and sustainable approach to talent and development issues relating to people. Messrs. Daniel J. Sajkowski, Daniel L. Sheets, John (“Jack”) G. Boss, and Ms. Amy M. Schumacher serve as members of our leadership and talent development committee. Mr. Boss serves as the chair of the leadership and talent development committee. The board of directors has adopted a written charter for the leadership and talent development committee which defines the scope of the committee’s authority. The leadership and talent development committee held four meetings during 2023.
Code of Ethics
We have adopted a Code of Business Conduct and Ethics that applies to all directors, officers, employees and contractors.
Available on our website at www.calumet.com are copies of our board of director’s committee charters and Code of Business Conduct and Ethics, all of which also will be provided to unitholders without charge upon their written request to: Investor Relations, Calumet Specialty Products Partners, L.P., 2780 Waterfront Parkway East Drive, Indianapolis, Indiana, 46214. We intend to disclose, to the extent required, future amendments to certain provisions of the Code of Business Conduct and Ethics, and waivers of the Code of Business Conduct and Ethics granted to executive officers and directors, on our website within four business days following the date of the amendment or waiver.
Delinquent Section 16(a) Reports
Section 16(a) of the Exchange Act, as amended, requires Calumet’s directors and certain executive officers, as well as beneficial owners of ten percent or more of Calumet’s common units, to report their holdings and transactions in Calumet’s securities. Based on information furnished to Calumet and contained in reports filed pursuant to Section 16(a), as well as written representations that no other reports were required for 2023, Calumet’s directors and executive officers filed all reports required by Section 16(a) with the exception of (i) one late filing related to the vesting of phantom units into common units delivered on April 20, 2023 for Bruce Fleming, (ii) one late filing related to the vesting of phantom units into common units delivered on April 20, 2023 for Todd Borgmann, (iii) one late filing related to the initial statement of beneficial ownership of securities for Gregory Morical, which was filed on December 28, 2023, and (iv) one late filing related to the issuance of phantom unit awards on August 1, 2023 for Gregory Morical.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive and Director Compensation
COMPENSATION DISCUSSION & ANALYSIS
This Compensation Discussion & Analysis describes the compensation elements, rationale and policies for the following individuals, who are our named executive officers for the 2023 fiscal year:
Name
Title
Todd Borgmann
Chief Executive Officer
Vincent Donargo
Former Executive Vice President - Chief Financial Officer (1)
Bruce Fleming
Executive Vice President - Montana Renewables & Corporate Development
Scott Obermeier
Executive Vice President - Specialties
Gregory Morical
Senior Vice President, General Counsel & Secretary
(1) Effective January 1, 2024, Mr. Donargo transitioned to an advisory role with the Company until his planned retirement in April 2024, and David Lunin assumed the role of Executive Vice President and Chief Financial Officer.
Overview
The compensation committee of the board of directors of our general partner oversees our compensation programs. Our general partner maintains compensation and benefits programs designed to allow us to attract, motivate and retain the best possible employees, including executive compensation programs designed to reward the achievement of both short-term and long-term goals necessary to promote growth and generate positive unitholder returns. Our executive compensation programs are based on a pay-for-performance philosophy. They include both long-term compensation under the Calumet GP, LLC Amended and Restated Long-Term Incentive Plan (the “LTIP”) and short-term compensation, which, together with base salary and employee benefits, provide a total compensation package intended to be competitive with the companies with which we compete for executive talent.
Under their collective authority, the compensation committee and the board of directors maintain the right to develop and modify compensation programs and policies as they deem appropriate. Factors they may consider in making decisions to materially increase or decrease compensation include our overall financial performance, our growth over time, changes in the complexity of our business operations as well as individual executive job scope, complexity and performance, and changes in competitive compensation practices in our labor markets. In determining any forms of compensation other than the base salary for the senior executives, or in the case of the chief executive officer, the recommendation to the board of directors of the forms of compensation for the chief executive officer, the compensation committee considers our financial performance and relative unitholder return, the value of similar incentive awards to senior executives at comparable companies and the awards granted to senior executives in past years.
Objectives of Compensation Programs
Our executive compensation programs are designed with the following primary objectives:
● reward strong individual performance that drives our positive financial results and enterprise value;
● make incentive compensation a significant portion of an executive’s total compensation, designed to balance short-term and long-term performance;
● align the interests of our executives with those of our unitholders; and
● attract, develop and retain executives with a compensation structure that is competitive with other publicly-traded companies of similar size.
Our primary business objectives are to generate cash flows, reduce debt leverage, grow our business and increase unitholder value. As a result, Adjusted EBITDA is the primary measurement of performance taken into account in making compensation decisions, as we believe this represents the most comprehensive measurement of our ability to generate cash flows and recognizes the integrated and collaborative effort required by the full executive team to maximize performance. As such, short-term compensation is earned or awarded based on Adjusted EBITDA performance, as well as achievement of business unit and individual performance objectives. Long-term compensation is earned or awarded based on Adjusted EBITDA performance, as well as achievement of individual performance objectives. Adjusted EBITDA is a non-GAAP measure that we define, consistent with the terms of our Credit Agreement and senior notes indentures. The most directly comparable GAAP performance measure for Adjusted EBITDA is Net income (loss). Please read Part II, Item 7 “Management’s Discussion and Analysis - Non-GAAP Financial Measures.”
Executive Officer Transitions
Effective January 1, 2024, Mr. Donargo transitioned from his role as Executive Vice President - Chief Financial Officer of the Company and was succeeded by David Lunin. Mr. Donargo will remain with the Company in an advisory role until his planned retirement in April 2024.
Process for Determining Compensation
Role of Compensation Committee
The compensation committee of our board of directors of our general partner has primary responsibility for overseeing our executive compensation program. In general, the compensation committee recommends to the board of directors the compensation of our chief executive officer and approves the compensation of the other named executive officers. Although the compensation committee has the authority to engage a compensation consultant, it did not engage a compensation consultant during 2023.
Review of Named Executive Officer Performance
In making determinations regarding the compensation elements for each named executive officer, the compensation committee considers the scope of responsibilities and experience and balances these against competitive salary levels and other components of the compensation. The compensation committee has the opportunity to meet with the named executive officers and does so at their own discretion at various times during the year, which allows the compensation committee to form its own assessment of each individual’s performance.
Role of Management
In conjunction with the Senior Vice President - Human Resources of the Company, the Chief Executive Officer (“CEO”) evaluates the performance of other named executive officers, as well as other members of management in the Company, against individual and business objectives. Based on the outcomes, the CEO makes recommendations to the compensation committee in regard to compensation for both named executive officers and other members of management of the Company.
Elements of Executive Compensation
The total compensation and benefits program for our named executive officers consists of the following elements:
● base salary
● short-term cash awards under an annual incentive plan
● long-term incentive compensation, including unit-based awards under the LTIP
● deferred compensation, retirement, health and welfare benefits
● limited perquisites
These elements are designed to constitute an integrated executive compensation structure meant to incentivize a high level of individual executive officer performance in line with our financial and operating goals.
Base Salary
Base salaries provide executives with a base level of income as consideration for fulfillment of the roles and responsibilities of their positions. The base salary levels are intended to assist in attracting and retaining the services of quality individuals who are essential for the growth and profitability of Calumet. Generally, changes in the base salary levels for our executive officers are reviewed on an annual basis by the compensation committee and are effective at the beginning of the following fiscal year. Each of our named executive officers received an annual merit increase during 2023, in the case of Mr. Borgmann, effective January 1, 2023, and in the case of Messrs. Donargo, Fleming, Obermeier and Morical, effective April 1, 2023. Mr. Borgmann’s base salary increase was in recognition of his increased role and responsibilities following Mr. Mawer’s transition from Executive Chairman to non-executive Chairman of the board of directors of our general partner. Base salary increases for the other named executive officers were primarily market driven increases. The table below sets forth each named executive officer’s base salary as of the end of the 2022 and 2023 fiscal years:
Base Salary as
Base Salary as
Name
of 12/31/2022
of 12/31/2023
Todd Borgmann
$
650,000
$
735,000
Vincent Donargo
$
400,000
$
420,000
Bruce Fleming
$
447,022
$
470,000
Scott Obermeier
$
425,000
$
452,000
Gregory Morical
$
332,721
$
354,000
Short-Term Cash Bonus Awards
We provide short-term cash bonus awards to named executive officers under our annual cash incentive plan (the “Cash Incentive Plan”). These awards are designed to incentivize executives in meeting financial performance, operational, and strategic objectives on an annual basis.
The compensation committee determines each named executive officer’s target cash bonus award at the beginning of the year, expressed as a percentage of each named executive officer’s base salary actually earned. The following table sets forth each named executive officer’s minimum, target and stretch cash bonus award opportunities for 2023 all as a percentage of each named executive officer’s base salary.
Name
Minimum
Target
Stretch
Todd Borgmann
%
%
%
Vincent Donargo
%
%
%
Bruce Fleming
%
%
%
Scott Obermeier
%
%
%
Gregory Morical
%
%
%
Adjusted EBITDA
As in prior years, funding of our cash bonus awards for the 2023 fiscal year were based on the achievement of Adjusted EBITDA and business unit performance targets. As described above, Adjusted EBITDA represents the most comprehensive measurement of our ability to generate cash flows and grow our business, and as a result, the compensation committee believes that Adjusted EBITDA establishes a direct link between executive compensation and our financial performance. At the recommendation of the compensation committee, the board of directors approved the minimum, target
and stretch levels of Adjusted EBITDA for 2023 based on budgets prepared by management after consideration of the specific circumstances we expected to face during 2023. No cash bonus awards would be paid for 2023 if Adjusted EBITDA fell below the minimum performance level established by the board of directors, and performance between the minimum and target levels or between the target and stretch levels would result in an interpolated payout. However, regardless of our actual Adjusted EBITDA results, our compensation committee and board of directors may exercise discretion to pay cash bonuses at higher or lower levels than those payable under the formulaic approach described above, based on additional factors deemed by the compensation committee and board of directors to be relevant to such determination. The table below sets forth the minimum, target and stretch levels of Adjusted EBITDA for 2023 under our short-term cash bonus program as well as our actual Adjusted EBITDA results, which came in below the minimum threshold under the Cash Incentive Plan. Adjusted EBITDA is defined in Item 7 “Management’s Discussion and Analysis - Non-GAAP Financial Measures.”
Minimum
Target
Stretch
Actual
Adjusted EBITDA (in millions)
$
300.0
$
400.0
$
500.0
$
260.5
Individual Performance Objectives
The 2023 cash bonus awards for our named executive officers were based on achievement of Adjusted EBITDA performance and achievement of operational, strategic, business unit performance, and individual performance goals. Individual performance objectives for Mr. Borgmann were determined by the board of directors while the individual performance objectives for Messrs. Donargo, Fleming, Obermeier and Morical were recommended by the chief executive officer and approved by the compensation committee. Individual performance objectives are specific to each officer position and are set at the beginning of the fiscal year.
Criteria used to measure an individual’s performance may include assessment of objective criteria (e.g., execution of projects, improving profitability, or timely completing an acquisition or divestiture) as well as qualitative factors such as the executive’s ability to lead, ability to communicate, and successful adherence to our stated values (i.e., commitment to safety, teamwork, ownership, passion for customers, and excellence). There are no specific weights assigned to these various elements of performance.
2023 Approved Cash Bonus Awards
For the reasons described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - 2023 Update,” we did not achieve the minimum Adjusted EBITDA goal for 2023. Despite not achieving the minimum Adjusted EBITDA goal, the compensation committee and board of directors considered, amongst other things, the achievement of business unit and individual performance objectives, and approved bonus payments for certain employees, including certain of our named executive officers. As a result of achieving certain business unit performance goals in 2023, specifically as it related to the performance of the Company’s specialties business, and individual contribution goals, including those associated with the increase in role and responsibility assumed in conjunction with the Company’s structural integration of the specialties business, the compensation committee and board of directors approved a cash bonus award payment of $302,770 for Mr. Obermeier. No other named executive officers received a 2023 bonus under the Cash Incentive Plan.
Long-Term Unit-Based Awards
2023 LTI Awards
In fiscal year 2023, the compensation committee established a minimum, target and stretch long-term incentive (LTI) award opportunity for each named executive officer, expressed as a percentage of each named executive officer’s base salary as of the end of the fiscal year. The following table sets forth each named executive officer’s minimum, target and stretch LTI awards for 2023 all as a percentage of each named executive officer’s base salary. Mr. Borgmann’s LTI award opportunities were increased in recognition of his increased role and responsibilities following Mr. Mawer’s transition from Executive Chairman to non-executive Charman of the board of directors of our general partner at the start of the year.
Minimum
Target
Stretch
Todd Borgmann(1)
%
%
%
Vincent Donargo
%
%
%
Bruce Fleming
%
%
%
Scott Obermeier
%
%
%
Gregory Morical
%
%
%
(1) After considering the results of benchmark studies, amongst other criteria evaluated during the annual performance review completed for fiscal year 2023, the compensation committee recommended and the board of directors approved an increase in Mr. Borgmann’s target LTI award opportunity to 200% of base salary, effective January 1, 2024.
Our 2023 LTI award program provided each named executive officer with the opportunity to receive a grant of phantom units based on our Adjusted EBITDA performance and achievement of individual performance objectives, as described above. The dollar amount earned under the 2023 LTI award program based on performance is converted into a number of phantom units based on the closing price of our common units on the date the phantom units are issued. The phantom units are granted under the LTIP and vest on the third anniversary of the date of grant. Following vesting, the phantom units are settled in common units (or cash equivalent). Because of the three-year cliff vesting, we believe phantom units establish a direct link between executive compensation and the interests of our unitholders, serve as a strong retention incentive and reinforce unit ownership levels among our executives.
As a result of the Company’s Adjusted EBITDA performance falling below the minimum threshold for 2023, no annual equity-based awards under the Long-Term Incentive Plan for our named executive officers were approved by the compensation committee for the 2023 performance year.
2023 Strategic Repositioning Grants
In connection with the Company’s phased long-term investment approach in the Montana Renewables business, the board of directors of our general partner approved grants of phantom units to Mr. Mawer, our Chairman, as well as certain of our named executive officers in August 2023, as well as Mr. Mawer, as an incentive to successfully complete the second phase of the MRL project, which includes the MaxSAF expansion project. Messrs. Borgmann and Fleming each received 107,428 phantom units and Mr. Morical received 30,694 phantom units, each of which vest in full on the third anniversary of the date of grant, subject to the individual’s continued employment or service through such date.
Other Elements of Compensation
Health and Welfare Benefits
We offer a variety of health and welfare benefits to all eligible employees of our general partner. These benefits are consistent with the types of benefits provided by our peer group and are provided to maintain a competitive position in terms of attracting and retaining executive officers and other employees. In addition, the health and welfare programs are intended to protect employees against catastrophic loss and encourage a healthy lifestyle. The executive officers generally are eligible for the same benefit programs on the same basis as the rest of our employees. Our U.S. health and welfare programs include medical, pharmacy, dental, life and accidental death and dismemberment insurance coverages.
In addition, all U.S.-based employees working over 30 hours per week are eligible for long-term disability coverage. In addition to the long-term disability coverage provided to all eligible employees, we provide our executive officers with a compensation allowance, which is grossed up for the payment of taxes, to allow them to purchase additional long-term disability coverage on an after-tax basis at no net cost to them. As structured, these combined long-term disability benefits will pay 60% of monthly earnings, as defined by the policy, up to a maximum of $15,000 per month during a period of continuing disability up to normal retirement age, as defined by the policy.
Retirement Benefits
We maintain the Calumet GP, LLC Retirement Savings Plan (the “401(k) Plan”) to assist our U.S.-based eligible officers and employees in saving for their retirement. Our executive officers participate in the same retirement savings plan as other eligible employees. We match 100% of participant contributions up to 4% of the participant’s eligible compensation, and 50% of each additional 1% of eligible compensation contributed up to 6% of the participant’s eligible compensation, for a maximum contribution by us of up to 5% of eligible compensation contributed per participant.
Perquisites
We provide our named executive officers with limited perquisites and other personal benefits that we believe are reasonable and consistent with our overall compensation programs and philosophy. These benefits are provided to enable us to attract and retain these executives. Decisions made with respect to this compensation element do not significantly factor into or affect decisions made with respect to other compensation elements.
Each executive officer is provided with all, or certain of, the following benefits as a supplement to their other compensation:
● Executive Physical Program: We generally pay for a complete and professional annual personal physical exam for each named executive officer appropriate for their age to improve their health and productivity.
● Spousal and Family Travel: On an occasional basis, we pay expenses related to travel of the spouses or certain family members of our executive officers in order to accompany the executive officer to business-related events. For the year ended December 31, 2023, we paid no expenses related to travel for family members of our executive officers.
The compensation committee periodically reviews the perquisite program to determine if adjustments are appropriate.
Other Compensation Related Matters
Clawback Policy; Restatement Analysis
The LTIP includes provisions that address the potential need to recover awards granted under that plan. In addition, during 2023, we adopted our Policy Governing the Recovery of Certain Incentive Compensation (the “Policy”), a clawback policy that is intended to comply with the requirements of Nasdaq Stock Market Listing Standard 5608 implementing Rule 10D-1 under the Exchange Act. In the event we are required to prepare an accounting restatement of our financial statements due to material non-compliance with any financial reporting requirement under the federal securities law, we will recover the excess incentive-based compensation received by any covered executive, including our named executive officers, on or after October 2, 2023 and during the prior three fiscal years that exceeds the amount that the executive otherwise would have received had the incentive-based compensation been determined based on the restated financial statements.
During 2023, we were required to prepare an accounting restatement as described in Note 21 - “Restatement of Previously Issued Financial Statements” in Part II, Item 8 “Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements.” In accordance with the Policy, the compensation committee reviewed the restated financials and concluded that there was no recovery of erroneously awarded compensation required under the Policy because the restated financials did not impact any incentive-based compensation received on or after October 2, 2023.
Executive Ownership of Units
While we have not adopted any security ownership requirements or policies for our executives, our executive compensation programs foster the enhancement of executives’ equity ownership through long-term unit-based awards under the LTIP. For a listing of security ownership by our named executive officers, please read Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.” The board of directors of our general partner has adopted the Insider Trading Policy of Calumet GP, LLC and Calumet Specialty Products Partners, L.P. (the “Insider Trading Policy”), which provides guidelines to employees, officers and directors with respect to transactions in our securities. Pursuant to Calumet’s Insider Trading Policy, all executive officers and directors must confer with our general counsel before effecting any put or call options for our securities or purchase or sale of common units. Further, the Insider Trading Policy states that we strongly discourage options transactions by officers, directors and all other employees and consultants that could result in a short sale. The Insider Trading Policy is available on our website at www.calumet.com or a copy will be provided at no cost to unitholders upon their written request to: Investor Relations, Calumet Specialty Products Partners, L.P., 2780 Waterfront Parkway East Drive, Suite 200, Indianapolis, Indiana, 46214.
Employment Agreements & Severance Benefits
As of December 31, 2023, there were no active employment agreements between our general partner and any of our executive officers. We provide offer letters to newly hired or promoted employees that set forth the general terms of their employment with us as of the offer letter date, which do not provide for severance, change in control or other post-termination benefits. In March 2023, the board of our general partner adopted the Calumet Specialty Products Partners, L.P. Change of Control Protection Plan. For more information on this plan, refer to the “Potential Payments Upon Termination or Change in Control” section below.
Risk Considerations in our Overall Compensation Program
Our compensation policies and practices are designed to provide rewards for achieving financial, operational, and strategic objectives that will support the growth and profitability of our business. Currently, our incentive compensation programs are based on performance, at the Company and business unit level, relative to goals we set for Adjusted EBITDA. In our assessment of risk related to such use of a single financial performance metric, we considered the relative difficulty for any employee to engage in an undue amount of risk-taking activity with a result that would be reasonably likely to have a material adverse effect on us due to the breadth and scope of activities, both operational and financial, across that organization that are captured in the calculation of Adjusted EBITDA. Also, we considered the current approval controls that exist to mitigate against excessive risk-taking that might impact Adjusted EBITDA and, in turn, our compensation programs. For example, we have specific approval policies related to the entry into derivative instruments, material commercial agreements and material capital expenditures. In addition, our full board of directors, including its various committees, regularly assesses our key risk areas to monitor the impacts of such risks on our financial performance. Further, we considered the design of our incentive compensation programs, noting that the inclusion of both short-term cash incentive awards and long-term unit awards further align the interest our employees and our unitholders. As a result of these considerations, we have concluded that the risks arising from our compensation policies and practices for our employees are not reasonably likely to have a material adverse effect on us.
Report of the Compensation Committee for the Year Ended December 31, 2023
The compensation committee of our general partner has reviewed and discussed our Compensation Discussion and Analysis with management. Based upon such review, the related discussion with management and such other matters deemed relevant and appropriate by the compensation committee, the compensation committee has recommended to the board of directors that our Compensation Discussion and Analysis be included in the Company’s Annual Report on Form 10-K.
Members of the Compensation Committee:
● Daniel L. Sheets, Chairman
● Amy M. Schumacher
● Karen A. Twitchell
2023 Summary Compensation Table
The following table sets forth the annual compensation earned by or granted to our named executive officers for the fiscal years ended December 31, 2023, 2022 and 2021. Neither Mr. Donargo nor Mr. Morical were named executive officers prior to 2022.
Summary Compensation Table for 2023
Non-Equity
All
Unit Awards
Incentive Plan
Other
Name and Principal Position
Year
Salary ($)
Bonus ($) (1)
($) (2)
Compensation ($)
Compensation ($) (3)
Total ($)
Todd Borgmann
$
735,000
$
-
$
1,750,000
$
-
$
17,040
$
2,502,040
Chief Executive Officer
$
568,593
$
-
$
2,195,828
$
1,279,334
$
21,434
$
4,065,189
$
334,100
$
250,575
$
548,528
$
-
$
19,897
$
1,153,100
Vincent Donargo
$
415,000
$
-
$
-
$
-
$
19,399
$
434,399
Executive Vice President - Chief Financial Officer
$
380,478
$
-
$
480,000
$
608,764
$
120,087
$
1,589,329
Bruce Fleming
$
464,255
$
-
$
1,750,000
$
-
$
19,715
$
2,233,970
Executive Vice President - Montana
$
447,022
$
-
$
2,355,648
$
1,005,800
$
25,652
$
3,834,122
Renewables & Corporate Strategy
$
431,197
$
323,498
$
708,911
$
-
$
19,830
$
1,483,436
Scott Obermeier
$
445,250
$
302,770
$
-
$
-
$
17,594
$
765,614
Executive Vice President - Specialties
$
397,220
$
-
$
470,000
$
610,830
$
22,616
$
1,500,666
$
342,990
$
257,243
$
562,926
$
-
$
11,724
$
1,174,883
Gregory Morical
$
348,680
$
-
$
500,000
$
-
$
15,821
$
864,501
Senior Vice President, General Counsel & Secretary
$
332,721
$
-
$
787,828
$
399,265
$
33,342
$
1,553,156
(1) Amounts in this column for 2023 include the cash bonus award approved for Mr. Obermeier for fiscal year 2023 performance. For more information regarding the cash bonus awards, see “Compensation Discussion & Analysis - Elements of Executive Compensation - Short-Term Cash Bonus Awards - 2023 Approved Cash Bonus Awards” above.
(2) Amounts in this column for 2023 include the grant date fair value calculated in accordance with FASB ASC Topic 718, disregarding estimated forfeitures, of the following final phase of the strategic repositioning phantom unit awards granted on August 1, 2023 under the LTIP: (i) 107,428 phantom units granted to each of Messrs. Borgmann and Fleming, and (ii) 30,694 phantom units granted to Mr. Morical. For more information regarding these phantom units, see “Compensation Discussion & Analysis - Elements of Executive Compensation - Long-Term Unit-Based Awards - 2023 LTI Awards” above. The grant date fair value of each phantom unit award is based on the closing price of our common units on the applicable date of grant. Please read Note 12 to our consolidated financial statements for the fiscal year ending December 31, 2023 for a discussion of the assumptions used to determine the FASB ASC Topic 718 value of the awards.
(3) The following table provides the aggregate “All Other Compensation” information for each of the named executive officers for 2023:
Todd
Vincent
Bruce
Scott
Gregory
Borgmann
Donargo
Fleming
Obermeier
Morical
401(k) Plan Matching Contributions
$
16,500
$
16,500
$
16,500
$
16,500
$
13,275
HSA Plan Matching Contributions
-
-
1,000
-
1,000
Term Life Insurance Premiums
2,899
2,215
1,094
1,546
Total
$
17,040
$
19,399
$
19,715
$
17,594
$
15,821
Grants of Plan-Based Awards
The following table includes information about awards granted to our named executive officers during 2023, which includes the bonus opportunities under the Cash Incentive Plan and phantom unit awards under the LTIP.
Estimated Possible Payouts Under
Estimated Future Payouts Under
Grant
Non-Equity
Equity
All Other
Date Fair
Incentive Plan Awards (1)
Incentive Plan Awards (2)
Unit
Value of
Awards:
Unit and
Number
Option
Grant
Minimum
Target
Stretch
Minimum
Target
Stretch
of Units
Awards
Name
Date
($)
($)
($)
($)
($)
($)
(#) (3)
($) (4)
Todd Borgmann
$
551,250
$
1,102,500
$
1,653,750
$
551,250
$
1,102,500
$
653,750
-
$
-
8/01/2023
107,428
$
1,750,000
Vincent Donargo
$
210,000
$
420,000
$
630,000
$
168,000
$
336,000
$
504,000
-
$
-
Bruce Fleming
$
352,500
$
705,000
$
1,057,500
$
141,000
$
282,000
$
423,000
-
$
-
8/01/2023
107,428
$
1,750,000
Scott Obermeier
$
226,000
$
452,000
$
678,000
$
180,800
$
361,600
$
542,400
-
$
-
Gregory Morical
$
141,600
$
283,200
$
424,800
$
106,200
$
212,400
$
318,600
-
$
-
8/01/2023
30,694
$
500,000
(1) Amounts in this column represent the minimum, target and stretch incentive opportunities for short-term bonus awards under the Cash Incentive Plan. The actual bonuses paid to our named executive officers for 2023 under the Cash Incentive Plan can be found in the “Bonus” column of the Summary Compensation Table above and are described in more detail under “Compensation Discussion & Analysis - Elements of Executive Compensation - Short-Term Cash Bonus Awards” above.
(2) Amounts in this column represent the minimum, target and stretch incentive levels for our 2023 LTI award program. Following the end of the 2023 fiscal year, the amount earned based on our Adjusted EBITDA performance is converted into a number of phantom units by dividing the dollar amount earned by the closing price of our common unit on the date the phantom units are granted. For more information regarding our LTI award program, see “Compensation Discussion & Analysis - Elements of Executive Compensation -2023 LTI Awards” above.
(3) The phantom unit awards in this column vest on the third anniversary of the date of grant, subject to continued employment through such vesting date.
(4) Amounts in this column represent the grant date fair value calculated in accordance with FASB ASC Topic 718, disregarding estimated forfeitures. The grant date fair value of each phantom unit award is based on the closing price of our common units on the applicable date of grant. Please read Note 12 to our consolidated financial statements for the fiscal year ending December 31, 2023 for a discussion of the assumptions used to determine the FASB ASC Topic 718 value of the awards.
Outstanding Equity Awards at Fiscal Year-End
The table below reflects information regarding outstanding equity-based awards held by the named executive officers as of December 31, 2023.
Unit Awards
Number of
Market Value
Units
of Units
That Have Not
That Have Not
Name
Vested (#)(1)
Vested ($)(2)
Todd Borgmann
271,522
$
4,852,098
Vincent Donargo
-
$
-
Bruce Fleming
-
$
-
Scott Obermeier
55,696
$
995,288
Gregory Morical
103,675
$
1,852,672
(1) The phantom units in this column reflect time-based phantom units held by the named executive officers as of December 31, 2023. In light of the retirement provisions applicable to such grants, all outstanding phantom unit awards held by Messrs. Donargo and Fleming are fully vested as of December 31, 2023. The market value of fully vested outstanding phantom unit awards held by our named executive officers as of December 31, 2023 are reflected in the “Quantification of Potential Payments” table in the “Potential Payments Upon Termination or Change in Control” section below. Outstanding phantom unit awards that have not vested as of December 31, 2023 for each of our named executive officers will vest as follows:
Todd
Vincent
Bruce
Scott
Gregory
Vesting Date
Borgmann
Donargo
Fleming
Obermeier
Morical
July 1, 2024
-
-
-
-
1,403
February 22, 2025
114,120
-
-
31,606
55,634
July 1, 2025
-
-
-
-
February 21, 2026
49,974
-
-
24,090
15,348
July 1, 2026
-
-
-
-
August 1, 2026
107,428
-
-
-
30,694
July 1, 2027
-
-
-
-
271,522
-
-
55,696
103,675
(2) Market value of phantom units reported in these columns is calculated by multiplying the closing market price of $17.87 of our common units at December 29, 2023, the last trading day of the 2023 fiscal year, by the number of phantom units outstanding.
Units Vested
The following table provides information about phantom units held by the named executive officers that vested and were settled during the 2023 fiscal year. None of the named executive officers exercised any option awards during the 2023 fiscal year.
Unit Awards
Number of
Units Acquired on Vesting
Name
(#)(1)
Value Realized on Vesting ($)(2)
Todd Borgmann
42,135
$
716,716
Vincent Donargo
10,000
$
186,600
Bruce Fleming
63,203
$
1,075,083
Scott Obermeier
249,992
$
4,219,865
Gregory Morical
45,967
$
775,923
(1) Amounts in this column represent the phantom units held by each named executive officer that vested and were settled during the 2023 fiscal year.
(2) Amounts in this column equal the number of phantom units vested multiplied by the closing price of our common units on the applicable vesting date (or, if the vesting date was not a trading day, on the last trading day immediately prior to such date).
Nonqualified Deferred Compensation
We maintain the Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan (the “Deferred Compensation Plan”) to encourage our officers to save for retirement and to assist us in retaining our officers. Pursuant to the Deferred Compensation Plan, a select group of management, including the named executive officers, and all of the non-employee directors are eligible to participate by making an annual irrevocable election to defer, in the case of management, all or a portion of their annual cash incentive award under the Cash Incentive Plan, and, in the case of non-management directors, all or none of their annual cash retainer.
The deferred amounts are credited to participants’ accounts in the form of phantom units, with each phantom unit representing a notional unit that entitles the holder to receive either an actual common unit or the cash value of a common unit (determined by using the fair market value of a common unit at the time a determination is needed). The phantom units credited to each participant’s account also receive distribution equivalent rights, which are credited to the participant’s account in the form of additional phantom units. In our sole discretion, we may make matching contributions of phantom units or purely discretionary contributions of phantom units, in amounts and at times as the compensation committee recommends and the board of directors approves.
Participants will at all times be 100% vested in amounts they have deferred; however, amounts we have contributed may be subject to a vesting schedule, as determined appropriate by the compensation committee. Distributions from the Deferred Compensation Plan are payable on the earlier of the date specified by each participant on their deferral election form and the participant’s termination of employment. Death, disability, normal retirement or a change in control require automatic distribution of the Deferred Compensation Plan benefits and will also accelerate at that time the vesting of any portion of a participant’s account that has not already become vested. Benefits will be distributed to participants in the form of our common units, cash or a combination of common units and cash at the election of the compensation committee. In the event that accounts are paid in common units, such units will be distributed pursuant to the LTIP. Unvested portions of a participant’s account will be forfeited in the event that a distribution was due to a participant’s voluntary resignation or a termination for cause. To ensure compliance with Section 409A of the Code, distributions to participants that are considered “specified employees” (as defined in Code Section 409A of the Code) may be delayed for a period of six months following such employees’ termination of employment with us.
The table below sets forth information regarding the value of accumulated benefits of our named executive officers under the Deferred Compensation Plan as of December 31, 2023.
Aggregate
Executive
Registrant
Withdrawals /
Contributions in
Contributions in
Aggregate Earnings
Distributions in 2023
Aggregate Balance at
Name
2023 ($)
2023 ($)
in 2023 ($)
($)
End of 2023 ($) (1)
Todd Borgmann
$
-
$
-
$
96,306
$
(752,952)
$
1,738,376
Vincent Donargo
$
-
$
-
$
24,000
$
-
$
433,205
Bruce Fleming
$
-
$
-
$
420,588
$
(1,129,438)
$
7,591,819
Scott Obermeier
$
-
$
-
$
-
$
-
$
-
Gregory Morical
$
-
$
-
$
37,060
$
(71,176)
$
668,946
(1) The aggregate balance for each named executive officer as of December 31, 2023 was determined by multiplying all phantom units in each named executive officer’s account under the Deferred Compensation Plan by the closing price of our common units on December 29, 2023 (the last trading day of 2023). The phantom units in each named executive officer’s account as of December 31, 2023 was as follows: (i) Mr. Borgmann, 97,279, (ii) Mr. Donargo, 24,242, (iii) Mr. Fleming, 424,836, and (iv) Mr. Morical, 37,434.
Potential Payments Upon Termination or Change in Control
The board of our general partner adopted the Calumet Specialty Products Partners, L.P. Change of Control Protection Plan, effective March 13, 2023 (the “CIC Plan”), pursuant to which each of our named executive officers are eligible to receive severance benefits upon an involuntary termination by us without cause or by the named executive officer for good reason, in each case, occurring within the three month period immediately prior to or twelve month period immediately following a “change of control”. For purposes of the CIC Plan, a “change of control” generally occurs upon one or more of the following events: (i) any person or group, other than a person or group who is our affiliate, becomes the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the voting power of our outstanding equity interests; (ii) a person or group, other than our general partner or one of our general partner’s affiliates, becomes our general partner; (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of our assets or the assets of our general partner in one or more transactions to any person or group other than an a person or group who is our affiliate, or (iv) any other transaction, reorganization, consolidation, sale of a business segment, spin-off, split-off, merger or similar event that our board, in its sole discretion, determines to be a “change of control” with respect to a particular executive participating in the CIC Plan. Payment of severance under the CIC Plan is contingent upon the executive entering into a release of claims with us. There is no eligibility for severance benefits under the CIC Plan if, in connection with an applicable change of control, the executive declines an offer of employment for a comparable position with a successor or acquirer.
The following describes, for our named executive officers, the benefits that would be received under the CIC Plan in a qualifying termination circumstance:
● 1.5x (for Mr. Borgmann) or 1.0x (for our other named executive officers) the sum of the executive’s (i) annual base salary plus (ii) target annual bonus for the year in which termination of employment occurs;
● Continued medical, dental and vision benefits coverage for twelve months following the termination date;
● Reimbursement for up to $10,000 of outplacement services provided within six months following the termination date; and
● Accelerated vesting of all unvested time and performance-based awards under the LTIP, with performance-based awards vesting at the greater of target or actual performance through the termination date
We believe these benefits are important retention tools and, specifically with respect to the change of control benefits, these benefits provide the named executive officers with a sense of stability, both in the middle of transactions that may
create uncertainty regarding their future employment and post-termination as they seek future employment and an opportunity to realize value from these awards in the event of such transaction.
Phantom Unit Awards Under the LTIP
Although the LTIP provides the compensation committee with broad discretion to accelerate outstanding phantom units in the event of certain termination events or a change of control, the outstanding phantom unit award agreements provide for full accelerated vesting in the event of a named executive officer’s death, disability or normal retirement (termination after reaching age 62), as well as in the event of a qualifying termination due to a “change in control,” as outlined in the Company’s CIC Plan. Refer to “Compensation Discussion & Analysis - Potential Payments Upon Termination or Change in Control” above for additional information regarding the Company’s CIC Plan.
For purposes of the LTIP, “change of control” generally occurs upon one or more of the following events: (i) any person or group, other than a person or group who is our affiliate, becomes the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the voting power of our outstanding equity interests; (ii) a person or group, other than our general partner or one of our general partner’s affiliates, becomes our general partner; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of our assets or the assets of our general partner in one or more transactions to any person or group other than an a person or group who is our affiliate.
Phantom Units Under the Deferred Compensation Plan
Each named executive officer’s phantom units under the Deferred Compensation Plan will become fully vested in the event of such named executive officer’s death, disability or normal retirement (termination after reaching age 62), as well as in the event of a “change of control” (which generally has the meaning provided under the LTIP, as described above).
Executive Long-Term Disability Coverage
Each of our named executive officers receive additional long-term disability coverage, which is in addition to the long-term disability coverage the Company provides to all employees. As a result of this additional long-term disability coverage, each named executive officer would be entitled to receive additional benefits in the event of their qualifying long-term disability, which when combined with the long-term disability coverage provided to all eligible employees will result in payment of 60% of monthly earnings, as defined by the policy, up to a maximum of $15,000 per month until normal retirement age.
Quantification of Potential Payments
The table below shows the value sets forth the amount of compensation or other benefits due to each named executive officer in the event of the specified terminations of employment or a change of control, assuming such termination or change of control occurred on December 31, 2023. The amounts below are only estimates of the amounts that would be received upon a change of control or termination of employment-the actual amount will only be determined at the time such event occurs.
Qualifying Termination
Death; Normal
in Connection with
Name
Plan
Retirement ($)
Disability ($)
Change of Control ($)
Todd Borgmann
Cash Severance (1)
$
-
$
-
$
2,756,250
LTIP Phantom Units (2)
6,371,048
6,371,048
6,371,048
Deferred Compensation Plan (2)
1,738,376
1,738,376
1,738,376
Post-Employment Health Care (3)
-
-
30,342
Outplacement Assistance (4)
-
-
10,000
Executive Long-Term Disability Coverage (5)
-
108,000
-
Total
$
8,109,424
$
8,217,424
$
10,906,016
Vincent Donargo
Cash Severance (1)
$
-
$
-
$
840,000
LTIP Phantom Units (2)
600,914
600,914
600,914
Deferred Compensation Plan (2)
433,205
433,205
433,205
Post-Employment Health Care (3)
-
-
19,458
Outplacement Assistance (4)
-
-
10,000
Executive Long-Term Disability Coverage (5)
-
108,000
-
Total
$
1,034,119
$
1,142,119
$
1,903,577
Bruce Fleming
Cash Severance (1)
$
-
$
-
$
1,175,000
LTIP Phantom Units (2)
7,279,613
7,279,613
7,279,613
Deferred Compensation Plan (2)
7,591,819
7,591,819
7,591,819
Post-Employment Health Care (3)
-
-
19,225
Outplacement Assistance (4)
-
-
10,000
Executive Long-Term Disability Coverage (5)
-
108,000
-
Total
$
14,871,432
$
14,979,432
$
16,075,657
Scott Obermeier
Cash Severance (1)
$
-
$
-
$
904,000
LTIP Phantom Units (2)
995,288
995,288
995,288
Deferred Compensation Plan (2)
-
-
-
Post-Employment Health Care (3)
-
-
31,327
Outplacement Assistance (4)
-
-
10,000
Executive Long-Term Disability Coverage (5)
-
108,000
-
Total
$
995,288
$
1,103,288
$
1,940,615
Gregory Morical
Cash Severance (1)
$
-
$
-
$
637,200
LTIP Phantom Units (2)
1,816,950
1,816,950
1,816,950
Deferred Compensation Plan (2)
668,946
668,946
668,946
Post-Employment Health Care (3)
-
-
26,689
Outplacement Assistance (4)
-
-
10,000
Executive Long-Term Disability Coverage (5)
-
108,000
-
Total
$
2,485,896
$
2,593,896
$
3,159,785
(1) For all of our named executive officers, this amount represents the value of cash severance payable in connection with a qualifying termination under the CIC Plan.
(2) The values reported with respect to LTIP phantom units and the Deferred Compensation Plan are based on the closing price of our common stock on December 29, 2023 (the last trading day of the 2023 fiscal year) of $17.87 and the total number of outstanding phantom units, including the number of unvested units that would accelerate and vest upon a qualifying termination event or change of control.
(3) As per the CIC Plan, each of our named executive officers shall receive continued medical dental and vision benefits coverage for 12 months following the date of termination at the employer’s expense if a qualifying termination occurs in connection with a Change of Control.
(4) As per the CIC Plan, each of our named executive officers shall receive reimbursement for the cost of outplacement services with a provider designated by the employer, provided that the cost of such reimbursement shall not exceed $10,000 and such services must be provided within six months following the date of termination if a qualifying termination occurs in connection with a Change of Control.
(5) Includes only the portion of each named executive officer’s long-term disability benefits that are in excess of the long-term disability benefits generally provided to employees of our general partner.
DIRECTOR COMPENSATION
Officers or employees of our general partner who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner receives an annual fee as well as compensation for attending meetings of the board of directors and board committee meetings. Non-employee directors were entitled to fees and equity awards for 2023 that consisted of the following:
● an annual fee of $130,000 for the Chairperson of the Board, and $80,000 for all other non-employee Board members;
● an annual equity award in the form of restricted or phantom units, valued at approximately $195,000 for the Chairperson of the Board, and $100,000 for all other non-employee Board members;
● an audit and finance committee chair annual fee of $20,000;
● a non-chair audit and finance committee member annual fee of $10,000;
● a strategy and growth committee chair annual fee of $10,000;
● a non-chair strategy and growth committee annual fee of $5,000;
● a conflicts committee and compensation committee chair annual fee of $10,000;
● a non-chair conflicts committee and compensation committee annual fee of $4,000;
● all other committee chair annual fee of $10,000; and
● all other committee member annual fee of $2,500.
In addition, we reimburse each non-employee director for his or her out-of-pocket expenses incurred in connection with attending meetings of the board of directors or board committees. Under certain circumstances, we will also indemnify each director for his or her actions associated with being a director to the fullest extent permitted under Delaware law.
As described above under “Long-Term Unit-Based Awards - 2023 Strategic Repositioning Grants,” in connection with the Company’s phased long-term investment approach in the Montana Renewables business, the board of directors of our general partner approved an award of 61,387 phantom units to Mr. Mawer, our Chairman. Such phantom units vest in full on the third anniversary of the date of grant, subject to the Mr. Mawer’s continued service through such date.
The following table sets forth certain compensation information of our non-employee directors for the year ended December 31, 2023:
Fees Earned or
Unit
Name
Paid in Cash ($) (1)
Awards ($) (2)
Total
James S. Carter
$
101,500
$
133,833
$
235,333
Daniel J. Sajkowski
$
88,750
$
100,000
$
188,750
Amy M. Schumacher
$
84,000
$
128,000
$
212,000
Stephen P. Mawer
$
103,125
$
1,195,000
$
1,298,125
Daniel L. Sheets
$
103,500
$
134,500
$
238,000
Paul C. Raymond III
$
90,000
$
130,000
$
220,000
Jennifer G. Straumins
$
85,000
$
100,000
$
185,000
John (“Jack”) G. Boss
$
102,250
$
123,858
$
226,108
Karen A. Twitchell
$
101,000
$
100,000
$
201,000
(1) The amounts in this column include director fees which have been deferred under the Deferred Compensation Plan. During 2023, each eligible non-employee director other than Messrs. Sajkowski and Mawer, Ms. Straumins and Ms. Twitchell elected to defer some or all of their director fees.
(2) The amounts in this column are calculated based on the aggregate grant date fair value of (i) annual phantom unit awards issued to non-employee directors serving on the board on the date the awards were granted, (ii) matching phantom unit awards granted to those non-employee directors who deferred all, or a portion of, the fees they earned in 2023 pursuant to the Deferred Compensation Plan, and (iii) Mr. Mawer’s 2023 strategic repositioning phantom unit grant. The amounts reflect the aggregate grant date fair value computed in accordance with FASB ASC Topic 718, disregarding estimated forfeitures. Please read Note 12 to our consolidated financial statements for the fiscal year ending December 31, 2023 for a discussion of the assumptions used to determine the FASB ASC Topic 718 value of the awards. As of December 31, 2023, the following directors each held outstanding phantom units, including phantom units held under the Deferred Compensation Plan, as follows: Mr. Carter, 146,322; Mr. Sajkowski, 73,604; Ms. Schumacher, 136,619; Mr. Mawer, 364,006; Mr. Sheets, 115,805; Mr. Raymond, 52,803; Ms. Straumins, 21,464; Mr. Boss, 15,935; and Ms. Twitchell, 10,016.
Deferred Compensation Plan
Our directors are eligible to defer all or a portion of their fees earned into the Deferred Compensation Plan. When directors elect to defer any portion of their compensation into the plan, these deferred amounts are credited to the participant in the form of phantom units. The compensation committee may recommend a matching contribution for the deferred fees at its discretion. Phantom units credited to a participant’s account as either a deferral or a matching contribution carry distribution equivalent rights to be credited to the participant’s account in the form of additional phantom units. Matching contributions in the form of phantom units were credited to the accounts of each director who elected to defer all or a portion of their fees earned into the Deferred Compensation Plan for fiscal year 2023 in the following number of phantom units: Mr. Carter, 2,088; Ms. Schumacher, 1,741; Mr. Sheets, 2,111; Mr. Raymond, 1,852; and Mr. Boss, 1,480.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The members of our compensation committee are Daniel L. Sheets, Amy M. Schumacher, and Karen A. Twitchell, who are all members of the board of our general partner. Please read Item 13 “Certain Relationships and Related Transactions and Director Independence” for descriptions of our transactions in fiscal year 2023 with certain entities related to Mr. Sheets, Ms. Schumacher, and Ms. Twitchell. Ms. Schumacher is not an independent member of the compensation committee. No executive officer of our general partner served as a member of the compensation committee of another entity that had an executive officer serving as a member of our board of directors or compensation committee.
CEO Pay Ratio
As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we are providing the following information about the relationship between the annual total compensation of our general partner’s median compensated employee and the annual total compensation of Todd Borgmann, our Chief Executive Officer (“CEO”).
The employees who provide services to us are employed by Calumet GP, LLC, our general partner as we do not have any employees. Rather than providing a pay ratio disclosure that contemplates no employees, we have determined that the disclosure that would be most aligned with the spirit and intent of the pay ratio rules and that would provide our unitholders with more meaningful information would be to provide a ratio using the median employee from our general partner’s employee population. References to “our” employees below therefore refer to the employees of our general partner.
To identify our general partner’s median employee, as well as to determine the annual total compensation of our general partner’s median employee and the CEO, we took the following steps:
● We selected December 31, 2023 as our identification date for determining our median employee compensation.
● We determined that, as of December 31, 2023, our general partner’s employee population consisted of approximately 1,580 individuals, all of whom were located in the United States. This population consisted of our full-time, part-time, and temporary employees.
● We used a consistently applied compensation measure to identify the median employee, namely 2023 W-2 wages as reflected in our general partner’s payroll records. We did not annualize the compensation for any employees that were not employed by our general partner for all of 2023. We do not widely distribute annual equity awards to employees, therefore, such awards were excluded from our compensation measure.
● Our general partner’s median employee was determined to be a full-time employee. After we identified our general partner’s median employee, we calculated such employee’s annual total compensation for the 2023 year using the same methodology we used for our CEO as set forth in the “Total” column of our 2023 Summary Compensation Table included in this Annual Report.
For 2023, our last completed fiscal year:
● The annual total compensation of the median employee of our general partner (other than the CEO) was $104,717;
● The annual total compensation of the CEO, as reported in the Summary Compensation Table above, was $2,502,040; and
● Based on this information, for 2023 the ratio of the annual total compensation of our CEO to that of the median employee of our general partner was approximately 24 to 1.
Our 2023 pay ratio is intended to be a reasonable estimate calculated in a manner consistent with SEC rules. Given the different methodologies that various public companies use to determine their estimates of pay ratio, including the different assumptions, exclusions, estimates and methodologies allowed under the SEC rules, and differing employment and compensation practices among companies, our reported pay ratio should not be used as a basis of comparison between us or our general partner and other companies.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The following table sets forth the beneficial ownership of our units as of February 28, 2024, held by:
● each person who beneficially owns 5% or more of our outstanding units;
● each director of our general partner;
● each named executive officer of our general partner; and
● all directors and executive officers of our general partner as a group.
The amounts and percentages of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he or she has no economic interest.
Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. Except as indicated by footnote, the address for the beneficial owners listed below is 2780 Waterfront Parkway East Drive, Suite 200, Indianapolis, Indiana, 46214.
Percentage of
Common Units
Total Units
Beneficially
Beneficially
Name of Beneficial Owner
Owned
Owned
The Heritage Group (1)(2)
11,867,533
14.79
%
Calumet, Incorporated (2)
1,934,287
2.41
%
Adams Asset Advisors, LLC (3)
5,446,477
6.79
%
Wasserstein Debt Opportunities Management, LP and related persons (4)
6,534,338
8.15
%
Dorset Partners LLC and related persons (5)
4,407,000
5.49
%
James S. Carter
319,138
*
Daniel J. Sajkowski
156,607
*
Amy M. Schumacher (1)(6)
181,673
*
Daniel L. Sheets
61,472
*
Paul C. Raymond III
6,963
*
Jennifer G. Straumins (7)
663,520
*
John (“Jack”) G. Boss
25,000
*
Karen A. Twitchell
-
*
Stephen P. Mawer (8)
172,610
*
David Lunin (8)
-
*
Bruce Fleming (8)
371,965
*
Scott Obermeier (8)
206,537
*
Todd Borgmann (8)
106,613
*
Vincent Donargo (8)
9,125
*
Gregory Morical (8)
44,956
*
All directors and executive officers as a group (15 persons)
2,326,179
2.90
%
*
= less than 1 percent.
(1) Twenty-nine grantor trusts indirectly own all of the outstanding general partner interests in The Heritage Group, an Indiana general partnership. The direct or indirect beneficiaries of the grantor trusts are members of the Fehsenfeld family. Each of the grantor trusts has five trustees, Fred M. Fehsenfeld, Jr., James C. Fehsenfeld, Nicholas J. Rutigliano, William S. Fehsenfeld and Amy M. Schumacher, each of whom exercises equivalent voting rights with respect to each such trust. Each of Fred M. Fehsenfeld, Jr. and Amy M. Schumacher, who are directors of our general partner, disclaims beneficial ownership of all of the common units owned by The Heritage Group, and none of these units are shown as being beneficially owned by such directors in the table above. Of these common units, 367,197 are
owned by The Heritage Group Investment Company, LLC (“Investment LLC”). Investment LLC is under common ownership with The Heritage Group. The Heritage Group, although not the owner of the common units, serves as the Manager of Investment LLC, and in that capacity has sole voting and investment power over the common units. The Heritage Group disclaims beneficial ownership of the common units owned by Investment LLC except to the extent of its pecuniary interest therein. The address for The Heritage Group is 5400 W. 86th St., Indianapolis, Indiana, 46268.
(2) The common units of Calumet, Incorporated are indirectly owned 45.8% by The Heritage Group and 5.1% by Fred M. Fehsenfeld, Jr. personally. Fred M. Fehsenfeld, Jr. was formerly a director of Calumet, Incorporated. Accordingly, 885,294 of the common units owned by Calumet, Incorporated are also shown as being beneficially owned by The Heritage Group in the table above, and 97,971 of the common units owned by Calumet, Incorporated are beneficially owned by Fred M. Fehsenfeld, Jr. The Heritage Group and Fred M. Fehsenfeld, Jr. disclaim beneficial ownership of all of the common units owned by Calumet, Incorporated in excess of their respective pecuniary interests in such units. The address of Calumet, Incorporated is 5400 W. 86th St., Indianapolis, Indiana, 46268.
(3) As noted in the Schedule 13G filed with the SEC on January 14, 2023, the filing person has indicated that it has or shares beneficial ownership of such units. According to the Schedule 13G, Adams Asset Advisors has sole voting power and sole dispositive power over 4,033,903 units and shared voting power and shared dispositive power over 1,407,710 units. The address for Adams Asset Advisors, LLC is 8150 N. Central Expwy #M1120, Dallas, Texas 75206.
(4) Based on the Schedule 13G/A filed with the SEC on February 10, 2023. According to the Schedule 13G/A, Wasserstein Debt Opportunities Management has shared voting power and shared dispositive power over 6,072,088 units. 5,672,088 of the reported units are owned directly by private investment funds and separately managed accounts for which Wasserstein Debt Opportunities Management serves as the investment adviser. 400,000 of the reported units represent options, which have not been exercised, beneficially owned by private investment funds for which Wasserstein Debt Opportunities Management serves as the investment adviser. The general partner of Wasserstein Debt Opportunities Management is WDO Management GP, LLC (the “General Partner”). Rajay Bagaria is a control person of Wasserstein Debt Opportunities Management and manager of the General Partner, and could be deemed to share such indirect beneficial ownership with Wasserstein Debt Opportunities Management and the General Partner. Additionally, Mr. Bagaria personally owns 462,250 units, over which he has sole voting power and sole dispositive power, and such units are reflected in the table. Joseph Dutton is a control person of Wasserstein Debt Opportunities Management and could be deemed to share such indirect beneficial ownership with Wasserstein Debt Opportunities Management. Mr. Bagaria and Mr. Dutton each disclaim any beneficial ownership of any such units of common units representing limited partnership interest in excess of their actual pecuniary interest therein. The business address of Wasserstein Debt Opportunities Management is 1185 Avenue of the Americas, 39th Floor, New York, NY 10036.
(5) Based on the Schedule 13G/A filed with the SEC on February 13, 2024. According to the Schedule 13G/A, Dorset Partners LLC has sole voting power and sole dispositive power over 4,325,000 units. According to the Schedule 13G/A, David M. Knott, Jr., president of Dorset Management Corporation, has sole voting power and sole dispositive power over 4,407,000 units and shared voting power and shared dispositive power over zero units. According to the Schedule 13G/A, Knott Partners, L.P. has sole voting power and sole dispositive power over 4,069,276 units and shared voting power and shared dispositive power over zero units. The business address of Dorset Management Corporation is 485 Underhill Boulevard, Suite 205, Syosset, New York 11791.
(6) Includes common units that are owned by the spouse and children of Amy M. Schumacher, for which she disclaims beneficial ownership.
(7) Jennifer G. Straumins disclaims beneficial ownership of all common units reported herein.
(8) Ownership of common unit amounts for our named executive officers and other current executive officers excludes outstanding phantom unit awards, both vested and unvested as of February 28, 2024, which we expect to settle in common units. Each such individual’s total beneficially owned common units, vested phantom units, and unvested phantom units are set forth in the table below.
Common Units
Vested Phantom
Unvested Phantom
Name
Beneficially Owned
Units
Units
Total
Todd Borgmann
106,613
182,279
271,522
560,414
Vincent Donargo
9,125
57,869
-
66,994
David Lunin
-
-
42,478
42,478
Bruce Fleming
371,965
832,201
-
1,204,166
Scott Obermeier
206,537
-
55,696
262,233
Gregory Morical
44,956
35,435
103,675
184,066
Equity Compensation Plan Information
The following table summarizes information about our equity compensation plans as of December 31, 2023:
(a)
(b)
(c)
Number of Securities
Remaining Available for
Number of Securities
Weighted-Average
Future Issuance Under
to be Issued Upon
Exercise Price
Equity Compensation
Exercise of Outstanding
of Outstanding
Plans (Excluding
Options, Warrants
Options, Warrants
Securities Reflected
and Rights (2)
and Rights
in Column (a))
Equity compensation plans approved by security holders (1)
580,368
$
-
-
Equity compensation plans not approved by security holders
N/A
N/A
N/A
Total
580,368
$
-
-
(1) Represents securities under the LTIP.
(2) As of December 31, 2023, the LTIP contemplates the issuance or delivery of up to 5,283,960 common units to satisfy awards under the plan. The number of units presented in column (a) represents the maximum number of common units that may be delivered pursuant to outstanding awards under the plan as of December 31, 2023. If such maximum number of common units had been delivered pursuant to outstanding awards, no common units would have remained available for future delivery under column (c) as of December 31, 2023.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions and Director Independence
Distributions and Payments to Our General Partner and its Affiliates
Owners of our general partner and their affiliates own 16,695,396 common units representing an approximately 20.4% limited partner interest in us. In addition, our general partner owns a 2% general partner interest in us and all of the incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.495 ($1.98 annualized) per unit, 25% of the amounts we distribute in excess of $0.563 ($2.25 annualized) per unit and 50% of amounts we distribute in excess of $0.675 ($2.70 annualized) per unit. We suspended distributions in April 2016. Please read Part II, Item 5 “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities - Cash Distribution Policy” for additional information related to our distribution policy and the incentive distribution rights.
Our general partner does not receive any management fee or other compensation for its management of our partnership; however, our general partner and its affiliates are reimbursed for all expenses incurred on our behalf. These expenses include the cost of employee, officer and director compensation and benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business and allocable to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed.
Omnibus Agreement
We entered into an omnibus agreement, dated January 31, 2006, with The Heritage Group and certain of its affiliates pursuant to which The Heritage Group and its controlled affiliates agreed not to engage in, whether by acquisition or otherwise, the business of refining or marketing specialty lubricating oils, solvents and wax products as well as gasoline, diesel and jet fuel products in the continental U.S. (“restricted business”) for so long as The Heritage Group controls us. This restriction does not apply to:
● any business owned or operated by The Heritage Group or any of its affiliates as of January 31, 2006;
● the refining and marketing of asphalt and asphalt-related products and related product development activities;
● the refining and marketing of other products that do not produce “qualifying income” as defined in the Internal Revenue Code;
● the purchase and ownership of up to 9.9% of any class of securities of any entity engaged in any restricted business;
● any restricted business acquired or constructed that The Heritage Group or any of its affiliates acquires or constructs that has a fair market value or construction cost, as applicable, of less than $5.0 million;
● any restricted business acquired or constructed that has a fair market value or construction cost, as applicable, of $5.0 million or more if we have been offered the opportunity to purchase it for fair market value or construction cost and we decline to do so with the concurrence of the conflicts committee of the board of directors of our general partner; and
● any business conducted by The Heritage Group with the approval of the conflicts committee of the board of directors of our general partner.
Employee Costs
Our general partner employs all of our employees and we reimburses the general partner for certain of its expenses.
Product Sales and Related Purchases
During 2023, we made ordinary course sales of certain specialty products to Monument Chemical, LLC (“Monument Chemical”), a specialty chemical company owned in part by The Heritage Group and Jennifer G. Straumins. Paul C. Raymond III is the Chief Executive Officer of Monument Chemical. We made an immaterial amount of purchases from Monument Chemical in 2023. The total sales made by us to Monument Chemical in 2023 were approximately $6.8 million. As of December 31, 2023, there was approximately $1.7 million due to us from Monument Chemical related to these products sales. We anticipate that we will continue to sell products to Monument Chemical in the future. We believe that the product sales prices and credit terms offered to Monument Chemical are comparable to prices and terms offered to non-affiliated third-party customers.
During 2023, we made ordinary course purchases from Heritage Environmental Services (“Heritage Environmental”), a cleaning and waste removal company owned in part by The Heritage Group. Total purchases made by us from Heritage Environmental in 2023 for cleaning and waste removal services were approximately $8.5 million. As of December 31, 2023, there was a $5.8 million balance due from us to Heritage Environmental related to these purchases. We expect that we will continue to utilize these services from Heritage Environmental in the future.
During 2023, we made ordinary course sales of certain fuel products to Asphalt Materials of $1.2 million, a company in the asphalt formulation and manufacturing business owned in part by The Heritage Group. As of December 31, 2023, there was no balance due to us from Asphalt Materials related to these products sales. We anticipate that we will continue
to sell products to Asphalt Materials in the future. We believe that the product sales prices and credit terms offered to Asphalt Materials are comparable to prices and terms offered to non-affiliated third-party customers.
Intellectual Property Rights Agreement
On January 6, 2012, the Partnership acquired all of the membership interests of TruSouth Oil, LLC (“TruSouth”). As part of the transaction, TruSouth, the Partnership and the sellers of TruSouth, which included The Heritage Group, entered into an Intellectual Property Rights Agreement dated January 6, 2012 (“IPRA”). In the IPRA, TruSouth (now known as Calumet Branded Products, LLC (“Calumet Branded”)) agreed to pay the sellers a royalty on each qualified gallon of engineered fuel sold to third parties. For the years ended December 31, 2023 and 2022, Calumet Branded paid The Heritage Group a total of $0.7 million and $0.7 million, respectively, in royalties under the IPRA.
Procedures for Review and Approval of Related Person Transactions
Effective February 9, 2007, to further formalize the process by which related person transactions are analyzed and approved or disapproved, the board of directors of our general partner has adopted the Calumet Specialty Products Partners, L.P. Related Person Transactions Policy (the “Policy”) to be followed in connection with all related person transactions (as defined by the Policy) involving the Company and its subsidiaries. The Policy was adopted to provide guidelines and procedures for the application of the partnership agreement to related person transactions and to further supplement the conflict resolution policies already set forth therein.
The Policy defines a “related person transaction” to mean any transaction since the beginning of the Company’s last fiscal year (or any currently proposed transaction) in which: (i) the Company or any of its subsidiaries was or is to be a participant; (ii) the amount involved exceeds $120,000 (including any series of similar transactions exceeding such amount on an annual basis); and (iii) any related person (as defined in the Policy) has or will have a direct or indirect material interest. Under the terms of the policy, our general partner’s chief executive officer (“CEO”) has the authority to approve a related person transaction (considering any and all factors as the CEO determines in his sole discretion to be relevant, reasonable or appropriate under the circumstances) so long as it is:
(a) in the normal course of the Company’s business;
(b) not one in which the CEO or any of his immediate family members has a direct or indirect material interest; and
(c) on terms no less favorable to the Company than those generally being provided to or available from unrelated third parties or fair to the Company, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Company).
The compensation committee has delegated certain powers and duties to the CEO under the Company’s Long-Term Incentive Plan, including the authority to approve the issuances of equity or grants of awards under the plan subject to limitations on such delegated powers and duties. Pursuant to the Policy, any other related person transaction must be approved by the conflicts committee acting in accordance with the terms and provisions of its charter.
A copy of the Policy is available on our website at www.calumet.com and will be provided to unitholders without charge upon their written request to: Investor Relations, Calumet Specialty Products Partners, L.P., 2780 Waterfront Parkway E. Drive, Indianapolis, Indiana, 46214.
Please read Item 10 “Directors, Executive Officers of Our General Partner and Corporate Governance” for a discussion of director independence matters.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
The following table details the aggregate fees billed for professional services rendered by our independent auditor, Ernst & Young, LLP, during 2023 and 2022 (in millions):
Year Ended December 31,
Audit fees
$
4.5
$
4.2
Audit-related fees
-
-
Total
$
4.5
$
4.2
“Audit fees” above include those related to our annual audit, audit of subsidiaries and quarterly review procedures.
Pre-Approval Policy
The audit and finance committee of our general partner’s board of directors has adopted an audit and finance committee charter, which is available on our website at www.calumetspecialty.com. The charter requires the audit and finance committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The audit and finance committee does not delegate its pre-approval responsibilities to management or to an individual member of the audit and finance committee. Services for the audit, tax and all other fee categories above were pre-approved by the audit and finance committee.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits
(a)(1) Consolidated Financial Statements
The consolidated financial statements of Calumet Specialty Products Partners, L.P. are included in Part II, Item 8 “Financial Statements and Supplementary Data.”
(a)(2) Financial Statement Schedules
All schedules are omitted because they are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
See Index to Exhibits of this Annual Report.
Index to Exhibits
Exhibit Number
Description
2.1
-
Partnership Restructuring Agreement, dated as of November 9, 2023, by and among the Partnership, the General Partner and the other parties thereto (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on November 9, 2023 (File No. 000-51734)).
2.2
-
First Amendment to Partnership Restructuring Agreement, dated as of February 9, 2024, by and among Calumet Specialty Products Partners, L.P., Calumet GP, LLC and the other parties thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 12, 2024 (File No. 000-51734)).
2.3
-
Conversion Agreement, dated as of February 9, 2024, by and among Calumet Specialty Products Partners, L.P., Calumet GP, LLC, Calumet, Inc., Calumet Merger Sub I LLC, Calumet Merger Sub II LLC and the other parties thereto (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 12, 2024 (File No. 000-51734)).
3.1
-
Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
3.2
-
First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
3.3
-
Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No. 000-51734)).
3.4
-
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No. 000-51734)).
3.5
-
Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 4, 2018 (File No. 000-51734)).
3.6
-
Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).
3.7
-
Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
4.1
-
Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 3.7 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on November 4, 2010 (File No. 000-51734)).
4.2
-
Description of Common Units (incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report on Form 10-K filed with the Commission on March 5, 2020 (File No. 000-51734)).
4.3
-
Indenture, dated October 11, 2019, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., the guarantors party thereto and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on October 11, 2019 (File No. 000-51734)).
4.4
-
Form of 11.00% Senior Notes due 2025 (included in Exhibit 4.3).
4.5
-
Indenture, dated as of August 5, 2020, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., the guarantors party thereto and Wilmington Trust, National
Exhibit Number
Description
Association, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on August 5, 2020 (File No. 000-51734)).
4.6
-
Form of 9.25% Senior Secured First Lien Note due 2024 (included in Exhibit 4.5).
4.7
-
Indenture, dated January 20, 2022, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., the guarantors party thereto and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 24, 2022 (File No. 000-51734)).
4.8
-
Form of 8.125% Senior Notes due 2027 (included in Exhibit 4.7).
4.9
-
Indenture, dated June 27, 2023, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., the guarantors party thereto and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on June 29, 2023 (File No. 000-51734)).
4.10
-
Form of 9.75% Senior Notes due 2028 (included in Exhibit 4.9).
10.1
-
Amended Crude Oil Sale Contract, effective April 1, 2008, between Plains Marketing, L.P. and Calumet Shreveport Fuels, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on March 20, 2008 (File No. 000-51734)).
10.2†
-
Calumet Specialty Products Partners, L.P. Executive Deferred Compensation Plan, dated December 18, 2008 and effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on December 22, 2008 (File No. 000-51734)).
10.3†
-
Form of Phantom Unit Grant Agreement (incorporated by reference to Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K filed with the Commission on March 15, 2023 (File No. 000-51734)).
10.4
-
Omnibus Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).
10.5
-
Third Amended and Restated Credit Agreement, dated as of February 23, 2018, by and among Calumet Specialty Products Partners, L.P. and certain of its subsidiaries as Borrowers, certain of its subsidiaries as Guarantors, the Lenders, Bank of America, N.A., as Agent, JPMorgan Chase Bank, N.A and Wells Fargo Bank, N.A., as Co-Syndication Agents (incorporated by reference from exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the commission on March 1, 2018 (File-No. 000-51734)).
10.6
-
First Amendment to Third Amended and Restated Credit Agreement, dated as of September 4, 2019, by and among Calumet Specialty Products Partners, L.P. and certain of its subsidiaries as Borrowers, certain of its subsidiaries as Guarantors, the Lenders, Bank of America, N.A., as Agent, JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A., as Co-Syndication Agents (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on September 6, 2019 (File No. 000-51734)).
10.7
-
Consent and Amendment No. 2 to Third Amended and Restated Credit Agreement dated as of November 18, 2021, by and among Calumet Specialty Products Partners, L.P., Bank of America, N.A., and the other parties thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on November 24, 2021 (File No. 000-51734)).
10.8
-
Third Amendment to Credit Agreement dated as of January 20, 2022, by and among Calumet Specialty Products Partners, L.P., Bank of America, N.A., and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 24, 2022 (File No. 000-51734))
10.9
-
Amended and Restated Collateral Trust Agreement, dated as of April 20, 2016, among Calumet Specialty Products Partners, L.P., the obligors party thereto, the secured hedge counterparties party thereto and Wilmington Trust, National Association, as Trustee and Collateral Trustee (incorporated by reference to exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the commission on April 21, 2016 (File No. 000-51734)).
Exhibit Number
Description
10.10
-
Second Amended and Restated Intercreditor Agreement, dated April 20, 2016, by and among the Collateral Trustee, Bank of America, N.A., as administrative agent, and the obligors named therein (incorporated by reference to exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the commission on April 21, 2016 (File No. 000-51734)).
10.11†
-
Amended and Restated Long-Term Incentive Plan, effective as of December 10, 2015 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on December 11, 2015 (File No. 000-51734)).
10.12†
-
First Amendment to Calumet GP, LLC Amended and Restated Long-Term Incentive Plan, effective as of December 9, 2021 (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 22, 2022 (File No. 000-51734)
10.13
-
Buyer Parent Guaranty, dated as of August 11, 2017, by and between Husky Oil Operations Limited and Calumet Lubricants Co., Limited Partnership (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on August 14, 2017 (File No. 000-51734)).
10.14†
-
Employment Letter, effective as of February 29, 2016, by and between Calumet GP, LLC and Bruce A. Fleming (incorporated by reference to Exhibit 10.27 to the Registrant’s Annual Report on Form 10-K filed with the Commission on March 4, 2022 (File No. 000-51734)).
10.15†
-
Scott Obermeier Promotion Letter, effective as of January 27, 2020, between Calumet GP, LLC and Scott Obermeier (incorporated by reference to Exhibit 10.28 to the Registrant’s Annual Report on Form 10-K filed with the Commission on March 4, 2022 (File No. 000-51734)).
10.16
-
Amendment No. 1 to Amended and Restated Collateral Trust Agreement, dated as of July 31, 2020, by and among the Partnership, the obligors party thereto and Wilmington Trust, National Association, as collateral trustee (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on August 5, 2020 (File No. 000-51734)).
10.17
-
Consent to Third Amended and Restated Credit Agreement, dated July 3, 2020, by and among Calumet Specialty Products Partners, L.P. and certain of its subsidiaries, as Borrowers, the Lenders party thereto and Bank of America, N.A., as Agent (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 6, 2020 (File No. 000-51734)).
10.18
-
Master Lease Agreement, together with Property Schedule No. 1 thereto, each dated as of February 12, 2021, and each by and between Stonebriar Commercial Finance LLC and Calumet Shreveport Refining, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the commission on February 16, 2021 (File No. 000-51734)).
10.19
-
Master Lease Agreement, dated December 31, 2021, by and between Montana Renewables, LLC and Stonebriar Commercial Finance LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 6, 2022 (File No. 000-51734)).
10.20#
-
Interim Funding Agreement, dated December 31, 2021, by and between Montana Renewables, LLC and Stonebriar Commercial Finance LLC (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 6, 2022 (File No. 000-51734)).
10.21†
-
Todd Borgmann Promotion Letter, effective as of May 1, 2022, between Calumet GP, LLC and Todd Borgmann (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on March 1, 2022 (File No. 000-51734)).
10.22
-
Preferred Unit Purchase Agreement, among Montana Renewables Holdings LLC, Calumet Specialty Products Partners, L.P., WPGG 14 United Aggregator, L.P. and, solely for the purposes of Section 4.4, Calumet GP, LLC, dated as of August 5, 2022 (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on November 9, 2022 (File No. 000-51734)).
Exhibit Number
Description
10.23
-
Second Amended and Restated Limited Liability Company Agreement of Montana Renewables Holdings LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on August 10, 2022 (File No. 000-51734)).
10.24
-
Equipment Schedule No. 2, dated August 5, 2022, by and between Montana Renewables, LLC and Stonebriar Commercial Finance LLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on November 9, 2022 (File No. 000-51734)).
10.25
-
Interim Funding Agreement, dated August 5, 2022, by and between Montana Renewables, LLC and Stonebriar Commercial Finance LLC (incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on November 9, 2022 (File No. 000-51734)).
10.26
-
Amendment to Interim Funding Agreement, dated August 5, 2022, by and between Montana Renewables, LLC and Stonebriar Commercial Finance LLC (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on November 9, 2022 (File No. 000-51734)).
10.27
-
Credit Agreement, dated November 2, 2022, by and among Montana Renewables, LLC, Montana Renewables Holdings LLC and Wells Fargo Bank, National Association, as agent and lender (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on November 7, 2022 (File No. 000-51734)).
10.28
-
Change of Control Protection Plan, effective March 13, 2023 (incorporated by reference to Exhibit 10.49 to the Registrant’s Annual Report on Form 10-K filed with the Commission on March 15, 2023 (File No. 000-51734)).
10.29
-
Credit Agreement dated April 19, 2023, among Montana Renewables, LLC, as Borrower, Montana Renewable Holdings LLC, as Holdings, the lenders from time to time party hereto, and Delaware Trust Company, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 4, 2023 (File No. 000-51734)).
10.30
-
Collateral Trust and Intercreditor Agreement dated as of April 19, 2023, among Montana Renewables Holdings LLC, as Holdings, Montana Renewables, LLC, as Company, the Other Obligors from time to time party hereto, Delaware Trust Company, as Administrative Agent, the Other Parity Lien Representatives, from time to time party thereto, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 4, 2023 (File No. 000-51734)).
10.31
-
Amendment No. 1 to Credit Agreement, dated as of April 4, 2023, by and among Montana Renewables, LLC, Montana Renewables Holdings LLC and Wells Fargo Bank, National Association, as agent and lender (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 4, 2023 (File No. 000-51734)).
10.32
-
Amendment No. 2 to Credit Agreement and Amendment No. 1 to Guaranty and Security Agreement, dated as of April 19, 2023, by and among Montana Renewables, LLC, Montana Renewables Holdings LLC and Wells Fargo Bank, National Association, as agent and lender (incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 4, 2023 (File No. 000-51734)).
10.33
-
Amendment No. 3 to Credit Agreement, dated as of July 26, 2023, by and among Montana Renewables, LLC, Montana Renewables Holdings LLC and Wells Fargo Bank, National Association, as agent and lender (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 4, 2023 (File No. 000-51734)).
10.34†
-
Employment Letter, effective as of September 11, 2023, by and between Calumet GP, LLC and David A. Lunin (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on November 9, 2023 (File No. 000-51734)).
Exhibit Number
Description
10.35
-
ISDA 2002 Master Agreement, dated October 3, 2023, by and among Montana Renewables, LLC and Wells Fargo Commodities, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on October 10, 2023 (File No. 000-51734)).
10.36
-
Schedule to the ISDA 2002 Master Agreement, dated October 3, 2023, by and among Montana Renewables, LLC and Wells Fargo Commodities, LLC (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on October 10, 2023 (File No. 000-51734)).
10.37
-
Credit Support Annex to the Schedule to the ISDA 2002 Master Agreement, dated October 3, 2023, by and among Montana Renewables, LLC and Wells Fargo Commodities, LLC as lender (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the Commission on October 10, 2023 (File No. 000-51734)).
10.38
-
Renewable Fuel and Feedstock Repurchase Master Confirmation, dated October 3, 2023, by and among Montana Renewables, LLC and Wells Fargo Commodities, LLC (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed with the Commission on October 10, 2023 (File No. 000-51734)).
10.39
-
Monetization Master Agreement, dated as of January 17, 2024, among J. Aron & Company LLC, Calumet Shreveport Refining, LLC, Calumet Refining, LLC and Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 24, 2024 (File No. 000-51734)).
10.40
-
Financing Agreement, dated as of January 17, 2024, among J. Aron & Company LLC, Calumet Shreveport Refining, LLC and Calumet Refining, LLC (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 24, 2024 (File No. 000-51734)).
10.41
-
Supply and Offtake Agreement, dated as of January 17, 2024, among J. Aron & Company LLC, Calumet Shreveport Refining, LLC and Calumet Refining, LLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 24, 2024 (File No. 000-51734)).
10.42
-
Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of January 17, 2024, by and among Calumet Specialty Products Partners, L.P., Bank of America, N.A, and the other parties signatory thereto (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 24, 2024 (File No. 000-51734)).
10.43
-
Note Purchase Agreement, dated February 23, 2024, by and among the Partnership, Finance Corp., the General Partner, the Guarantors and the purchasers named therein (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 23, 2024 (File No. 000-51734)).
21.1*
-
List of Subsidiaries of Calumet Specialty Products Partners, L.P.
23.1*
-
Consent of Ernst & Young, LLP, independent registered public accounting firm.
31.1*
-
Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
-
Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
-
Certification of Chief Executive Officer and Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
97.1*
-
Calumet Specialty Products Partners, L.P. Clawback Policy.
101.INS*
-
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*
-
Inline XBRL Taxonomy Extension Schema Document.
101.CAL*
-
Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*
-
Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*
-
Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*
-
Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104*
-
The cover page from the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, formatted Inline XBRL (included within the Exhibit 101 attachments)
†Identifies management contract and compensatory plan arrangements.
*Filed herewith.
**Furnished herewith.
#
Certain confidential information contained in this agreement has been omitted because it is both (i) not material and (ii) the type of information that the Partnership treats as private or confidential.