HOUSTON – (BUSINESS WIRE) – Genesis Energy, L.P. (NYSE: GEL) today announced its fourth quarter results.
We generated the following financial results for the fourth quarter of 2020:
•Net Loss Attributable to Genesis Energy, L.P. of $85.2 million for the fourth quarter of 2020, compared to Net Income Attributable to Genesis Energy, L.P. of $22.4 million for the same period in 2019.
•Cash Flows from Operating Activities of $1.1 million for the fourth quarter of 2020 compared to $50.6 million for the same period in 2019.
•Total Segment Margin in the fourth quarter of 2020 of $137.0 million.
•Available Cash before Reserves to common unitholders of $52.4 million for the fourth quarter of 2020, which provided 2.85X coverage for the quarterly distribution of $0.15 per common unit attributable to the fourth quarter.
•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.
•Adjusted EBITDA of $134.6 million in the fourth quarter of 2020.
•Adjusted Consolidated EBITDA of $602.4 million for the year ended December 31, 2020 and a bank leverage ratio of 5.57X, both calculated in accordance with our credit agreement and are discussed further in this release.
Grant Sims, CEO of Genesis Energy, said, “2020 was understandably a challenging year for our businesses due to the Covid-19 related demand destruction, lower refinery utilization and crude differentials as well as an unprecedented hurricane season. Despite these challenges, we were able to generate approximately $602 million of Adjusted Consolidated EBITDA, as calculated under our senior secured credit facility, hitting the mid-point of our previously announced guidance. In fact, we were able to reduce Total Adjusted Debt by approximately $62 million despite having to pay approximately $45 million of financing fees associated with two unsecured re-financings and $50 million from the fourth quarter of 2019 common unit distributions that was actually paid in the first quarter of 2020.
To better position the partnership for long term success, we took several proactive steps during the year, including significantly reducing our common distribution, implementing significant cost cutting measures and opportunistically refinancing two of our near term unsecured maturities. While we expect 2021 to be somewhat a year of transition as our base businesses continue to recover and we move ever closer to the significant contribution from several contracted offshore projects, we are increasingly confident in the long-term fundamentals of our businesses and our significant operating leverage to the upside as the global economy continues to improve.
Our offshore pipeline transportation segment was challenged in 2020 from an unprecedented hurricane season, but the outlook remains strong. Over the last ten years through 2019, Genesis had never experienced more than 13 days of named storm downtime in a single year. This past year, we experienced approximately 28 days of named storm downtime and minor structural damage to one of our platforms. This downtime and the non-recurring costs associated with platform inspections and repairs, negatively impacted 2020 Segment Margin by some $40 million. That being said, the CHOPS pipeline was up and
running as of February 4th and the first quarter of 2021 remains on track to generate a more normalized earnings profile of approximately $85 million per quarter from our industry critical infrastructure assets in the central Gulf of Mexico.
In regards to the new administration’s most recent Executive Order, which directs the Department of the Interior to temporarily pause new oil and natural gas leasing on federal lands, it is very important to note the targeted pause by the Department of Interior “does not impact existing operations or permits for valid, existing leases, which are continuing to be reviewed and approved.” From January 21st to February 16th, the Bureau of Ocean Energy Management has issued 63 new permits, including 38 revised new well permits and 4 new well permits.
In fact, each of the operators of our larger, contracted offshore projects, Argos and King’s Quay, has just recently publicly confirmed that both projects remain on track for first oil in 2022. We anticipate that these two fields, when fully ramped up, will generate in excess of $25 million a quarter, or over $100 million a year, in additional segment margin. Also, we remain in active discussions with three separate new stand-alone deepwater production hubs, in various stages of sanctioning and with first oil starting in the late 2024-2025 time frame totaling more than 220,000 barrels a day of potential new Gulf of Mexico production.
If the temporary ban on new leases were to be extended or become permanent, which we believe would require a change in the law, we have the equivalent of hundreds of thousands of acres that are dedicated to our offshore pipeline systems under life of lease dedications, all of which are existing, valid leases under primary term, previously granted extensions of their primary term or held by production in perpetuity, alone or in recognized units. We believe there is a tremendous inventory of incremental drilling and sub-sea tie back opportunities on these existing, valid leases that can keep our base production levels flat to slightly growing for many years, if not decades, to come.
Our soda ash business continues to improve from one of the most challenging operating environments in recent history with soda ash sales volumes down approximately 23% year over year. To put it in perspective, this was the first year since 2010 that we did not run at 100% utilization. Global demand for soda ash continues to recover but total demand remains below pre-pandemic levels driven by the wide ranging impact on demand from Covid-19. As a result, we expect both domestic and export prices in 2021 will be marginally lower than those we experienced this past year.
That being said, we were sold out in the fourth quarter and currently expect to be sold out of 100% of our production from our Westvaco facility in 2021. This incremental volume over 2020 will drive a growth in Segment Margin contribution and allow for greater fixed cost absorption and an improved cost structure. We believe all natural producers globally are in a similar situation. As we progress through this year and demand continues to recover, the incremental tons must be supplied with synthetic production, which in general is twice as expensive to make as natural soda. This dynamic is why we believe prices will rise as we go through the year and the market will continue to tighten, especially towards the end of the year when we would otherwise re-determine most of our contract prices for the majority of our sales in 2022.
Our legacy refinery services business continued to improve during the quarter, as we have moved past certain supply disruptions in our supply chain caused by the active hurricane season along the Gulf Coast. Demand for NaHS has returned almost all the way to pre-pandemic levels, driven in large part by pulp and paper as well as our mining customer’s production levels returning to pre-pandemic levels driven by the recent dramatic run up in copper prices, which we think is driven by rapid economic recoveries in the world’s economies.
Our onshore facilities and transportation segment was challenged in 2020 from lower upstream activity around our legacy systems, unfavorable crude-by-rail economics and lower refinery utilization. Looking forward, we continue to see steady crude-by-rail volumes at our scenic station as the differential between WCS and the Gulf Coast continues to support rail movements. While we do not expect any financial impact to us in the first half of 2021 as our main customer works through pre-paid credits, if the current market conditions persist we could see incremental margin contribution from these activities in late 2021 and potentially on into 2022.
Despite a relatively strong first half of 2020, our marine transportation segment continues to be negatively impacted by lower refinery utilization in the Midwest and Gulf Coast which has pressured both rates and utilization within our brown water fleet. The tight supply and demand dynamic that drove our improved results in the first half of the year could return as refineries return to more normalized run rates in the second half of 2021 and more intermediate products need to be moved from location to location. The pace of this recovery could potentially be aided by the equipment retirements that took place in 2020 along with the limited number of new builds over the past few years. As we have mentioned in the past, 2020 was also a challenging contracting environment for the American Phoenix, and we contracted her at a lower rate during the fourth quarter of 2020 and first quarter of 2021. More recently, we were able to re-contract her at a higher rate starting in the second quarter of 2021 through the first quarter of 2022 with an investment grade refining company.
2
In addition to the successful refinancing of our 2022 notes earlier in the year, in December 2020 we successfully accessed the unsecured bond market and completed an upsized $750 million note offering to fully call and redeem our 2023 notes. The remaining proceeds were used to pay down our senior secured credit facility by approximately $350 million, leaving us with ample capacity heading into 2021. Our nearest unsecured maturity is now June of 2024. Our senior credit facility matures in May of 2022, and we anticipate extending it during the first half of this year.
Our reported leverage ratio increased in the quarter primarily due to the $40 million in weather related impacts we incurred in the second half of the year in the Gulf of Mexico. If only we had experienced a more “normalized” hurricane season, our total leverage ratio at the end of 2020 would have been closer to 5.22X versus the reported 5.57X.
Looking forward to 2021, we would reasonably expect to generate Adjusted Consolidated EBITDA in 2021, as calculated under our senior secured credit facility, between $630 and $660 million1, which includes some $30 to $40 million of pro forma adjustments. We currently expect cash obligations for 2021 totaling approximately $500 million, which includes all, among others, cash taxes, interest on bank debt and bonds, all maintenance capital spent, growth capital spent, asset retirement obligations, financing fees, estimated changes in working capital, preferred cash distributions and common distributions at the current $0.15 per unit quarterly payout. At this point, we have budgeted approximately $40 million of growth capital outside of the Granger expansion, which dollars are expected to be paid via the redeemable preferred structure at the soda ash operational level. This minimal growth capital is predominantly allocated to the offshore segment for additional upgrades to our existing system for anticipated future volumes. Importantly, we expect to generate free cash flow after these identified cash obligations of $80 to $110 million which we intend to use to repay debt.
Turning to the increasingly important topic of the energy transition, while we are highly confident that crude oil will have a significant role to play for the foreseeable future, we continue to look at ways to position ourselves to operate and participate in a lower carbon world. The Gulf of Mexico is already one of the most highly regulated upstream basins in North America, with no fracking or flaring, and has some of the lowest carbon intensity on a per barrel basis of any production in the world. Our soda ash business should increasingly participate in multiple renewable energy themes moving forward including the production of new LEED certified glass windows to retro-fit older buildings, manufacturing of glass for solar panels and the production of lithium carbonate and lithium hydroxide, some of the building blocks of lithium ion/phosphate batteries used in both the electrification of vehicles and long-term battery storage. Our refinery service business continues to help its host refineries lower their emissions by processing their sour gas stream using our proprietary, closed-loop, non-combustion technology to remove sulfur from their H2S stream. In addition, we sell both produced soda ash and sodium hydrosulfide from our sulfur removal services into certain downstream applications that help reduce customer’s carbon footprints. We are also pleased to announce that we are very near to launching our ESG web site which will greatly increase our disclosures and illustrate to investors that we are committed to operating our business in an ESG responsible manner.
In summary, we are highly encouraged by the rebound in our businesses, and we still believe we have a clear line of sight to $700 million1 plus in annual Adjusted Consolidated EBITDA in the coming years. Just a return to 2018-2019 soda ash pricing combined with the incremental contribution margin from our contracted offshore volumes, would add upwards of $100 million of additional Segment Margin to the 2021 guidance described above. With this accelerating ability to pay down debt and with relatively de minimus capital requirements to realize the financial benefits of these improving business conditions, we remain steadfast in our commitment to achieving our long-term target leverage ratio of 4.0X.
I would like to once again recognize our entire workforce, and especially our miners, mariners and offshore personnel who live and work in close quarters during this time of social distancing. I am extremely proud to say we have safely operated our assets under our own Covid-19 safety procedures and protocols with no impact to our business partners and customers. As always, we intend to be prudent, diligent and intelligent and focus on delivering long-term value for everyone in our capital structure without ever losing our commitment to safe, reliable and responsible operations."
1Adjusted Consolidated EBITDA is a non-GAAP financial measure. We are unable to provide a reconciliation of the forward-looking Adjusted Consolidated EBITDA projections contained in this press release to its respective most directly comparable GAAP financial measure because the information necessary for quantitative reconciliations of the Adjusted Consolidated EBITDA measures to its respective most directly comparable GAAP financial measure is not available to us without unreasonable efforts. The probable significance of providing these forward-looking Adjusted Consolidated EBITDA measures without directly comparable GAAP financial measures may be materially different from the corresponding GAAP financial measures.
3
Financial Results
Segment Margin
Variances between the fourth quarter of 2020 (the “2020 Quarter”) and the fourth quarter of 2019 (the “2019 Quarter”) in these components are explained below.
Segment Margin results for the 2020 Quarter and 2019 Quarter were as follows:
Three Months Ended December 31,
2020
2019
(in thousands)
Offshore pipeline transportation
$
52,304
$
86,045
Sodium minerals and sulfur services
40,726
52,306
Onshore facilities and transportation
36,642
25,060
Marine transportation
7,331
16,356
Total Segment Margin
$
137,003
$
179,767
Offshore pipeline transportation Segment Margin for the 2020 Quarter decreased $33.7 million, or 39%, from the 2019 Quarter, primarily due to lower overall volumes on our crude oil and natural gas pipeline systems and a relative increase in operating costs. During the 2020 Quarter, our Gulf of Mexico assets continued to experience unplanned maintenance downtime from certain fields connected to our assets and the continued interruption from weather events, including Hurricanes Delta and Zeta, as a result of producers shutting in during the storm and us taking the necessary precautions to remove all personnel from the platform assets that we operate and maintain. In addition to the majority of our assets being shut in for approximately 15 days, our 100% owned CHOPS pipeline, although not damaged, has been out of service since August 26, 2020 due to damage at a junction platform that the CHOPS system goes up and over. During the 2020 Quarter, we were able to successfully divert all CHOPS barrels to our 64% owned and operated Poseidon oil pipeline system, but continued to incur our fixed costs associated with the CHOPS pipeline. On February 4, 2021, we placed the CHOPS pipeline back into service upon the installation of a bypass that allows our pipeline to operate around the junction platform. We expect volumes on our other offshore pipeline transportation assets to return to normal pre-hurricane levels in the first quarter of 2021.
Sodium minerals and sulfur services Segment Margin for the 2020 Quarter decreased $11.6 million, or 22% from the 2019 Quarter, primarily due to lower volumes and pricing in our Alkali Business and lower NaHS volumes in our refinery services business. During the 2020 Quarter, we experienced lower ANSAC and domestic sales volumes of soda ash relative to the 2019 Quarter primarily due to the absence of production volumes from our Granger facility, which was put in cold standby earlier in 2020 due to the demand destruction from the Covid-19 pandemic. We began to see an uptick in demand both domestically and on ANSAC volumes relative to the proceeding two quarters as certain regions of the world began to re-open their economies and we expect continued demand recovery as we enter 2021. We sold 100% of the production from our Westvaco facility in the 2020 Quarter and expect to do so in 2021. These lower volumes were coupled with lower export pricing due to supply and demand imbalances that existed at the time of our re-contracting phase for 2020 volumes in December 2019 and January 2020. In our refinery services business, we experienced lower NaHS volumes during the 2020 Quarter due to lower demand from our mining customers, primarily in Peru. We have begun to see some recovery in demand from previous customer shut-ins amidst the spread of Covid-19 and we expect these volumes to continue recovering to their normal levels as we enter 2021.
Onshore facilities and transportation Segment Margin for the 2020 Quarter increased by $11.6 million, or 46%, from the 2019 Quarter. On October 30, 2020, we reached an agreement with a subsidiary of Denbury Inc. to transfer to them the ownership of our remaining CO2 assets, including the NEJD and Free State pipelines. As a part of the agreement, we received $22.5 million in cash proceeds for the Free State pipeline (which is included in segment margin during the 2020 Quarter) and will receive $70 million in equal installments during each quarter of 2021 for the remaining principal payments associated with NEJD. This increase of $22.5 million to segment margin was partially offset by lower principal payments received in the 2020 Quarter from NEJD as we did not receive any in the 2020 Quarter compared to $5.2 million received during the 2019 Quarter. Additionally, we had lower volumes throughout our onshore facilities and transportation asset base, primarily in Louisiana at our Baton Rouge corridor assets and our Raceland rail facility. The volumes at our Baton Rouge facilities were below our minimum take-or-pay levels and we were only able to recognize our minimum volume commitment in segment margin during the 2020 Quarter. Additionally, the volumes on our Texas pipeline were lower during the 2020 Quarter as a result of less receipts originating from the Gulf of Mexico, primarily due to our CHOPS pipeline being out of service.
Marine transportation Segment Margin for the 2020 Quarter decreased $9.0 million, or 55%, from the 2019 Quarter, primarily due to lower utilization and day rates in our inland business. We continued to face pressure on our utilization and spot
4
rates in our inland business as refinery utilization remained low due to weakened demand from Covid-19 and hurricanes impacting the Gulf Coast during the 2020 Quarter. Additionally, we re-contracted our M/T American Phoenix tanker beginning in the fourth quarter of 2020 at a lower rate and shorter term than the previous five year contractual term. We have continued to enter into short term contracts (less than a year) in both the inland and offshore (including the M/T American Phoenix) markets because we believe the day rates currently being offered by the market have yet to fully recover from their cyclical lows.
Other Components of Net Income
In the 2020 Quarter, we recorded Net Loss Attributable to Genesis Energy, L.P. of $85.2 million compared to Net Income Attributable to Genesis Energy, L.P. of $22.4 million in the 2019 Quarter. Net Loss Attributable to Genesis Energy, L.P. in the 2020 Quarter was impacted, relative to the 2019 Quarter, by: (i) lower Segment Margin of $42.8 million, which is inclusive of the $22.5 million in cash receipts associated with the sale of our Free State pipeline received in the 2020 Quarter; (ii) a loss on sale of assets of $22.0 million; (iii) an unrealized loss of $18.3 million on the valuation of the embedded derivative associated with our Class A Convertible Preferred Units recorded in other expense, net, compared to an unrealized loss of $9.3 million recorded during the 2019 Quarter; (iv) lower non-cash revenues of $9.3 million within our offshore pipeline transportation and onshore facilities and transportation segments as a result of how we recognize revenue in accordance with GAAP on certain contracts; and (v) a loss of $8.2 million associated with the tender of certain of our 2023 Notes during the 2020 Quarter recorded in other expense, net. These decreases were partially offset by (i) lower depreciation, depletion and amortization expense of $6.2 million during the 2020 Quarter due to lower depreciation expense on our rail logistics assets as they were impaired during the second quarter of 2020; and (ii) cancellation of debt income of $6.8 million associated with the repurchase of certain of our senior unsecured notes on the open market during the 2020 Quarter.
Earnings Conference Call
We will broadcast our Earnings Conference Call on Thursday, February 18, 2021, at 8:30 a.m. Central time (9:30 a.m. Eastern time). This call can be accessed at www.genesisenergy.com. Choose the Investor Relations button. For those unable to attend the live broadcast, a replay will be available beginning approximately one hour after the event and remain available on our website for 30 days. There is no charge to access the event.
Genesis Energy, L.P. is a diversified midstream energy master limited partnership headquartered in Houston, Texas. Genesis’ operations include offshore pipeline transportation, 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.
5
GENESIS ENERGY, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED
(in thousands, except per unit amounts)
Three Months Ended December 31,
Year Ended December 31,
2020
2019
2020
2019
REVENUES
$
453,140
$
604,329
$
1,824,655
$
2,480,820
COSTS AND EXPENSES:
Costs of sales and operating expenses
377,853
441,507
1,415,500
1,835,624
General and administrative expenses
11,062
12,590
56,920
52,687
Depreciation, depletion and amortization
73,112
79,293
295,322
319,806
Impairment expense
—
—
280,826
—
Loss on sale of assets
22,045
—
22,045
—
OPERATING INCOME (LOSS)
(30,932)
70,939
(245,958)
272,703
Equity in earnings of equity investees
22,803
16,611
64,019
56,484
Interest expense
(51,884)
(53,559)
(209,779)
(219,440)
Other expense, net
(20,383)
(9,332)
(7,269)
(9,026)
INCOME (LOSS) BEFORE INCOME TAXES
(80,396)
24,659
(398,987)
100,721
Income tax (expense) benefit
(752)
1
(1,327)
(655)
NET INCOME (LOSS)
(81,148)
24,660
(400,314)
100,066
Net income attributable to noncontrolling interests
(289)
(331)
(251)
(1,834)
Net income attributable to redeemable noncontrolling interests
(3,719)
(1,961)
(16,113)
(2,233)
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.
$
(85,156)
$
22,368
$
(416,678)
$
95,999
Less: Accumulated distributions attributable to Class A Convertible Preferred Units
NaOH (caustic soda) volumes (dry short tons sold) (2)
19,723
18,756
77,274
78,927
Onshore Facilities and Transportation Segment
Crude oil pipelines (barrels/day):
Texas
37,701
95,546
62,213
59,435
Jay
8,942
9,916
8,443
10,461
Mississippi
5,735
6,014
5,638
5,994
Louisiana
63,005
125,417
90,319
117,130
Onshore crude oil pipelines total
115,383
236,893
166,613
193,020
Free State- CO2 Pipeline (Mcf/day) (3)
60,436
132,388
101,845
97,912
Crude oil and petroleum products sales (barrels/day)
30,946
28,973
27,073
31,681
Rail unload volumes (barrels/day) (4)
27,016
55,155
32,174
79,530
Marine Transportation Segment
Inland Fleet Utilization Percentage (5)
56.8
%
94.9
%
77.8
%
96.8
%
Offshore Fleet Utilization Percentage (5)
89.7
%
96.0
%
95.4
%
94.6
%
(1)Volumes for our equity method investees are presented on a 100% basis. We own 64% of Poseidon and 29% of Odyssey, as well as equity interests in various other entities.
(2)Caustic soda sales volumes include volumes sold from our Alkali and Refinery Services businesses.
(3)The volumes presented for 2020 represent the average Mcf/day through October 29, 2020, which was the last day of operations under our ownership.
(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.
7
GENESIS ENERGY, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED
(in thousands, except number of units)
December 31, 2020
December 31, 2019
ASSETS
Cash, cash equivalents and restricted cash
$
27,018
$
56,405
Accounts receivable - trade, net
392,465
417,002
Inventories
99,877
65,137
Other current assets
60,809
54,530
Total current assets
580,169
593,074
Fixed assets and mineral leaseholds, net
4,403,909
4,850,300
Investment in direct financing leases, net
—
107,702
Equity investees
319,068
334,523
Intangible assets, net
128,742
138,927
Goodwill
301,959
301,959
Right of use assets, net
153,925
177,071
Other assets, net
45,847
94,085
Total assets
$
5,933,619
$
6,597,641
LIABILITIES AND CAPITAL
Accounts payable - trade
$
198,433
$
218,737
Accrued liabilities
184,978
196,758
Total current liabilities
383,411
415,495
Senior secured credit facility
643,700
959,300
Senior unsecured notes, net of debt issuance costs
2,750,016
2,469,937
Deferred tax liabilities
13,317
12,640
Other long-term liabilities
393,018
393,850
Total liabilities
4,183,462
4,251,222
Mezzanine capital:
Class A convertible preferred units
790,115
790,115
Redeemable noncontrolling interests
141,194
125,133
Partners' capital:
Common unitholders
829,326
1,443,320
Accumulated other comprehensive loss
(9,365)
(8,431)
Noncontrolling interests
(1,113)
(3,718)
Total partners' capital
818,848
1,431,171
Total liabilities, mezzanine capital and partners' capital
$
5,933,619
$
6,597,641
Common Units Data:
Total common units outstanding
122,579,218
122,579,218
8
GENESIS ENERGY, L.P.
RECONCILIATION OF NET INCOME(LOSS) TO SEGMENT MARGIN - UNAUDITED
(in thousands)
Three Months Ended December 31,
2020
2019
Net income (loss) attributable to Genesis Energy, L.P.
$
(85,156)
$
22,368
Corporate general and administrative expenses
9,297
12,877
Depreciation, depletion, amortization and accretion
73,841
74,865
Interest expense
51,884
53,559
Income tax expense (benefit)
752
(1)
Loss on sale of assets
22,045
—
Provision for leased items no longer in use
723
(534)
Cancellation of debt income
(6,768)
—
Redeemable noncontrolling interest redemption value adjustments (1)
3,719
1,961
Plus (minus) Select Items, net
66,666
14,672
Segment Margin (2)
$
137,003
$
179,767
(1)Includes distributions paid in kind (PIK) attributable to the period and accretion on the redemption feature.
(2)See definition of Segment Margin later in this press release.
9
GENESIS ENERGY, L.P.
RECONCILIATIONS OF NET INCOME(LOSS) TO ADJUSTED EBITDA AND AVAILABLE CASH BEFORE RESERVES- UNAUDITED
(in thousands)
Three Months Ended December 31,
2020
2019
Net income (loss) attributable to Genesis Energy, L.P.
$
(85,156)
$
22,368
Interest expense
51,884
53,559
Income tax expense (benefit)
752
(1)
Loss on sale of assets
22,045
—
Depreciation, depletion, amortization, and accretion
73,841
74,865
EBITDA
63,366
150,791
Redeemable noncontrolling interest redemption value adjustments (1)
3,719
1,961
Plus (minus) Select Items, net
67,541
14,877
Adjusted EBITDA
134,626
167,629
Maintenance capital utilized (2)
(11,533)
(7,500)
Interest expense
(51,884)
(53,559)
Cash tax expense
(100)
(231)
Cash distributions to preferred unitholders (3)
(18,684)
(18,684)
Available Cash before Reserves (4)
$
52,425
$
87,655
(1)Includes PIK distributions attributable to the period and accretion on the redemption feature.
(2)Maintenance capital expenditures in the 2020 Quarter and 2019 Quarter were $34.4 million and $33.8 million, respectively. Our maintenance capital expenditures are principally associated with our alkali and marine transportation businesses.
(3)Distributions to preferred unitholders attributable to the 2020 Quarter were paid on February 12, 2021 to unitholders of record at close of business on January 29, 2021.
(4)Represents the Available Cash before Reserves to common unitholders.
10
GENESIS ENERGY, L.P.
RECONCILIATION OF NET CASH FLOWS FROM OPERATING ACTIVITIES TO ADJUSTED EBITDA - UNAUDITED
(in thousands)
Three Months Ended December 31,
2020
2019
Cash Flows from Operating Activities
$
1,117
$
50,558
Adjustments to reconcile net cash flow provided by operating activities to Adjusted EBITDA:
Interest Expense
51,884
53,559
Amortization and write-off of debt issuance costs and discount
(5,095)
(2,701)
Distribution from unrestricted subsidiaries not included in operating cash flows (1)
22,500
—
Effects of available cash from equity method investees not included in operating cash flows
2,397
2,918
Net effect of changes in components of operating assets and liabilities
33,519
65,454
Non-cash effect of long-term incentive compensation plans
887
(2,198)
Expenses related to acquiring or constructing growth capital assets
861
333
Differences in timing of cash receipts for certain contractual arrangements (2)
11,668
2,408
Loss on debt extinguishment (3)
8,250
—
Cancellation of debt income
6,768
—
Other items, net
(130)
(2,702)
Adjusted EBITDA
$
134,626
$
167,629
(1) The 2020 Quarter includes the distribution from our Free State pipeline of $22.5 million, which is defined as an unrestricted subsidiary under our senior secured credit agreement, and is included in our cash flows from investing activities.
(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. 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 the transaction costs and write-off of the unamortized issuance costs associated with the tender of our 2023 Notes.
11
GENESIS ENERGY, L.P.
ADJUSTED DEBT-TO-ADJUSTED CONSOLIDATED EBITDA RATIO - UNAUDITED
(in thousands)
December 31, 2020
Senior secured credit facility
$
643,700
Senior unsecured notes, net of debt issuance costs
(1) We define Adjusted Debt as the amounts outstanding under our senior secured credit facility and senior unsecured notes (including any unamortized premiums or discounts) less the amount outstanding under our inventory financing sublimit, 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 approximately $13.5 million for cost savings initiatives we are permitted to add back through the second quarter of 2021. In addition, it includes a pro rata portion of projected future annual EBITDA of approximately $12.8 million associated with material organic projects. This amount is calculated based on the percentage of capital expenditures incurred to date relative to the expected budget, which was approximately 36% as of the 2020 quarter, multiplied by the total annual contractual minimum cash commitments we expect to receive as a result of the project. This adjustment 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 credit facility covenants, the anticipated benefits of our transactions with Denbury, our expectations regarding the potential impact of the Covid-19 pandemic, 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) and a reduction in demand for our services resulting in further impairments of our assets, the outbreak or continued spread of disease (including Covid-19), the timing and success of business development efforts and other uncertainties, and the realized benefits of the preferred equity investment in Alkali Holdings by affiliates of GSO Capital Partners LP or our ability to comply with the Granger transaction agreements and maintain control and ownership of our Alkali Business. 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, 2019 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.
12
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 as adjusted for certain items, the most significant of which in the relevant reporting periods have been the sum of maintenance capital utilized, net cash 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.
13
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.
Initially, 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.
As we exist today, a substantial amount of our maintenance capital expenditures from time to time will be (a) related to our assets other than pipelines, such as our marine vessels, trucks and similar assets, (b) discretionary in nature and (c) potentially material in amount as compared to our Available Cash before Reserves measure. Those expenditures will be discretionary (or non-mandatory) in nature because we will have significant discretion as to whether or when we incur them. We will not be forced to incur them in order to continue to operate the related assets in a safe and reliable manner. If we chose not make those expenditures, we would be able to continue to operate those assets economically, although in lieu of maintenance capital expenditures, we would incur increased operating expenses, including maintenance expenses. An example of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel in spite of its increasing maintenance and other operating expenses.
In summary, as we continue to expand certain non-pipeline portions of our business, we are experiencing changes in the nature (discretionary vs. non-discretionary), timing and amount of our maintenance capital expenditures that merit a more detailed review and analysis than was required historically. Management’s 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.
Because we did not initially use our maintenance capital utilized measure, our future maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31, 2013.
14
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 earnings 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 Adjusted EBITDA and Available Cash before Reserves to net income:
Three Months Ended December 31,
2020
2019
I.
Applicable to all Non-GAAP Measures
Differences in timing of cash receipts for certain contractual arrangements (1)
$
11,668
$
2,408
Distributions from unrestricted subsidiaries not included in income (2)
21,870
2,183
Certain non-cash items:
Unrealized losses on derivative transactions excluding fair value hedges, net of changes in inventory value (3)
20,855
8,394
Loss on debt extinguishment (4)
8,250
—
Adjustment regarding equity investees (5)
2,542
2,662
Other
1,481
(975)
Sub-total Select Items, net (6)
66,666
14,672
II.
Applicable only to Adjusted EBITDA and Available Cash before Reserves
Certain transaction costs (7)
861
333
Other
14
(128)
Total Select Items, net (8)
$
67,541
$
14,877
(1) 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. 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 2020 Quarter includes distributions from our Free State pipeline of $22.5 million. The 2019 Quarter includes cash payments received from our NEJD pipeline of $2.2 million not included in income. Both the Free State Pipeline and NEJD are defined as unrestricted subsidiaries under our senior secured credit agreement.
(3) The 2020 Quarter includes a $18.3 million unrealized loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units and the 2019 Quarter includes a $9.3 million unrealized loss from the valuation of the embedded derivative.
(4) Includes the transaction costs and write-off of the unamortized issuance costs associated with the tender of our 2023 Notes.
(5) Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
(6) Represents all Select Items applicable to Segment Margin and Available Cash before Reserves.
(7) Represents transaction costs relating to certain merger, acquisition, transition, and financing transactions incurred in advance of acquisition.
(8) Represents Select Items applicable to Adjusted EBITDA and Available Cash before Reserves.
15
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 as revenues less product costs, operating expenses, and segment general and administrative expenses, after eliminating gain or loss on sale of assets, 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.
