Genesis Energy, L.P. Reports First Quarter 2023 Results

HOUSTON--(BUSINESS WIRE)-- Genesis Energy, L.P. (NYSE: GEL) today announced its first quarter results.

We generated the following financial results for the first quarter of 2023:

• Net Loss Attributable to Genesis Energy, L.P. of $1.6 million for the first quarter of 2023 compared to Net Loss Attributable to Genesis Energy, L.P. of $5.3 million for the same period in 2022.
• Cash Flows from Operating Activities of $97.7 million for the first quarter of 2023 compared to $54.2 million for the same period in 2022.
• 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 $77.7 million for the first quarter of 2023, which provided 4.22X coverage for the quarterly distribution of $0.15 per common unit attributable to the first quarter.
• Total Segment Margin of $195.1 million for the first quarter of 2023.
• Adjusted EBITDA of $179.1 million for the first quarter of 2023.
• Adjusted Consolidated EBITDA of $775.0 million for the trailing twelve months ended March 31, 2023 and a bank leverage ratio of 3.99X, both calculated in accordance with our senior secured credit agreement and discussed further in this release.

Grant Sims, CEO of Genesis Energy, said, “While our financial results for the quarter were generally in-line and consistent with our annual guidance, they did end up below our internal expectations for reasons well beyond our control. During the first quarter, our soda ash business was negatively impacted by the coldest first calendar quarter in the last 23 years in southwest Wyoming. While the severe weather somewhat challenged our mining and processing operations, the primary reason for production and sales volumes coming in below internal goals was the lack of adequate and consistent rail service to move volumes from our Westvaco and Granger soda ash facilities to markets. Given the inadequate rail service and our limited on-site storage, we had no option other than to curtail production when loaded trains were not getting pulled out and/or empty trains were not returning to our facility on a ratable schedule. We estimate these lost volumes, which cannot practically be made up in subsequent periods, resulted in a reduction in realized Segment Margin and Adjusted EBITDA of approximately $15 million for the first quarter and fiscal year.

These weather and third-party service-related headwinds unfortunately masked the over-performance of our other businesses relative to internal expectations in the quarter. In any event, we continued to show improvement in our leverage ratio, as calculated by our senior secured lenders, ending the quarter at 3.99 times. We have achieved our long-term leverage target and the results show that the actions we have taken over the last several years, along with the underlying resilience of our market leading businesses, has positioned us with ample liquidity and financial flexibility going forward. Additionally, even with the non-recurring negatives in the first quarter, we are today reaffirming our previously announced guidance range for Adjusted EBITDA of $780 - $810¹ million for the full year. Even at the low end of that range, we expect to exit the year with a leverage ratio, as calculated by our banks, below 4 times, and this is after some $400 - $450 million of growth capital to be expended this year related to the expansions of our world-class midstream infrastructure in the Gulf of Mexico and our world-class soda ash operations in Wyoming.

We continue to see tremendous oil and gas producer activity in the central Gulf of Mexico around our existing, and soon to be expanded, midstream footprint. We can confirm that, in mid-April, we started receiving volumes from the Argos production facility, which supports the development of the Mad Dog 2 field by BP, as operator, along with Chevron and Woodside Petroleum. The soda ash market appears to be moving from an extremely tight to a more balanced market, as some of our distributors, as well as some of our direct customers, are telling us they are seeing some slowdown in demand, both domestically as well as internationally. Having said that, we do not believe we were alone in missing production targets in the first quarter as a result of inadequate rail service, meaning the worldwide market will have at least 300,000 tons, in our estimation, of less supply from all producers in Wyoming to be absorbed in future periods. Our marine transportation assets continue to run at an effective 100% utilization rate, and we are seeing both spot and term contracts rates exceeding those we realized in 2014 and 2015. We continue to believe that the clear line of sight on significantly increasing volumes in both the offshore and soda segments over the next two to three years, provides a future path to increasing amounts of free cash flow, increasing financial flexibility to simplify the capital structure and increasing opportunities to continue to build long-term value for all our stakeholders in the coming years.

With that, I would like to discuss our individual business segments in more detail.

Our offshore pipeline transportation segment performed in-line with, if not slightly ahead of, our internal expectations and importantly demonstrated a more normalized level of activity when compared to the fourth quarter. While we do expect some regularly scheduled maintenance and downtime at one of our major host fields in the second quarter, there is no doubt the results in the first quarter were more representative of our industry leading footprint in the central Gulf of Mexico. As I mentioned earlier, we started to receive first oil from BP’s operated Argos floating production facility in mid-April, which is supporting the 14 wells pre-drilled and completed at BP’s operated Mad Dog 2 field in the Green Canyon area of the Gulf of Mexico. Based on BP’s public disclosures we expect volumes from Argos to ramp over the remainder of 2023 with 100% of the volumes flowing through our 64% owned and operated CHOPS pipeline for ultimate delivery to shore.

As we look out over the remainder of the year, we continue to be excited about our industry leading footprint in the central Gulf of Mexico. Volumes from King’s Quay, Spruance and Argos, combined with the continued in-field development drilling and other sub-sea tiebacks to existing production facilities connected to our critical infrastructure, will provide a bridge to the next wave of incremental volumes on our pipelines which includes the approximately 160,000 barrels of oil per day of production handling capacity we expect on-line in late 2024 and early 2025 from our contracted developments, Shenandoah and Salamanca. The corresponding CHOPS expansion and new SYNC lateral remain on schedule to be completed by mid-to-late 2024 in advance of first production. The combination of the steady base of production from existing fields, ramping volumes from new facilities and the large-scale contracted projects that will come on-line in 2024 and 2025 demonstrate the stability, longevity and future potential of the deepwater areas of the central Gulf of Mexico.

In addition to these identified projects that are destined for our pipelines, we were pleased to see that the Bureau of Ocean Energy Management, or BOEM, held a successful lease sale on March 29, 2023. The results of this most recent lease sale would indicate there is still a tremendous amount of interest in the geographies of the Gulf of Mexico where our existing pipeline infrastructure seems to be the most competitive alternative to get new production to shore. This is yet another tangible data point that reinforces the competitive advantages of the Gulf of Mexico versus traditional onshore shale basins and highlights its ability to regenerate itself and support long-term, stable and growing cash flows for decades and decades to come.

As I mentioned earlier, our soda ash business performed below our expectations during the quarter, primarily due to reasons outside of our control, including weather and rail service. The combination of these challenges led to a reduction in soda ash production volumes, lower fixed cost absorption and ultimately lower segment margin for the first quarter. I’m confident in saying had the railroad been able to provide us with adequate rail service we would have been able to normalize our production volumes and capture the margin we lost during the quarter. While the railroad serving us is undergoing some senior management changes and has recently committed to improving their service to Green River, we believe it will still take some time to allow their network to recover from these service disruptions, and we could potentially see some impacts to our production and sales volumes in the second quarter. That being said, we remain confident the railroad has a plan to provide us, and our three neighbors in Wyoming, with the required level of service to support our growing soda ash operations in the years ahead.

It is important to note that we believe all the producers in the Green River basin were impacted by the inadequate rail service in the first quarter. These supply disruptions are expected to show up in the market in the back half of the year and could impact market dynamics and purchasing behavior at the same time supporting prices in a well-balanced global market for the remainder of the year. Despite the demand headwinds we are hearing from our customers, we did in fact see prices for our uncontracted export volumes in the second quarter increase above first quarter pricing. As a result we have now contractually agreed on the pricing for approximately 90% of our anticipated sales volumes of soda ash and related products in 2023. Despite continuing to forecast some uncertainty in pricing for our uncontracted volumes in the back half of the year, we continue to expect our weighted average realized price for the full year to exceed the weighted average realized price we received in 2022.

As we mentioned last quarter, we safely and responsibly re-started our legacy Granger production facility on January 1, 2023. Production from the legacy Granger facility continues to ramp towards its nameplate capacity of 500,000 tons of annual soda ash production and the Granger expansion project remains on schedule for first soda ash “on the belt” sometime in the second half of 2023. Once fully on-line in 2024, we will have approximately 4.7 – 4.8 million tons of soda ash production capacity and would expect the cost structure of our expanded Granger facility to be more in-line with the lowest cost soda ash production facilities in the world, including our Westvaco facility, and solidify our position as one of the largest and lowest cost suppliers of soda ash to the world.

Our marine transportation segment once again exceeded our expectations as market supply and demand fundamentals remain steady. During the quarter we again saw utilization rates at or near 100% of available capacity for all classes of our vessels as demand for Jones Act tanker tonnage remains extremely robust, driven in large part by effectively zero construction of our types of marine vessels over the last few years and the continued retirement of older tonnage. This lack of new supply of marine tonnage, combined with reasonably robust refinery utilization rates and the increasing demand to move renewable diesel on the West Coast, has effectively reduced the practical supply of marine equipment to the Gulf Coast, Mississippi River and East Coast, and has driven spot day rates and longer-term contracted rates in both of our fleets to their highest levels in the last decade. Furthermore, given the increased cost of steel and long-lead times to build new equipment, which in some cases is up to 3 – 4 years for the larger equipment, we believe these supply and demand fundamentals will remain strong for the foreseeable future and certainly over the next few years, regardless of any slowdown in the broader economy.

Turning now to our balance sheet. Our capital expenditures were lighter than we had originally expected in the first quarter due to weather challenges in Wyoming and the scheduling of certain construction activities offshore. Given this adjustment in the timing of our capital dollars over the remainder of the year it would also be reasonable to expect to see our quarterly leverage ratio, as calculated by our senior secured lenders, to fluctuate in the second quarter and third quarter to slightly higher than what we reported today merely due to the timing differences of our expenditures. Regardless of these fluctuations, and based on our current expectations for the remainder of the year, we continue to expect to exit 2023 with a leverage ratio, as calculated by our senior secured lenders, below 4.0 times.

Last quarter we also mentioned that, subject to maintaining ample liquidity and financial flexibility to complete the remaining spend on our announced growth projects, we would look at opportunistic ways to eliminate high-cost capital and/or return capital to our stakeholders in one form or another, all while maintaining a focus on our long-term leverage ratio. I am happy to report that in April we opportunistically repurchased $25 million worth of our corporate Series A convertible preferred securities at a discount to the current call premium. This transaction was accretive to the partnership and importantly will help lower our cost of capital moving forward.

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 first quarter of 2023 (the “2023 Quarter”) and the first quarter of 2022 (the “2022 Quarter”) in these components are explained below.

Segment Margin results for the 2023 Quarter and 2022 Quarter were as follows:

	Three Months Ended March 31,
		2023			2022
	(in thousands)
Offshore pipeline transportation	$	97,938		$	70,904
Soda and sulfur services		66,107			67,375
Onshore facilities and transportation		5,390			7,036
Marine transportation		25,694			12,137
Total Segment Margin	$	195,129		$	157,452

Offshore pipeline transportation Segment Margin for the 2023 Quarter increased $27.0 million, or 38%, from the 2022 Quarter due to increased crude oil and natural gas volumes and associated revenues during the 2023 Quarter. This increase in activity is primarily a result of production from the King’s Quay floating production system (“FPS”), which achieved first oil in the second quarter of 2022 and has successfully ramped up its production to levels of approximately 115,000 barrels of oil equivalent per day. The King’s Quay FPS, which is supporting the Khaleesi, Mormont and Samurai field developments, 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. We expect to continue to benefit from volumes from King’s Quay along with new volumes at the Argos FPS, which supports the 14 wells pre-drilled and completed at BP’s operated Mad Dog 2 field development that achieved first oil in April 2023. We anticipate volumes from Argos to ramp up over the remainder of 2023 with 100% of the volumes flowing through our 64% owned and operated CHOPS pipeline for ultimate delivery to shore. In addition, the 2023 Quarter had less downtime as compared to the 2022 Quarter, which experienced a significant period of unplanned operational maintenance associated with one of our lateral pipelines that also impacted volumes on our main pipeline downstream of it.

Soda and sulfur services Segment Margin for the 2023 Quarter decreased $1.3 million, or 2%, from the 2022 Quarter primarily due to a decrease in soda ash and NaHS volumes sold during the 2023 Quarter. During the 2023 Quarter, our Alkali Business saw both lower production and ultimate sales of soda ash during the period due to extreme winter weather conditions that impacted our operations and certain supply chain functions, most notably the rail service in and out of the Green River Basin. The decrease in Segment Margin as a result of the decrease in sales volumes was mostly offset by higher export and domestic pricing in our Alkali Business. In our Alkali Business, we have continued to see a balanced market 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. We continue to expect our weighted average sales price for 2023 to exceed our weighted average sales price in 2022. Additionally, we successfully restarted 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 that we anticipate to ramp up to. In our refinery services business, one of our largest host refineries completed its major turnaround in the fourth quarter of 2022 and spent the 2023 Quarter ramping back up to its normal level of activity. We were successfully able to build inventory prior to the turnaround to meet our customers’ demands during the fourth quarter of 2022, but exited the year with a minimal working level of inventory. As a result of this, and the slower than expected ramp up of activity in the 2023 Quarter by one of our largest host refineries, our NaHS production volumes and ultimately our sales volumes were lower during the period. We expect production levels to return to normal in the second quarter of 2023. Demand for NaHS remained high during the 2023 Quarter as a result of the continued global economic recovery and the use of NaHS in products, such as copper, that are a key part of the anticipated energy transition.

Onshore facilities and transportation Segment Margin for the 2023 Quarter decreased $1.6 million, or 23%, from the 2022 Quarter. This decrease is primarily due to a decrease in volumes on our Texas and Jay pipeline systems during the 2023 Quarter, as well as a decrease in rail unload volumes. The decrease was partially offset by an increase in pipeline and terminal volumes associated with our assets in the Baton Rouge corridor.

Marine transportation Segment Margin for the 2023 Quarter increased $13.6 million, or 112%, from the 2022 Quarter. This increase is primarily attributable to higher utilization and day rates in our inland and offshore businesses, including the M/T American Phoenix, during the 2023 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. Demand for our barge services to move intermediate and refined products remained high during the 2023 Quarter 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) combined with 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. Additionally, the M/T American Phoenix is under contract for the remainder of 2023 with an investment grade customer at a more favorable rate than 2022.

Other Components of Net Loss

We reported Net Loss Attributable to Genesis Energy, L.P. of $1.6 million in the 2023 Quarter compared to Net Loss Attributable to Genesis Energy, L.P. of $5.3 million in the 2022 Quarter.

Net Loss Attributable to Genesis Energy, L.P. in the 2023 Quarter was impacted primarily by: (i) an increase in operating income due to an increase in our Segment Margin of $37.7 million discussed above and a decrease in income attributable to our redeemable noncontrolling interests of $7.8 million as the associated Alkali Holdings preferred units were redeemed during the second quarter of 2022. These increases were offset partially by (i) an unrealized (non-cash) loss of $27.1 million in the 2023 Quarter compared to an unrealized (non-cash) gain of $6.2 million in the 2022 Quarter primarily from the valuation of our natural gas commodity derivatives; (ii) an increase in depreciation, depletion, and amortization expense of $3.7 million; and (iii) an increase in interest expense of $5.8 million. In addition, the 2022 Quarter included an unrealized (non-cash) loss of $4.3 million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units in the 2022 Quarter, which is included in “Other expense”.

Earnings Conference Call

We will broadcast our Earnings Conference Call on Thursday, May 4, 2023, at 8:30 a.m. Central time (9:30 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, soda 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 March 31,
		2023				2022
REVENUES	$	790,612			$	631,947
COSTS AND EXPENSES:
Costs of sales and operating expenses		653,519				495,648
General and administrative expenses		14,552				15,122
Depreciation, depletion and amortization		73,160				69,506
OPERATING INCOME		49,381				51,671
Equity in earnings of equity investees		17,553				12,444
Interest expense		(60,854	)			(55,104	)
Other expense		(1,808	)			(4,258	)
INCOME BEFORE INCOME TAXES		4,272				4,753
Income tax expense		(884	)			(304	)
NET INCOME		3,388				4,449
Net income attributable to noncontrolling interests		(5,032	)			(1,876	)
Net income attributable to redeemable noncontrolling interests		—				(7,823	)
NET LOSS ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	(1,644	)		$	(5,250	)
Less: Accumulated distributions attributable to Class A Convertible Preferred Units		(24,002	)			(18,684	)
NET LOSS ATTRIBUTABLE TO COMMON UNITHOLDERS	$	(25,646	)		$	(23,934	)
NET LOSS PER COMMON UNIT:
Basic and Diluted	$	(0.21	)		$	(0.20	)
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted		122,579,218				122,579,218

GENESIS ENERGY, L.P. OPERATING DATA - UNAUDITED
	Three Months Ended March 31,
		2023				2022
Offshore Pipeline Transportation Segment
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS(1)		234,136				175,881
Poseidon(1)		315,160				240,823
Odyssey(1)		65,655				97,230
GOPL		1,988				4,955
Offshore crude oil pipelines total		616,939				518,889
Natural gas transportation volumes (MMBtus/day)(1)		387,197				223,662
Soda and Sulfur Services Segment
NaHS (dry short tons sold)		28,090				32,169
Soda Ash volumes (short tons sold)		704,812				744,788
NaOH (caustic soda) volumes (dry short tons sold)(2)		20,176				20,724
Onshore Facilities and Transportation Segment
Crude oil pipelines (barrels/day):
Texas(3)		64,037				69,333
Jay		5,004				6,916
Mississippi		5,009				5,742
Louisiana(4)		80,960				61,781
Onshore crude oil pipelines total		155,010				143,772
Crude oil and petroleum products sales (barrels/day)		22,271				23,887
Rail unload volumes (barrels/day)		—				2,505
Marine Transportation Segment
Inland Fleet Utilization Percentage(5)		100.0	%			90.3	%
Offshore Fleet Utilization Percentage(5)		99.5	%			96.6	%

(1)	As of March 31, 2023 and 2022, 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 three months ended March 31, 2023 and 2022 include 31,525 and 28,720 barrels per day, respectively, of intermediate refined products and 48,914 and 30,399 barrels per 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)
	March 31, 2023				December 31, 2022
	(unaudited)
ASSETS
Cash, cash equivalents and restricted cash	$	36,806			$	26,567
Accounts receivable - trade, net		748,538				721,567
Inventories		121,328				78,143
Other current assets		46,123				26,770
Total current assets		952,795				853,047
Fixed assets and mineral leaseholds, net of accumulated depreciation and depletion		4,661,183				4,641,695
Equity investees		279,658				284,486
Intangible assets, net of amortization		127,461				127,320
Goodwill		301,959				301,959
Right of use assets, net		212,803				125,277
Other assets, net of amortization		50,601				32,208
Total assets	$	6,586,460			$	6,365,992
LIABILITIES AND CAPITAL
Accounts payable - trade	$	518,822			$	427,961
Accrued liabilities		286,424				281,146
Total current liabilities		805,246				709,107
Senior secured credit facility		124,400				205,400
Senior unsecured notes, net of debt issuance costs and premium		3,008,568				2,856,312
Alkali senior secured notes, net of debt issuance costs and discount		399,656				402,442
Deferred tax liabilities		17,072				16,652
Other long-term liabilities		490,860				400,617
Total liabilities		4,845,802				4,590,530
Mezzanine capital:
Class A Convertible Preferred Units		891,909				891,909
Partners’ capital:
Common unitholders		523,244				567,277
Accumulated other comprehensive income		6,236				6,114
Noncontrolling interests		319,269				310,162
Total partners’ capital		848,749				883,553
Total liabilities, mezzanine capital and partners’ capital	$	6,586,460			$	6,365,992
Common Units Data:
Total common units outstanding		122,579,218				122,579,218

GENESIS ENERGY, L.P. RECONCILIATION OF LOSS ATTRIBUTABLE TO GENESIS ENERGY, L.P. TO SEGMENT MARGIN - UNAUDITED
(in thousands)
	Three Months Ended March 31,
		2023				2022
Net loss attributable to Genesis Energy, L.P.	$	(1,644	)		$	(5,250	)
Corporate general and administrative expenses		15,764				15,721
Depreciation, depletion, amortization and accretion		75,935				72,948
Interest expense		60,854				55,104
Income tax expense		884				304
Change in provision for leased items no longer in use		—				(431	)
Redeemable noncontrolling interest redemption value adjustments(1)		—				7,823
Plus (minus) Select Items, net(2)		43,336				11,233
Segment Margin(3)	$	195,129			$	157,452

(1)	The 2022 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 LOSS ATTRIBUTABLE TO GENESIS ENERGY L.P. TO ADJUSTED EBITDA AND AVAILABLE CASH BEFORE RESERVES - UNAUDITED
(in thousands)
	Three Months Ended March 31,
		2023				2022
Net loss attributable to Genesis Energy, L.P.	$	(1,644	)		$	(5,250	)
Interest expense		60,854				55,104
Income tax expense		884				304
Depreciation, depletion, amortization and accretion		75,935				72,948
EBITDA		136,029				123,106
Redeemable noncontrolling interest redemption value adjustments(1)		—				7,823
Plus (minus) Select Items, net(2)		43,063				12,211
Adjusted EBITDA(3)		179,092				143,140
Maintenance capital utilized(4)		(16,100	)			(13,500	)
Interest expense		(60,854	)			(55,104	)
Cash tax expense		(464	)			(125	)
Distributions to preferred unitholders(5)		(24,002	)			(18,684	)
Available Cash before Reserves(6)	$	77,672			$	55,727

(1)	The 2022 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 Adjusted EBITDA later in this press release.
(4)	Maintenance capital expenditures in the 2023 Quarter and 2022 Quarter were $24.0 million and $21.9 million, respectively. Our maintenance capital expenditures are principally associated with our alkali and marine transportation businesses.
(5)	Distributions to preferred unitholders attributable to the 2023 Quarter are payable on May 15, 2023 to unitholders of record at close of business on April 28, 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 March 31,
		2023				2022
Cash Flows from Operating Activities	$	97,657			$	54,245
Adjustments to reconcile net cash flows from operating activities to Adjusted EBITDA:
Interest Expense		60,854				55,104
Amortization and write-off of debt issuance costs, discount and premium		(3,534	)			(2,034	)
Effects of available cash from equity method investees not included in operating cash flows		6,697				6,172
Net effect of changes in components of operating assets and liabilities		17,648				29,169
Non-cash effect of long-term incentive compensation plans		(4,630	)			(3,061	)
Expenses related to business development activities and growth projects		34				612
Differences in timing of cash receipts for certain contractual arrangements(1)		10,575				8,230
Other items, net		(6,209	)			(5,297	)
Adjusted EBITDA(2)	$	179,092			$	143,140

(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)	See definition of Adjusted EBITDA later in this press release.

GENESIS ENERGY, L.P. ADJUSTED DEBT-TO-ADJUSTED CONSOLIDATED EBITDA RATIO - UNAUDITED
(in thousands)
		March 31, 2023
Senior secured credit facility		$	124,400
Senior unsecured notes, net of debt issuance costs and premium			3,008,568
Less: Outstanding inventory financing sublimit borrowings			(22,700	)
Less: Cash and cash equivalents			(17,468	)
Adjusted Debt(1)		$	3,092,800
		Pro Forma LTM
		March 31, 2023
Consolidated EBITDA (per our senior secured credit facility)		$	737,893
Consolidated EBITDA adjustments(2)			37,117
Adjusted Consolidated EBITDA (per our senior secured credit facility)(3)		$	775,010
Adjusted Debt-to-Adjusted Consolidated EBITDA			3.99X

(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, our bank leverage ratio 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, 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, 2022 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.

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 March 31,
			2023				2022
		(in thousands)
I.	Applicable to all Non-GAAP Measures
	Differences in timing of cash receipts for certain contractual arrangements(1)	$	10,575			$	8,230
	Certain non-cash items:
	Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(2)		27,132				(1,893	)
	Loss on debt extinguishment		1,809				—
	Adjustment regarding equity investees(3)		6,281				6,574
	Other		(2,461	)			(1,678	)
	Sub-total Select Items, net(4)		43,336				11,233
II.	Applicable only to Adjusted EBITDA and Available Cash before Reserves
	Certain transaction costs		34				612
	Other		(307	)			366
	Total Select Items, net(5)	$	43,063			$	12,211

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 2023 Quarter includes unrealized losses of $27.1 million from the valuation of our commodity derivative transactions (excluding fair value hedges). The 2022 Quarter includes unrealized gains of $6.2 million from the valuation of our commodity derivative transactions (excluding fair value hedges), and an unrealized loss of $4.3 million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units.
3. Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
4. Represents all Select Items applicable to Segment Margin and Available Cash before Reserves.
5. 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

Source: Genesis Energy, L.P.