Genesis Energy, L.P. Reports Third Quarter 2022 Results
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 2022:
•Net Income Attributable to Genesis Energy, L.P. of $3.4 million for the third quarter of 2022 compared to Net Loss Attributable to Genesis Energy, L.P. of $20.9 million for the same period in 2021.
•Cash Flows from Operating Activities of $94.3 million for the third quarter of 2022 compared to $54.2 million for the same period in 2021.
•We declared cash distributions on our preferred units of $0.7374 for each preferred unit, which equates to a cash distribution of approximately $18.7 million and is reflected as a reduction to Available Cash before Reserves to common unitholders.
•Available Cash before Reserves to common unitholders of $92.6 million for the third quarter of 2022, which provided 5.04X coverage for the quarterly distribution of $0.15 per common unit attributable to the third quarter.
•Total Segment Margin of $196.2 million for the third quarter of 2022.
•Adjusted EBITDA of $183.6 million in the third quarter of 2022.
•Adjusted Consolidated EBITDA of $692.3 million for the trailing twelve months ended September 30, 2022 and a bank leverage ratio of 4.27X, both calculated in accordance with our senior secured credit agreement and discussed further in this release.
Grant Sims, CEO of Genesis Energy, said, “We are once again very pleased with the financial performance of our market leading businesses for the third quarter. Our reported Adjusted EBITDA of $183.6 million exceeded even our internal expectations. The fundamentals and macro conditions for our business segments continue to remain strong, and we believe this backdrop provides the foundation for us to continue to improve our balance sheet, generate increasing amounts of discretionary cash flow, and create value for everyone in our capital structure in the coming years. Importantly, we delivered yet another sequential reduction in our quarter-end leverage ratio, as calculated by our senior secured lenders, to 4.27 times. This is also a significant improvement from the 5.51 times reported in the third quarter last year.
Our financial results were driven by strong operating performance across all of our business segments with steadily increasing volumes in our offshore segment, as well as strong soda ash prices in all regions, especially in our export markets. Based on our financial performance over the first three quarters and our expectations for the remainder of 2022, we are today again raising our full year guidance for Adjusted EBITDA(1) to a range of $700 - $710 million for 2022, which includes approximately $41 million of non-recurring income for the year, of which the majority is associated with the gain on the sale of the Independence Hub platform, and expect to exit 2022 with a leverage ratio, as calculated by our senior secured lenders, at or below 4.25 times.
As we look ahead to 2023 and what risks might be on the horizon, we remain confident our market leading businesses are well positioned to navigate any reasonably expected policy induced recession or potential economic slowdown. We have a tremendous amount of momentum supporting volume growth and increasing financial results out of the Gulf of Mexico, none of which should be impacted by an economic slowdown or a near-term reduction in oil prices. The current structural tightness
1
in the soda ash market combined with the rapidly increasing demand for soda ash as a fundamental building block for the transition to a lower carbon world will, in our opinion, to continue to provide support for soda ash prices, even if all or parts of the world see a slowdown in economic activity. It appears to us that this structurally tight market will persist over the course of 2023 during which time we expect to be increasing our ability to produce and sell soda ash by some 700,000 tons with the full 1.2 to 1.3 million tons annually from our Granger facility available in 2024. Our remaining business segments remain steady, and we believe each will continue to benefit from their respective market dynamics over the next year. Accordingly, we continue to anticipate generating Adjusted EBITDA(1) next year in the mid $700 million range and exit 2023 with a leverage ratio, as calculated by our senior secured lenders, below 4.0 times. With this anticipated financial performance and clear line of sight to increasing free cash flow in the years ahead, we believe we have all the flexibility we need, and in fact have multiple options, to address any near-term maturities in our capital structure under virtually any operating, financial, or economic environment.
With that, I would like to next discuss our individual business segments and focus on their recent and expected performance in more detail.
Our offshore pipeline transportation segment continued to exceed our expectations. During the third quarter, and so far in the fourth quarter, we have experienced de minimus weather related downtime and thus have benefited by some $8 - $9 million dollars versus our original 2022 budget, which assumed 10 days of downtime during the third and fourth quarters. Volumes from Murphy’s King’s Quay development continued to ramp ahead of our internal expectations and according to Murphy’s latest public disclosure, is currently producing volumes in excess of 90,000 barrels of oil equivalent per day from only 5 of the 7 original wells. They are expected to bring on-line both the 6th and 7th wells in the near future and are continuing to work on increasing the capacity of King’s Quay beyond the original design capacity of 85,000 barrels of oil and 100 million cubic feet of gas per day over the remainder of the year. We remain encouraged with Murphy’s operating performance and continue to believe we will see strong volumes from King’s Quay through the remainder of the year and into 2023 as well as for years and years to come.
As we look ahead, we continue to anticipate first oil from BP’s operated Argos floating production facility and the 14 wells pre-drilled and completed at their Mad Dog 2 field development in the coming months. The volumes from Argos are expected to ramp close to its nameplate capacity of 140,000 barrels of oil per day over the subsequent 9 to 12 months after first production and will provide a steady bridge to the incremental 160,000 barrels of oil per day we expect in late 2024 and early 2025 from our recently contracted developments, Shenandoah and Salamanca. We also continue to pursue multiple in-field, sub-sea and/or secondary recovery development opportunities representing upwards of 200,000 barrels of oil per day in the aggregate that could turn to production over the next two to four years, all of which have been identified but not yet fully sanctioned by the operators and producers involved.
Our sodium minerals and sulfur services segment continues to perform ahead of our expectations. The macro story for soda ash remains intact as worldwide demand, ex-China, continues to outpace supply, despite any concerns of a slowdown of the broader economy. Demand growth for soda ash, ex-China, is expected to remain in excess of one million tons per year over the next several years, which is driven by a combination of industrial production growth and increasing demand associated with the green transition, specifically from solar panel and lithium battery manufacturers at the same time there is no new supply available to the market outside of higher cost synthetic production.
As a result of this structural tightness and the cost structure of the synthetic producer, our non-contracted export soda ash prices have steadily increased throughout 2022, and this again held true as our fourth quarter soda ash prices are expected to be higher than our third quarter prices. Given this starting point and the nature of our contracts, we currently expect, and all of our recent pricing conversations thus far would confirm, that our weighted average soda ash price will be higher in 2023 versus 2022. This will be true even if we were to see a decline in market-clearing spot prices over the course of 2023, which is not impossible but is dependent on a number of negative dynamics all playing out together.
We remain on schedule to have first production from our original Granger facility as early as January 2023 with the expanded Granger facility expected to be on-line sometime in the third quarter of 2023. We continue to expect a net increase in production of around 700,000 tons in 2023, which will be contracted at current market prices, with the full 1.2 to 1.3 million tons from old and new Granger available for sale in 2024. Once expanded, Granger will join our Westvaco facility as one of the lowest cost soda ash production facilities in the world.
Our legacy sulfur services business also exceeded our expectations for the quarter. We benefited from a strong operating performance combined with steady volumes to our mining and pulp and paper customers. As a result of certain vessel loading schedules, we were able to take advantage of the opportunity to secure the sale of incremental volumes to our South American copper mining customers during the quarter. Despite any concerns of a potential recession, copper remains a fundamental building block of the global economy and specifically the green energy revolution given its importance in the manufacturing of solar panels and lithium batteries for electric vehicles and battery storage. We continue to expect global
2
demand for copper to remain inelastic to any broader slowdown in economic activity and thus will provide us with steady, if not growing, demand for our sulfur based products moving forward.
As referenced last quarter, our largest host refinery is taking an extended maintenance outage during the fourth quarter. As a result, we are simultaneously taking an extended outage at our sulfur removal unit to conduct a variety of scheduled and long-term maintenance items during this period. This planned outage will impact certain production volumes during the quarter. At the same time, we would reasonably expect our costs to be higher than normal, both of which would be expected to negatively impact our segment margin in the fourth quarter. In advance of this scheduled downtime, we proactively increased our inventory levels of our sulfur based products to ensure we had adequate volumes to fulfill all of our contracted sales volumes during the fourth quarter and would otherwise expect to return to normal operations in the next couple of weeks. However, we are expecting an overall negative impact of around $5 million on fourth quarter segment margin relative to the quarter just ended. We continue to remain encouraged about the future prospects from our refinery services business and believe it will continue to be a steady contributor for us through all economic cycles.
Our marine transportation segment performed in-line with our expectations as market conditions continue to remain strong. During the third quarter, we continued to see tremendously high utilization for all classes of our vessels as demand for Jones Act tanker tonnage remains extremely robust due to strong refinery utilization and the increasing need for movements from the Gulf Coast to the East Coast for certain products. As a result of these conditions, and no availability of equipment in the spot market, the demand for both our inland and offshore vessels, especially our larger horsepower vessels, continued to increase, thus allowing us to operate at effectively 100% utilization while also steadily increasing our day rates. This structural tightness has recently been exacerbated by record low water levels on the Mississippi River, which has caused increased traffic, navigational delays and longer than normal wait times to move through locks, and thus further reduced the practical availability of marine equipment available to make moves up or down the Mississippi River. It is important to note that we have not experienced any negative financial effects as a result of such conditions on the Mississippi River since we operate on a day rate plus fuel basis without going “off the clock” due to navigational issues, whereas traditional dry cargo or line-haul carriers generally operate on a per ton mile rate structure.
The American Phoenix completed her scheduled dry-docking near the end of the third quarter and started her most recent charter with an investment grade counterparty through the end of this year at a rate meaningfully higher than her previous charter. We also recently entered into a longer-term contract with another investment grade counterparty starting in January 2023 at a rate equal to or better than her current charter. These contracted day rates are fast approaching the original rates she commanded when we first purchased the vessel in 2014. This new arrangement will last at least six months and more likely than not throughout calendar 2023. Regardless of a slowdown in the broader economy or a policy induced recession in the United States, we expect the Jones Act compliant marine vessel market to remain tight, driven in large part by the lack of new construction, regardless of class, and the normal retirement of older tonnage.
Our onshore facilities and transportation segment performed in-line with our expectations. During the third quarter we were able to capture certain crude by rail volumes which increased segment margin, but we do not anticipate any of these volumes to continue during the fourth quarter. We are scheduled to complete a number of planned maintenance projects on our onshore facilities and transportation assets during the fourth quarter and would otherwise expect segment margin to reflect these increased costs and lower utilization. In other words, this segment could reasonably be expected to be down some $4 million relative to the third quarter. Longer term, we continue to believe our onshore facilities and transportation segment will continue to benefit as additional offshore volumes come on-line and make their way to our onshore terminals and pipelines for further delivery to refining and other demand centers along the Gulf Coast.
As we have said in the past, we continue to be very excited about the future of Genesis. The decisions we have made over the last few years, combined with the recovery in our market leading businesses off the double black swan bottom of 2020 and the expected growth we have in front of us, all combine to provide the foundation for increasing amounts of discretionary cash flow and an improving credit profile in the coming years. Our current expectations for 2023 will not only allow us to exit the year with a leverage ratio, as calculated by our banks, at or below 4 times, but will also allow us to manage our capital structure to the extent the regular way capital markets remain closed for any extended period of time. Along these lines, we have demonstrated time and time again we have tremendous support from our banks and that we are fairly creative in terms of executing on structured finance or asset sale opportunities. As a result, we are absolutely confident we have the flexibility and multiple ways to deal with any near-term maturities as well as extend, and possibly even expand, our senior secured credit commitments.
The board of directors and management continue to deliver on our stated goals. At times, it seems the market may not understand or appreciate what we see as the tremendous opportunities in front of us. However, we believe the fundamentals behind each of our businesses have never been better, and we continue to believe any recession or period of economic slowdown will not materially impact the trajectory of our financial performance. We fully intend to keep our heads down and continue to work tirelessly to deliver for all of our stakeholders now and for many years and decades to come.
3
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.
4
Financial Results
Segment Margin
Variances between the third quarter of 2022 (the “2022 Quarter”) and the third quarter of 2021 (the “2021 Quarter”) in these components are explained below.
Segment Margin results for the 2022 Quarter and 2021 Quarter were as follows:
Three Months Ended September 30,
2022
2021
(in thousands)
Offshore pipeline transportation
$
91,402
$
76,045
Sodium minerals and sulfur services
80,067
39,649
Onshore facilities and transportation
9,442
29,145
Marine transportation
15,279
9,023
Total Segment Margin
$
196,190
$
153,862
Offshore pipeline transportation Segment Margin for the 2022 Quarter increased $15.4 million, or 20%, from the 2021 Quarter due to increased crude oil and natural gas volumes (on a 100% basis) and associated revenues during the 2022 Quarter primarily as a result of first oil being achieved on April 12, 2022 at the King’s Quay floating production system. The King’s Quay floating production system, 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. During the 2022 Quarter, the volumes at King’s Quay increased significantly from the second quarter of 2022 as the operator continued to bring additional wells online and ramp up activity. In addition to this, we have contractual minimum volume commitments (“MVCs”) that began in 2022 associated with the Argos floating production system (which supports the Mad Dog 2 development) that are included in our reported Segment Margin during the 2022 Quarter. Argos is anticipated to have first oil in the coming months. Lastly, the 2021 Quarter had more downtime compared to the 2022 Quarter as a result of Hurricane Ida. These increases more than offset the effects to reported Segment Margin from our decrease in ownership of CHOPS, as we sold a 36% minority interest on November 17, 2021.
Sodium minerals and sulfur services Segment Margin for the 2022 Quarter increased $40.4 million, or 102%, from the 2021 Quarter primarily due to higher export pricing and increased volumes in our Alkali Business as well as increased volumes and pricing in our refinery services business. In our Alkali Business, we have continued to see strong demand improvement and growth as a result of the global economic recovery and the continued use of soda ash in the production of everyday end use products and in products such as solar panels and lithium batteries that are expected to play a large role in the anticipated energy transition. This continued demand improvement, combined with flat or even slightly declining supply of soda ash in the near term, has continued to tighten the overall supply and demand balance and created a higher price environment for our tons and increased contribution to Segment Margin during the 2022 Quarter. We expect to continue to see this favorable price environment for the remainder of 2022. To take advantage of the existing market conditions, we made the decision and are still on schedule to re-start our original Granger production facility and its roughly 500,000 tons of annual production in the first quarter of 2023 in advance of the completion of the Granger Optimization Project (“GOP”), which represents an incremental 750,000 tons of annual production, and is expected to have first production in the third quarter of 2023. In our refinery services business, we had an increase in NaHS sales volumes in the 2022 Quarter due to an increase in demand from our mining customers, primarily in South America, 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. Additionally, during the 2022 Quarter, we were able to continue benefiting from favorable index pricing.
Onshore facilities and transportation Segment Margin for the 2022 Quarter decreased $19.7 million, or 68%, from the 2021 Quarter. This decrease is primarily due to the 2021 Quarter including cash receipts of $17.5 million associated with our previously owned NEJD pipeline. The last principal payment associated with our previously owned NEJD pipeline was received in the fourth quarter of 2021. Additionally, the 2021 Quarter included the effects of and benefited from a one-time contractual billing of approximately $10 million. These decreases were partially offset by higher rail unload, terminal, and pipeline volumes associated with our assets in the Baton Rouge corridor as well as increased volumes on our Texas pipeline. Our increase in rail volumes was a result of our main customer sourcing volumes to replace international volumes that were impacted by certain geopolitical events through August 2022. Our Texas pipeline had increased activity during the 2022
5
Quarter as it is a key destination point for various grades of crude oil produced in the Gulf of Mexico including those transported on our 64% owned CHOPS pipeline.
Marine transportation Segment Margin for the 2022 Quarter increased $6.3 million, or 69%, from the 2021 Quarter. This increase is primarily attributable to higher utilization and day rates in our inland business and higher day rates in our offshore business, including the M/T American Phoenix (while it was on hire), during the 2022 Quarter. We have continued to see an increase in demand and utilization of our vessels due to increased refinery utilization and the increased need for movements from the Gulf Coast to the East Coast for certain products. While we have continued to see increases in our day rates from both the 2021 Quarter and sequentially from the second quarter of 2022, we have continued to enter into short term contracts (less than a year) in the inland and offshore markets because we believe the day rates currently being offered by the market have yet to fully recover from their cyclical lows. These increases were partially offset by the contribution to our reported Segment Margin from the M/T American Phoenix, as it was in its planned mandatory regulatory dry-dock from July 21, 2022 to September 16, 2022, at which time it went back on hire and is under contract for the remainder of 2022 with an investment grade customer at a more favorable rate than 2021 and the first eight months of 2022.
Other Components of Net Income (Loss)
We reported Net Income Attributable to Genesis Energy, L.P. of $3.4 million in the 2022 Quarter compared to Net Loss Attributable to Genesis Energy, L.P. of $20.9 million in the 2021 Quarter.
In addition to the overall increase to Segment Margin discussed above, Net Income Attributable to Genesis Energy, L.P. in the 2022 Quarter was impacted by: (i) the redemption of the Alkali Holdings preferred units in the second quarter of 2022 resulted in no net income attributable to redeemable noncontrolling interest compared to net income attributable to redeemable noncontrolling interest of $7.1 million in the 2021 quarter; and (ii) cancellation of debt income recognized during the 2022 Quarter of $3.9 million associated with the open market repurchase and extinguishment of certain of our senior unsecured notes. These increases during the 2022 Quarter were partially offset by: (i) an unrealized (non-cash) loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of $25.0 million in the 2022 Quarter compared to an unrealized (non-cash) gain of $1.7 million during the 2021 Quarter recorded within “Other income (expense)”; and (ii) increases in general and administrative expenses and depreciation, depletion, and amortization expenses of $6.8 million and $2.7 million, respectively, in the 2022 Quarter.
Earnings Conference Call
We will broadcast our Earnings Conference Call on Thursday, October 27, 2022, at 9:00 a.m. Central time (10:00 a.m. Eastern time). This call can be accessed at www.genesisenergy.com. Choose the Investor Relations button. For those unable to attend the live broadcast, a replay will be available beginning approximately one hour after the event and remain available on our website for 30 days. There is no charge to access the event.
Genesis Energy, L.P. is a diversified midstream energy master limited partnership headquartered in Houston, Texas. Genesis’ operations include offshore pipeline transportation, sodium minerals and sulfur services, onshore facilities and transportation and marine transportation. Genesis’ operations are primarily located in Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida, Wyoming and the Gulf of Mexico.
6
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,
2022
2021
2022
2021
REVENUES
$
721,248
$
518,821
$
2,074,920
$
1,543,895
COSTS AND EXPENSES:
Costs of sales and operating expenses
555,169
402,808
1,621,619
1,215,924
General and administrative expenses
17,038
14,371
52,825
38,944
Depreciation, depletion and amortization
73,946
67,148
217,125
200,975
Gain on sale of asset
—
—
(40,000)
—
OPERATING INCOME
75,095
34,494
223,351
88,052
Equity in earnings of equity investees
13,236
10,301
40,252
45,183
Interest expense
(57,710)
(59,940)
(168,773)
(176,938)
Other income (expense)
(21,388)
1,741
(10,758)
(34,169)
INCOME (LOSS) BEFORE INCOME TAXES
9,233
(13,404)
84,072
(77,872)
Income tax expense
(660)
(423)
(1,535)
(1,170)
NET INCOME (LOSS)
8,573
(13,827)
82,537
(79,042)
Net loss (income) attributable to noncontrolling interests
(5,188)
10
(18,612)
(124)
Net income attributable to redeemable noncontrolling interests
—
(7,082)
(30,443)
(17,639)
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.
$
3,385
$
(20,899)
$
33,482
$
(96,805)
Less: Accumulated distributions attributable to Class A Convertible Preferred Units
Natural gas transportation volumes (MMBtus/day)(1)
358,618
317,025
338,598
329,908
Sodium Minerals and Sulfur Services Segment
NaHS (dry short tons sold)
29,441
27,873
97,243
84,727
Soda Ash volumes (short tons sold)
776,284
686,851
2,293,213
2,221,803
NaOH (caustic soda) volumes (dry short tons sold)(2)
23,186
22,456
65,983
63,842
Onshore Facilities and Transportation Segment
Crude oil pipelines (barrels/day):
Texas(3)
113,962
64,027
92,508
60,561
Jay
5,481
7,694
6,348
8,133
Mississippi
5,800
5,088
5,926
5,171
Louisiana
40,171
38,454
41,024
49,305
Onshore crude oil pipelines total
165,414
115,263
145,806
123,170
Crude oil and petroleum products sales (barrels/day)
25,613
20,878
23,860
24,292
Rail unload volumes (barrels/day)(4)
15,130
3,001
14,485
15,466
Marine Transportation Segment
Inland Fleet Utilization Percentage(5)
100.0
%
79.9
%
97.3
%
77.7
%
Offshore Fleet Utilization Percentage(5)
94.0
%
93.5
%
96.1
%
95.2
%
(1)On November 17, 2021, we sold a 36% minority interest in our CHOPS pipeline. As of September 30, 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. Volumes during the nine months ended September 30, 2021 were impacted as a result of the CHOPS pipeline being out of service from August 26, 2020 to February 4, 2021.
(4)Indicates total barrels for which fees were charged for unloading at all rail facilities.
(5)Utilization rates are based on a 365-day year, as adjusted for planned downtime and dry-docking.
8
GENESIS ENERGY, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except units)
September 30, 2022
December 31, 2021
(unaudited)
ASSETS
Cash, cash equivalents and restricted cash
$
24,485
$
24,992
Accounts receivable - trade, net
575,927
400,334
Inventories
92,907
77,958
Other current assets
33,111
39,200
Total current assets
726,430
542,484
Fixed assets and mineral leaseholds, net of accumulated depreciation and depletion
4,566,499
4,461,190
Equity investees
285,417
294,050
Intangible assets, net of amortization
127,201
127,063
Goodwill
301,959
301,959
Right of use assets, net
128,288
140,796
Other assets, net of amortization
33,745
38,259
Total assets
$
6,169,539
$
5,905,801
LIABILITIES AND CAPITAL
Accounts payable - trade
$
378,367
$
264,316
Accrued liabilities
266,950
232,623
Total current liabilities
645,317
496,939
Senior secured credit facility
120,200
49,000
Senior unsecured notes, net of debt issuance costs and premium
2,854,874
2,930,505
Alkali senior secured notes, net of debt issuance costs and discount
402,254
—
Deferred tax liabilities
15,307
14,297
Other long-term liabilities
373,397
434,925
Total liabilities
4,411,349
3,925,666
Mezzanine capital:
Class A Convertible Preferred Units
891,909
790,115
Redeemable noncontrolling interests
—
259,568
Partners’ capital:
Common unitholders
562,373
641,313
Accumulated other comprehensive loss
(5,242)
(5,607)
Noncontrolling interests
309,150
294,746
Total partners’ capital
866,281
930,452
Total liabilities, mezzanine capital and partners’ capital
$
6,169,539
$
5,905,801
Common Units Data:
Total common units outstanding
122,579,218
122,579,218
9
GENESIS ENERGY, L.P.
RECONCILIATION OF NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P. TO SEGMENT MARGIN - UNAUDITED
(in thousands)
Three Months Ended September 30,
2022
2021
Net income (loss) attributable to Genesis Energy, L.P.
$
3,385
$
(20,899)
Corporate general and administrative expenses
18,132
14,878
Depreciation, depletion, amortization and accretion
76,301
69,665
Interest expense
57,710
59,940
Income tax expense
660
423
Change in provision for leased items no longer in use
(68)
—
Cancellation of debt income(1)
(3,881)
—
Redeemable noncontrolling interest redemption value adjustments(2)
—
7,082
Plus (minus) Select Items, net(3)
43,951
22,773
Segment Margin(4)
$
196,190
$
153,862
(1)The 2022 Quarter includes income associated with the repurchase and extinguishment of certain of our senior unsecured notes on the open market.
(2)The 2021 Quarter includes PIK distributions and accretion on the redemption feature. The associated Alkali Holdings preferred units were fully redeemed during the second quarter of 2022.
(3)Refer to additional detail of Select Items later in this press release.
(4)See definition of Segment Margin later in this press release.
10
GENESIS ENERGY, L.P.
RECONCILIATIONS OF NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY L.P. TO ADJUSTED EBITDA AND AVAILABLE CASH BEFORE RESERVES - UNAUDITED
(in thousands)
Three Months Ended September 30,
2022
2021
Net income (loss) attributable to Genesis Energy, L.P.
$
3,385
$
(20,899)
Interest expense
57,710
59,940
Income tax expense
660
423
Depreciation, depletion, amortization and accretion
76,301
69,665
EBITDA
138,056
109,129
Redeemable noncontrolling interest redemption value adjustments(1)
—
7,082
Plus (minus) Select Items, net(2)
45,583
24,309
Adjusted EBITDA(3)
183,639
140,520
Maintenance capital utilized(4)
(14,400)
(13,500)
Interest expense
(57,710)
(59,940)
Cash tax expense
(250)
(195)
Distributions to preferred unitholders(5)
(18,684)
(18,684)
Available Cash before Reserves(6)
$
92,595
$
48,201
(1)The 2021 Quarter includes PIK distributions and accretion on the redemption feature. The associated Alkali Holdings preferred units were fully redeemed during the second quarter of 2022.
(2)Refer to additional detail of Select Items later in this press release.
(3)See definition of Adjusted EBITDA later in this press release.
(4)Maintenance capital expenditures in the 2022 Quarter and 2021 Quarter were $44.3 million and $23.1 million, respectively. Our maintenance capital expenditures are principally associated with our alkali and marine transportation businesses.
(5)Distributions to preferred unitholders attributable to the 2022 Quarter are payable on November 14, 2022 to unitholders of record at close of business on October 31, 2022.
(6)Represents the Available Cash before Reserves to common unitholders.
11
GENESIS ENERGY, L.P.
RECONCILIATION OF NET CASH FLOWS FROM OPERATING ACTIVITIES TO ADJUSTED EBITDA - UNAUDITED
(in thousands)
Three Months Ended September 30,
2022
2021
Cash Flows from Operating Activities
$
94,308
$
54,173
Adjustments to reconcile net cash flows from operating activities to Adjusted EBITDA:
Interest Expense
57,710
59,940
Amortization and write-off of debt issuance costs, discount and premium
(2,458)
(2,277)
Effects of available cash from equity method investees not included in operating cash flows
4,365
7,021
Net effect of changes in components of operating assets and liabilities
22,346
24,815
Non-cash effect of long-term incentive compensation plans
(4,191)
(2,227)
Expenses related to business development activities and growth projects
939
903
Differences in timing of cash receipts for certain contractual arrangements(1)
13,775
657
Other items, net
(3,155)
(2,485)
Adjusted EBITDA(2)
$
183,639
$
140,520
(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.
12
GENESIS ENERGY, L.P.
ADJUSTED DEBT-TO-ADJUSTED CONSOLIDATED EBITDA RATIO - UNAUDITED
(in thousands)
September 30, 2022
Senior secured credit facility
$
120,200
Senior unsecured notes, net of debt issuance costs and premium
(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 our sale of a 36% interest in CHOPS and pro forma adjustments associated with the May 17, 2022 issuance of our Alkali senior secured notes, which are secured by a fifty-year limited term overriding royalty interest in our trona mineral leases. These adjustments may not be indicative of future results.
(3) Adjusted Consolidated EBITDA for the four-quarter period ending with the most recent quarter, as calculated under our senior secured credit facility.
This press release includes forward-looking statements as defined under federal law. Although we believe that our expectations are based upon reasonable assumptions, we can give no assurance that our goals will be achieved. Actual results may vary materially. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that we expect, believe or anticipate will or may occur in the future, including but not limited to statements relating to future financial and operating results and compliance with our senior secured credit facility covenants, the timing and anticipated benefits of the King’s Quay and Argos developments, our expectations regarding our Granger expansion, the expected performance of our other projects and business segments, and our strategy and plans, are forward-looking statements, and historical performance is not necessarily indicative of future performance. Those forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside our control, that could cause results to differ materially from those expected by management. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for products (which may be affected by the actions of OPEC and other oil exporting nations), impacts due to inflation, and a reduction in demand for our services resulting in impairments of our assets, the spread of disease (including Covid-19), the impact of international military conflicts (such as the conflict in Ukraine),the result of any economic recession or depression that has occurred or may occur in the future, construction and anticipated benefits of the SYNC pipeline and expansion of the capacity of the CHOPS system, the timing and success of business development efforts and other uncertainties. Those and other applicable uncertainties, factors and risks that may affect those forward-looking statements are described more fully in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Securities and Exchange Commission and other filings, including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q. We undertake no obligation to publicly update or revise any forward-looking statement.
13
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; and 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, also referred to 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.
14
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 have been and will continue to 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 recently 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. Our maintenance capital utilized measure, which is described in more detail below, 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 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 initially 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.
15
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 and amortization (including impairment, write-offs, accretion and similar items, often referred to as EBITDA) 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 September 30,
2022
2021
(in thousands)
I.
Applicable to all Non-GAAP Measures
Differences in timing of cash receipts for certain contractual arrangements(1)
$
13,775
$
657
Distributions from unrestricted subsidiaries not included in income(2)
—
17,500
Certain non-cash items:
Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value(3)
26,295
(1,708)
Loss on debt extinguishment
293
—
Adjustment regarding equity investees(4)
5,247
7,142
Other
(1,659)
(818)
Sub-total Select Items, net(5)
43,951
22,773
II.
Applicable only to Adjusted EBITDA and Available Cash before Reserves
Certain transaction costs
939
903
Other
693
633
Total Select Items, net(6)
$
45,583
$
24,309
(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 2021 Quarter includes $17.5 million in cash receipts associated with principal repayments on our previously owned NEJD pipeline not included in income. We received the last principal payment associated with our previously owned NEJD pipeline in the fourth quarter of 2021. Genesis NEJD Pipeline, LLC is defined as an unrestricted subsidiary under our senior secured credit facility.
(3) The 2022 Quarter includes an unrealized loss of $25.0 million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. The 2021 Quarter includes an unrealized gain of $1.7 million from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units.
16
(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.
