GENESIS ENERGY, L.P. Introduction
We are a growth-oriented MLP formed inDelaware in 1996. Our common units are traded on theNew York Stock Exchange , or NYSE, under the ticker symbol "GEL." We are (i) a provider of an integrated suite of midstream services (primarily transportation, storage, sulfur removal, blending, terminaling and processing) for a large area of theGulf of Mexico and theGulf Coast region of the crude oil and natural gas industry and (ii) one of the leading producers in the world of natural soda ash. We provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprises and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks. The other core focus of our business is our trona and trona-based exploring, mining, processing, producing, marketing and selling business based inWyoming (our "Alkali Business"). Our Alkali Business mines and processes trona from which it produces natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products, and has been operating for over 70 years.
Included in Management's Discussion and Analysis are the following sections:
•Overview of 2022 Results
•Recent Developments and Initiatives
•Results of Operations •Other Consolidated Results •Financial Measures
•Liquidity and Capital Resources
•Guarantor Summarized Financial Information
•Critical Accounting Estimates
•Recent Accounting Pronouncements
Overview of 2022 Results
We reported Net Income Attributable toGenesis Energy, L.P. of$75.5 million in 2022 compared to Net Loss Attributable toGenesis Energy, L.P. of$165.1 million in 2021. Net Income Attributable toGenesis Energy, L.P. in 2022 was impacted by: (i) an increase in segment margin of$152.3 million compared to 2021 (which was inclusive of$70.0 million in cash receipts associated with our previously owned NEJD pipeline not included in operating income, see "Results of Operations" below for additional details on the results of our operating segments); (ii) a decrease in depreciation, depletion and amortization expense of$13.5 million and a decrease in interest expense of$7.6 million (see "Results of Operations" below for additional details); and (iii) cancellation of debt income of$8.6 million from the repurchase of certain of our senior unsecured notes on the open market throughout 2022, which is recorded in "Other expense, net." Additionally, we incurred an unrealized (non-cash) loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of$18.6 million in 2022 compared to an unrealized (non-cash) loss of$30.9 million in 2021 recorded within "Other expense, net." These increases were partially offset by higher net income that we attributed to our noncontrolling interests during 2022 as a result of the sale of our 36% interest in our CHOPS pipeline in the fourth quarter of 2021. Cash flows from operating activities were$334.4 million for the 2022 period compared to$338.0 million for 2021. This decrease was primarily attributable to the 2021 period including$70.0 million in cash receipts associated with our previously owned NEJD pipeline and is included in cash flows from operating activities and changes in our working capital requirements. These were offset by higher segment margin reported during 2022. Available Cash before Reserves (as defined below in "Financial Measures") increased$148.7 million in 2022 to$352.6 million as compared to 2021 Available Cash before Reserves of$203.9 million , primarily due to an increase in segment margin, which is further discussed below in "Results from Operations." See "Financial Measures" below for additional information on Available Cash before Reserves.
Segment Margin was
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minerals and sulfur services, onshore facilities and transportation and marine transportation. A more detailed discussion of our segment results and other costs is included below in "Results of Operations".
Distributions to Unitholders
On
With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of$0.9473 per unit (or$3.789 on an annualized basis). These distributions were paid onFebruary 14, 2023 to unitholders holders of record at the close of businessJanuary 31, 2023 .
Recent Developments and Initiatives
Our primary objectives are to generate and grow stable free cash flows and continue to deleverage our balance sheet, while never wavering from our commitment to safe and responsible operations, as well as continue to advance and integrate our Environmental, Social and Governance ("ESG") program. We believe the following are important to meet our objectives:
•New and increased volumes on our existing offshore assets in theGulf of Mexico through long-term contracted commercial opportunities that require minimal to no additional investment from us, including volumes from the Argos (scheduled for first production in 2023) and King's Quay (which achieved first oil in the second quarter of 2022 and has ramped to in excess of 100,000 barrels of oil equivalent per day) floating production systems. •New volumes from long-term contracted offshore commercial opportunities in theGulf of Mexico , including the Shenandoah development, which will tie into our SYNC pipeline (which is currently under construction) and further downstream to our CHOPS pipeline (which we are currently in the process of expanding the capacity of), and theSalamanca floating production system, which will tie into our existing SEKCO pipeline for further transportation downstream to our existing pipeline network. These developments and their associated volumes are expected to come online in late 2024 and 2025. •Increased capacity for soda ash production by bringing the original Granger facility and its approximately 500,000 tons of annual production back online onJanuary 1, 2023 and investing into ourGranger Optimization Project , which is scheduled to begin first production in the second half of 2023 and ramp up to its design capacity of 750,000 tons per year over the subsequent nine to twelve months.
•The continued increase in demand for soda ash (including its anticipated participation in the energy transition).
We continue to have a significant amount of available borrowing capacity under our senior secured credit facility, which will allow us, when combined with our increasing free cash flow from operations as discussed above, to fund our high return capital projects, including ourGranger Optimization Project , our SYNC pipeline and the expansion of our existing CHOPS pipeline (all of which are further discussed below), which will provide future cash flows to continue to further deleverage our balance sheet.
Offshore Growth Commitments and Capital Projects
During 2022, we entered into definitive agreements to provide transportation services for 100% of the crude oil production associated with two separate, standalone deepwater developments that have a combined production capacity of approximately 160,000 barrels per day. In conjunction with these agreements, we expect to spend total gross capital expenditures of approximately$650 million (or approximately$550 million net to our ownership interests) to: (i) expand the current capacity of the CHOPS pipeline; and (ii) construct a new, 100% owned, approximately 105 mile, 20" diameter crude oil pipeline (the "SYNC pipeline") to connect one of the developments to our existing asset footprint in theGulf of Mexico . We plan to complete the construction in line with the producers' plan for the achievement of first oil production, which is currently expected in late 2024 or 2025. The producer agreements include long term take-or-pay arrangements and, accordingly, we are able to receive a project completion credit for purposes of calculating the leverage ratio under our senior secured credit facility throughout the construction period.
Granger Production Facility Expansion
OnSeptember 23, 2019 , we announced theGranger Optimization Project along with the issuance of theAlkali Holdings preferred units. The anticipated completion date of theGOP is the second half of 2023 and the expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year while also reducing our fixed cost per ton of production. The proceeds received from the issuance of ourAlkali Holdings preferred units assisted in the funding of the anticipated cost of theGOP . During the fourth quarter of 2021, we made the decision to fund the remaining construction costs 67
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required to complete theGOP through a combination of our internally generated free cash flows and availability under our senior secured credit facility, and subsequently, as noted above, redeemed the outstandingAlkali Holdings preferred units. Results of Operations In the discussions that follow, we will focus on our revenues, costs and expenses, as well as two measures that we use to manage the business and to review the results of our operations - Segment Margin and Available Cash before Reserves. Segment Margin and Available Cash before Reserves are defined in the "Financial Measures" section below.
Revenues, Costs and Expenses
Our revenues for the year endedDecember 31, 2022 increased$663.5 million , or 31%, from the year endedDecember 31, 2021 , and our costs and expenses (excluding the gain on sale of assets in 2022) increased$464.2 million , or 23%, between the two periods, with a net increase to operating income (loss) of$199.3 million . The increase in our operating income during 2022 is primarily attributable to increased volumes and pricing within our sodium minerals and sulfur services segment and increased utilization and day rates in our marine transportation segment, as well as lower depreciation, depletion and amortization during 2022. A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil in our crude oil marketing business, which is included in our onshore facilities and transportation segment, revenues and costs associated with our Alkali Business, which is included in our sodium minerals and sulfur services segment, and revenues and costs associated with our offshore pipeline transportation segment. We describe, in more detail, the impact on revenues and costs for each of our businesses below. As it relates to our crude oil marketing business, the average closing prices for West Texas Intermediate crude oil on theNew York Mercantile Exchange ("NYMEX") increased approximately 39% to$94.90 per barrel in 2022 as compared to$68.14 per barrel in 2021. We would expect changes in crude oil prices to continue to proportionately affect our revenues and costs attributable to our purchase and sale of crude oil and petroleum products, producing minimal direct impact on Segment Margin, Net income (loss) and Available Cash before Reserves. We have limited our direct commodity price exposure in our crude oil and petroleum products operations through the broad use of fee-based service contracts, back-to-back purchase and sale arrangements, and hedges. As a result, changes in the price of crude oil would proportionately impact both our revenues and our costs, with a disproportionately smaller net impact on our Segment Margin. However, we do have some indirect exposure to certain changes in prices for oil and petroleum products, particularly if they are significant and extended. We tend to experience more demand for certain of our services when prices increase significantly over extended periods of time, and we tend to experience less demand for certain of our services when prices decrease significantly over extended periods of time. For additional information regarding certain of our indirect exposure to commodity prices, see our segment-by-segment analysis below and the previous section above entitled "Risks Related to Our Business". As it relates to our Alkali Business, our revenues are derived from the extraction of trona, as well as the activities surrounding the processing and sale of natural soda ash and other alkali specialty products, including sodium sesquicarbonate (S-Carb) and sodium bicarbonate (Bicarb), and are a function of our selling prices and volume sold. We sell our products to an industry-diverse and worldwide customer base. Our sales prices are contracted at various times throughout the year and for different durations. Our sales prices for volumes sold internationally and to ANSAC are contracted for the current year either annually in the prior year or periodically throughout the current year (often quarterly), and our volumes priced and sold domestically are contracted at various times and can be of varying durations, often multi-year terms. Our sales volumes can fluctuate from period to period and are dependent upon many factors, of which the main drivers are the global market, customer demand, economic growth, and our ability to produce soda ash. Positive or negative changes to our revenue, through fluctuations in sales volumes or sales prices, can have a direct impact to Segment Margin, Net income (loss) and Available Cash before Reserves as these fluctuations have a lesser impact to operating costs due to the fact that a portion of our costs are fixed in nature. Our costs, some of which are variable in nature and others are fixed in nature, relate primarily to the processing and producing of soda ash (and other alkali specialty products) and marketing and selling activities. In addition, costs include activities associated with mining and extracting trona ore, including energy costs and employee compensation. In our Alkali Business, during 2022, as noted above, we had positive effects to our revenues compared to 2021 (with a lesser impact to costs) due to favorable export pricing of soda ash and higher sales volumes as a result of increased economic and market demand. For additional information, see our segment-by-segment analysis below. Our offshoreGulf of Mexico crude oil and natural gas pipeline transportation and handling operations focus on integrated and large independent energy companies who make intensive capital investments (often in excess of a billion dollars) to develop large reservoir, long-lived crude oil and natural gas properties. Our revenues are primarily derived from the fees, typically on a per barrel basis, we charge to transport and deliver commodities (or reserve capacity on our infrastructure in some cases) downstream to other pipelines or refineries along theGulf Coast . The shippers on our offshore pipelines are mostly integrated and large independent energy companies whose production is ideally suited for the vast majority of refineries along 68
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theGulf Coast . Their large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive and yet, we believe, economically viable, in most cases, even in volatile commodity price environments. Costs include activities associated with employee compensation and benefits, the maintenance of our pipelines and pipeline related infrastructure, marketing, and other variable type expenses associated with operating the business. We do not expect changes in commodity prices to impact our Net income (loss), Available Cash before Reserves or Segment Margin derived from our offshoreGulf of Mexico crude oil and natural gas pipeline transportation and handling operations in the same manner in which they impact our revenues and costs derived from the purchase and sale of crude oil and petroleum products. In addition to our crude oil marketing business, Alkali Business and offshore pipeline transportation and handling operations discussed above, we continue to operate in our other core businesses, including our sulfur services business and our onshore-based refinery-centric operations located primarily in theGulf Coast region of theU.S. , which focus on providing a suite of services primarily to refiners. Refiners are the shippers of approximately 98% of the volumes transported on our onshore crude pipelines, and refiners contract for approximately 90% of the revenues from our marine inland barges, which are used primarily to transport intermediate refined products (not crude oil) between refining complexes. Additionally, changes in certain of our operating costs between the respective periods, such as those associated with our sodium minerals and sulfur services, offshore pipeline and marine transportation segments, are not directly correlated with crude oil prices. We discuss certain of those costs in further detail below in our segment-by-segment analysis.
Included below is additional detailed discussion of the results of our operations focusing on Segment Margin and other costs including general and administrative expenses, depreciation, depletion and amortization, gain on sale of assets, interest expense and income taxes.
Segment Margin
The contribution of each of our segments to total Segment Margin in each of the last three years was as follows:
Year Ended December 31,
2022 2021 2020
(in thousands)
Offshore pipeline transportation $ 363,373 $ 317,560 $ 270,078
Sodium minerals and sulfur services 306,718 166,773 130,083 Onshore facilities and transportation 33,755 98,824 147,254 Marine transportation 66,209 34,572 60,058 Total Segment Margin$ 770,055 $ 617,729 $ 607,473 69
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Year Ended
Offshore Pipeline Transportation Segment
Operating results and volumetric data for our offshore pipeline transportation segment are presented below:
Year Ended December 31,
2022 2021
(in thousands) Offshore crude oil pipeline revenue, net to our ownership interest and excluding non-cash revenues
$ 287,318 $ 264,690
Offshore natural gas pipeline revenue, excluding non-cash revenues
46,660 41,776
Offshore pipeline operating costs, net to our ownership interest and excluding non-cash expenses
(75,811) (71,812)
Distributions from equity investments(1) 73,206 82,906
Distributions from unrestricted subsidiaries(2) 32,000 -
Offshore pipeline transportation Segment Margin $ 363,373 $ 317,560
Volumetric Data 100% basis:
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS 207,008 189,904
Poseidon 257,444 263,169
Odyssey 84,682 114,128
GOPL(3) 6,964 7,826
Total crude oil offshore pipelines 556,098 575,027
Natural gas transportation volumes (MMBtus/day) 343,347 345,870
Volumetric Data net to our ownership interest(4):
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS(5) 132,485 180,173
Poseidon 164,764 168,428
Odyssey 24,558 33,097
GOPL(3) 6,964 7,826
Total crude oil offshore pipelines 328,771 389,524
Natural gas transportation volumes (MMBtus/day) 108,908 107,417
(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2022 and 2021, respectively.
(2)Offshore pipeline transportation Segment Margin in 2022 includes distributions received from one of our unrestricted subsidiaries,Independence Hub LLC , of$32.0 million associated with the sale of our 80% owned platform asset.
(3)One of our wholly-owned subsidiaries (
(4)Volumes are the product of our effective ownership interest throughout the year, including changes in ownership interest, multiplied by the relevant throughput over the given year.
(5)OnNovember 17, 2021 , we divested a 36% minority interest in our CHOPS pipeline. The volumes for 2021 represent our 100% ownership during 2021 throughNovember 16, 2021 and our 64% ownership fromNovember 17, 2021 throughDecember 31, 2021 . 70
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Offshore Pipeline Transportation Segment Margin for 2022 increased$45.8 million , or 14%, from 2021, primarily due to (i) distributions received from one of our unrestricted subsidiaries,Independence Hub LLC , of$32 million , net to our interest, for the sale of our 80% owned platform asset, and (ii) increased crude oil and natural gas activity, primarily from first oil achieved at the King's Quay FPS onApril 12, 2022 , which supports volumes from the Khaleesi, Mormont and Samurai field developments, succeeded by a ramp up in production that has reached 100,000 barrels of oil equivalent per day. The King's Quay FPS is life-of-lease dedicated to our 100% owned crude oil and natural gas lateral pipelines and further downstream to our 64% owned Poseidon and CHOPS crude oil systems and our 25.67% owned Nautilus natural gas system for ultimate delivery to shore. Additionally, our 2022 segment margin benefited from our minimum volume commitments associated with the Argos FPS, which will handle production from the Mad Dog 2 field development and is anticipated to come online in the middle part of 2023. These increases were partially offset by an increased level of operational downtime during 2022 that was primarily a result of unplanned operational maintenance associated with one of our lateral pipelines that also impacted volumes on our main pipeline downstream of it in the first quarter of 2022, and a period of unplanned producer downtime at numerous fields connected to our pipeline infrastructure in the fourth quarter of 2022, which returned to normal operations by the end of the year. Lastly, the 2022 period was impacted, relative to the 2021 period, by our decrease in ownership of CHOPS, as we sold a 36% minority interest onNovember 17, 2021 .
Sodium Minerals and Sulfur Services Segment
Operating results for our sodium minerals and sulfur services segment were as
follows:
Year Ended December 31,
2022 2021
Volumes sold :
NaHS volumes (Dry short tons "DST") 128,851 114,292
Soda Ash volumes (short tons sold) 3,096,494 2,994,507
NaOH (caustic soda) volumes (DST sold) 90,876 84,278
Revenues (in thousands):
NaHS revenues, excluding non-cash revenues $ 183,966 $ 128,959
NaOH (caustic soda) revenues 74,284 42,182
Revenues associated with our Alkali Business 896,125 696,117
Other revenues 8,226 4,728
Total segment revenues, excluding non-cash revenues(1) $
1,162,601
Sodium minerals and sulfur services operating costs, excluding non-cash items(1)
(855,883) (705,213)
Segment Margin (in thousands) $
306,718
Average index price for NaOH per DST(2)$ 1,118 $ 787
(1)Totals are for external revenues and costs prior to intercompany elimination upon consolidation.
(2)Source: IHS Chemical. Sodium minerals and sulfur services Segment Margin for 2022 increased$139.9 million , or 84%, from 2021. This increase is primarily due to more favorable export and domestic pricing and higher sales volumes in our Alkali Business and higher NaHS sales volumes in our refinery services business during 2022. In our Alkali Business, we have continued to see strong demand improvement and growth as a result of the global economic recovery and the continued application of soda ash in everyday end use products, including solar panels, and in the production of lithium carbonate and lithium hydroxide, which are some of the building blocks of lithium batteries that are expected to play a large role in the anticipated energy transition. This continued demand, combined with flat or even slightly declining supply of soda ash in the near term, has tightened the overall supply and demand balance and created a higher price environment for our tons and increased contribution to Segment Margin during 2022. We expect our weighted average sales price for 2023 to exceed 2022 prices. Additionally, we successfully restarted our original Granger production facility onJanuary 1, 2023 and are still on schedule to complete ourGranger Optimization Project in the second half of 2023, which represents an incremental 750,000 tons of annual production that we 71
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anticipate to ramp up. In our refinery services business, we had an increase in NaHS sales volumes and the corresponding pricing of these sales volumes in 2022 due to an increase in demand from our mining customers as a result of the continued global economic recovery and the use of NaHS in the mining of copper, which is used in products that are a key part of the anticipated energy transition.
Onshore Facilities and Transportation Segment
Our onshore facilities and transportation segment utilizes an integrated set of pipelines and terminals, trucks and barges to facilitate the movement of crude oil and refined products on behalf of producers, refiners and other customers. This segment includes crude oil and refined products pipelines, terminals and rail unloading facilities operating primarily within theU.S. Gulf Coast crude oil market. In addition, we utilize our trucking fleet that supports the purchase and sale of gathered and bulk-purchased crude oil, as well as purchased and sold refined products. Through these assets we offer our customers a full suite of services, including the following as ofDecember 31, 2022 : •facilitating the transportation of crude oil from producers to refineries and from our terminals, as well as those owned by third parties, to refiners via pipelines;
•shipping crude oil and refined products to and from producers and refiners via trucks and pipelines;
•storing and blending of crude oil and intermediate and finished refined products;
•purchasing/selling and/or transporting crude oil from the wellhead to markets for ultimate use in refining;
•purchasing products from refiners, transporting those products to one of our terminals and blending those products to a quality that meets the requirements of our customers and selling those products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets; and
•unloading railcars at our crude-by-rail terminals.
We also may use our terminal facilities to take advantage of contango market conditions for crude oil gathering and marketing and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products. Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. ManyU.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and inefficiencies relative to meeting the refiners' requirements may also provide opportunities for us to utilize our purchasing and logistical skills to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials. 72
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Operating results for our onshore facilities and transportation segment were as follows:
Year Ended December 31,
2022 2021
(in thousands)
Gathering, marketing, and logistics revenue $ 890,719 $ 651,097
Crude oil and CO2 pipeline tariffs and revenues 31,822 35,303
Distributions from unrestricted subsidiaries not included in income(1)
- 70,000
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions
(828,933) (584,880)
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses
(66,400) (60,992)
Other 6,547 (11,704)
Segment Margin $ 33,755 $ 98,824
Volumetric Data (average Bbls/day unless otherwise noted):
Onshore crude oil pipelines:
Texas 90,562 65,918
Jay 6,601 7,941
Mississippi 5,725 5,206
Louisiana(2) 94,389 99,927
Onshore crude oil pipelines total 197,277 178,992
Total crude oil and petroleum products sales 24,643 24,239
Rail unload volumes(3) 10,834 11,782
(1)2021 includes total cash payments received from our previously owned NEJD
pipeline of
(2)Total daily volumes for the years endedDecember 31, 2022 and 2021 include 28,850 and 32,526 Bbls/day, respectively, of intermediate refined products and 53,459 and 55,363 Bbls/day, respectively, of crude oil associated with ourPort of Baton Rouge Terminal pipelines.
(3)Includes total barrels for unloading at all rail facilities.
Segment Margin for our onshore facilities and transportation segment decreased$65.1 million , or 66% , in 2022 as compared to 2021. The decrease is primarily due to 2021 including cash receipts of$70 million associated with our previously owned NEJD pipeline. This decrease was partially offset by higher volumes on ourTexas pipeline during 2022, which is a destination point for various grades of crude oil produced in theGulf of Mexico including those transported on our 64% owned CHOPS pipeline. 73
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Marine Transportation Segment
Within our marine transportation segment, we own a fleet of 91 barges (82 inland
and 9 offshore) with a combined transportation capacity of 3.2 million barrels,
42 push/tow boats (33 inland and 9 offshore), and a 330,000 barrel capacity
ocean going tanker, the M/T American Phoenix. Operating results for our marine
transportation segment were as follows:
Year Ended December 31,
2022 2021
Revenues (in thousands):
Inland freight revenues $ 105,583 $ 73,465
Offshore freight revenues 87,587 68,703
Other rebill revenues(1) 100,125 48,659
Total segment revenues $ 293,295 $ 190,827 Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses(1)
$ 227,086 $ 156,255 Segment Margin (in thousands)$ 66,209 $ 34,572 Fleet Utilization:(2) Inland Barge Utilization 98.6 % 81.9 % Offshore Barge Utilization 96.9 % 95.9 %
(1) Under certain of our marine contracts, we "rebill" our customers for a portion of our operating costs.
(2) Utilization rates are based on a 365 day year, as adjusted for planned downtime and drydocking.
Marine Transportation Segment Margin for 2022 increased$31.6 million , or 92%, from 2021. This increase is primarily attributable to higher utilization rates, which exited the year at 100% in both our inland and offshore fleets, and higher day rates, including the M/T American Phoenix, during 2022. Demand for our barge services to move intermediate and refined products has increased throughout 2022 due to the recovery of refinery utilization rates as well as the lack of new supply of similar type vessels (primarily due to higher construction costs) as well as the retirement of older vessels in the market. These factors have also contributed to an overall increase in spot and term rates for our services. These increases were partially offset by the M/T American Phoenix. While the M/T American Phoenix had higher day rates throughout 2022 relative to 2021, its contribution to our segment margin was negatively impacted as it went into a planned mandatory regulatory dry-dock fromJuly 21, 2022 throughSeptember 16, 2022 . Upon completion of the dry-dock, the M/T American Phoenix went back on hire and is currently under contract through the end of 2023 with an investment grade customer at a more favorable rate than 2022.
Other Costs, Interest and Income Taxes
General and administrative expenses
Year Ended December 31,
2022 2021
(in thousands) General and administrative expenses not separately identified below: Corporate
$ 47,306 $ 43,329 Segment 3,674 4,162 Long-term incentive based compensation plan expense 8,279 4,748
Third-party costs related to business development activities and growth projects
7,339 8,946
Total general and administrative expenses $ 66,598 $ 61,185
Total general and administrative expenses increased $5.4 million between 2022
and 2021. The increase is primarily due to higher costs associated with our
long-term incentive compensation plan as a result of the assumptions used to
value our outstanding awards and higher corporate general and administrative
costs during 2022.
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Depreciation, depletion and amortization expense
Year Ended December 31,
2022 2021
(in thousands)
Depreciation and depletion expense $ 285,302 $ 298,953
Amortization expense 10,903 10,793
Total depreciation, depletion and amortization expense $ 296,205 $ 309,746
Total depreciation, depletion and amortization expense decreased $13.5 million
between 2022 and 2021. The decrease in depreciation and depletion expense is
primarily attributable to the acceleration of depreciation on certain of our
asset retirement obligation assets during 2021 as a result of updates to the
estimated timing and costs associated with certain of our non-core offshore
natural gas assets.
Interest expense, net
Year Ended December 31,
2022 2021
(in thousands) Interest expense, senior secured credit facility (including commitment fees)
$ 10,980 $ 22,287 Interest expense, Alkali senior secured notes 15,811 - Interest expense, senior unsecured notes 209,001 206,352 Amortization of debt issuance costs, premium and discount 8,479 9,452 Capitalized interest (18,115) (4,367) Interest expense, net$ 226,156 $ 233,724 Net interest expense decreased$7.6 million between 2022 and 2021 primarily due to a decrease in interest expense associated with our senior secured credit facility and an increase in capitalized interest. The decrease in interest expense on our senior secured credit facility is due to a lower outstanding balance throughout 2022 as a result of: (i) the proceeds we received from the additional issuance of$250 million in aggregate principal of our 2027 Notes inApril 2021 ; (ii) the proceeds from the sale of a noncontrolling interest in our CHOPS pipeline inNovember 2021 ; and (iii) the proceeds we received from the issuance of our Alkali senior secured notes inMay 2022 in excess of the funds used to redeem ourAlkali Holdings preferred units, all of which were used to pay down the outstanding balance under our senior secured credit facility. Additionally, we had higher capitalized interest during 2022 as a result of our increased capital expenditures associated with theGOP and our offshore growth capital construction projects, both of which are being funded internally.
Income tax expense
A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations. The balance of the income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles and foreign income taxes.
Other Consolidated Results
Net income for the year endedDecember 31, 2022 included an unrealized loss of$18.6 million from the valuation of our previously recognized embedded derivative associated with our Class A Convertible Preferred Units, and also included cancellation of debt income of$8.6 million associated with the open market repurchase and extinguishment of certain of our senior unsecured notes. Both of these amounts are included within "Other,expense, net" on the Consolidated Statement of Operations. In addition, net income for the year endedDecember 31, 2022 included a gain of$40.0 million recorded in "Loss (gain) on sale of asset" on the Consolidated Statement of Operations, of which$8.0 million , or 20%, is attributable to our noncontrolling interest holder, related to the sale of our Independence Hub platform to a producer group in theGulf of Mexico for gross proceeds of$40.0 million . Net loss for the year endedDecember 31, 2021 included an unrealized loss of$30.8 million from the valuation of our embedded derivative associated with our Class A Convertible Preferred Units included in "Other expense, net" in the Consolidated Statement of Operations. 75
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A discussion of the operating results for the year endedDecember 31, 2021 compared with the year endedDecember 31, 2020 has been omitted from this Form 10-K. This discussion can be found within our previously filed 2021 Form 10-K, which was filed with theSEC onFebruary 24, 2022 .
Non-GAAP Financial Measures
General
To help evaluate our business, this Annual Report on Form 10-K includes the
non-generally accepted accounting principle ("non-GAAP") financial measure of
Available Cash before Reserves. We also present total Segment Margin as if it
were a non-GAAP measure. Our non-GAAP measures may not be comparable to
similarly titled measures of other companies because such measures may include
or exclude other specified items. The accompanying schedules provide
reconciliations of these non-GAAP financial measures to their most directly
comparable financial measures calculated in accordance with generally accepted
accounting principles in the United States of America (GAAP). A reconciliation
of Net income (loss) attributable to Genesis Energy, L.P. to total Segment
Margin is included in our segment disclosure in Note 13 to our Consolidated
Financial Statements in Item 8. Our non-GAAP financial measures should not be
considered (i) as alternatives to GAAP measures of liquidity or financial
performance or (ii) as being singularly important in any particular context;
they should be considered in a broad context with other quantitative and
qualitative information. Our Available Cash before Reserves and total Segment
Margin measures are just two of the relevant data points considered from time to
time.
When evaluating our performance and making decisions regarding our future
direction and actions (including making discretionary payments, such as
quarterly distributions) our board of directors and management team have access
to a wide range of historical and forecasted qualitative and quantitative
information, such as our financial statements; operational information; various
non-GAAP measures; internal forecasts; credit metrics; analyst opinions;
performance, liquidity and similar measures; income; cash flow expectations for
us; and certain information regarding some of our peers. Additionally, our board
of directors and management team analyze, and place different weight on, various
factors from time to time. We believe that investors benefit from having access
to the same financial measures being utilized by management, lenders, analysts
and other market participants. We attempt to provide adequate information to
allow each individual investor and other external user to reach her/his own
conclusions regarding our actions without providing so much information as to
overwhelm or confuse such investor or other external user. Our non-GAAP
financial measures should not be considered as an alternative to GAAP measures
such as net income, operating income, cash flow from operating activities or any
other GAAP measure of liquidity or financial performance.
Segment Margin
We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses (all of which are net of the effects of our noncontrolling interest holders), plus or minus applicable Select Items (defined below). Although, we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and capital investment. A reconciliation of Net income (loss) attributable toGenesis Energy, L.P. to total Segment Margin is included in our segment disclosure in Note 13 to our Consolidated Financial Statements in Item 8.
Available Cash before Reserves
Purposes, Uses and Definition
Available Cash before Reserves, often referred to by others as distributable
cash flow, is a quantitative standard used throughout the investment community
with respect to publicly-traded partnerships and is commonly used as a
supplemental financial measure by management and by external users of financial
statements such as investors, commercial banks, research analysts and rating
agencies, to aid in assessing, among other things:
(1) the financial performance of our assets;
(2) our operating performance;
(3) the viability of potential projects, including our cash and overall return
on alternative capital investments as compared to those of other companies in
the midstream energy industry;
(4) the ability of our assets to generate cash sufficient to satisfy certain
non-discretionary cash requirements, including interest payments and certain
maintenance capital requirements; and
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(5) our ability to make certain discretionary payments, such as distributions on our preferred and common units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.
We define Available Cash before Reserves ("Available Cash before Reserves") as
Net income (loss) attributable to Genesis Energy, L.P. before interest, taxes,
depreciation, depletion and amortization (including impairment, write-offs,
accretion and similar items) after eliminating other non-cash revenues,
expenses, gains, losses and charges (including any loss on asset dispositions),
plus or minus certain other select items that we view as not indicative of our
core operating results (collectively, "Select Items"), as adjusted for certain
items, the most significant of which in the relevant reporting periods have been
the sum of maintenance capital utilized, net interest expense, cash tax expense
and cash distributions paid to our Class A convertible preferred unitholders.
Although we do not necessarily consider all of our Select Items to be
non-recurring, infrequent or unusual, we believe that an understanding of these
Select Items is important to the evaluation of our core operating results. The
most significant Select Items in the relevant reporting periods are set forth
below.
Year Ended
December 31,
2022 2021
I. Applicable to all Non-GAAP Measures (in thousands)
Differences in timing of cash receipts for certain contractual
arrangements(1) $ 51,102 $ 15,482
Distributions from unrestricted subsidiaries not included in
income(2) 32,000 70,000
Certain non-cash items:
Unrealized losses (gains) on derivative transactions excluding fair
value hedges, net of changes in inventory value(3) (5,717) 30,700
Loss on debt extinguishment(4) 794 1,627
Adjustment regarding equity investees(5) 21,199 26,207
Other (2,598) 207
Sub-total Select Items, net 96,780 144,223
II. Applicable only to Available Cash before Reserves
Certain transaction costs(6) 7,339 8,946
Other 2,208 1,398
Total Select Items, net $ 106,327 $ 154,567
(1)Represents the difference in timing of cash receipts from customers during
the period and the revenue we recognize in accordance with GAAP on our related
contracts. For purposes of our non-GAAP measures, we add those amounts in the
period of payment and deduct them in the period in which GAAP recognizes them.
(2)2022 includes $32.0 million in cash receipts associated with the sale of the
Independence Hub platform by our 80% owned unrestricted subsidiary (as defined
under our credit agreement), Independence Hub, LLC . 2021 includes $70.0 million
in cash receipts associated with principal repayments on our previously owned
NEJD pipeline not included in income, which is defined as an unrestricted
subsidiary under our credit agreement.
(3)2022 includes an unrealized loss of $18.6 million from the valuation of our
previously recorded embedded derivative associated with our Class A Convertible
Preferred Units and an unrealized gain of $24.3 million from the valuation of
our commodity derivatives transactions (excluding fair value hedges). 2021
includes an unrealized loss of $30.8 million from the valuation of the embedded
derivative and an unrealized gain of $0.1 million from the valuation of our
commodity derivatives (excluding fair value hedges).
(4)2022 includes the write-off of the unamortized issuance costs associated with
the repurchase and extinguishment of certain of our senior unsecured notes
during the year. 2021 includes the transaction costs and write-off of the
unamortized issuance costs associated with the redemption of our remaining 2023
Notes.
(5)Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
(6)Represents transaction costs relating to certain merger, acquisition, divestiture, transition and financing transactions incurred in advance of the associated transaction.
Disclosure Format Relating to
We use a modified format relating to maintenance capital requirements because
our maintenance capital expenditures vary materially in nature (discretionary
vs. non-discretionary), timing and amount from time to time. We believe that,
without such modified disclosure, such changes in our maintenance capital
expenditures could be confusing and potentially misleading
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to users of our financial information, particularly in the context of the nature and purposes of our Available Cash before Reserves measure. Our modified disclosure format provides those users with information in the form of our maintenance capital utilized measure (which we deduct to arrive at Available Cash before Reserves). Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period.
Maintenance Capital Requirements
Maintenance capital expenditures are capitalized costs that are necessary to maintain the service capability of our existing assets, including the replacement of any system component or equipment which is worn out or obsolete. Maintenance capital expenditures can be discretionary or non-discretionary, depending on the facts and circumstances. Prior to 2014, substantially all of our maintenance capital expenditures were (a) related to our pipeline assets and similar infrastructure, (b) non-discretionary in nature and (c) immaterial in amount as compared to our Available Cash before Reserves measure. Those historical expenditures were non-discretionary (or mandatory) in nature because we had very little (if any) discretion as to whether or when we incurred them. We had to incur them in order to continue to operate the related pipelines in a safe and reliable manner and consistently with past practices. If we had not made those expenditures, we would not have been able to continue to operate all or portions of those pipelines, which would not have been economically feasible. An example of a non-discretionary (or mandatory) maintenance capital expenditure would be replacing a segment of an old pipeline because one can no longer operate that pipeline safely, legally and/or economically in the absence of such replacement. Beginning with 2014, we believe a substantial amount of our maintenance capital expenditures from time to time will be (a) related to our assets other than pipelines, such as our marine vessels, trucks and similar assets, (b) discretionary in nature and (c) potentially material in amount as compared to our Available Cash before Reserves measure. Those expenditures will be discretionary (or non-mandatory) in nature because we will have significant discretion as to whether or when we incur them. We will not be forced to incur them in order to continue to operate the related assets in a safe and reliable manner. If we chose not make those expenditures, we would be able to continue to operate those assets economically, although in lieu of maintenance capital expenditures, we would incur increased operating expenses, including maintenance expenses. An example of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel in spite of its increasing maintenance and other operating expenses. In summary, as we continue to expand certain non-pipeline portions of our business, we are experiencing changes in the nature (discretionary vs. non-discretionary), timing and amount of our maintenance capital expenditures that merit a more detailed review and analysis than was required historically. Management's increasing ability to determine if and when to incur certain maintenance capital expenditures is relevant to the manner in which we analyze aspects of our business relating to discretionary and non-discretionary expenditures. We believe it would be inappropriate to derive our Available Cash before Reserves measure by deducting discretionary maintenance capital expenditures, which we believe are similar in nature in this context to certain other discretionary expenditures, such as growth capital expenditures, distributions/dividends and equity buybacks. Unfortunately, not all maintenance capital expenditures are clearly discretionary or non-discretionary in nature. Therefore, we developed a measure, maintenance capital utilized, that we believe is more useful in the determination of Available Cash before Reserves.
Maintenance Capital Utilized
We believe our maintenance capital utilized measure is the most useful quarterly maintenance capital requirements measure to use to derive our Available Cash before Reserves measure. We define our maintenance capital utilized measure as that portion of the amount of previously incurred maintenance capital expenditures that we utilize during the relevant quarter, which would be equal to the sum of the maintenance capital expenditures we have incurred for each project/component in prior quarters allocated ratably over the useful lives of those projects/components. Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period. Because we did not use our maintenance capital utilized measure before 2014, our maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred sinceDecember 31, 2013 . 78
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Available Cash before Reserves for the years ended
Year Ended December 31,
2022 2021
(in thousands)
Net income (loss) attributable to Genesis Energy, L.P. $ 75,457 $ (165,067)
Income tax expense 3,169 1,670
Depreciation, depletion, amortization, and accretion 307,519 315,896
Gain on sale of assets (32,000) -
Plus (minus) Select Items, net 106,327 154,567
Maintenance capital utilized (57,400) (53,150)
Cash tax expense (815) (690)
Distributions to preferred unitholders (80,052) (74,736)
Redeemable noncontrolling interest redemption value adjustments(1)
30,443 25,398
Available Cash before Reserves $ 352,648 $ 203,888
(1)Includes PIK distributions and accretion on the redemption feature
attributable to each period, and valuation adjustments to the redemption feature
as the associated preferred units were redeemed during the year ended December
31, 2022 .
Liquidity and Capital Resources
General
OnApril 8, 2021 , we entered into our Fifth Amended and Restated Credit Agreement, which initially provided for a$950 million senior secured credit facility, which comprised a revolving loan with a borrowing capacity of$650 million and a term loan with a borrowing capacity of$300 million , with the ability to increase the aggregate size of the revolving loan by an additional$200 million subject to lender consent and certain other customary conditions. Our term loan was paid off in full onNovember 17, 2021 with a portion of the gross proceeds of$418 million received from the sale of a 36% minority interest in CHOPS. OnFebruary 17, 2023 , we entered into the Sixth Amended and Restated Credit Agreement (our "new credit agreement") to replace our Fifth Amended and Restated Credit Agreement. The new credit agreement matures onFebruary 13, 2026 , subject to extension at our request for one additional year on up to two occasions and subject to certain conditions, unless more than$150 million of our 6.500% senior notes due 2025 remain outstanding as ofJune 30, 2025 , in which case the new credit agreement matures on such date. OnApril 22, 2021 we completed our offering of an additional$250 million in aggregate principal amount of our 2027 Notes (as defined in Note 10 to our Consolidated Financial Statements in Item 8). The additional$250 million of notes have identical terms as (other than with respect to issue price) and constitute part of the same series as our 2027 Notes and the net proceeds from this additional offering were used for general partnership purposes, including repaying a portion of the outstanding borrowings under our senior secured credit facility. OnApril 29, 2022 , we received$40 million , or$32 million net to our ownership interests, for the sale of our 80% owned Independence Hub platform which allowed us to repay a portion of the borrowings outstanding under our senior secured credit facility and further increase our borrowing capacity. OnMay 17, 2022 ,Genesis Energy, L.P. , through its newly created indirect unrestricted subsidiary,GA ORRI , issued$425 million principal amount of our 5.875% Alkali senior secured notes due 2042 to certain institutional investors, secured byGA ORRI's fifty-year 10% limited term overriding royalty interest in substantially all of the Company's Alkali Business trona mineral leases. The issuance generated net proceeds of$408 million , net of the issuance discount of$17 million . We make quarterly interest payments on our Alkali senior secured notes untilMarch 2024 , at which time we begin making quarterly principal and interest payments through the maturity date. We used a portion of net proceeds from the issuance to fully redeem the outstandingAlkali Holdings preferred units and utilized the remainder to repay a portion of the outstanding borrowings under our senior secured credit facility. The redemption of ourAlkali Holdings preferred units, which carried an implied interest rate of 12-13%, and the issuance of our Alkali senior secured notes with a coupon rate of 5.875%, has allowed us to simplify our capital structure and lower our cost of capital, provide us additional flexibility under our senior secured credit facility, and remove any risk of refinancing ourAlkali Holdings preferred units that were initially due in 2026. OnJanuary 25, 2023 , we issued$500 million in aggregate principal amount of our 8.875% senior unsecured notes dueApril 15, 2030 (the "2030 Notes"). Interest payments are dueApril 15 andOctober 15 of each year with the initial interest payment due onOctober 15, 2023 . That issuance generated net proceeds of approximately$491 million , net of issuance costs 79
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incurred. The net proceeds were used to purchase approximately$316 million of our existing 2024 Notes, including the related accrued interest and tender premium and fees on those notes that were tendered in the tender offer that endedJanuary 24, 2023 and the remaining proceeds at the time were used to repay a portion of the borrowings outstanding under our senior secured credit facility and for general partnership purposes. OnJanuary 26, 2023 , we issued a notice of redemption for the remaining principal of approximately$25 million of our 2024 Notes, and discharged the indebtedness with respect to the 2024 Notes onFebruary 14, 2023 by depositing the redemption amount with the trustee of the 2024 Notes for redemption of the 2024 Notes onFebruary 25, 2023 , all in accordance with the terms and conditions of the indenture governing the 2024 Notes. The successful completion of the above events has resulted in no scheduled maturities of our unsecured notes until 2025 and has provided us a significant amount of available borrowing capacity under our senior secured credit facility, subject to compliance with covenants, to, amongst other things, utilize for funding the remaining growth capital expenditures associated with ourGranger Optimization Project and our offshore growth projects discussed earlier. Additionally, these events have allowed us to simplify our capital structure and eliminate our highest interest rate instrument, theAlkali Holdings preferred units. As ofDecember 31, 2022 , we believe our balance sheet and liquidity position remained strong, including$436.1 million of borrowing capacity available (which does not include our repayment of excess proceeds from the issuance of our 2030 Notes), subject to compliance with our covenants, under the$650 million revolving portion of our senior secured credit facility as of such date. We anticipate that our future internally-generated funds and the funds available under our senior secured credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have historically been cash flows from operations, borrowing availability under our senior secured credit facility, proceeds from the sale of non-core assets, the creation of strategic arrangements to share capital costs through joint ventures or strategic alliances, and the proceeds from issuances of equity (common and preferred) and senior unsecured or secured notes.
Our primary cash requirements consist of:
•working capital, primarily inventories and trade receivables and payables;
•routine operating expenses;
•capital growth (as discussed in more detail below) and maintenance projects;
•interest payments related to outstanding debt;
•asset retirement obligations;
•quarterly cash distributions to our preferred and common unitholders; and
•acquisitions of assets or businesses.
Capital Resources
Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital from time to time, including through equity and debt offerings (public and private), borrowings under our senior secured credit facility and other financing transactions, and to implement our growth strategy successfully. No assurance can be made that we will be able to raise necessary funds on satisfactory terms. AtDecember 31, 2022 , we had$205.4 million borrowed under our senior secured credit facility, with$4.7 million of the borrowed amount designated as a loan under the inventory sublimit. Our senior secured credit facility does not include a "borrowing base" limitation except with respect to our inventory loans. Due to the revolving nature of loans under our senior secured credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of our senior secured credit facility. The total amount available for borrowings under our senior secured credit facility atDecember 31, 2022 was$436.1 million , subject to compliance with our covenants. On a pro forma basis, when considering the increased borrowing capacity associated with our new credit agreement, we would have had$636.1 million available for borrowings, subject to compliance with our covenants. AtDecember 31, 2022 , our long-term debt totaled approximately$3.5 billion , consisting of$205.4 million outstanding under our senior secured credit facility (including$4.7 million borrowed under the inventory sublimit tranche),$2.9 billion of senior unsecured notes, net and$402.4 million of Alkali senior secured notes, net, which are secured by the ORRI Interests. Our senior unsecured notes, net balance is comprised of$671.7 million of our 2028 notes,$976.3 million of our 2027 Notes,$336.8 million of our 2026 Notes,$531.6 million of our 2025 Notes, and$339.9 million of our 2024 Notes. Future payment obligations related to our senior secured credit facility and senior unsecured notes as ofDecember 31, 2022 , including both principal and estimated interest payments, are summarized in the table below: 80
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Estimated
Annual Interest
Interest Rate Maturity Date Principal Payable
(in thousands)
Senior secured credit facility(1) Varies March 15, 2024 $ 205,400 $ 12,324
2024 Notes(2)(3) 5.625% June 15, 2024 341,135 19,189
2025 Notes(2) 6.500% October 1, 2025 534,834 34,764
2026 Notes(2) 6.250% May 15, 2026 339,310 21,207
2027 Notes(2) 8.000% January 15, 2027 981,245 78,500
2028 Notes(2) 7.750% February 1, 2028 679,360 52,650
Total estimated payments $ 3,081,284 $ 218,634
(1)Amounts shown above for estimated interest payments represent the amounts
that would be paid on an annual basis if the debt outstanding at December 31,
2022 remained outstanding through the final maturity date of March 15, 2024 , and
interest rates remained constant from December 31, 2022 through the maturity
date.
(2)Each series of senior unsecured notes is further discussed and defined in
Note 10 to our Consolidated Financial Statements in Item 8.
(3)Subsequent to
Future payment obligations associated with our Alkali senior secured notes, as ofDecember 31, 2022 , including both estimated principal and interest payments, are summarized in the table below: Payment Obligations Estimated Interest Payments Estimated Principal Payments 2023 $ 24,969 $ - 2024 24,712 11,618 2025 23,997 13,097 2026 through 2042 227,794 400,285 We have the right to redeem each of our series of senior unsecured notes beginning on specified dates as summarized below, at a premium to the face amount of such notes that varies based on the time remaining to maturity on such notes. Additionally, we may redeem up to 35% of the principal amount of each of our series of senior unsecured notes with the proceeds from an equity offering of our common units during certain periods. A summary of the applicable redemption periods is provided in the table below. 2024 Notes 2025 Notes 2026 Notes 2027 Notes 2028 Notes Redemption right beginning on June 15, 2019 October 1, 2020 February 15, 2021 January 15, 2024 February 1, 2023 Redemption of up to 35% of the principal amount of notes with the proceeds of an equity February 15, offering permitted prior to June 15, 2019 October 1, 2020 2021 January 15, 2024 February 1, 2023
For additional information on our long-term debt and covenants see Note 10 to our Consolidated Financial Statements in Item 8.
Class A Convertible Preferred Units
OnSeptember 1, 2017 , we sold$750 million of Class A Convertible Preferred Units in a private placement, comprised of 22,249,494 units for a cash purchase price per unit of$33.71 (subject to certain adjustments, the "Issue Price") to two initial purchasers. Our general partner executed an amendment to our partnership agreement in connection therewith, which, among other things, authorized and established the rights and preferences of our Class A Convertible Preferred Units. Our Class A Convertible Preferred Units are a new class of security that ranks senior to all of our currently outstanding classes or series of limited partner interests with respect to distribution and/or liquidation rights. Holders of our Class A Convertible Preferred Units vote on an as-converted basis with holders of our common units and have certain class voting rights, including with 81
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respect to any amendment to the partnership agreement that would adversely affect the rights, preferences or privileges, or otherwise modify the terms, of those Class A Convertible Preferred Units.
Our Class A Convertible Preferred Units contained a distribution Rate Reset Election (as defined in Note 11 ), which was elected by the holders of the Class A Convertible Preferred Units onSeptember 29, 2022 (the "election date"). From the date of issuance through the election date, each of our Class A Convertible Preferred Units accumulated quarterly distribution amounts in arrears at an annual rate of 8.75% (or$2.9496 ), yielding a quarterly rate of 2.1875% (or$0.7374 ). On the election date, the holders of the Class A Convertible Preferred Units elected to reset the rate to 11.24%, yielding a quarterly distribution of$0.9473 per preferred unit beginning with the fourth quarter of 2022. With respect to any quarter ending on or prior toMarch 1, 2019 , we exercised our option to pay the holders of our Class A Convertible Preferred Units the applicable distribution in additional Class A Convertible Preferred Units equal the product of (i) the number of then outstanding Class A Convertible Preferred Units and (ii) the quarterly rate. For all subsequent periods ending afterMarch 1, 2019 , we have paid and will pay all distribution amounts in respect of our Class A Convertible Preferred Units in cash. As ofDecember 31, 2022 , there are 25,336,778 Class A Convertible Preferred Units outstanding.
Redeemable Noncontrolling interests
OnSeptember 23, 2019 , we, through a subsidiary,Alkali Holdings , entered into an amended and restated Limited Liability Company Agreement ofAlkali Holdings (the "LLC Agreement") and a Securities Purchase Agreement (the "Securities Purchase Agreement") whereby BXC purchased$55.0 million of preferred units (or 55,000 preferred units) and committed to purchase, during a three-year commitment period, up to a total of$350.0 million of preferred units (or 350,000 preferred units) inAlkali Holdings .Alkali Holdings utilized the net proceeds from the preferred units to fund a portion of the anticipated cost of theGranger Optimization Project . OnApril 14, 2020 , we entered into an amendment to our agreements with BXC to, among other things, extend the construction timeline of theGranger Optimization Project by one year, which we currently anticipate completing in the second half of 2023. In consideration for the amendment, we issued 1,750Alkali Holdings preferred units to BXC, which was accounted for as issuance costs. As part of the amendment, the commitment period was increased to four years, and the total commitment of BXC was increased to, subject to compliance with the covenants contained in our agreements with BXC, up to$351.8 million of preferred units (or 351,750 preferred units) inAlkali Holdings . From time to time after we had drawn at least$251.8 million , we had the option to redeem the outstanding preferred units in whole for cash at a price equal to the initial$1,000 per preferred unit purchase price, plus no less than the greater of a predetermined fixed internal rate of return amount or a multiple of invested capital metric, net of cash distributions paid to date ("Base Preferred Return"). Additionally, if all outstanding preferred units were redeemed, we had not drawn at least$251.8 million , and BXC was not a "defaulting member" under the LLC Agreement, BXC had the right to a make-whole amount on the number of undrawn preferred units. OnMay 17, 2022 (the "Redemption Date"), we fully redeemed the 251,750 outstandingAlkali Holdings preferred units a Base Preferred Return Amount of$288.6 million utilizing a portion of the proceeds we received from the issuance of our Alkali senior secured notes. As ofDecember 31, 2022 , there were noAlkali Holdings preferred units outstanding.
See Note 11 to our Consolidated Financial Statements in Item 8 for additional information regarding our mezzanine capital.
Shelf Registration Statements
We have the ability to issue additional equity and debt securities in the future to assist us in meeting our future liquidity requirements, particularly those related to opportunistically acquiring assets and businesses and constructing new facilities and refinancing outstanding debt. We have a universal shelf registration statement (our "2021 Shelf") on file with theSEC which we filed onApril 19, 2021 to replace our previous universal shelf registration statement that expired onApril 20, 2021 . Our 2021 Shelf allows us to issue an unlimited amount of equity and debt securities in connection with certain types of public offerings. However, the receptiveness of the capital markets to an offering of equity and/or debt securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions. Our 2021 Shelf is set to expire inApril 2024 . We expect to file a replacement universal shelf registration statement before our 2021 Shelf expires.
Cash Flows from Operations
We generally utilize the cash flows we generate from our operations to fund our
common and preferred distributions and working capital needs. Excess funds that
are generated are used to repay borrowings under our senior secured credit
facility and/or to fund a portion of our capital expenditures. Our operating
cash flows can be impacted by changes in items of working capital, primarily
variances in the carrying amount of inventory and the timing of payment of
accounts payable and accrued
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liabilities related to capital expenditures and interest charges, and the timing of accounts receivable collections from our customers.
We typically sell our crude oil in the same month in which we purchase it, so we do not need to rely on borrowings under our senior secured credit facility to pay for such crude oil purchases, other than inventory. During such periods, our accounts receivable and accounts payable generally move in tandem as we make payments and receive payments for the purchase and sale of crude oil. In our petroleum products activities, we buy products and typically either move those products to one of our storage facilities for further blending or sell those products within days of our purchase. The cash requirements for these activities can result in short term increases and decreases in the borrowings under our senior secured credit facility. In our Alkali Business, we typically extract trona from our mining facilities, process into soda ash and other alkali products, and deliver and sell to our customers all within a relatively short time frame. If we did experience any differences in timing of extraction, processing and sales of this trona or Alkali products, this could impact the cash requirements for these activities in the short term. The storage of our inventory of crude oil, petroleum products and alkali products can have a material impact on our cash flows from operating activities. In the month we pay for the stored crude oil or petroleum products (or pay for extraction and processing activities in the case of alkali products), we borrow under our senior secured credit facility (or use cash on hand) to pay for the crude oil or petroleum products (or extraction/processing of alkali products), utilizing a portion of our operating cash flows. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil, petroleum products or alkali products. Additionally, for our exchange-traded derivatives, we may be required to deposit margin funds with the respective exchange when commodity prices increase as the value of the derivatives utilized to hedge the price risk in our inventory fluctuates. These deposits also impact our operating cash flows as we borrow under our senior secured credit facility or use cash on hand to fund the deposits.
Net cash flows provided by our operating activities were
Capital Expenditures and Distributions Paid to Our Unitholders
We use cash primarily for our operating expenses, working capital needs, debt
service, acquisition activities, internal growth projects and distributions we
pay to our common and preferred unitholders. We finance maintenance capital
expenditures and smaller internal growth projects and distributions primarily
with cash generated by our operations. We have historically funded material
growth capital projects (including acquisitions and internal growth projects)
with borrowings under our senior secured credit facility, equity issuances
(common and preferred units), the issuance of senior unsecured or secured notes,
and/or the creation of strategic arrangements to share capital costs through
joint ventures or strategic alliances.
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Capital Expenditures for Fixed and Intangible Assets and Equity Investees
The following table summarizes our expenditures for fixed and intangible assets and equity investees in the periods indicated:
Years Ended December 31,
2022 2021 2020
(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Offshore pipeline transportation assets $ 6,292 $ 8,749 $ 8,715
Sodium mineral and sulfur services assets 77,918 51,241 43,744
Marine transportation assets 39,084 34,456 31,357
Onshore facilities and transportation assets 2,928 4,476 3,644
Information technology systems 6,317 946 383
Total maintenance capital expenditures 132,539 99,868 87,843
Growth capital expenditures:
Offshore pipeline transportation assets(1) $ 227,803 $ 41,445 $ 4,608
Sodium minerals and sulfur services assets 96,600 175,877 51,767
Marine transportation assets - - -
Onshore facilities and transportation assets - 133 489
Information technology systems 9,379 8,259 6,331
Total growth capital expenditures 333,782 225,714 63,195
Total capital expenditures for fixed and intangible assets 466,321
325,582 151,038
Capital expenditures related to equity investees 10,301 352 -
Total capital expenditures $ 476,622 $ 325,934 $ 151,038 (1)Growth capital expenditures in our offshore pipeline transportation segment for 2022 represent 100% of the costs incurred.
Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital. We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows. We continue to pursue a long term growth strategy that may require significant capital. Growth Capital Expenditures OnSeptember 23, 2019 , we announced theGOP along with the issuance of theAlkali Holdings preferred units, which were anticipated to fund up to the total estimated cost of theGOP . The anticipated completion date of the project is the second half of 2023. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year. During the fourth quarter of 2021, we made the decision to fund the remaining capital expenditures associated with theGOP internally in lieu of issuing additionalAlkali Holdings preferred units. During 2022, we entered into definitive agreements to provide transportation services for 100% of the crude oil production associated with two separate standalone deepwater developments that have a combined production capacity of approximately 160,000 barrels per day. In conjunction with these agreements, we are in the process of expanding the current capacity of the CHOPS pipeline and constructing a new 100% owned, approximately 105 mile, 20" diameter crude oil pipeline (the "SYNC pipeline") to connect one of the developments to our existing asset footprint in theGulf of Mexico . We plan to complete the construction in line with the producers' plan for first oil achievement, which is currently expected in late 2024 or 2025. The producer agreements include long term take-or-pay arrangements and, accordingly, we are able to receive a project completion credit for purposes of calculating the leverage ratio under our senior secured credit facility throughout the construction period. We plan to fund our estimated growth capital expenditures utilizing the available borrowing capacity under our senior secured credit facility and our recurring cash flows generated from operations, which we anticipate to increase during 2023 as a result of increased offshore volumes from King's Quay and Argos, favorable export pricing and continued demand in our Alkali business, and the restart of our original Granger facility onJanuary 1, 2023 and our expanded Granger facility in the second half of 2023. 84
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Maintenance Capital Expenditures
Maintenance capital expenditures incurred primarily relate to our marine transportation segment to replace and upgrade certain equipment associated with our vessels and in our Alkali Business, which is included in our sodium minerals and sulfur services segment, due to the costs to maintain our related equipment and facilities. Additionally, our offshore transportation assets incur maintenance capital expenditures to replace, maintain, and upgrade equipment at certain of our offshore platforms and pipelines that we operate. We expect future expenditures to be within a reasonable range of 2022's expenditures dependent upon the timing of when we incur certain costs. See previous discussion under "Available Cash before Reserves" for how such maintenance capital utilization is reflected in our calculation of Available Cash before Reserves. Distributions to Unitholders Our partnership agreement requires us to distribute 100% of our available cash (as defined therein) within 45 days after the end of each quarter to unitholders of record. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:
•less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or appropriate to:
•provide for the proper conduct of our business; •comply with applicable law, any of our debt instruments, or other agreements; or •provide funds for distributions to our common and preferred unitholders 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. Working capital borrowings are generally borrowings that are made under our senior secured credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners. OnFebruary 14, 2023 , we paid a distribution of$0.15 per common unit related to the fourth quarter of 2022. With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of$0.9473 per unit (or$3.7890 on an annualized basis). These distributions were paid onFebruary 14, 2023 to unitholders holders of record at the close of businessJanuary 31, 2023 . Our historical distributions to common unitholders and Class A Convertible Preferred unitholders are shown in the table below (in thousands, except per unit amounts). Per Common Unit Total Per Preferred Total Distribution For Date Paid Amount Amount Unit Amount Amount 2020 1st Quarter May 15, 2020$ 0.1500 $ 18,387 $ 0.7374 $ 18,684 2nd Quarter August 14, 2020$ 0.1500 $ 18,387 $ 0.7374 $ 18,684 3rd Quarter November 13, 2020$ 0.1500 $ 18,387 $ 0.7374 $ 18,684 4th Quarter February 12, 2021$ 0.1500 $ 18,387 $ 0.7374 $ 18,684 2021 1st Quarter May 14, 2021$ 0.1500 $ 18,387 $ 0.7374 $ 18,684 2nd Quarter August 13, 2021$ 0.1500 $ 18,387 $ 0.7374 $ 18,684 3rd Quarter November 12, 2021$ 0.1500 $ 18,387 $ 0.7374 $ 18,684 4th Quarter February 14, 2022$ 0.1500 $ 18,387 $ 0.7374 $ 18,684 2022 1st Quarter May 13, 2022$ 0.1500 $ 18,387 $ 0.7374 $ 18,684 2nd Quarter August 12, 2022$ 0.1500 $ 18,387 $ 0.7374 $ 18,684 3rd Quarter November 14, 2022$ 0.1500 $ 18,387 $ 0.7374 $ 18,684 4th Quarter February 14, 2023 (1)$ 0.1500 $ 18,387 $ 0.9473 $ 24,000
(1)This distribution was paid on
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Contractual Obligations and Commitments
In addition to the principal and interest payment commitments associated with our long-term debt discussed above, we have other contractual obligations and commitments as ofDecember 31, 2022 , which are summarized below. •We have estimated operating lease payment obligations totaling$234.6 million , of which$25.8 million is expected to be paid in 2023 (see Note 4 to our Consolidated Financial Statements in Item 8 for details on our lease obligations). •We have unconditional purchase obligations from agreements to purchase goods and services that are enforceable and legally binding and specify all significant terms. The estimated total for our unconditional purchase obligations is$54.1 million , of which$41.9 million is estimated to be paid in 2023. Contracts to purchase natural gas and utilities are generally at market-based prices. The estimated volumes and market prices atDecember 31, 2022 were used to value those obligations. The actual physical volumes and settlement prices may vary due to uncertainties involved in these estimates which include levels of production at the wellhead, changes in market prices and other conditions beyond our control. •We have estimated cash requirements associated with our growth capital spending program. We expect to complete ourGranger Optimization Project during 2023 and anticipate approximately$100 million of remaining capital expenditures. Additionally, we expect to spend approximately$400 million , which is net to our interests, over the next two years to complete the construction of our SYNC pipeline and expansion of our CHOPS pipeline. We also have current asset retirement obligations of approximately$27 million that we expect to pay in 2023. These requirements are expected to be funded primarily with free cash flow generated from our operations and availability under our senior secured credit facility.
Guarantor Summarized Financial Information
Our$2.9 billion aggregate principal amount of senior unsecured notes co-issued byGenesis Energy, L.P. andGenesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all ofGenesis Energy, L.P.'s current and future 100% owned domestic subsidiaries (the "Guarantor Subsidiaries"), exceptGA ORRI andGA ORRI Holdings and certain other subsidiaries. The remaining non-guarantor subsidiaries are indirectly owned byGenesis Crude Oil, L.P. , a Guarantor Subsidiary. The Guarantor Subsidiaries largely own the assets that we use to operate our business. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts ofGenesis Energy, L.P. ,Genesis Energy Finance Corporation or the Guarantor Subsidiaries, and the liabilities of our unrestricted subsidiaries do not constitute obligations ofGenesis Energy, L.P. , Genesis Energy Finance Corporation or the Guarantor Subsidiaries. See Note 10 to our Consolidated Financial Statements in Item 8 for additional information regarding our consolidated debt obligations. The guarantees are senior unsecured obligations of each Guarantor Subsidiary and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor Subsidiary, and senior in right of payment to all existing and future subordinated indebtedness of such Guarantor Subsidiary. The guarantee of our senior unsecured notes by each Guarantor Subsidiary is subject to certain automatic customary releases, including in connection with the sale, disposition or transfer of all of the capital stock, or of all or substantially all of the assets, of such Guarantor Subsidiary to one or more persons that are not us or a restricted subsidiary, the exercise of legal defeasance or covenant defeasance options, the satisfaction and discharge of the indentures governing our senior unsecured notes, the designation of such Guarantor Subsidiary as a non-Guarantor Subsidiary or as an unrestricted subsidiary in accordance with the indentures governing our senior unsecured notes, the release of such Guarantor Subsidiary from its guarantee under our senior secured credit facility, or liquidation or dissolution of such Guarantor Subsidiary (collectively, the "Releases"). The obligations of each Guarantor Subsidiary under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. We are not restricted from making investments in the Guarantor Subsidiaries and there are no significant restrictions on the ability of the Guarantor Subsidiaries to make distributions toGenesis Energy, L.P.
The rights of holders of our senior unsecured notes against the Guarantor
Subsidiaries may be limited under the
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OnMay 17, 2022 , we entered into our credit agreement amendment, which designated GA ORRI andGA ORRI Holdings as unrestricted subsidiaries under our credit agreement. In addition, the credit agreement amendment re-designatedGenesis Alkali Holdings Company LLC ,Genesis Alkali Holdings, LLC ,Genesis Alkali, LLC andGenesis Alkali Wyoming, LP (the subsidiary entities that own our Alkali Business, other than the ORRI Interests) as restricted entities and guarantors of our credit agreement. OnMay 17, 2022 , we designated GA ORRI andGA ORRI Holdings as unrestricted subsidiaries and reclassified the entities that originally held our Alkali Business as restricted subsidiaries under the indentures governing our senior unsecured notes. The Alkali Business was historically presented as non-guarantor subsidiaries and because of such designation are now presented as guarantor subsidiaries. The changes made did not impact the Company's previously reported consolidated net operating results, financial position, or cash flows.
The following is the summarized financial information for
Genesis Energy, L.P. and
Balance Sheets Guarantor Subsidiaries
December 31, 2022
(in thousands)
ASSETS:
Current assets $ 795,381
Fixed assets, net 3,680,119
Non-current assets(1) 869,793
LIABILITIES AND CAPITAL:(2)
Current liabilities 498,358
Non-current liabilities $ 3,635,959
Class A Convertible Preferred Units 891,909
Genesis Energy, L.P. and
Statements of Operations Guarantor Subsidiaries
Year Ended December 31,
2022
(in thousands)
Revenues(3) $ 2,638,473
Operating costs 2,443,529
Operating income 194,944
Net income before income taxes 29,031
Net income(2) 25,862
Less: Accumulated distributions to Class A Convertible Preferred Units
(80,052)
Net loss available to common unitholders $ (54,190)
(1)Excluded from non-current assets in the table above are
(2)There are no noncontrolling interests held at the Issuer or Guarantor Subsidiaries for the period presented.
(3)Excluded from revenues in the table above are
Critical Accounting Estimates The preparation of our consolidated financial statements in conformity withU.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We base these estimates and assumptions on historical experience and other information that are believed to be reasonable under the circumstances. Although we believe our estimates to be reasonable, these estimates and assumptions about future events and their effects cannot be determined with certainty, and, accordingly, are evaluated on a regular basis and revised as needed as new events occur or more information is acquired, and as the business environment in which we operate 87
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changes. Significant accounting policies that we employ are presented in Note 2 to our Consolidated Financial Statements in Item 8.
We have defined critical accounting estimates as those that: (i) are material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (ii) the impact to the financial condition or operating performance of the Company is material. Our most critical accounting estimates are discussed below.
Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets
In conjunction with each acquisition we make, we must allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. As additional information becomes available, we may adjust the original estimates within a short time period subsequent to the acquisition. In addition, we are required to recognize intangible assets separately from goodwill. Determining the fair value of assets and liabilities acquired, as well as intangible assets such as customer relationships, contracts, trade names and non-compete agreements involves professional judgment and is ultimately based on acquisition models and management's assessment of the value of the assets and liabilities acquired, and to the extent available, third-party assessments. Intangible assets with finite lives are amortized over their estimated useful life as determined by management.Goodwill , if any, is not amortized but instead is periodically assessed for impairment, as discussed further below. Uncertainties associated with these estimates include fluctuations in economic obsolescence factors in the area and potential future sources of cash flow.
Depreciation, Amortization and Depletion of Long-Lived Assets and Intangibles
In order to calculate depreciation, depletion and amortization we must estimate the useful lives of our fixed and intangible assets (including the reserve life of our mineral leaseholds) at the time the assets are placed in service. We compute depreciation and amortization on a straight-line basis using the best estimated useful life at the time the asset is placed into service. The actual period over which we will use the asset may differ from the assumptions we have made about the estimated useful life. Any subsequent events that result in a change in these estimates can impact future depreciation and amortization calculations, and these changes are adjusted as we become aware of such circumstances. At a minimum, we will assess the useful lives and residual values of all long-lived assets on an annual basis to determine if adjustments are required.
We compute depletion using the units of production method using actual production and our estimated reserve life. The actual reserve life may differ from the assumptions we have made about the estimated reserve life.
Impairment of Long-Lived Assets
When events or changes in circumstances indicate that the carrying amount of a fixed asset, intangible asset, equity method investment, or right of use asset with finite lives may not be recoverable, we review our assets for impairment. We compare the carrying value of the associated asset to the estimated undiscounted future cash flows expected to be generated from that asset. Estimates of future net cash flows include estimating future volumes and/or contractual commitments, future margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans. If we determine that an asset's unamortized cost may not be recoverable due to impairment, we may be required to reduce the carrying value and/or the subsequent useful life of the asset. Any such write-down of the value and unfavorable change in the useful life of a long-lived asset would increase costs and expenses at that time. For the years endedDecember 31, 2022 and 2021, we did not recognize an impairment expense associated with our long-lived assets. For the year endedDecember 31, 2020 , we recognized impairment expense of$280.8 million associated with long-lived assets (refer to Note 7 in our Consolidated Financial Statements in Item 8 for additional details).Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values. We do not amortize goodwill; however, we evaluate, and test if necessary, our goodwill (at the reporting unit level) for impairment onOctober 1 of each fiscal year, and more frequently, if indicators of impairment are present. We may perform a qualitative assessment of relevant events and circumstances about the likelihood of goodwill impairment. If it is deemed more likely than not the fair value of the reporting unit is less than its carrying amount, we calculate the fair value of the reporting unit. Otherwise, further testing is not required. We may also elect to exercise our unconditional option to bypass this qualitative assessment, in which case we would also calculate the fair value of the reporting unit. The qualitative assessment is based on reviewing the totality of several factors, including macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other entity specific events (for example, changes in management) or other events such as selling or disposing of a reporting unit. The determination of a reporting unit's fair value is predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include (i) discrete financial forecasts for the assets contained within the reporting unit, which rely on management's estimates of operating margins, (ii) long-term growth rates for cash flows beyond the discrete forecast period, (iii) appropriate discount rates and (iv) estimates of the cash flow multiples to apply in estimating the market value of our reporting units. Changes in these 88
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estimates could have a significant impact on fair value. If the fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, a charge to earnings may be required to reduce the carrying value of goodwill to its implied fair value. If future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. We monitor the markets for our products and services, in addition to the overall market, to determine if a triggering event occurs that would indicate that the fair value of a reporting unit is less than its carrying value. One of our other monitoring procedures is the comparison of our market capitalization to our book equity to determine if there is an indicator of impairment. We performed a qualitative assessment as ofOctober 1, 2022 for our refinery services reporting unit, which is the only reporting unit as of our assessment date that has goodwill. We did not identify any relevant events or circumstances indicating that it is more likely than not that the fair value of the reporting unit is less than the respective carrying value. As such, a quantitative goodwill test was not required, and no goodwill impairment was recognized for the year endedDecember 31, 2022 .
For additional information regarding our goodwill, see Note 9 to our Consolidated Financial Statements in Item 8.
Revenue recognition - Estimation of variable consideration
Our offshore pipeline transportation segment has certain long-term contracts with customers that include variable consideration that must be estimated at contract inception and re-assessed at each reporting period. Total consideration for these arrangements is recognized as revenue over the applicable contract period and is based on our measure of satisfaction of our corresponding performance obligation. Any difference in timing of revenue recognition and billings results in contract assets and liabilities. The estimated performance obligation over the life of a contract includes significant judgments by management including volume and forecasted production information, future price indexing, our ability to transport volumes produced by our customers, and the contract period. Changes in these assumptions or a contract modification could have a material effect on the amount of variable consideration recognized as revenue. Fair Value of Derivatives We reflect estimates for the fair value of our derivatives based on our internal records and information from third parties. We have commodity and other derivatives that are accounted for as assets and liabilities at fair value in our Consolidated Balance Sheets. The valuations of our derivatives that are exchange traded are based on market prices on the applicable exchange on the last day of the period. For our derivatives that are not exchange traded, the estimates we use are based on indicative broker quotations. Changes in these estimates could cause a material change to our financial results. We identified a feature within our Class A Convertible Preferred Units that was required to be bifurcated and recorded as an embedded derivative measured at fair value. Our final valuation of the embedded derivative occurred onSeptember 29, 2022 , which is when the feature within the Class A Convertible Preferred Units that required bifurcation and fair value measurement no longer existed. OnSeptember 29, 2022 , the fair value of the liability associated with the embedded derivative was reclassified to mezzanine equity. The fair value of the embedded derivative associated with our Class A Convertible Preferred Units was estimated using a Monte Carlo simulation approach that contained inputs, including our common unit price relative to the issuance price, dividend yield, discount yield, equity volatility, 30-yearU.S. Treasury rates, and default and redemption probabilities and timing estimates, which involved management judgment. During the years endedDecember 31, 2022 and 2021, we recorded unrealized losses of$18.6 million and$30.8 million , respectively, associated with fair value changes of the embedded derivative. Changes in the fair value estimate during 2022 were primarily driven by the election of the rate reset, which increased the distribution rate from 8.75% to 11.24%, and changes in the fair value estimate during 2021 were primarily driven by fluctuations in the discount yield from period to period. A significant increase or decrease in these inputs could have materially affected our fair value estimate, resulting in impacts to our Consolidated Financial Statements. For example, a 10% increase or decrease in the volatility used in the calculation could have caused a decrease or an increase to the fair value of our embedded derivative of approximately$8 million or$11 million , respectively as ofSeptember 29, 2022 .
For additional information regarding the Class A Convertible Preferred Units and the associated embedded derivative, see Note 11 and Note 18 to our Consolidated Financial Statements in Item 8.
Liability and Contingency Accruals and Asset Retirement Obligations
We accrue reserves for contingent liabilities including environmental
remediation and potential legal claims. When our assessment indicates that it is
probable that a liability has occurred and the amount of the liability can be
reasonably estimated, we make accruals. We base our estimates on all known facts
at the time and our assessment of the ultimate outcome, including consultation
with external experts and counsel. We revise these estimates as additional
information is obtained or resolution is achieved.
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We also make estimates related to future payments for environmental costs to remediate existing conditions attributable to past operations. Environmental costs include costs for studies and testing as well as remediation and restoration. We sometimes make these estimates with the assistance of third parties involved in monitoring the remediation effort.
Significant changes in new information or judgments could have a material impact to our financial results.
AtDecember 31, 2022 , we were not aware of any contingencies or environmental liabilities that would have a material effect on our financial position, results of operations or cash flows. Additionally, certain of our assets have contractual and regulatory obligations to perform dismantlement and removal activities, and in some instances remediation, when the assets are abandoned. Our asset retirement obligations are recorded as a liability at fair value and have significant assumptions and inputs, including the estimated costs and timing of the associated abandonment activities as well as the discount and inflation rates utilized to calculate the present value of the future estimated costs, that could materially impact our financial results. During 2022, we recognized changes in estimates (primarily due to updated estimated costs and the timing of when we expect to spend these costs) associated with certain of our non-core offshore assets of approximately$11 million . We could have impacts to our future earnings based on the actual costs we incur relative to our estimated costs.
Employee Benefits
We sponsor a defined benefit pension plan for union-only employees of our Alkali Business. We recognize the net funded status of the pension plan under GAAP as a net liability, included within "Other long-term liabilities" as ofDecember 31, 2022 and 2021 on our Consolidated Balance Sheets. The funded status represents the difference between the fair value of the pension plan's assets and the estimated benefit obligation of the plan. The benefit obligation represents the present value of the estimated future benefits we expect to pay to plan participants based on service at the end of each period. The benefit obligation and plan assets are measured at the end of each year, or more frequently, upon the occurrence of a significant event, such as a settlement or curtailment. We utilize actuarial valuations to measure our funded status in the plan, which include assumptions such as discount rates, expected long-term rate of return on our plan assets, the timing of our contributions and payments, employee headcount and compensation changes, amongst others. Significant changes to certain of these assumptions can have a material impact to our financial statements. We recognized an actuarial gain of$11.2 million during 2022 in accumulated other comprehensive income (loss) primarily as a result of an increase to the discount rate utilized to calculate our benefit obligation from 3.27% atDecember 31, 2021 to 5.33% atDecember 31, 2022 . The impact of the increase in our discount rate was partially offset as a result of an actuarial loss recognized due to the difference between the actual and expected return on our plan assets during 2022.
Recent Accounting Pronouncements
Recently Issued and Recently Adopted
InMarch 2020 , the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848), which provides expedients and exceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of the London InterBank Offered Rate ("LIBOR") and other rates resulting from rate reform that are entered into on or beforeDecember 31, 2022 . Contract terms that are modified due to the replacement of a reference rate are not required to be remeasured or reassessed under relevant accounting standards. OnMay 17, 2022 , we entered into our Second Amendment and Consent to the credit agreement (defined in Note 10 to our Consolidated Financial Statements in Item 8), which among other things, replaced our existing LIBOR rate based borrowings with the Term SOFR rate, which is based on the Secured Overnight Financing Rate ("SOFR") borrowings. The impact to our senior secured credit facility and related interest expense upon transition to SOFR did not have a material impact on our Consolidated Financial Statements for the year ended December 31, 2022. Refer to Note 10 in our Consolidated Financial Statements in Item 8 for more details. 90
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