Genesis Energy, L.P. Reports Second Quarter 2025 Results

Globe and Mail

5 days ago

Genesis Energy, L.P. (NYSE: GEL) today announced its second quarter results.
We generated the following financial results for the second quarter of 2025:
Net Loss Attributable to Genesis Energy, L.P. of $0.4 million for the second quarter of 2025 compared to Net Loss Attributable to Genesis Energy, L.P. of $8.7 million for the same period in 2024.
Cash Flows from Operating Activities of $47.0 million for the second quarter of 2025 compared to $104.7 million for the same period in 2024.
We declared cash distributions on our preferred units of $0.9473 for each preferred unit, which equates to a cash distribution of approximately $14.9 million and is reflected as a reduction to Available Cash before Reserves to common unitholders.
Available Cash before Reserves to common unitholders of $32.2 million for the second quarter of 2025, which provided 1.59X coverage for the quarterly distribution of $0.165 per common unit attributable to the second quarter.
Total Segment Margin of $135.9 million for the second quarter of 2025.
Adjusted EBITDA of $122.9 million for the second quarter of 2025.
Adjusted Consolidated EBITDA of $555.4 million for the trailing twelve months ended June 30, 2025 and a bank leverage ratio of 5.52X, both calculated in accordance with our senior secured credit agreement and discussed further in this release.
Grant Sims, CEO of Genesis Energy, said, 'The second quarter was generally in-line with our expectations, driven primarily by sequential improvement in our offshore pipeline transportation segment as several of the previously shut-in wells returned to service in addition to collecting one month's contribution from our minimum volume commitments from the Shenandoah development. More importantly, because we are in the business of actually moving oil, I am extremely happy to report on the successful commissioning and start-up of the Shenandoah production facility which delivered first oil to our new SYNC pipeline lateral and downstream through our expanded CHOPS pipeline just last week. While initial production was delayed a number of weeks due to some commissioning challenges, including persistent loop currents in the Gulf of America affecting sub-sea activities early in the quarter, the operator has successfully brought on-line the first of four previously drilled and completed wells. We anticipate the remaining wells will be brought online in the coming weeks, with production ramping steadily and likely to achieve initial anticipated peak production of 90-100 kbd. This important milestone is the culmination of over three years of hard work and dedication from our entire team, and I could not be prouder of their collective effort.
Looking ahead, Salamanca remains on track to achieve first oil by the end of the third quarter. The operator, who has been largely dependent on some of the same support equipment and vessels that are currently working on Shenandoah, has been progressing through their safety checks and pre-commissioning activities, including their sub-sea connection to our SEKCO pipeline lateral in advance of first production. Similar to Shenandoah, we expect Salamanca's production to ramp very quickly over the subsequent few months after first production to its initial peak design of 40-50 kbd. Despite both Shenandoah and Salamanca experiencing some timing delays, these two new developments remain central to the Genesis story over the next 12 to 18 months. With the anticipated increase in our offshore pipeline transportation segment margin, the completion of our growth capital expenditures, and continued steady performance from our legacy businesses, we remain well positioned to generate increasing amounts of free cash flow in excess of the cash costs of running our businesses starting in the third quarter.
We exited the second quarter with approximately $72 million outstanding on our senior secured revolving credit facility, which included approximately $36 million of hedged inventory and was a reflection of a high working capital quarter. This included several significant cash outlays such as the full redemption of our senior unsecured notes due 2027, final growth capital associated with our offshore expansion projects, and multiple semi-annual cash interest payments on our outstanding senior unsecured notes. Importantly, we expect to use the estimated free cash flow to begin paying down the revolver balance in the third quarter, and we anticipate exiting the year with no outstanding borrowings under such facility. The combination of growing Segment Margin and a lower absolute debt balance is also expected to drive sequential improvement in our bank calculated leverage ratio over the remainder of the year and throughout 2026.
We remain steadfast in our commitment to creating long-term value for all stakeholders. As our financial flexibility and liquidity continue to improve, we intend to take an all-of-the-above approach to capital allocation. This includes the reduction of debt in absolute terms, the possible redemption of our high-cost corporate preferreds, and the potential for increased distributions to our common unitholders in future quarters. At the same time, we will remain disciplined and balanced, preserving the ability to evaluate and pursue incremental commercial opportunities that align with our long-term strategic objectives.
With that, I will briefly discuss our individual business segments in more detail.
During the quarter, our offshore pipeline transportation segment saw an uplift in activity as a couple of the previously impacted offshore wells that had been down due to producer mechanical issues were brought back online and are now flowing again on our pipelines. While a couple of the high margin wells remain offline, the producers continue to have deepwater drilling rigs on location that are actively working to restore the production in conjunction with drilling new development wells that will also be tied into these existing production facilities. Notwithstanding the ramp in volumes from Shenandoah and Salamanca, the base volumes from these impacted fields as we exited the second quarter were greater than what we saw when we exited the first quarter, and we would expect to see this upward trend continue with the expectation of the remaining work being completed, by and large, by the end of the third quarter. There is no doubt these delays have been unfortunate. While the remediation efforts have lagged behind our original expectations, we believe there continues to be no lasting impact on the underlying reservoirs, and we will ultimately transport all of the oil production on our systems once all these issues are successfully addressed by the various operators.
Despite recent fluctuations in commodity prices, we continue to experience strong activity levels from our producer customers in the central Gulf of America. While the number of active onshore drilling rigs has declined in recent weeks, perhaps more rapidly than some anticipated, we have seen no change in the number of rigs actively working offshore in the deepwater. This underscores the structural resilience of deepwater development, where investment decisions are based on long-cycle planning rather than short-term price movements. Many of our producer customers remain focused on maximizing output from existing facilities while advancing a robust backlog of sub-sea tieback and development drilling opportunities. We remain actively engaged in commercial discussions to connect several of these new opportunities to our offshore infrastructure throughout the remainder of this year and into next. Given the long-term nature of these developments, and the increasingly economic break-even costs, we do not expect continued price weakness or any additional near-term macroeconomic headwinds to significantly alter deepwater activity in the Gulf of America for the foreseeable future.
Our marine transportation segment performed in line with expectations during the second quarter. Market fundamentals for our inland, or brown water, fleet remain constructive. While refinery profitability was challenged during the quarter and refinery crude slates, particularly in the Midwest, shifted, and heavy to light differentials narrowed on the Gulf Coast, market conditions continue to be supported by limited to no net additions of Jones Act-qualified tonnage. Looking ahead, we expect to see a robust refinery turnaround season in the third and fourth quarters, which should drive increased demand for our brown water equipment. In contrast, market conditions in the blue water market have softened somewhat in recent months. This shift is largely driven by an increase in available equipment along the Gulf and East Coasts, as larger operators redeploy vessels that were otherwise working in West Coast markets. The added tonnage, coupled with a slowdown in clean product demand moving to the East Coast, has kept utilization relatively stable. However, these factors have tempered our ability to continue to push day rates higher as term charters come up for renewal. Looking ahead, while market conditions remain mixed, we believe the fundamentals of our marine transportation segment are sound and should be supportive throughout the remainder of this year and in the years to come.
Our onshore transportation and services segment performed in line with expectations during the quarter. We experienced higher than anticipated volumes through both our Texas system and Raceland terminal, driven by increased refinery demand in both Texas City and South Louisiana. Beginning in the third quarter, we could see a modest increase in volumes through both our Texas City and Raceland terminals as new production from Shenandoah and Salamanca comes online and quickly ramps. Our legacy sulfur services business also performed as expected, though results were modestly impacted by an unplanned turnaround at our primary host facility in Westlake, Louisiana. This was partially offset by strong operating performance in June, driven in large part by the continued strength in pulp and paper demand.
As we look at the back half of the year, I would like to briefly touch on the financial impact of both the extended outages related to producer mechanical issues, which we have referenced for several quarters, and the unfortunate timing delays in receiving first oil from both Shenandoah and Salamanca. While these factors have been entirely outside of our control, they have nonetheless delayed the timing of when we will realize the full financial benefit of these volumes on our pipeline systems. Based on our current visibility into final remediation efforts, the expected timing of first production from both new developments and their anticipated pace of ramping production, we now reasonably expect full-year 2025 Adjusted EBITDA to be at or near the low end of our prior guidance range of $545–$575 million (1). More importantly, these delays are all temporary in nature and are not expected to have any lasting impact on our ability to generate increasing Adjusted EBITDA and free cash flow in 2026 and beyond.
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.'
Financial Results
Segment Margin
Segment Margin
In the first quarter of 2025, we reorganized our operating segments as a result of the way our chief operating decision maker (our Chief Executive Officer) evaluates the performance of operations, develops strategy and allocates resources, including capital. Our sulfur services business, formerly reported under our Soda and Sulfur Services reporting segment with our trona and trona-based exploring, mining, processing, producing, marketing, logistics and selling business based in Wyoming (the 'Alkali Business'), is now reported under our onshore transportation and services reporting segment along with our previously reported onshore facilities and transportation segment. As a result of this change, we now manage our businesses through the following three divisions that constitute our reportable segments:
Offshore pipeline transportation, which includes the transportation and processing of crude oil and natural gas in the Gulf of America;
Marine transportation, which provides waterborne transportation of petroleum products (primarily fuel oil, asphalt and other heavy refined products) and crude oil throughout North America; and
Onshore transportation and services, which includes terminaling, blending, storing, marketing, and transporting crude oil and petroleum products, as well as the processing of high sulfur (or 'sour') gas streams for refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or 'NaHS,' commonly pronounced 'nash').
Variances between the second quarter of 2025 (the '2025 Quarter') and the second quarter of 2024 (the '2024 Quarter') in these components are explained below.
Segment Margin results for the 2025 Quarter and 2024 Quarter were as follows:
Offshore pipeline transportation Segment Margin for the 2025 Quarter increased $1.5 million, or 2%, from the 2024 Quarter primarily due to several factors including: (i) the commencement of contractual minimum volume commitments ('MVC's') on our 100% owned SYNC Pipeline and 64% owned CHOPS Pipeline associated with the deepwater Shenandoah development that began in June 2025 and contributed to our reported Segment Margin; and (ii) an increase in volumes on our CHOPS Pipeline primarily related to production from the Warrior and Winterfell projects, which produced first oil in late June 2024 and early July 2024, respectively. Production volumes from the Shenandoah floating production system ('FPS') are life-of-lease dedicated to our 100% owned SYNC Pipeline and further downstream to our 64% owned CHOPS Pipeline. The Shenandoah FPS achieved first oil production in late July 2025, but we were able to recognize our MVC's that began in the 2025 Quarter in Segment Margin. We expect the Shenandoah FPS to ramp up to its design capacity over the remainder of the year as the operator brings additional wells on-line. These increases to Segment Margin in the 2025 Quarter were partially offset by: (i) an economic step-down in the rate on a certain existing life-of-lease transportation dedication; (ii) producer underperformance at several of the major fields attached to our pipeline infrastructure; and (iii) an increase in our operating costs. At the beginning of the third quarter of 2024, we reached the 10-year anniversary of a certain existing life-of-lease transportation dedication, which resulted in the contractual economic step-down of the associated transportation rate. In addition, there was an increase in producer downtime in the 2025 Quarter relative to the 2024 Quarter as a result of several wells being shut in due to certain sub-sea operational and technical challenges. The production from these wells impacted our results as they are molecules that we touch multiple times throughout our oil and natural gas pipeline infrastructure.
Marine transportation Segment Margin for the 2025 Quarter decreased $1.7 million, or 5%, from the 2024 Quarter. We experienced slightly lower utilization rates during the 2025 Quarter in our inland barge services primarily due to a slight decline in Midwest refinery demand for black oil equipment as a result of changing crude slates. This was partially offset by fewer dry-docking days in our offshore fleet during the 2025 Quarter and a higher contractual rate on our M/T American Phoenix in the 2025 Quarter as compared to the 2024 Quarter. Our offshore bluewater business began to experience pressure on day rates during the 2025 Quarter and as we entered the third quarter as certain third-party vessels were relocated to the East and Gulf coasts from the West Coast markets.
Onshore transportation and services Segment Margin for the 2025 Quarter decreased $1.8 million, or 9%, from the 2024 Quarter primarily due to lower NaHS and caustic soda sales volumes. This decrease was partially offset by an increase in rail unload volumes at our Scenic Station facility and an overall increase in volumes on our onshore crude oil pipeline systems, principally driven by an increase in volumes on our Texas pipeline system, which is a key destination point for various grades of crude oil produced in the Gulf of America including those transported on our 64% owned CHOPS Pipeline.
Other Components of Net Income (Loss)
We reported Net Income from Continuing Operations of $10.0 million in the 2025 Quarter compared to Net Loss from Continuing Operations of $4.0 million in the 2024 Quarter.
Net Income from Continuing Operations in the 2025 Quarter was impacted by: (i) an increase in operating income from our operating segments; (ii) a decrease in interest expense, net, of $3.8 million; and (iii) a decrease in general and administrative expenses of $3.6 million relative to the 2024 Quarter. These were partially offset by an increase in depreciation and amortization of $4.7 million during the 2025 Quarter and an increase in other expense of $7.5 million primarily related to the premium associated with the redemption of our 2027 Notes in April 2025.
We reported Net Income from Discontinued Operations, net of tax of $2.6 million during the 2024 Quarter associated with the Alkali Business that was sold on February 28, 2025.
Earnings Conference Call
We will broadcast our Earnings Conference Call on Thursday, July 31, 2025, 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, marine transportation and onshore transportation and services. Genesis' operations are primarily located in the Gulf of America and in the Gulf Coast region of the United States.
Three Months Ended
June 30,
Six Months Ended
June 30,
2025
2024
2025
2024
COSTS AND EXPENSES:
Costs of sales and operating costs
238,984
310,934
518,509
623,235
General and administrative
14,744
18,299
55,386
32,999
Depreciation and amortization
55,905
51,167
112,076
100,558
OPERATING INCOME
67,715
49,779
89,688
107,834
Equity in earnings of equity investees
12,330
12,213
24,822
28,654
Interest expense, net
(60,754
)
(64,539
)
(130,792
)
(126,873
)
Other expense
(8,935
)
(1,429
)
(9,779
)
(1,429
)
Income (loss) from continuing operations before income taxes
10,356
(3,976
)
(26,061
)
8,186
Income tax benefit (expense)
(345
)
11
(489
)
(798
)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS
10,011
(3,965
)
(26,550
)
7,388
Income from discontinued operations, net of tax
—
2,578
8,448
10,181
Loss from disposal of discontinued operations
—
—
(432,193
)
—
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF TAX
—
2,578
(423,745
)
10,181
NET INCOME (LOSS)
10,011
(1,387
)
(450,295
)
17,569
Net income attributable to noncontrolling interests
(10,417
)
(7,357
)
(19,186
)
(14,960
)
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.
$
(406
)
$
(8,744
)
$
(469,481
)
$
2,609
Less: Accumulated distributions and returns attributable to Class A Convertible Preferred Units
(14,868
)
(21,894
)
(43,270
)
(43,788
)
NET LOSS ATTRIBUTABLE TO COMMON UNITHOLDERS
$
(15,274
)
$
(30,638
)
$
(512,751
)
$
(41,179
)
NET INCOME (LOSS) PER COMMON UNIT:
Net loss from continuing operations per common unit - Basic and Diluted
$
(0.12
)
$
(0.27
)
$
(0.73
)
$
(0.42
)
Net income (loss) from discontinued operations per common unit - Basic and Diluted
—
0.02
(3.46
)
0.08
Net loss per common unit - Basic and Diluted
$
(0.12
)
$
(0.25
)
$
(4.19
)
$
(0.34
)
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted
122,464,318
122,464,318
122,464,318
122,464,318
GENESIS ENERGY, L.P.
OPERATING DATA - UNAUDITED
Three Months Ended
June 30,
Six Months Ended
June 30,
2025
2024
2025
2024
Offshore Pipeline Transportation Segment
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS (1)
324,533
296,325
318,787
297,319
Poseidon (1)
248,785
280,248
246,566
286,085
Odyssey (1)
71,309
64,213
67,545
63,955
GOPL
1,383
1,465
1,532
1,911
Offshore crude oil pipelines total
646,010
642,251
634,430
649,270
Natural gas transportation volumes (MMBtus/day) (1)
403,703
357,687
402,739
382,621
Marine Transportation Segment
Inland Barge Utilization Percentage (2)
98.1
%
100.0
%
95.9
%
100.0
%
Offshore Barge Utilization Percentage (2)
97.3
%
94.9
%
96.8
%
97.0
%
Onshore Transportation and Services Segment
Crude oil pipelines (average barrels/day):
Texas (3)
98,626
65,229
80,377
74,923
Jay
4,036
5,332
4,181
5,396
Mississippi
1,059
2,789
1,124
2,800
Louisiana (4)
48,178
56,172
43,203
64,514
Onshore crude oil pipelines total
151,899
129,522
128,885
147,633
Crude oil product sales (average barrels/day)
15,366
21,702
17,655
22,570
Rail unload volumes (average barrels/day)
24,979
19,811
22,748
10,526
NaHS volumes (Dry short tons 'DST')
23,256
29,656
49,129
58,693
NaOH (caustic soda) volumes (DST sold)
8,678
10,593
17,223
20,951
(1)
As of June 30, 2025 and 2024, 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)
Utilization rates are based on a 365-day year, as adjusted for planned downtime and dry-docking.
(3)
Our Texas pipeline and infrastructure is a destination point for many pipeline systems in the Gulf of America, including the CHOPS pipeline.
(4)
Total daily volumes for the three months ended June 30, 2025 and June 30, 2024 include 16,403 and 19,356 Bbls/day, respectively, of intermediate refined products and 31,775 and 36,269 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines. Total daily volumes for the six months ended June 30, 2025 and June 30, 2024 include 17,500 and 24,766 Bbls/day, respectively, of intermediate refined petroleum products and 25,703 and 39,059 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines.
(in thousands, except unit amounts)
June 30, 2025
December 31, 2024
(unaudited)
ASSETS
Cash and cash equivalents
$
4,452
$
7,352
Accounts receivable - trade, net
499,590
479,504
Inventories
58,184
37,782
Other
25,082
18,789
Current assets held for discontinued operations
—
368,307
Total current assets
587,308
911,734
Fixed assets, net of accumulated depreciation
3,525,628
3,539,886
Equity investees
228,682
240,368
Intangible assets, net of amortization
80,449
85,287
Goodwill
301,959
301,959
Right of use assets, net
58,605
65,739
Other assets
55,907
53,606
Non-current assets held for discontinued operations
—
1,839,113
Total assets
$
4,838,538
$
7,037,692
LIABILITIES AND CAPITAL
Accounts payable - trade
$
414,436
$
388,245
Accrued liabilities
207,469
254,202
Current liabilities held for discontinued operations
—
216,308
Total current liabilities
621,905
858,755
Senior secured credit facility
71,600
291,000
Senior unsecured notes, net of debt issuance costs, discount and premium
3,035,915
3,436,860
Deferred tax liabilities
16,764
16,575
Other long-term liabilities
374,950
389,161
Long-term liabilities held for discontinued operations
—
529,558
Total liabilities
4,121,134
5,521,909
Mezzanine capital:
Class A Convertible Preferred Units
552,523
813,589
Partners' capital (deficit):
Common unitholders
(273,274
)
279,891
Accumulated other comprehensive income
—
9,486
Noncontrolling interests
438,155
412,817
Total partners' capital
164,881
702,194
Total liabilities, mezzanine capital and partners' capital
$
4,838,538
$
7,037,692
Common Units Data:
Total common units outstanding
122,464,318
122,464,318
(in thousands)
Three Months Ended
June 30,
Six Months Ended
June 30,
2025
2024
2025
2024
Income (loss) from continuing operations before income taxes
$
10,356
$
(3,976
)
$
(26,061
)
$
8,186
Net income attributable to noncontrolling interests
(10,417
)
(7,357
)
(19,186
)
(14,960
)
Corporate general and administrative expenses
15,068
19,405
56,744
34,616
Depreciation, amortization and accretion
59,011
53,940
118,022
106,103
Interest expense, net
60,754
64,539
130,792
126,873
Adjustment to include distributable cash generated by equity investees not included in income and exclude equity in investees net income (1)
5,595
4,879
11,687
11,687
Unrealized gains on derivative transactions excluding fair value hedges, net of changes in inventory value
(133
)
(289
)
(204
)
(42
)
Other non-cash items
(4,229
)
(2,474
)
(6,951
)
(4,601
)
Loss on extinguishment of debt
8,935
1,429
9,779
1,429
Differences in timing of cash receipts for certain contractual arrangements (2)
(9,071
)
7,820
(17,358
)
15,892
Total Segment Margin (3)
$
135,869
$
137,916
$
257,264
$
285,183
(1)
Includes distributions attributable to the quarter and received during or promptly following such quarter.
(2)
Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts.
(3)
See definition of Segment Margin later in this press release.
(in thousands)
Three Months Ended
June 30,
Six Months Ended
June 30,
2025
2024
2025
2024
Net income (loss) attributable to Genesis Energy, L.P.
$
(406
)
$
(8,744
)
$
(469,481
)
$
2,609
Interest expense, net
60,754
64,539
130,792
126,873
Income tax expense (benefit)
345
(11
)
489
798
Depreciation, amortization and accretion
59,011
53,940
118,022
106,103
Loss from disposal of discontinued operations
—
—
432,193
—
Interest expense and income tax expense from discontinued operations
—
6,364
4,195
12,764
Other non-cash items from discontinued operations, net (1)
—
20,853
15,584
39,843
EBITDA
119,704
136,941
231,794
288,990
Plus (minus) Select Items, net (2)
3,195
11,937
22,784
22,964
Adjusted EBITDA (3)
122,899
148,878
254,578
311,954
Maintenance capital utilized (4)
(14,750
)
(18,200
)
(31,650
)
(36,300
)
Interest expense, net
(60,754
)
(64,539
)
(130,792
)
(126,873
)
Cash tax expense
(300
)
(300
)
(557
)
(600
)
Distributions to preferred unitholders (5)
(14,868
)
(21,894
)
(34,810
)
(43,788
)
Interest expense and income tax expense from discontinued operations
—
(6,364
)
(4,195
)
(12,764
)
Available Cash before Reserves (6)
$
32,227
$
37,581
$
52,574
$
91,629
(1)
Includes non-cash items such as depreciation, depletion and amortization and unrealized gains or losses on derivative transactions, amongst other non-cash items attributable to discontinued operations.
(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 for the 2025 Quarter and 2024 Quarter were $16.8 million and $29.4 million, respectively, which excludes maintenance capital expenditures of $17.7 million for the 2024 Quarter associated with the Alkali Business that was sold on February 28, 2025. Maintenance capital expenditures for the six months ended June 30, 2025 and 2024, were $39.4 million and $44.5 million, respectively, which excludes maintenance capital expenditures of $4.6 million and $29.1 million for the six months ended June 30, 2025 and 2024, respectively, associated with the Alkali Business. Our continuing maintenance capital expenditures are principally associated with our marine transportation business.
(5)
Distributions to preferred unitholders attributable to the 2025 Quarter are payable on August 14, 2025 to unitholders of record at close of business on July 31, 2025.
(in thousands)
Three Months Ended
June 30,
Six Months Ended
June 30,
2025
2024
2025
2024
Cash Flows from Operating Activities
$
46,987
$
104,721
$
71,792
$
230,642
Adjustments to reconcile net cash flows from operating activities to Adjusted EBITDA:
Interest expense, net (1)
60,754
70,870
134,971
139,604
Amortization and write-off of debt issuance costs, premium and discount
(3,549
)
(4,486
)
(7,406
)
(7,370
)
Effects from equity method investees not included in operating cash flows
5,797
4,007
11,949
11,687
Net effect of changes in components of operating assets and liabilities
37,691
(20,759
)
70,059
(49,232
)
Non-cash effect of long-term incentive compensation plans
(3,153
)
(5,471
)
(5,638
)
(9,786
)
Expenses related to business development activities and growth projects
310
37
25,518
60
Differences in timing of cash receipts for certain contractual arrangements (2)
(9,071
)
7,820
(17,358
)
15,892
Other items, net (3)
(12,867
)
(7,861
)
(29,309
)
(19,543
)
Adjusted EBITDA (4)
$
122,899
$
148,878
$
254,578
$
311,954
(1)
Includes interest expense, net of $60.8 million and $130.8 million from continuing operations for the three and six months ended June 30, 2025, respectively, and includes interest expense, net of $4.2 million from discontinued operations for the six months ended June 30, 2025. Includes interest expense, net of $64.5 million and $126.9 million from continuing operations for the three and six months ended June 30, 2024, respectively, and includes interest expense, net of $6.4 million and $12.7 million from discontinued operations for the three and six months ended June 30, 2024, respectively.
(2)
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.
(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.
(in thousands)
June 30, 2025
Senior secured credit facility
$
71,600
Senior unsecured notes, net of debt issuance costs and discount
3,035,915
Less: Outstanding inventory financing sublimit borrowings
(36,000
)
Less: Cash and cash equivalents
(3,448
)
Adjusted Debt (1)
$
3,068,067
Pro Forma LTM
June 30, 2025
Consolidated EBITDA (per our senior secured credit facility)
$
535,717
Consolidated EBITDA adjustments (2)
19,717
Adjusted Debt-to-Adjusted Consolidated EBITDA
5.52X
(1)
We define Adjusted Debt as the amounts outstanding under our senior secured credit facility and senior unsecured notes (including any unamortized discounts 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. For any material organic growth project not yet completed or in-service, the EBITDA Adjustment is calculated based on the percentage of capital expenditures incurred to date relative to the expected budget multiplied by the total annual contractual minimum cash commitments we expect to receive as a result of the project. Additionally, it includes the pro forma adjustments to Adjusted Consolidated EBITDA (using historical amounts in the test period) associated with the sale of the Alkali Business. 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, liquidity and capital expenditures, anticipated benefits from the sale of the Alkali Business, distributions to our unitholders or other capital allocation plans or expectations, the timing or anticipated benefits of the Shenandoah and Salamanca developments, production rates or volumes or refinery demand, the expected performance of our offshore assets and other projects and business segments, the impact of proposed or increased tariffs or lower commodity prices on our business, 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, increased tariffs and proposed tariffs, taxes, duties and similar matters affecting international trade, 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, the Israel and Hamas war and broader geopolitical tensions in the Middle East and Eastern Europe), the result of any economic recession or depression that has occurred or may occur in the future, 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, 2024 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, interest expense, net, 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 to make those expenditures, we would be able to continue to operate those assets economically, although in lieu of maintenance capital expenditures, we would incur increased operating expenses, including maintenance expenses. An example of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel in spite of its increasing maintenance and other operating expenses.
In summary, as we continue to expand certain non-pipeline portions of our business, we are experiencing changes in the nature (discretionary vs. non-discretionary), timing and amount of our maintenance capital expenditures that merit a more detailed review and analysis than was required historically. Management's increasing ability to determine if and when to incur certain maintenance capital expenditures is relevant to the manner in which we analyze aspects of our business relating to discretionary and non-discretionary expenditures. We believe it would be inappropriate to derive our Available Cash before Reserves measure by deducting discretionary maintenance capital expenditures, which we believe are similar in nature in this context to certain other discretionary expenditures, such as growth capital expenditures, distributions/dividends and equity buybacks. Unfortunately, not all maintenance capital expenditures are clearly discretionary or non-discretionary in nature. Therefore, we developed a measure, maintenance capital utilized, that we believe is more useful in the determination of Available Cash before Reserves.
Maintenance Capital Utilized
We believe our maintenance capital utilized measure is the most useful quarterly maintenance capital requirements measure to use to derive our Available Cash before Reserves measure. We define our maintenance capital utilized measure as that portion of the amount of previously incurred maintenance capital expenditures that we utilize during the relevant quarter, which would be equal to the sum of the maintenance capital expenditures we have incurred for each project/component in prior quarters allocated ratably over the useful lives of those projects/components.
Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period. Because we did not use our maintenance capital utilized measure before 2014, our maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31, 2013.
ADJUSTED EBITDA
Purposes, Uses and Definition
Adjusted EBITDA is commonly used as a supplemental financial measure by management and by external users of financial statements such as investors, commercial banks, research analysts and rating agencies, to aid in assessing, among other things:
(1)
the financial performance of our assets without regard to financing methods, capital structures or historical cost basis;
(2)
our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure;
(3)
the viability of potential projects, including our cash and overall return on alternative capital investments as compared to those of other companies in the midstream energy industry;
(4)
the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements, including interest payments and certain maintenance capital requirements; and
(5)
our ability to make certain discretionary payments, such as distributions on our preferred and common units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.
We define Adjusted EBITDA ('Adjusted EBITDA') as Net income (loss) attributable to Genesis Energy, L.P. before interest, taxes, depreciation, depletion and amortization (including impairment, write-offs, accretion and similar items) after eliminating other non-cash revenues, expenses, gains, losses and charges (including any loss on asset dispositions), plus or minus certain other select items that we view as not indicative of our core operating results (collectively, 'Select Items'). Although we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results. The most significant Select Items in the relevant reporting periods are set forth below.
The table below includes the Select Items discussed above as applicable to the reconciliation of Net income (loss) attributable to Genesis Energy, L.P. to Adjusted EBITDA and Available Cash before Reserves:
(in thousands)
I.
Applicable to all Non-GAAP Measures
Differences in timing of cash receipts for certain contractual arrangements (1)
$
(9,071
)
$
7,820
$
(17,358
)
$
15,892
Certain non-cash items:
Unrealized gains on derivative transactions excluding fair value hedges, net of changes in inventory value
(133
)
(289
)
(204
)
(42
)
Loss on debt extinguishment
8,935
1,429
9,779
1,429
Adjustment regarding equity investees (2)
5,595
4,879
11,687
11,687
Other
(4,229
)
(2,474
)
(6,951
)
(4,601
)
Sub-total Select Items, net (3)
1,097
11,365
(3,047
)
24,365
II.
Applicable only to Adjusted EBITDA and Available Cash before Reserves
Certain transaction costs
310
37
25,518
60
Other
1,788
535
313
(1,461
)
Total Select Items, net (4)
$
3,195
$
11,937
$
22,784
$
22,964
(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)
Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
(3)
Represents Select Items applicable to all Non-GAAP measures.
(4)
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, and, where relevant, 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.