HOUSTON--(BUSINESS WIRE)--Genesis Energy, L.P. (NYSE: GEL) today announced its third quarter results.
We generated the following financial results for the third quarter of 2023:
- Net Income Attributable to Genesis Energy, L.P. of $58.1 million for the third quarter of 2023 compared to Net Income Attributable to Genesis Energy, L.P. of $3.4 million for the same period in 2022.
- Cash Flows from Operating Activities of $141.0 million for the third quarter of 2023 compared to $94.3 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 $22.6 million and is reflected as a reduction to Available Cash before Reserves to common unitholders.
- Available Cash before Reserves to common unitholders of $89.0 million for the third quarter of 2023, which provided 4.84X coverage for the quarterly distribution of $0.15 per common unit attributable to the third quarter.
- Total Segment Margin of $207.9 million for the third quarter of 2023.
- Adjusted EBITDA of $190.6 million for the third quarter of 2023.
- Adjusted Consolidated EBITDA of $808.8 million for the trailing twelve months ended September 30, 2023 and a bank leverage ratio of 3.92X, both calculated in accordance with our senior secured credit agreement and discussed further in this release.
Grant Sims, CEO of Genesis Energy, said, “Our financial results for the third quarter came in ahead of our internal expectations and once again demonstrated the resilient earnings power of our diversified market leading businesses. During the third quarter, our offshore pipeline transportation segment benefited from steady and increasing volumes across our footprint along with zero downtime associated with any weather-related events in the Gulf of Mexico that would have otherwise caused our shippers to limit their production activities. Our soda and sulfur services segment performed in line with our expectations. Our marine transportation segment continued to perform in-line with, if not exceed, our expectations as the market for Jones Act equipment continues to remain structurally short, which is continuing to drive strong utilization and increasing day rates across all our classes of vessels. This strong financial performance in the third quarter resulted in our leverage ratio, as calculated by our senior secured lenders, ending the quarter at 3.92 times.
"We expect the balance of the year to consist of strong financial contributions from our offshore pipeline transportation and marine transportation segments being somewhat offset by marginally weaker performance in our soda ash operations, driven in large part by continued weakness in soda ash prices, primarily in our export markets. These current expectations should, nonetheless, allow us to deliver full year results at or above the midpoint, if not approaching the top end, of our previously revised full year guidance range for Adjusted EBITDA(1) of $725 - $745 million. It is important to remember that we continue to expect to generate record annual Adjusted EBITDA(1) for the partnership this year, along with record segment margin for our offshore pipeline transportation segment, at or near record segment margin from our marine transportation segment and near record contribution from our soda ash business, despite the weakness in soda ash prices in the back half of the year. Importantly, we continue to expect to exit the year with a leverage ratio, as calculated by our senior secured lenders, at or near our long-term target leverage ratio of 4.00 times.
"As we look ahead to next year, we expect to see continued volume growth offshore from additional wells coming online at Argos, along with additional volumes from new sub-sea tiebacks and continuing in-field drilling. We believe the Jones Act market will remain structurally tight driving marginally increasing day-rates in both our inland and offshore fleets in addition to our new long-term contract for the American Phoenix commencing in mid-January. Any weakness in our soda ash business due to prolonged weakness in soda ash prices is expected to be at least partially offset by the new volumes from the Granger expansion project and the corresponding reduction in our average operating costs per ton.
"Regardless of the makeup of our 2024 results, it is important to remember that the long-term outlook for Genesis remains completely unchanged. We remain well positioned to benefit from the increasing amounts of cash flow we expect to generate once our identified and ongoing growth capital projects are complete in mid to late 2024, along with a significant step change in offshore volumes and corresponding segment margin contributions in 2025 as the Shenandoah and Salamanca developments are expected to come on-line. This increased financial flexibility will continue to afford us with the opportunity to further simplify our capital structure, return capital to our stakeholders in one form or another, and ultimately allow us to continue to build long-term value for everyone in the capital structure in the coming years ahead.
"With that, I would like to discuss our individual business segments in more detail. Our offshore pipeline transportation segment performed ahead of our expectations, driven in large part by robust volumes across our system and a hurricane season where we saw no downtime during the quarter as a result of zero weather events in the central Gulf of Mexico that negatively impacted the production from our customers. During the quarter, we continued to see a steady ramp in volumes from BP’s Argos facility, which is fast approaching 90,000 barrels per day as well as strong volumes from King’s Quay, Spruance and our other host fields. We expect the balance of the year to show continued steady volumes across our offshore infrastructure, including from Argos and our other host fields along with some new volumes from additional sub-sea developments such as Woodside’s Shenzi North project and Quarternorth’s Katmai project, both of which commenced production in the third quarter.
"During the third quarter we also achieved record throughput volumes on our long-haul pipelines to shore, shipping upwards of ~675,000 barrels per day on several days, which represents approximately 5% of total U.S. crude oil production and a 50% increase over our long-haul volumes exiting 2021, just some 18-20 months ago. It is important to remember that we continue to expect to see our volumes grow into 2024 with additional wells at Argos coming on-line and a full year’s worth of production from several new developments and sub-sea tiebacks. Furthermore, we have successfully laid the 105 miles of the SYNC lateral and remain on schedule and importantly on budget with this project and our CHOPS expansion project, both of which we expect to be ready for service in the second half of 2024. The contracted Shenandoah and Salamanca developments and their combined 160,000 barrels of oil per day of incremental production handling capacity remain on-schedule and will be additive to our then base of volumes in 2024. These two new projects, combined with our steady base volumes and an increasing inventory of identified sub-sea tiebacks, provides us with the visibility to generate more than $500 million per year of segment margin starting in 2025. All of this is to say that we remain well positioned to deliver steady, stable and growing cash flows from our offshore pipeline transportation segment for many years ahead.
"Our soda and sulfur services segment performed in-line with our expectations during the quarter. The continued weak economic data out of China, combined with a continued increase in new production from Inner Mongolia continues to affect normalized customer behavior and is ultimately contributing to an increase in export volumes from China, which is putting downward pressure on prices in our export markets in Asia. We have also started to see early signals of a slowdown in the domestic market and certain end markets in Europe, specifically in container glass, as customers look to further optimize their purchasing activities based on their most recent forecasts. Given these broader economic headwinds, one might reasonably expect to see some level of supply rationalization in the long run as higher cost synthetic production becomes increasingly uneconomic in Europe and China at today’s prices. Alternatively, a quicker recovery to more normalized levels of global economic activity and growth, when combined with the green shoots from steady and growing demand from lithium and solar panel customers could help the soda ash market return to balance much quicker than in prior periods of oversupply. While it is likely going to be a combination of both supply and demand responses that will begin to balance the soda ash market and the ultimate balancing might take some time, we remain extremely bullish on the long-term fundamentals of the business, regardless of any near-term price volatility.
"Our legacy Granger production facility continues to run at or above its original nameplate capacity of approximately 500,000 tons of annual soda ash production. We recently started the commissioning activities at our Granger expansion project and expect this work to continue over the balance of the year. Once fully on-line in 2024, we will undoubtedly benefit from the increased sales volumes and lower operating cost per ton as our fixed costs today will be spread over an additional 750,000 tons which should help to partially offset any potential weakness in soda ash prices next year. Our legacy refinery services business performed in-line with our expectations.
"Our marine transportation segment continues to exceed our expectations as market supply and demand fundamentals remain steady. We continue to operate with utilization rates at or near 100% of available capacity for all classes of our vessels as the supply and demand outlook for Jones Act tanker tonnage remains structurally tight, driven by a combination of steady and robust demand and effectively zero new supply of our types of marine vessels. This lack of new supply of marine tonnage, combined with strong demand continues to drive spot day rates and longer-term contracted rates in both of our fleets to record levels. These fundamentals, combined with our increasingly term contracted portfolio, lead me to believe our marine transportation segment remains well positioned to deliver marginally growing and steady earnings over the next few years.
"Turning now to our balance sheet. As we mentioned earlier in the release, we are nearing the completion of our Granger expansion project and continue to advance the construction of the SYNC lateral and CHOPS expansion project. Given the timing of certain milestone achievements for both projects, we expect to experience some timing differences in our growth capital expenditures between 2023 and 2024. As a result, we expect the cash outlay from our growth capital expenditures in 2023 to range from $350 - $400 million versus our original estimate of $400 million to $450 million. While both projects remain on schedule and more importantly on budget, we expect to see the balance of these growth capital expenditures to show up in the first half of 2024 and will be additive to the roughly $100-$150 million in tail capital associated with our offshore expansion projects we previously expected to incur next year. Regardless of these changes in timing, 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, at or near 4.0 times.
"We continue to believe we are uniquely positioned to generate additional significant cash flow, especially given our size, starting in 2024 and accelerating into 2025. This central thesis has not changed and will undoubtedly give us tremendous flexibility to optimize our capital structure and return capital to all of our stakeholders, all while maintaining a focus on our long-term leverage ratio. In advance of this significant step change in 2025, so far this year we have utilized a portion of our available liquidity to opportunistically re-purchase $75 million of our Series A preferred security at a discount to the contracted call premium as well as purchase 114,900 of our common units at an average price of $9.09 per unit. While we do not have a programmatic approach for additional purchases of these securities, we will continue to be opportunistic in acquiring all securities in our capital structure, including both debt and equity, to the extent we feel they remain mispriced in the market. As we gain an increasingly clear line of sight to generating cash flow of roughly $200 million to $300 million, or more, per year after certain cash obligations (including interest payments, preferred and existing common unit distributions, maintenance capital requirements, principal payments on our Alkali senior secured notes, and cash taxes) we will continue to evaluate the various levers we can pull to return capital to our stakeholders, all while maintaining a focus on our long-term leverage ratio.
"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 third quarter of 2023 (the “2023 Quarter”) and the third 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 September 30, |
||||
|
|
2023 |
|
|
2022 |
|
(in thousands) |
||||
Offshore pipeline transportation |
$ |
109,267 |
|
$ |
91,402 |
Soda and sulfur services |
|
61,957 |
|
|
80,067 |
Onshore facilities and transportation |
|
9,547 |
|
|
9,442 |
Marine transportation |
|
27,126 |
|
|
15,279 |
Total Segment Margin |
$ |
207,897 |
|
$ |
196,190 |
Offshore pipeline transportation Segment Margin for the 2023 Quarter increased $17.9 million, or 20%, from the 2022 Quarter primarily due to higher crude oil and natural gas activity and volumes and less overall downtime during the 2023 Quarter. The increase in our volumes during the 2023 Quarter is primarily a result of the King’s Quay Floating Production System (“FPS”), which achieved first oil in the second quarter of 2022, and has since ramped up production levels reaching approximately 130,000 barrels of oil equivalent per day in the 2023 Quarter, and the Argos FPS, which achieved first oil in April 2023. 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. The Argos FPS, which supports BP’s operated Mad Dog 2 field development, began producing in the second quarter of 2023 and achieved production levels of approximately 90,000 barrels of oil per day in the 2023 Quarter, with 100% of the volumes flowing through our 64% owned and operated CHOPS pipeline for ultimate delivery to shore. We expect to continue to benefit from King’s Quay FPS and Argos FPS volumes throughout 2023 and over their anticipated production profiles. In addition to these developments, activity in and around our Gulf of Mexico asset base continues to be robust, including incremental in-field drilling at existing fields that tie into our infrastructure. Lastly, the 2023 Quarter had less overall downtime as compared to the 2022 Quarter, which was primarily a result of no weather-related events and no significant planned producer downtime during the period.
Soda and sulfur services Segment Margin for the 2023 Quarter decreased $18.1 million, or 23%, from the 2022 Quarter primarily due to lower export pricing in our Alkali Business and lower NaHS and caustic soda sales volumes and pricing during the 2023 Quarter, which was partially offset by higher soda ash sales volumes in the period. The 2023 Quarter was impacted by a decline in export pricing as compared to the 2022 Quarter (as well as when compared to the first half of 2023) as a result of slowing global demand and a slower than anticipated re-opening of China’s economy combined with the anticipated ramp in new global supply entering the market. We expect this volatility and supply and demand dynamic to continue to impact our pricing in the fourth quarter of 2023. We successfully restarted our original Granger production facility on January 1, 2023 and expect to see first production from our expanded Granger facility in the fourth quarter of 2023, which represents an incremental 750,000 tons of lower cost annual production that we anticipate to ramp up to. As a result of restarting our original Granger facility and ramping up production to its original nameplate capacity of approximately 500,000 tons on an annual basis, we had higher soda ash sales volumes during the 2023 Quarter. Once we complete the Granger Optimization Project, we would expect these incremental sales volumes to have a more meaningful impact to our reported Segment Margin in subsequent quarters as we can better absorb the fixed cost structure at our Granger facility. In our sulfur services business, we experienced a decrease in Segment Margin due to a decrease in NaHS sales volumes and pricing. NaHS sales volumes, when compared to the 2022 Quarter, decreased due to multiple factors, including a reduction in production volumes from a host refinery that partially converted its facility into a renewable diesel facility in the fourth quarter of 2022 and continued pressure on demand (that also negatively impacted prices) and timing delays in shipments, primarily in South America. In addition, the 2022 Quarter experienced robust NaHS sales volumes and pricing due to an increase in demand from our mining customers, primarily in South America, and due to our ability to leverage our multi-faceted supply and terminal sites in our sulfur services business to capitalize on incremental spot volumes as certain of our competitors experienced one-off supply challenges. NaHS production volumes and inventory levels during the 2023 Quarter returned to a more normalized level, as the unplanned operational and weather-related outages we experienced in the second quarter of 2023 were resolved.
Onshore facilities and transportation Segment Margin for the 2023 Quarter increased $0.1 million, or 1%, from the 2022 Quarter primarily due to a favorable mix of terminal and pipelines volumes on our Baton Rouge corridor assets (as we get a higher contribution to Segment Margin on intermediate refined products moving through our assets) and higher volumetric gains on our pipelines during the 2023 Quarter. These increases were offset by a decrease in rail unload volumes in the 2023 Quarter. The 2022 Quarter had an increase in rail volumes as a result of our main customer sourcing volumes to replace international volumes that were impacted by certain geopolitical events in the period. The rail unload volumes during the 2022 Quarter also increased our Louisiana pipeline volumes in the respective period as the crude oil unloaded was subsequently transported on our Louisiana pipeline to our customer’s refinery complex.
Marine transportation Segment Margin for the 2023 Quarter increased $11.8 million, or 78%, from the 2022 Quarter. This increase is primarily attributable to higher day rates in our inland and offshore businesses, including the M/T American Phoenix, during the 2023 Quarter. Demand for our barge services to move intermediate and refined products remained high during the 2023 Quarter due to the continued strength of refinery utilization rates as well as the lack of new supply of similar type vessels (primarily due to higher construction costs and long lead times for construction) as well as the retirement of older vessels in the market. These factors have also contributed to an overall increase in spot and term rates for our services. 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, and during the 2023 Quarter, we entered into a new three-and-a-half-year contract starting in January of 2024 with a credit-worthy counterparty at the highest day rate we have received since we first purchased the vessel in 2014.
Other Components of Net Income
We reported Net Income Attributable to Genesis Energy, L.P. of $58.1 million in the 2023 Quarter compared to Net Income Attributable to Genesis Energy, L.P. of $3.4 million in the 2022 Quarter.
Net Income Attributable to Genesis Energy, L.P. in the 2023 Quarter was impacted by an increase in Segment Margin of $11.7 million primarily due to increased volumes and activity in our offshore pipeline transportation segment and higher day rates in our marine transportation segment, and a decrease in depreciation, depletion and amortization expense of $5.6 million during the 2023 Quarter. Additionally, the 2023 Quarter included $12.3 million in unrealized gains associated with the valuation of our commodity derivative transactions compared to unrealized losses of $1.3 million during the 2022 Quarter. The 2022 Quarter also included an unrealized (non-cash) loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of $25.0 million, which was included within “Other expense” on the Unaudited Condensed Consolidated Statement of Operations.
Earnings Conference Call
We will broadcast our Earnings Conference Call on Thursday, November 2, 2023, at 9:30 a.m. Central time (10:30 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 September 30, |
|
Nine Months Ended September 30, |
||||||||||||
|
|
2023 |
|
|
|
2022 |
|
|
|
2023 |
|
|
|
2022 |
|
REVENUES |
$ |
807,618 |
|
|
$ |
721,248 |
|
|
$ |
2,402,892 |
|
|
$ |
2,074,920 |
|
|
|
|
|
|
|
|
|
||||||||
COSTS AND EXPENSES: |
|
|
|
|
|
|
|
||||||||
Costs of sales and operating expenses |
|
610,775 |
|
|
|
555,169 |
|
|
|
1,880,814 |
|
|
|
1,621,619 |
|
General and administrative expenses |
|
16,770 |
|
|
|
17,038 |
|
|
|
48,253 |
|
|
|
52,825 |
|
Depreciation, depletion and amortization |
|
68,379 |
|
|
|
73,946 |
|
|
|
209,966 |
|
|
|
217,125 |
|
Gain on sale of asset |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(40,000 |
) |
OPERATING INCOME |
|
111,694 |
|
|
|
75,095 |
|
|
|
263,859 |
|
|
|
223,351 |
|
Equity in earnings of equity investees |
|
17,242 |
|
|
|
13,236 |
|
|
|
49,606 |
|
|
|
40,252 |
|
Interest expense |
|
(61,580 |
) |
|
|
(57,710 |
) |
|
|
(184,057 |
) |
|
|
(168,773 |
) |
Other expense |
|
— |
|
|
|
(21,388 |
) |
|
|
(1,812 |
) |
|
|
(10,758 |
) |
INCOME BEFORE INCOME TAXES |
|
67,356 |
|
|
|
9,233 |
|
|
|
127,596 |
|
|
|
84,072 |
|
Income tax expense |
|
(574 |
) |
|
|
(660 |
) |
|
|
(1,748 |
) |
|
|
(1,535 |
) |
NET INCOME |
|
66,782 |
|
|
|
8,573 |
|
|
|
125,848 |
|
|
|
82,537 |
|
Net income attributable to noncontrolling interests |
|
(8,712 |
) |
|
|
(5,188 |
) |
|
|
(20,078 |
) |
|
|
(18,612 |
) |
Net income attributable to redeemable noncontrolling interests |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(30,443 |
) |
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. |
$ |
58,070 |
|
|
$ |
3,385 |
|
|
$ |
105,770 |
|
|
$ |
33,482 |
|
Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units |
|
(22,308 |
) |
|
|
(18,684 |
) |
|
|
(69,220 |
) |
|
|
(56,052 |
) |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNITHOLDERS |
$ |
35,762 |
|
|
$ |
(15,299 |
) |
|
$ |
36,550 |
|
|
$ |
(22,570 |
) |
NET INCOME (LOSS) PER COMMON UNIT: |
|
|
|
|
|
|
|
||||||||
Basic and Diluted |
$ |
0.29 |
|
|
$ |
(0.12 |
) |
|
$ |
0.30 |
|
|
$ |
(0.18 |
) |
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS: |
|
|
|
|
|
|
|
||||||||
Basic and Diluted |
|
122,520,592 |
|
|
|
122,579,218 |
|
|
|
122,559,461 |
|
|
|
122,579,218 |
|
| GENESIS ENERGY, L.P. |
| OPERATING DATA - UNAUDITED |
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
||||||||
|
2023 |
|
|
2022 |
|
|
2023 |
|
|
2022 |
|
Offshore Pipeline Transportation Segment |
|
|
|
|
|
|
|
||||
Crude oil pipelines (average barrels/day unless otherwise noted): |
|
|
|
|
|
|
|
||||
CHOPS(1) |
307,045 |
|
|
197,583 |
|
|
266,974 |
|
|
198,067 |
|
Poseidon(1) |
310,817 |
|
|
282,583 |
|
|
304,771 |
|
|
262,222 |
|
Odyssey(1) |
60,830 |
|
|
88,112 |
|
|
62,119 |
|
|
95,160 |
|
GOPL |
3,033 |
|
|
7,578 |
|
|
2,471 |
|
|
7,047 |
|
Offshore crude oil pipelines total |
681,725 |
|
|
575,856 |
|
|
636,335 |
|
|
562,496 |
|
|
|
|
|
|
|
|
|
||||
Natural gas transportation volumes (MMBtus/day)(1) |
408,866 |
|
|
358,618 |
|
|
398,060 |
|
|
338,598 |
|
|
|
|
|
|
|
|
|
||||
Soda and Sulfur Services Segment |
|
|
|
|
|
|
|
||||
NaHS (dry short tons sold) |
27,325 |
|
|
29,441 |
|
|
81,501 |
|
|
97,243 |
|
Soda Ash volumes (short tons sold) |
867,319 |
|
|
776,284 |
|
|
2,424,150 |
|
|
2,293,213 |
|
NaOH (caustic soda) volumes (dry short tons sold) |
18,229 |
|
|
23,186 |
|
|
58,751 |
|
|
65,983 |
|
|
|
|
|
|
|
|
|
||||
Onshore Facilities and Transportation Segment |
|
|
|
|
|
|
|
||||
Crude oil pipelines (barrels/day): |
|
|
|
|
|
|
|
||||
Texas(2) |
66,376 |
|
|
113,962 |
|
|
65,648 |
|
|
92,508 |
|
Jay |
6,161 |
|
|
5,481 |
|
|
5,710 |
|
|
6,348 |
|
Mississippi |
4,854 |
|
|
5,800 |
|
|
4,866 |
|
|
5,926 |
|
Louisiana(3) |
60,973 |
|
|
127,827 |
|
|
70,843 |
|
|
103,195 |
|
Onshore crude oil pipelines total |
138,364 |
|
|
253,070 |
|
|
147,067 |
|
|
207,977 |
|
|
|
|
|
|
|
|
|
||||
Crude oil and petroleum products sales (barrels/day) |
23,703 |
|
|
25,613 |
|
|
23,006 |
|
|
23,860 |
|
|
|
|
|
|
|
|
|
||||
Rail unload volumes (barrels/day) |
— |
|
|
15,130 |
|
|
— |
|
|
14,485 |
|
|
|
|
|
|
|
|
|
||||
Marine Transportation Segment |
|
|
|
|
|
|
|
||||
Inland Fleet Utilization Percentage(4) |
99.4 |
% |
|
100.0 |
% |
|
99.8 |
% |
|
97.3 |
% |
Offshore Fleet Utilization Percentage(4) |
98.5 |
% |
|
94.0 |
% |
|
97.6 |
% |
|
96.1 |
% |
(1) |
As of September 30, 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) |
Our Texas pipeline and infrastructure is a destination point for many pipeline systems in the Gulf of Mexico, including the CHOPS pipeline. |
|
(3) |
Total daily volumes for the three and nine months ended September 30, 2023 include 42,622 and 34,720 Bbls/day, respectively, of intermediate refined products and 17,201 and 35,564 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines. Total daily volumes for the three and nine months ended September 30, 2022 include 23,265 and 27,131 Bbls/day, respectively, of intermediate refined products and 87,656 and 62,172 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines. |
|
(4) |
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 unit amounts) |
|
September 30, 2023 |
|
December 31, 2022 |
||
|
(unaudited) |
|
|
||
ASSETS |
|
|
|
||
Cash, cash equivalents and restricted cash |
$ |
39,905 |
|
$ |
26,567 |
Accounts receivable - trade, net |
|
871,298 |
|
|
721,567 |
Inventories |
|
126,946 |
|
|
78,143 |
Other current assets |
|
53,396 |
|
|
26,770 |
Total current assets |
|
1,091,545 |
|
|
853,047 |
Fixed assets and mineral leaseholds, net of accumulated depreciation and depletion |
|
4,864,498 |
|
|
4,641,695 |
Equity investees |
|
270,294 |
|
|
284,486 |
Intangible assets, net of amortization |
|
141,703 |
|
|
127,320 |
Goodwill |
|
301,959 |
|
|
301,959 |
Right of use assets, net |
|
229,785 |
|
|
125,277 |
Other assets, net of amortization |
|
38,658 |
|
|
32,208 |
Total assets |
$ |
6,938,442 |
|
$ |
6,365,992 |
LIABILITIES AND CAPITAL |
|
|
|
||
Accounts payable - trade |
$ |
660,577 |
|
$ |
427,961 |
Accrued liabilities |
|
363,136 |
|
|
281,146 |
Total current liabilities |
|
1,023,713 |
|
|
709,107 |
Senior secured credit facility |
|
198,400 |
|
|
205,400 |
Senior unsecured notes, net of debt issuance costs and premium |
|
3,011,386 |
|
|
2,856,312 |
Alkali senior secured notes, net of debt issuance costs and discount |
|
394,320 |
|
|
402,442 |
Deferred tax liabilities |
|
17,577 |
|
|
16,652 |
Other long-term liabilities |
|
541,373 |
|
|
400,617 |
Total liabilities |
|
5,186,769 |
|
|
4,590,530 |
Mezzanine capital: |
|
|
|
||
Class A Convertible Preferred Units |
|
839,695 |
|
|
891,909 |
|
|
|
|
||
Partners’ capital: |
|
|
|
||
Common unitholders |
|
547,622 |
|
|
567,277 |
Accumulated other comprehensive income |
|
6,479 |
|
|
6,114 |
Noncontrolling interests |
|
357,877 |
|
|
310,162 |
Total partners’ capital |
|
911,978 |
|
|
883,553 |
Total liabilities, mezzanine capital and partners’ capital |
$ |
6,938,442 |
|
$ |
6,365,992 |
|
|
|
|
||
Common Units Data: |
|
|
|
||
Total common units outstanding |
|
122,464,318 |
|
|
122,579,218 |
| GENESIS ENERGY, L.P. |
| RECONCILIATION OF NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. TO SEGMENT MARGIN - UNAUDITED |
|
| (in thousands) |
|
Three Months Ended
|
|
Nine Months Ended
|
|||||||||||
|
|
2023 |
|
|
|
2022 |
|
|
|
2023 |
|
|
2022 |
|
Net income attributable to Genesis Energy, L.P. |
$ |
58,070 |
|
|
$ |
3,385 |
|
|
$ |
105,770 |
|
$ |
33,482 |
|
Corporate general and administrative expenses |
|
18,329 |
|
|
|
18,132 |
|
|
|
52,580 |
|
|
54,958 |
|
Depreciation, depletion, amortization and accretion |
|
71,099 |
|
|
|
76,301 |
|
|
|
218,788 |
|
|
225,526 |
|
Interest expense |
|
61,580 |
|
|
|
57,710 |
|
|
|
184,057 |
|
|
168,773 |
|
Income tax expense |
|
574 |
|
|
|
660 |
|
|
|
1,748 |
|
|
1,535 |
|
Gain on sale of asset, net to our ownership interest(1) |
|
— |
|
|
|
— |
|
|
|
— |
|
|
(32,000 |
) |
Change in provision for leased items no longer in use |
|
— |
|
|
|
(68 |
) |
|
|
— |
|
|
(599 |
) |
Cancellation of debt income(2) |
|
— |
|
|
|
(3,881 |
) |
|
|
— |
|
|
(8,618 |
) |
Redeemable noncontrolling interest redemption value adjustments(3) |
|
— |
|
|
|
— |
|
|
|
— |
|
|
30,443 |
|
Plus (minus) Select Items, net(4) |
|
(1,755 |
) |
|
|
43,951 |
|
|
|
54,701 |
|
|
99,414 |
|
Segment Margin(5) |
$ |
207,897 |
|
|
$ |
196,190 |
|
|
$ |
617,644 |
|
$ |
572,914 |
|
(1) |
On April 29, 2022, we sold our Independence Hub platform and recognized a gain on the sale of $40.0 million, of which $32.0 million was attributable to our 80% ownership interest. |
|
(2) |
The three and nine months ended September 30, 2022 include income associated with the repurchase and extinguishment of certain of our senior unsecured notes on the open market of $3.9 million and $8.6 million, respectively. |
|
(3) |
The nine months ended September 30, 2022 include paid-in-kind distributions, accretion on the redemption feature and valuation adjustments to the redemption feature as the associated preferred units were redeemed during the second quarter of 2022. |
|
(4) |
Refer to additional detail of Select Items later in this press release. |
|
(5) |
See definition of Segment Margin later in this press release. |
| GENESIS ENERGY, L.P. |
| RECONCILIATIONS OF NET INCOME ATTRIBUTABLE TO GENESIS ENERGY L.P. TO ADJUSTED EBITDA AND AVAILABLE CASH BEFORE RESERVES - UNAUDITED |
|
| (in thousands) |
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
||||||||||||
|
|
2023 |
|
|
|
2022 |
|
|
|
2023 |
|
|
|
2022 |
|
Net income attributable to Genesis Energy, L.P. |
$ |
58,070 |
|
|
$ |
3,385 |
|
|
$ |
105,770 |
|
|
$ |
33,482 |
|
Interest expense |
|
61,580 |
|
|
|
57,710 |
|
|
|
184,057 |
|
|
|
168,773 |
|
Income tax expense |
|
574 |
|
|
|
660 |
|
|
|
1,748 |
|
|
|
1,535 |
|
Gain on sale of asset, net to our ownership interest |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(32,000 |
) |
Depreciation, depletion, amortization and accretion |
|
71,099 |
|
|
|
76,301 |
|
|
|
218,788 |
|
|
|
225,526 |
|
EBITDA |
|
191,323 |
|
|
|
138,056 |
|
|
|
510,363 |
|
|
|
397,316 |
|
Redeemable noncontrolling interest redemption value adjustments(1) |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
30,443 |
|
Plus (minus) Select Items, net(2) |
|
(767 |
) |
|
|
45,583 |
|
|
|
57,255 |
|
|
|
109,145 |
|
Adjusted EBITDA(3) |
|
190,556 |
|
|
|
183,639 |
|
|
|
567,618 |
|
|
|
536,904 |
|
Maintenance capital utilized(4) |
|
(17,200 |
) |
|
|
(14,400 |
) |
|
|
(49,900 |
) |
|
|
(42,050 |
) |
Interest expense |
|
(61,580 |
) |
|
|
(57,710 |
) |
|
|
(184,057 |
) |
|
|
(168,773 |
) |
Cash tax expense |
|
(200 |
) |
|
|
(250 |
) |
|
|
(823 |
) |
|
|
(525 |
) |
Distributions to preferred unitholders(5) |
|
(22,612 |
) |
|
|
(18,684 |
) |
|
|
(69,928 |
) |
|
|
(56,052 |
) |
Available Cash before Reserves(6) |
$ |
88,964 |
|
|
$ |
92,595 |
|
|
$ |
262,910 |
|
|
$ |
269,504 |
|
(1) |
The nine months ended September 30, 2022 include paid-in-kind distributions, accretion on the redemption feature and valuation adjustments to the redemption feature as the associated preferred units were 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 $33.6 million and $44.3 million, respectively. Maintenance capital expenditures for the nine months ended September 30, 2023 and 2022 were $86.9 million and $90.5 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 November 14, 2023 to unitholders of record at close of business on October 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
|
|
Nine Months Ended
|
||||||||||||
|
|
2023 |
|
|
|
2022 |
|
|
|
2023 |
|
|
|
2022 |
|
Cash Flows from Operating Activities |
$ |
141,043 |
|
|
$ |
94,308 |
|
|
$ |
396,364 |
|
|
$ |
252,595 |
|
Adjustments to reconcile net cash flows from operating activities to Adjusted EBITDA: |
|
|
|
|
|
|
|
||||||||
Interest Expense |
|
61,580 |
|
|
|
57,710 |
|
|
|
184,057 |
|
|
|
168,773 |
|
Amortization and write-off of debt issuance costs, discount and premium |
|
(2,393 |
) |
|
|
(2,458 |
) |
|
|
(8,206 |
) |
|
|
(7,110 |
) |
Effects of available cash from equity method investees not included in operating cash flows |
|
6,320 |
|
|
|
4,365 |
|
|
|
19,704 |
|
|
|
14,737 |
|
Net effect of changes in components of operating assets and liabilities |
|
(2,647 |
) |
|
|
22,346 |
|
|
|
(3,604 |
) |
|
|
48,576 |
|
Non-cash effect of long-term incentive compensation plans |
|
(5,580 |
) |
|
|
(4,191 |
) |
|
|
(15,236 |
) |
|
|
(10,835 |
) |
Expenses related to business development activities and growth projects |
|
— |
|
|
|
939 |
|
|
|
105 |
|
|
|
6,881 |
|
Differences in timing of cash receipts for certain contractual arrangements(1) |
|
11,385 |
|
|
|
13,775 |
|
|
|
33,519 |
|
|
|
38,482 |
|
Distributions from unrestricted subsidiaries not included in operating cash flows(2) |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
32,000 |
|
Other items, net(3) |
|
(19,152 |
) |
|
|
(3,155 |
) |
|
|
(39,085 |
) |
|
|
(7,195 |
) |
Adjusted EBITDA(4) |
$ |
190,556 |
|
|
$ |
183,639 |
|
|
$ |
567,618 |
|
|
$ |
536,904 |
|
(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) |
Includes adjustments associated with the noncontrolling interest effects of our non-100% owned consolidated subsidiaries as our Adjusted EBITDA measure is reported net to our ownership interests, amongst other items. |
|
(4) |
See definition of Adjusted EBITDA later in this press release. |
| GENESIS ENERGY, L.P. |
ADJUSTED DEBT-TO-ADJUSTED CONSOLIDATED EBITDA RATIO - UNAUDITED |
|
| (in thousands) |
|
|
September 30, 2023 |
||
Senior secured credit facility |
|
$ |
198,400 |
|
Senior unsecured notes, net of debt issuance costs and premium |
|
|
3,011,386 |
|
Less: Outstanding inventory financing sublimit borrowings |
|
|
(21,700 |
) |
Less: Cash and cash equivalents |
|
|
(20,535 |
) |
Adjusted Debt(1) |
|
$ |
3,167,551 |
|
|
|
|
||
|
|
Pro Forma LTM |
||
|
|
September 30, 2023 |
||
Consolidated EBITDA (per our senior secured credit facility) |
|
$ |
742,164 |
|
Consolidated EBITDA adjustments(2) |
|
|
66,598 |
|
Adjusted Consolidated EBITDA (per our senior secured credit facility)(3) |
|
$ |
808,762 |
|
|
|
|
||
Adjusted Debt-to-Adjusted Consolidated EBITDA |
|
3.92X |
||
(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. 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, Spruance, Shenandoah, Salamanca and Shenzi North 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 war in Ukraine and conflict in Israel), 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 attributable to Genesis Energy, L.P. to Adjusted EBITDA and Available Cash before Reserves:
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
||||||||||||
|
|
|
2023 |
|
|
|
2022 |
|
|
|
2023 |
|
|
|
2022 |
|
|
|
(in thousands) |
||||||||||||||
I. |
Applicable to all Non-GAAP Measures |
|
|
|
|
|
|
|
||||||||
|
Differences in timing of cash receipts for certain contractual arrangements(1) |
$ |
11,385 |
|
|
$ |
13,775 |
|
|
$ |
33,519 |
|
|
$ |
38,482 |
|
|
Distributions from unrestricted subsidiaries not included in income(2) |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
32,000 |
|
|
Certain non-cash items: |
|
|
|
|
|
|
|
||||||||
|
Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(3) |
|
(12,299 |
) |
|
|
26,295 |
|
|
|
17,721 |
|
|
|
16,083 |
|
|
Loss on debt extinguishment |
|
— |
|
|
|
293 |
|
|
|
1,812 |
|
|
|
794 |
|
|
Adjustment regarding equity investees(4) |
|
6,387 |
|
|
|
5,247 |
|
|
|
18,535 |
|
|
|
15,981 |
|
|
Other |
|
(7,228 |
) |
|
|
(1,659 |
) |
|
|
(16,886 |
) |
|
|
(3,926 |
) |
|
Sub-total Select Items, net(5) |
|
(1,755 |
) |
|
|
43,951 |
|
|
|
54,701 |
|
|
|
99,414 |
|
II. |
Applicable only to Adjusted EBITDA and Available Cash before Reserves |
|
|
|
|
|
|
|
||||||||
|
Certain transaction costs |
|
— |
|
|
|
939 |
|
|
|
105 |
|
|
|
6,881 |
|
|
Other |
|
988 |
|
|
|
693 |
|
|
|
2,449 |
|
|
|
2,850 |
|
|
Total Select Items, net(6) |
$ |
(767 |
) |
|
$ |
45,583 |
|
|
$ |
57,255 |
|
|
$ |
109,145 |
|
(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 second quarter of 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 agreement), Independence Hub, LLC. |
|
(3) |
The three and nine months ended September 30, 2023 include unrealized gains of $12.3 million and unrealized losses of $17.7 million, respectively, from the valuation of our commodity derivative transactions (excluding fair value hedges). The three and nine months ended September 30, 2022 include unrealized losses of $1.3 million and unrealized gains of $2.5 million, respectively, from the valuation of our commodity derivative transactions (excluding fair value hedges), and unrealized losses of $25.0 million and $18.6 million, respectively, from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. |
|
(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.
