GEL Genesis Energy LP

Genesis Energy, L.P. (NYSE: GEL) today announced its fourth quarter results.

We generated the following financial results for the fourth quarter of 2022:

• Net Income Attributable to Genesis Energy, L.P. of $42.0 million for the fourth quarter of 2022 compared to Net Loss Attributable to Genesis Energy, L.P. of $68.3 million for the same period in 2021.
• Cash Flows from Operating Activities of $81.8 million for the fourth quarter of 2022 compared to $95.6 million for the same period in 2021.
• We declared cash distributions on our preferred units of $0.9473 for each preferred unit, which equates to a cash distribution of approximately $24.0 million and is reflected as a reduction to Available Cash before Reserves to common unitholders.
• Available Cash before Reserves to common unitholders of $83.1 million for the fourth quarter of 2022, which provided 4.52X coverage for the quarterly distribution of $0.15 per common unit attributable to the fourth quarter.
• Total Segment Margin of $197.1 million for the fourth quarter of 2022.
• Adjusted EBITDA of $180.2 million for the fourth quarter of 2022.
• Adjusted Consolidated EBITDA of $736.3 million for the trailing twelve months ended December 31, 2022 and a bank leverage ratio of 4.14X, both calculated in accordance with our senior secured credit agreement and discussed further in this release.

Grant Sims, CEO of Genesis Energy, said, “We are once again very pleased with the financial performance of our market leading businesses for the fourth quarter. Our reported Adjusted EBITDA of $180.2 million exceeded our internal expectations, despite being negatively impacted by approximately $10 million during the quarter as a result of certain unplanned downtime from our producer customers in the Gulf of Mexico, all of which have since returned to normal operations. For the full year, we generated Adjusted EBITDA of $717.1 million, which exceeded the high end of our thrice upwardly revised full year guidance range for Adjusted EBITDA of $700 – $710 million that we issued last quarter, ending up approximately 25% over our initial 2022 guidance, or up approximately 18% over such initial range, even if you exclude the $41 million of non-recurring income we recognized in 2022. Importantly, we once again saw a reduction in our quarter-end leverage ratio, as calculated by our senior secured lenders, to 4.14 times, which is down in less than fifteen months from our third quarter 2021 leverage ratio of 5.51 times.

As we look forward to 2023, the fundamentals and macro conditions across our largest businesses continue to be as positive as we have ever seen them in our careers, and we believe this backdrop provides the foundation for us to continue to improve our balance sheet, generate increasing amounts of free cash flow from operations and deliver value for everyone in our capital structure in the coming years. We continue to see a significant amount of activity in the Gulf of Mexico, including new in-field development wells and new sub-sea tiebacks to existing deepwater production facilities for which we are the exclusive provider of midstream services. Additionally, we will benefit from a full year of volumes from both King’s Quay and Spruance, both of which continue to perform ahead of producer expectations, along with new volumes from Argos, which is currently expected to start up in the middle of the year. The soda ash market remains structurally tight which provided us with a constructive backdrop for our price negotiations on our uncontracted volumes as we entered 2023. We can now report that we have contractually agreed on the pricing for approximately 85% of our anticipated sales volumes of soda ash (including the additional 600,000 – 700,000 incremental tons from Granger expected in 2023) and related products for 2023. As a result, we expect that our weighted average realized price for the full year will exceed the weighted average realized price we received in 2022. Our marine transportation segment also continues to see at or near 100% utilization across all our asset classes, and we are seeing spot day rates and longer term contracted rates approaching levels not seen since 2014 and 2015.

Based on what I mentioned above, and our visibility into 2023, we now expect to generate Adjusted EBITDA this year in the range of $780 – $810(1) million and to exit 2023 with a leverage ratio, as calculated by our senior secured lenders, at or below 4.0 times. The mid-point of this range represents growth of approximately 18% over our 2022 Adjusted EBITDA, excluding the $41 million of non-recurring income we recognized in 2022. We have built into our guidance the potential negative effects if a significant worldwide recession were to unfold as we move through the year. Should that not be the case, or even if there is indeed a recession, but it is milder than we have currently modeled, there could be bias to the upside of even the top end of our 2023 Adjusted EBITDA guidance range provided herein. This anticipated financial performance will provide a clear future path for increasing financial flexibility and opportunities to continue to build long-term value for all our stakeholders.

Given this backdrop, in mid-January we opportunistically accessed the capital markets and successfully priced an offering of $500 million of 8.875% senior unsecured notes due 2030, using the net proceeds from the new notes to redeem in full our 5.625% senior unsecured notes due 2024, with the remainder being used to repay borrowings outstanding under our credit facility. In addition, on February 17, 2023 we successfully syndicated and closed on an extension and upsizing of our existing revolving credit facility with $850 million in commitments from both existing and new lenders with an initial maturity date of February 13, 2026. The relevant covenants contained in the new facility will remain materially the same as our previous facility, although, prospectively, we will have expanded general and permitted investment baskets which will give us increased flexibility to potentially purchase existing private or public securities across our capital structure that we might then perceive to be a high-valued use of our capital. We very much value the relationships with the banks in our bank group and are very appreciative of their continued and increased support of Genesis.

Importantly, with these steps, we now have no maturities of long-term debt until late 2025, and when combined with our clear line of sight to increasing amounts of free cash flow from operations, we believe we are well positioned with ample liquidity and financial flexibility to complete the remaining spend associated with our Granger soda ash expansion project in 2023, as well as complete the construction of the SYNC lateral and CHOPS expansion projects in the Gulf of Mexico in the second half of 2024. As we then start to harvest the incremental cash flow from these growth projects along with the continued strong performance of our base businesses, we believe we are in very good shape to begin simplifying our capital structure and perhaps even start looking at ways to return capital to our bond and common equity holders in one form or another, all while maintaining a leverage ratio at or below 4.0 times.

With that, I would like to next discuss our individual business segments and focus on their recent and expected performance in more detail.

Our offshore pipeline transportation segment performed in-line with our expectations despite experiencing more than expected producer downtime and maintenance at multiple major production facilities connected to our systems which negatively impacted our financial results by approximately $10 million for the quarter. More importantly all of these facilities have since returned to normal operations and we would expect a more normalized level of activity in our offshore segment during the first quarter.

Volumes from Murphy Oil’s operated King’s Quay development continued to exceed our expectations with production from their initial 7 well program producing approximately 115,000 barrels of oil equivalent per day, which is some 15% higher than the original design capacity of 85,000 barrels of oil and 100 million cubic feet of gas per day. Furthermore, Murphy has stated they are forecasting to maintain these production levels at King’s Quay for approximately three years without any additional field development. Meanwhile, Murphy is currently drilling an additional well at their operated Samurai field following the discovery of additional pay sands during their initial phase of development, and they expect this well to be turned to production and flow through King’s Quay starting in the second quarter. First oil from BP’s operated Argos floating production facility and the 14 wells pre-drilled and completed at the Mad Dog 2 field development is currently expected towards the middle of the year, but we are awaiting final confirmation from BP and their partners. We continue to expect volumes from Argos will ramp close to its nameplate capacity of 140,000 barrels of oil per day over the nine to twelve months subsequent to the date of initial production. As a reminder, 100% of the volumes from Argos will flow through our 64% owned and operated CHOPS pipeline for ultimate delivery to shore.

These larger developments, along with other in-field development drilling and other sub-sea tiebacks to production facilities connected to our critical infrastructure, will provide a bridge to the next wave of volumes which includes the approximately 160,000 barrels of oil per day of production handling capacity we expect in late 2024 and early 2025 from our recently contracted developments, Shenandoah and Salamanca. The corresponding construction of the SYNC lateral and CHOPS expansion to support these new volumes in late 2024 and early 2025 remains on schedule, and we currently estimate a total project cost of approximately $550 million, net to our interest. Through the end of last year, we had spent approximately $150 million on this project and would expect to see most of the remaining capital spent this year and the first half of 2024, as we get ready for first oil later that year and early 2025.

We continue to pursue multiple in-field, sub-sea and/or secondary recovery development opportunities representing upwards of 150,000 – 200,000 barrels of oil per day in the aggregate that could turn to production on our pipeline systems over the next two to four years, all of which have been identified but not yet fully sanctioned by the operators and producers involved. The combination of a growing, steady and stable base of production combined with the large scale contracted projects that have or will come on-line every year from 2022 through 2025 demonstrates the stability, longevity and future potential of the deepwater areas of the central Gulf of Mexico and its ability to continue to regenerate itself and support long-term, stable and growing cash flows for many years and decades to come.

Our sodium minerals and sulfur services segment again exceeded our expectations, driven in large part by strong operating performance and the steady increase in soda ash prices throughout 2022. The global supply and demand balance for soda ash has remained tight as global demand has continued to rise at the same time no new natural production has come on-line and the cost structure of synthetic production has continued to remain elevated throughout the year. This increasingly tight market dynamic provided the framework for steadily increasing soda ash prices throughout 2022. We saw this firsthand with our quarterly contract prices increasing by approximately 40% from the first quarter to the fourth quarter 2022, during the same period that soda ash exports out of China actually increased.

The market dynamic at the end of last year provided a very constructive backdrop for our contract pricing negotiations for our 2023 volumes. We have successfully locked in the price for approximately 85% of our anticipated sales volumes of soda ash and related products in 2023, including our new soda ash volumes from Granger, and our weighted average realized price for the full year is expected to exceed the weighted average realized price we received in 2022 as many customers continue to focus on security of supply versus price. In addition, the re-opening of China after the Chinese New Year and the abandonment of their zero-covid lockdowns in early January should mirror the covid reopenings in the U.S. and EU and should provide some tailwinds for soda ash demand within China, which could reduce exports and thus provide some upward bias for prices in our export markets in the back half of the year, all of which we will be actively monitoring throughout the year.

We safely and responsibly re-started our legacy Granger production facility ahead of schedule and had first soda ash “on the belt” on January 1, 2023. We expect production from the legacy Granger facility to ramp over the first part of the year to its nameplate capacity of 500,000 tons of annual soda ash production. Furthermore, our Granger expansion project remains on schedule for first soda ash “on the belt” sometime in the second half of 2023. Through the end of last year we had spent approximately $275 million on the Granger expansion project and would expect to spend another $75 – $100 million over the remainder of 2023 to complete the project.

The net result of our original Granger facility coming back on-line in January and the Granger expansion starting up in the second half of the year means we would expect to see a net increase in production of around 600,000 – 700,000 tons, for total production capacity of approximately 4.2 million tons in 2023. It is important to note 2023 will not fully reflect the true total average cost structure of Granger as we will be operating a largely fixed cost production facility at roughly 50% of design capacity. However, we expect to exit 2023 at or near the full production rates for Granger and thus would expect an additional net increase in production of approximately 500,000 – 600,000 tons, at relatively minor incremental production cost relative to 2023, for total production capacity of approximately 4.7 – 4.8 million tons in 2024 and beyond. Once fully ramped, we would expect our total average cost per ton at Granger to be one of the lowest cost soda ash production facilities in the world.

Our legacy sulfur services business performed slightly ahead of our expectations during the quarter. We were able to utilize our diverse supply network and storage footprint to mitigate the impacts of our largest host refinery taking an extended maintenance outage during the fourth quarter. As a result, we were able to capture an additional vessel loading beyond our expectations and secure additional sales volumes to our South American copper mining customers during the quarter. The steady demand for our sulfur-based products from our copper customers further reinforces our belief that copper demand will be inelastic to any potential economic slowdown given its importance as a fundamental building block of the global economy and its vital role in the green energy revolution. While we anticipate our sales volumes of sulfur-based products to experience a slight decline in 2023 as a result of the partial conversion of one of our host refineries to a biodiesel processing facility, we continue to expect to be able to comfortably supply the steady demand from our copper mining, as well as pulp and paper customers, which will support steady earnings from our refinery service business for many years ahead.

Our marine transportation segment exceeded our expectations as market supply and demand fundamentals continue to remain very strong. During the fourth quarter, we saw tremendously high utilization rates, at or near 100% of available capacity, for all classes of our vessels as demand for Jones Act tanker tonnage remained extremely robust, driven in large part by the significant reduction in marine vessel construction over the last three years and the necessary retirement of older tonnage. This lack of new supply of marine tonnage, combined with strong refinery utilization rates and increasing demand to move intermediate products and refined products from one location to another, has driven spot day rates and longer term contracted rates in our brown water and blue water fleets to levels approaching those last seen in 2014 and 2015. Similarly, the American Phoenix started its twelve-month charter last month with an investment grade counterparty that will run into January 2024 at a day rate comparable to the original rates it commanded when we first purchased the vessel in 2014. Given the increased cost of steel and long-lead times to build new equipment, and regardless of any slowdown in the broader economy, we believe the supply and demand fundamentals for our marine transportation segment will remain strong for the foreseeable future and certainly over the next two to three years.

Our onshore facilities and transportation segment performed in-line with our expectations. During the quarter we saw steady and stable volumes and demand from our refinery customers in and around our Baton Rouge and Texas City corridors. We continue to expect our onshore facilities and transportation segment will benefit as additional offshore volumes come on-line and make their way to our onshore terminals and pipelines for further delivery to refining and other demand centers along the Gulf Coast.

In 2023, we expect growth capital expenditures to range from approximately $400 – $450 million as we finalize the spending on our Granger soda ash expansion project and progress the construction of the SYNC lateral and CHOPS expansion in the Gulf of Mexico. As we complete the spend on Granger this year and on our offshore expansion projects in mid-to-late 2024, absent any unforeseen events, we would reasonably expect to start generating free cash flow after all estimated fixed charges and growth capital expenditures in late 2024 and continuing thereafter, all while maintaining our leverage ratio, as calculated by our senior secured lenders, at or below 4.0 times.

I am also pleased to announce that we will be releasing our initial ESG report in the coming weeks. This inaugural report highlights our commitment to the principals of ESG. We believe we have a responsibility to conduct our business in a socially, economically and environmentally responsible manner and will endeavor to enhance our disclosures over time.

The management team and board of directors remain steadfast in our commitment to building long-term value for everyone in the capital structure, and we believe the decisions we are making reflect this commitment and our confidence in Genesis moving forward. I would once again like to recognize our entire workforce for their efforts and unwavering commitment to safe and responsible operations. I’m proud to have the opportunity to work alongside each and every one of you.”

(1) Adjusted EBITDA is a non-GAAP financial measure. We are unable to provide a reconciliation of the forward-looking Adjusted EBITDA projections contained in this press release to its most directly comparable GAAP financial measure because the information necessary for quantitative reconciliations of Adjusted EBITDA to its most directly comparable GAAP financial measure is not available to us without unreasonable efforts. The probable significance of providing these forward-looking Adjusted EBITDA measures without directly comparable GAAP financial measures may be materially different from the corresponding GAAP financial measures.

Financial Results

Segment Margin

Variances between the fourth quarter of 2022 (the “2022 Quarter”) and the fourth quarter of 2021 (the “2021 Quarter”) in these components are explained below.

Segment Margin results for the 2022 Quarter and 2021 Quarter were as follows:

 

Three Months Ended December 31,

 

2022

 

2021

 

(in thousands)

Offshore pipeline transportation

$

82,087

 

$

74,140

Sodium minerals and sulfur services

 

87,575

 

 

45,210

Onshore facilities and transportation

 

6,259

 

 

26,312

Marine transportation

 

21,220

 

 

9,972

Total Segment Margin

$

197,141

 

$

155,634

Offshore pipeline transportation Segment Margin for the 2022 Quarter increased $7.9 million, or 11%, from the 2021 Quarter primarily as a result of first oil achievement during the second quarter of 2022 from the King’s Quay floating production system (“FPS”) and the Spruance development (which all volumes are fully dedicated to our 64% owned Poseidon pipeline), which both successfully ramped up to their expected capacities in the 2022 Quarter. The King’s Quay FPS supports production from the Khaleesi, Mormont and Samurai field developments and 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 or our 25.67% owned Nautilus natural gas system for ultimate delivery to shore. During the 2022 Quarter, production volumes at King’s Quay reached in excess of 100,000 barrels of oil equivalent per day. In addition to this, we have contractual minimum volume commitments that began in 2022 associated with the Argos FPS (which supports the Mad Dog 2 development) that are included in our reported Segment Margin during the 2022 Quarter. Argos is anticipated to have first oil in the middle of 2023. These increases were partially offset by approximately $10 million as a result of certain unplanned producer downtime at numerous fields connected to our pipeline infrastructure in the 2022 Quarter, which returned to normal operations by the end of the year, and the effects to reported Segment Margin from our decrease in ownership of CHOPS, as we sold a 36% minority interest on November 17, 2021.

Sodium minerals and sulfur services Segment Margin for the 2022 Quarter increased $42.4 million, or 94%, from the 2021 Quarter primarily due to higher export and domestic pricing and higher sales volumes in our Alkali Business as well as increased volumes and pricing in our refinery services business. 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 use of soda ash in the production of everyday end use products along with increased demand for products associated with the energy transition, including solar panels, and the use of soda ash in the production of lithium carbonate and lithium hydroxide, which are some of the building blocks of lithium batteries. This continued demand improvement, combined with flat or even slightly declining supply of soda ash in the near term, has continued to tighten the overall supply and demand balance and created a higher price environment for our tons and increased contribution to Segment Margin during the 2022 Quarter. We have contractually agreed on the pricing for approximately 85% of our anticipated sales volumes of soda ash and related products for 2023, and as a result, we expect that our weighted average realized price for 2023 will exceed the weighted average realized price we received in 2022. Additionally, we successfully re-started our original Granger production facility on January 1, 2023 and are still on schedule to complete our Granger Optimization Project in the second half of 2023, which represents an incremental 750,000 tons of annual production capacity that we anticipate to ultimately ramp up to. In our refinery services business, we saw a decrease in production volumes as a result of an extended maintenance outage at our largest host refinery that was successfully completed in the 2022 Quarter. In advance of this scheduled downtime, we proactively increased our inventory levels of our sulfur based products to ensure we had adequate volumes to fulfill all of our contracted sales volumes during the 2022 Quarter, and ultimately saw an increase in sales volumes in the 2022 Quarter relative to the 2021 Quarter as a result of an increase in demand from our mining customers, primarily in South America.

Onshore facilities and transportation Segment Margin for the 2022 Quarter decreased $20.1 million, or 76%, from the 2021 Quarter. This decrease is primarily due to the 2021 Quarter including cash receipts of $17.5 million for the last principal payment associated with our previously owned NEJD pipeline and lower volumes transported on our Louisiana pipelines during the 2022 Quarter. These decreases were partially offset by increased volumes on our Texas pipeline as it is a key destination point for various grades of crude oil produced in the Gulf of Mexico including those transported on our 64% owned CHOPS pipeline.

Marine transportation Segment Margin for the 2022 Quarter increased $11.2 million, or 113%, from the 2021 Quarter. This increase is primarily attributable to higher utilization and day rates in our inland and offshore business during the 2022 Quarter. We have continued to see an increase in demand and utilization of our vessels due to increased refinery utilization and the increased need for movements from the Gulf Coast to the East Coast for certain products. In addition, the M/T American Phoenix operated at a higher day rate during the 2022 Quarter relative to the 2021 Quarter and is currently under contract for all of 2023 with an investment grade customer at a day rate comparable to the original rates it commanded when we first purchased the vessel in 2014.

Other Components of Net Income (Loss)

We reported Net Income Attributable to Genesis Energy, L.P. of $42.0 million in the 2022 Quarter compared to Net Loss Attributable to Genesis Energy, L.P. of $68.3 million in the 2021 Quarter.

In addition to the overall increase to Segment Margin of $41.5 million discussed above, Net Income Attributable to Genesis Energy, L.P. in the 2022 Quarter was impacted by: (i) a decrease in depreciation, depletion, and amortization expense of $29.7 million in the 2022 Quarter primarily related to the acceleration of depreciation on certain of our asset retirement obligation assets recognized during the 2021 Quarter as a result of updates to the estimated timing and costs associated with certain of our non-core offshore natural gas assets; (ii) an increase in unrealized (non-cash) gains primarily from natural gas commodity derivatives of $21.8 million in the 2022 Quarter; (iii) a decrease in general and administrative expenses of $8.5 million primarily related to transaction costs incurred during the 2021 Quarter associated with the sale of a 36% minority interest in CHOPS; and (iv) the redemption of the Alkali Holdings preferred units during 2022 that resulted in no net income attributable to redeemable noncontrolling interest in the 2022 Quarter compared to net income attributable to redeemable noncontrolling interest of $7.8 million in the 2021 quarter.

Earnings Conference Call

We will broadcast our Earnings Conference Call on Thursday, February 22, 2023, at 8:00 a.m. Central time (9:00 a.m. Eastern time). This call can be accessed at www.genesisenergy.com. Choose the Investor Relations button. For those unable to attend the live broadcast, a replay will be available beginning approximately one hour after the event and remain available on our website for 30 days. There is no charge to access the event.

Genesis Energy, L.P. is a diversified midstream energy master limited partnership headquartered in Houston, Texas. Genesis’ operations include offshore pipeline transportation, sodium minerals and sulfur services, onshore facilities and transportation and marine transportation. Genesis’ operations are primarily located in Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida, Wyoming and the Gulf of Mexico.

GENESIS ENERGY, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED

 

(in thousands, except unit amounts)

 

 

Three Months Ended

December 31,

 

Year Ended

December 31,

 

2022

 

2021

 

2022

 

2021

REVENUES

$

714,037

 

 

$

581,581

 

 

$

2,788,957

 

 

$

2,125,476

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES:

 

 

 

 

 

 

 

Costs of sales and operating expenses

 

529,523

 

 

 

462,925

 

 

 

2,151,142

 

 

 

1,678,849

 

General and administrative expenses

 

13,773

 

 

 

22,241

 

 

 

66,598

 

 

 

61,185

 

Depreciation, depletion and amortization

 

79,080

 

 

 

108,771

 

 

 

296,205

 

 

 

309,746

 

Gain on sale of asset

 

—

 

 

 

—

 

 

 

(40,000

)

 

 

—

 

OPERATING INCOME (LOSS)

 

91,661

 

 

 

(12,356

)

 

 

315,012

 

 

 

75,696

 

Equity in earnings of equity investees

 

13,954

 

 

 

12,715

 

 

 

54,206

 

 

 

57,898

 

Interest expense

 

(57,383

)

 

 

(56,786

)

 

 

(226,156

)

 

 

(233,724

)

Other expense

 

—

 

 

 

(2,063

)

 

 

(10,758

)

 

 

(36,232

)

INCOME (LOSS) BEFORE INCOME TAXES

 

48,232

 

 

 

(58,490

)

 

 

132,304

 

 

 

(136,362

)

Income tax expense

 

(1,634

)

 

 

(500

)

 

 

(3,169

)

 

 

(1,670

)

NET INCOME (LOSS)

 

46,598

 

 

 

(58,990

)

 

 

129,135

 

 

 

(138,032

)

Net income attributable to noncontrolling interests

 

(4,623

)

 

 

(1,513

)

 

 

(23,235

)

 

 

(1,637

)

Net income attributable to redeemable noncontrolling interests

 

—

 

 

 

(7,759

)

 

 

(30,443

)

 

 

(25,398

)

NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.

$

41,975

 

 

$

(68,262

)

 

$

75,457

 

 

$

(165,067

)

Less: Accumulated distributions attributable to Class A Convertible Preferred Units

 

(24,000

)

 

 

(18,684

)

 

 

(80,052

)

 

 

(74,736

)

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNITHOLDERS

$

17,975

 

 

$

(86,946

)

 

$

(4,595

)

 

$

(239,803

)

NET INCOME (LOSS) PER COMMON UNIT:

 

 

 

 

 

 

 

Basic and Diluted

$

0.15

 

 

$

(0.71

)

 

$

(0.04

)

 

$

(1.96

)

WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:

 

 

 

 

 

 

 

Basic and Diluted

 

122,579,218

 

 

 

122,579,218

 

 

 

122,579,218

 

 

 

122,579,218

 

GENESIS ENERGY, L.P.

OPERATING DATA - UNAUDITED

   

 

Three Months Ended December 31,

 

Year Ended December 31,

 

2022

 

2021

 

2022

 

2021

Offshore Pipeline Transportation Segment

 

 

 

 

 

 

 

Crude oil pipelines (average barrels/day unless otherwise noted):

 

 

 

 

 

 

 

CHOPS(1)

233,541

 

 

224,982

 

 

207,008

 

 

189,904

 

Poseidon(1)

243,265

 

 

240,995

 

 

257,444

 

 

263,169

 

Odyssey(1)

53,589

 

 

99,375

 

 

84,682

 

 

114,128

 

GOPL

6,717

 

 

8,702

 

 

6,964

 

 

7,826

 

Offshore crude oil pipelines total

537,112

 

 

574,054

 

 

556,098

 

 

575,027

 

 

 

 

 

 

 

 

 

Natural gas transportation volumes (MMBtus/day)(1)

357,441

 

 

393,234

 

 

343,347

 

 

345,870

 

 

 

 

 

 

 

 

 

Sodium Minerals and Sulfur Services Segment

 

 

 

 

 

 

 

NaHS (dry short tons sold)

31,608

 

 

29,565

 

 

128,851

 

 

114,292

 

Soda Ash volumes (short tons sold)

803,281

 

 

772,704

 

 

3,096,494

 

 

2,994,507

 

NaOH (caustic soda) volumes (dry short tons sold)(2)

24,893

 

 

20,436

 

 

90,876

 

 

84,278

 

 

 

 

 

 

 

 

 

Onshore Facilities and Transportation Segment

 

 

 

 

 

 

 

Crude oil pipelines (barrels/day):

 

 

 

 

 

 

 

Texas(3)

84,787

 

 

81,812

 

 

90,562

 

 

65,918

 

Jay

7,352

 

 

7,374

 

 

6,601

 

 

7,941

 

Mississippi

5,131

 

 

5,310

 

 

5,725

 

 

5,206

 

Louisiana(4)

68,255

 

 

86,552

 

 

94,389

 

 

99,927

 

Onshore crude oil pipelines total

165,525

 

 

181,048

 

 

197,277

 

 

178,992

 

 

 

 

 

 

 

 

 

Crude oil and petroleum products sales (barrels/day)

26,969

 

 

24,082

 

 

24,643

 

 

24,239

 

 

 

 

 

 

 

 

 

Rail unload volumes (barrels/day)

—

 

 

847

 

 

10,834

 

 

11,782

 

 

 

 

 

 

 

 

 

Marine Transportation Segment

 

 

 

 

 

 

 

Inland Fleet Utilization Percentage(5)

100.0

%

 

94.7

%

 

98.6

%

 

81.9

%

Offshore Fleet Utilization Percentage(5)

99.0

%

 

97.8

%

 

96.9

%

 

95.9

%

(1)

On November 17, 2021, we sold a 36% minority interest in our CHOPS pipeline. As of December 31, 2022 and 2021, we owned 64% of CHOPS, 64% of Poseidon and 29% of Odyssey, as well as equity interests in various other entities. Volumes are presented above on a 100% basis for all periods.

(2)

Caustic soda sales volumes include volumes sold from our alkali and refinery services businesses.

(3)

Our Texas pipeline and infrastructure is a destination point for many pipeline systems in the Gulf of Mexico, including the CHOPS pipeline.

(4)

Total daily volumes for the years ended December 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 our Port of Baton Rouge Terminal pipelines. Total daily volumes for the 2022 Quarter and 2021 Quarter include 33,948 and 28,030 Bbls/day, respectively, of intermediate refined products and 27,604 and 56,058 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines.

(5)

Utilization rates are based on a 365-day year, as adjusted for planned downtime and dry-docking.

GENESIS ENERGY, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

(in thousands, except units)

 

 

December 31, 2022

 

December 31, 2021

ASSETS

 

 

 

Cash, cash equivalents and restricted cash

$

26,567

 

$

24,992

 

Accounts receivable - trade, net

 

721,567

 

 

400,334

 

Inventories

 

78,143

 

 

77,958

 

Other current assets

 

26,770

 

 

39,200

 

Total current assets

 

853,047

 

 

542,484

 

Fixed assets and mineral leaseholds, net of accumulated depreciation and depletion

 

4,641,695

 

 

4,461,190

 

Equity investees

 

284,486

 

 

294,050

 

Intangible assets, net of amortization

 

127,320

 

 

127,063

 

Goodwill

 

301,959

 

 

301,959

 

Right of use assets, net

 

125,277

 

 

140,796

 

Other assets, net of amortization

 

32,208

 

 

38,259

 

Total assets

$

6,365,992

 

$

5,905,801

 

LIABILITIES AND CAPITAL

 

 

 

Accounts payable - trade

$

427,961

 

$

264,316

 

Accrued liabilities

 

281,146

 

 

232,623

 

Total current liabilities

 

709,107

 

 

496,939

 

Senior secured credit facility

 

205,400

 

 

49,000

 

Senior unsecured notes, net of debt issuance costs and premium

 

2,856,312

 

 

2,930,505

 

Alkali senior secured notes, net of debt issuance costs and discount

 

402,442

 

 

—

 

Deferred tax liabilities

 

16,652

 

 

14,297

 

Other long-term liabilities

 

400,617

 

 

434,925

 

Total liabilities

 

4,590,530

 

 

3,925,666

 

Mezzanine capital:

 

 

 

Class A Convertible Preferred Units

 

891,909

 

 

790,115

 

Redeemable noncontrolling interests

 

—

 

 

259,568

 

 

 

 

 

Partners’ capital:

 

 

 

Common unitholders

 

567,277

 

 

641,313

 

Accumulated other comprehensive income (loss)

 

6,114

 

 

(5,607

)

Noncontrolling interests

 

310,162

 

 

294,746

 

Total partners’ capital

 

883,553

 

 

930,452

 

Total liabilities, mezzanine capital and partners’ capital

$

6,365,992

 

$

5,905,801

 

 

 

 

 

Common Units Data:

 

 

 

Total common units outstanding

 

122,579,218

 

 

122,579,218

 

GENESIS ENERGY, L.P.

RECONCILIATION OF NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P. TO SEGMENT MARGIN - UNAUDITED

 

(in thousands)

 

 

Three Months Ended December 31,

 

2022

 

2021

Net income (loss) attributable to Genesis Energy, L.P.

$

41,975

 

 

$

(68,262

)

Corporate general and administrative expenses

 

16,862

 

 

 

22,898

 

Depreciation, depletion, amortization and accretion

 

81,993

 

 

 

107,550

 

Interest expense

 

57,383

 

 

 

56,786

 

Income tax expense

 

1,634

 

 

 

500

 

Change in provision for leased items no longer in use

 

(72

)

 

 

—

 

Redeemable noncontrolling interest redemption value adjustments(1)

 

—

 

 

 

7,759

 

Plus (minus) Select Items, net(2)

 

(2,634

)

 

 

28,403

 

Segment Margin(3)

$

197,141

 

 

$

155,634

 

(1)

The 2021 Quarter includes PIK distributions and accretion on the redemption feature. The associated Alkali Holdings preferred units were fully redeemed during the second quarter of 2022.

(2)

Refer to additional detail of Select Items later in this press release.

(3)

See definition of Segment Margin later in this press release.

GENESIS ENERGY, L.P.

RECONCILIATIONS OF NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY L.P. TO ADJUSTED EBITDA AND AVAILABLE CASH BEFORE RESERVES - UNAUDITED

 

(in thousands)

 

 

Three Months Ended December 31,

 

Year Ended December 31,

 

2022

 

2021

 

2022

 

2021

Net income (loss) attributable to Genesis Energy, L.P.

$

41,975

 

 

$

(68,262

)

 

$

75,457

 

 

$

(165,067

)

Interest expense

 

57,383

 

 

 

56,786

 

 

 

226,156

 

 

 

233,724

 

Income tax expense

 

1,634

 

 

 

500

 

 

 

3,169

 

 

 

1,670

 

Gain on sale of asset, net to our ownership interest

 

—

 

 

 

—

 

 

 

(32,000

)

 

 

—

 

Depreciation, depletion, amortization and accretion

 

81,993

 

 

 

107,550

 

 

 

307,519

 

 

 

315,896

 

EBITDA

 

182,985

 

 

 

96,574

 

 

 

580,301

 

 

 

386,223

 

Redeemable noncontrolling interest redemption value adjustments(1)

 

—

 

 

 

7,759

 

 

 

30,443

 

 

 

25,398

 

Plus (minus) Select Items, net(2)

 

(2,818

)

 

 

36,323

 

 

 

106,327

 

 

 

154,567

 

Adjusted EBITDA(3)

 

180,167

 

 

 

140,656

 

 

 

717,071

 

 

 

566,188

 

Maintenance capital utilized(4)

 

(15,350

)

 

 

(13,500

)

 

 

(57,400

)

 

 

(53,150

)

Interest expense

 

(57,383

)

 

 

(56,786

)

 

 

(226,156

)

 

 

(233,724

)

Cash tax expense

 

(290

)

 

 

(150

)

 

 

(815

)

 

 

(690

)

Distributions to preferred unitholders(5)

 

(24,000

)

 

 

(18,684

)

 

 

(80,052

)

 

 

(74,736

)

Available Cash before Reserves(6)

$

83,144

 

 

$

51,536

 

 

$

352,648

 

 

$

203,888

 

(1)

The year ended December 31, 2022 includes PIK distributions and accretion on the redemption feature, and valuation adjustments to the redemption feature. The three and twelve months ended December 31, 2021 includes PIK distributions and accretion on the redemption feature. The associated Alkali Holdings preferred units were fully redeemed during the second quarter of 2022.

(2)

Refer to additional detail of Select Items later in this press release.

(3)

See definition of Adjusted EBITDA later in this press release.

(4)

Maintenance capital expenditures in the 2022 Quarter and 2021 Quarter were $42.0 million and $26.8 million, respectively. Maintenance capital expenditures for the years ended December 31, 2022 and 2021 were $132.5 million and $99.9 million, respectively. Our maintenance capital expenditures are principally associated with our alkali and marine transportation businesses.

(5)

Distributions to preferred unitholders attributable to the 2022 Quarter were paid on February 14, 2023 to unitholders of record at close of business on January 31, 2023.

(6)

Represents the Available Cash before Reserves to common unitholders.

GENESIS ENERGY, L.P.

RECONCILIATION OF NET CASH FLOWS FROM OPERATING ACTIVITIES TO ADJUSTED EBITDA - UNAUDITED

 

(in thousands)

 

 

Three Months Ended December 31,

 

Year Ended December 31,

 

2022

 

2021

 

2022

 

2021

Cash Flows from Operating Activities

$

81,800

 

 

$

95,594

 

 

$

334,395

 

 

$

337,951

 

Adjustments to reconcile net cash flows from operating activities to Adjusted EBITDA:

 

 

 

 

 

 

 

Interest Expense

 

57,383

 

 

 

56,786

 

 

 

226,156

 

 

 

233,724

 

Amortization and write-off of debt issuance costs, discount and premium

 

(2,161

)

 

 

(4,474

)

 

 

(9,271

)

 

 

(13,716

)

Effects of available cash from equity method investees not included in operating cash flows

 

5,097

 

 

 

2,900

 

 

 

19,834

 

 

 

27,026

 

Net effect of changes in components of operating assets and liabilities

 

39,242

 

 

 

(23,587

)

 

 

87,818

 

 

 

(30,044

)

Non-cash effect of long-term incentive compensation plans

 

(6,975

)

 

 

(3,672

)

 

 

(17,810

)

 

 

(8,783

)

Expenses related to business development activities and growth projects

 

458

 

 

 

7,308

 

 

 

7,339

 

 

 

8,946

 

Differences in timing of cash receipts for certain contractual arrangements(1)

 

12,620

 

 

 

8,080

 

 

 

51,102

 

 

 

15,482

 

Distributions from unrestricted subsidiaries not included in operating cash flows(2)

 

—

 

 

 

—

 

 

 

32,000

 

 

 

—

 

Other items, net

 

(7,297

)

 

 

1,721

 

 

 

(14,492

)

 

 

(4,398

)

Adjusted EBITDA(3)

$

180,167

 

 

$

140,656

 

 

$

717,071

 

 

$

566,188

 

(1)

Includes the difference in timing of cash receipts from or billings to 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)

On April 29, 2022, we sold our Independence Hub platform for $40.0 million, of which $32.0 million is attributable to our 80% ownership interest and included in our Adjusted EBITDA.

(3)

See definition of Adjusted EBITDA later in this press release.

 

GENESIS ENERGY, L.P.

ADJUSTED DEBT-TO-ADJUSTED CONSOLIDATED EBITDA RATIO - UNAUDITED

(in thousands)

 

 

 

December 31, 2022

Senior secured credit facility

 

$

205,400

 

Senior unsecured notes, net of debt issuance costs and premium

 

 

2,856,312

 

Less: Outstanding inventory financing sublimit borrowings

 

 

(4,700

)

Less: Cash and cash equivalents

 

 

(7,821

)

Adjusted Debt(1)

 

$

3,049,191

 

 

 

 

 

 

Pro Forma LTM

 

 

December 31, 2022

Consolidated EBITDA (per our senior secured credit facility)

 

$

693,692

 

Consolidated EBITDA adjustments(2)

 

 

42,593

 

Adjusted Consolidated EBITDA (per our senior secured credit facility)(3)

 

$

736,285

 

 

 

 

Adjusted Debt-to-Adjusted Consolidated EBITDA

 

4.14X

(1)

We define Adjusted Debt as the amounts outstanding under our senior secured credit facility and senior unsecured notes (including any unamortized premiums or issuance costs) less the amount outstanding under our inventory financing sublimit, and less cash and cash equivalents on hand at the end of the period from our restricted subsidiaries.

(2)

This amount reflects adjustments we are permitted to make under our senior secured credit facility for purposes of calculating compliance with our leverage ratio. It includes a pro rata portion of projected future annual EBITDA associated with material organic growth projects, which is calculated based on the percentage of capital expenditures incurred to date relative to the expected budget multiplied by the total annual contractual minimum cash commitments we expect to receive as a result of the project. Additionally, it includes the pro forma adjustments to Adjusted Consolidated EBITDA (using historical amounts in the test period) associated with the May 17, 2022 issuance of our Alkali senior secured notes, which are secured by a fifty-year 10% limited term overriding royalty interest in substantially all of our trona mineral leases. These adjustments may not be indicative of future results.

(3)

Adjusted Consolidated EBITDA for the four-quarter period ending with the most recent quarter, as calculated under our senior secured credit facility.

This press release includes forward-looking statements as defined under federal law. Although we believe that our expectations are based upon reasonable assumptions, we can give no assurance that our goals will be achieved. Actual results may vary materially. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that we expect, believe or anticipate will or may occur in the future, including but not limited to statements relating to future financial and operating results and compliance with our senior secured credit facility covenants, the timing and anticipated benefits of the King’s Quay, Argos, Shenandoah and Salamanca developments, our expectations regarding our Granger expansion, the expected performance of our other projects and business segments, and our strategy and plans, are forward-looking statements, and historical performance is not necessarily indicative of future performance. Those forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside our control, that could cause results to differ materially from those expected by management. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for products (which may be affected by the actions of OPEC and other oil exporting nations), impacts due to inflation, and a reduction in demand for our services resulting in impairments of our assets, the spread of disease (including Covid-19), the impact of international military conflicts (such as the conflict in Ukraine),the result of any economic recession or depression that has occurred or may occur in the future, construction and anticipated benefits of the SYNC pipeline and expansion of the capacity of the CHOPS system, the timing and success of business development efforts and other uncertainties. Those and other applicable uncertainties, factors and risks that may affect those forward-looking statements are described more fully in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Securities and Exchange Commission and other filings, including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q. We undertake no obligation to publicly update or revise any forward-looking statement.

NON-GAAP MEASURES

This press release and the accompanying schedules include non-generally accepted accounting principle (non-GAAP) financial measures of Adjusted EBITDA and total Available Cash before Reserves. In this press release, 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). 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, Adjusted EBITDA and total Segment Margin measures are just three 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.

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

(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 Adjusted EBITDA 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.

Disclosure Format Relating to Maintenance Capital

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 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

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 since December 31, 2013.

ADJUSTED EBITDA

Purposes, Uses and Definition

Adjusted EBITDA 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 without regard to financing methods, capital structures or historical cost basis;

(2)

our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure;

(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

(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 Adjusted EBITDA (“Adjusted EBITDA”) 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”). 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.

The table below includes the Select Items discussed above as applicable to the reconciliation of Net income (loss) attributable to Genesis Energy, L.P. to Adjusted EBITDA and Available Cash before Reserves:

 

 

Three Months Ended December 31,

 

Year Ended December 31,

 

 

2022

 

2021

 

2022

 

2021

 

 

(in thousands)

I.

Applicable to all Non-GAAP Measures

 

 

 

 

 

 

 

 

Differences in timing of cash receipts for certain contractual arrangements(1)

$

12,620

 

 

$

8,080

 

 

$

51,102

 

 

$

15,482

 

Distributions from unrestricted subsidiaries not included in income(2)

 

—

 

 

 

17,500

 

 

 

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)

 

(21,800

)

 

 

(29

)

 

 

(5,717

)

 

 

30,700

 

Loss on debt extinguishment

 

—

 

 

 

—

 

 

 

794

 

 

 

1,627

 

Adjustment regarding equity investees(4)

 

5,218

 

 

 

2,517

 

 

 

21,199

 

 

 

26,207

 

Other

 

1,328

 

 

 

335

 

 

 

(2,598

)

 

 

207

 

Sub-total Select Items, net(5)

 

(2,634

)

 

 

28,403

 

 

 

96,780

 

 

 

144,223

II.

Applicable only to Adjusted EBITDA and Available Cash before Reserves

 

 

 

 

 

 

 

 

Certain transaction costs

 

458

 

 

 

7,308

 

 

 

7,339

 

 

 

8,946

 

Other

 

(642

)

 

 

612

 

 

 

2,208

 

 

 

1,398

 

Total Select Items, net(6)

$

(2,818

)

 

$

36,323

 

 

$

106,327

 

 

$

154,567

(1)

Includes the difference in timing of cash receipts from or billings to 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)

The year ended December 31, 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 senior secured credit facility), Independence Hub, LLC. The 2021 Quarter and year ended December 31, 2021 includes $17.5 million and $70.0 million, respectively, in cash receipts associated with principal repayments on our previously owned NEJD pipeline not included in income. We received the last principal payment associated with our previously owned NEJD pipeline in the fourth quarter of 2021. Genesis NEJD Pipeline, LLC is defined as an unrestricted subsidiary under our senior secured credit facility.

(3)

The 2022 Quarter includes an unrealized gain of $21.8 million from the valuation of our commodity derivative transactions (excluding fair value hedges). The year ended December 31, 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 $24.2 million from the valuation of our commodity derivatives transactions (excluding fair value hedges). The year ended December 31, 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)

Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.

(5)

Represents all Select Items applicable to Segment Margin and Available Cash before Reserves.

(6)

Represents Select Items applicable to Adjusted EBITDA and Available Cash before Reserves.

SEGMENT MARGIN

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. We define Segment Margin (“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. 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.

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Genesis Energy, L.P. Dwayne Morley VP - Investor Relations (713) 860-2536