EX-99.1 2 gel12312019exhibit991.htm EXHIBIT 99.1 Exhibit
genesisenergylogoa01a20.jpg
FOR IMMEDIATE RELEASE
February 19, 2020

Genesis Energy, L.P. Reports Fourth Quarter 2019 Results

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 2019:
•
Net Income Attributable to Genesis Energy, L.P. of $22.4 million for the fourth quarter of 2019 compared to Net Loss Attributable to Genesis Energy, L.P. of $24.8 million for the same period in 2018.

•
Cash Flows from Operating Activities of $50.6 million for the fourth quarter of 2019 compared to $82.5 million for the same period in 2018.

•
Total Segment Margin in the fourth quarter of 2019 of $179.8 million.

•
Available Cash before Reserves to common unitholders of $87.7 million for the fourth quarter of 2019, which provided 1.30X coverage for the quarterly distribution of $0.55 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 $167.6 million in the fourth quarter of 2019. Our bank leverage ratio, calculated consistent with our credit agreement, is 5.11X as of December 31, 2019 and is discussed further in this release.

Grant Sims, CEO of Genesis Energy, said, “For the quarter, our diversified businesses in total performed slightly better than our expectations, and we ended the year towards the high-end of our revised annual guidance for Adjusted EBITDA.
In our offshore pipeline transportation segment, we saw strong volumes across our platforms and pipelines as newer projects continued to ramp and sub-sea tiebacks and infield drilling more than offset any natural decline in our dedicated fields. We continue to actively pursue and contract new developments which can access our existing capacity and represent meaningful margin contribution to us at minimal or no capital, such as BP’s Argos platform, coming on in 2021, and Murphy’s King’s Quay platform, coming on in 2022.
The offshore midstream infrastructure business is significantly different than that in most onshore basins given, among other things, its cost of entry. Additionally, our systems in the central Gulf of Mexico have available capacity, and very economic capacity expansions, that can offer new shippers firm capacity to shore with the flexibility to go to multiple markets in either Louisiana or Texas. Generally speaking, our rates per barrel in our new contracts are going up, we have terms that are typically for the life-of-lease (some 30 to 40 years), and we are able to include annual escalators, which, due to the mechanics of compounding, tend to flatten out the financial contributions over time, even as volumes decline in the later contract years.
In our onshore facilities and transportation segment, we experienced a ramp in crude-by-rail volumes throughout the quarter as a result of curtailment relief granted in Alberta, Canada and we exited the year averaging approximately one train a day. We have experienced a continued ramp above that in January and February, and would otherwise anticipate these levels at least through March. The provincial government of Alberta is scheduled to review its self-imposed production curtailments policies in the March/April 2020 time frame. Additionally, the practical capacity of existing pipelines out of Canada increases in the second and third quarter as less diluent is needed to move the same amount of bitumen due to higher ambient temperatures. As a result of these two items, we could possibly see a reduction in volumes mid-year before a reasonably expected re-ramp into the end of


2020. We also saw increased volumes in the fourth quarter on our Texas pipeline. Otherwise, the rest of our businesses reported in onshore facilities and transportation segment performed consistent with our expectations.
Our marine transportation segment continued to perform as expected and reported increased segment margin for the eighth consecutive quarter. We experienced strong utilization and improving day rates across our inland and offshore fleets. IMO 2020 appears to be having a positive impact on our inland, black oil barges as refiners need to get the intermediate refined barrel to the right location. Upwards of 90% of our barges are typically contracted to provide services to refiners moving their intermediate products from one location to another.
We see improving fundamentals into 2020 for both fleets. The Army Corps of Engineers is undertaking significant repair and maintenance of locks on the Mississippi River and its major tributaries this summer. As a result, we anticipate a near-term reduction in “practical supply” as movements in and out of such region take longer and are less efficient than normal. As a result, demand and day-rates in our brown water fleet should improve. We are also seeing increased demand for our blue water vessels. Our clean fleet is benefiting from certain competitive dynamics on the East Coast as well as more required product movements because of the closure of refining capacity in Philadelphia. Our larger offshore vessels are benefiting from increased movements of crude oil as more and more barrels reach the Gulf Coast, where the Gulf Coast refiners basically have limited incremental demand for those types of barrels.
In our sodium minerals and sulfur services segment, our legacy refinery services business performed as expected in the quarter, and importantly it appears most of the production and market interruptions it faced in the second half of 2019 are largely behind us as we move into 2020.
Turning to sodium minerals, as we mentioned on our third quarter call, we were then seeing signs of slowdown in the demand for soda ash globally, particularly in Asia. We believed this was tied mainly to the ongoing economic uncertainty around the US-China trade war, but also to decelerating GDP resulting from tightening monetary policies by most central banks in early 2019, which policies appear to have been reversed in the second half of last year.
Nonetheless, this demand trend accelerated into the end of the quarter as customers continued to have excess inventory of soda ash and their respective finished goods, like flat glass. At the same time, it appears that Genesis and the other domestic producers made more soda ash for export in the fourth quarter compared to earlier quarters. As a result, price fell in the export markets to clear this demand/supply imbalance, and we experienced our lowest quarter of financial contribution from our soda ash operations, of just over $38 million, since we acquired the business in 2017.
Unfortunately, most contract prices for a subsequent year are negotiated in the prior December and January of that year. Even though most domestic prices are set on a multi-year basis, many subject to caps and collars, our export contracts and negotiated prices are much shorter in duration. Given the dynamics going into the price negotiations described above, we expect export prices, which represent approximately half of our total annual sales, to be significantly lower in 2020 than they have been in the prior two and half years since we acquired the operations. Experience has shown, because of the nature of the mix of contracts, it can take anywhere from 4-8 quarters for the underlying fundamentals to get prices back on historical trend. We would point out that the effects of the coronavirus on global demand and supply are not yet quantifiable, and this exogenous event could impact that historically observed time interval.
Having said that, we continue to believe in the long term fundamentals of the business and the cost competitive advantage natural soda ash enjoys over synthetically produced product. We remain confident that the market will need, and we can easily and profitably place, the incremental tons coming from our Granger expansion beginning in mid-2022.
When we purchased this business, we analyzed the previous twelve years of its financial history back through 2006, including how it performed during the Great Recession. The annual EBITDA ranged from approximately $120 million to $190 million, with an average of approximately $160 million. Our view then was, and still is, if around $120 million is the downside on a $1.2 billion acquisition, net of the working capital acquired, we would make that investment anytime, especially for a business that has over 70 years of operating history and a remaining reserve life of potentially 300-400 years.
Looking forward into 2020, we see Adjusted EBITDA coming in a range of $640-$680 million. This assumes the margin contribution from our soda ash operations is some $35-$45 million below the $165 million it earned this past year.
As you can therefore surmise, we feel reasonably positive about our other businesses and their prospects. We would reiterate we expect the offshore pipeline transportation segment to be $20-$30 million above 2019 levels. The marine transportation segment is budgeted to improve some $2-$6 million and our legacy refinery services business could be up a similar amount. Finally, the onshore facilities and transportation segment is forecasted to be flat to up $10 million, but such improved results are primarily dependent on the economics of crude-by-rail out of Canada staying constructive throughout this year.


2

As we analyze our financials, we identify recurring cash obligations for 2020 totaling approximately $620 million, which includes, among others, cash taxes, interest on bank debt and bonds, all maintenance capital spent, preferred cash distributions at the current $0.7374 per unit quarterly payout, and common distributions at the current $0.55 per unit quarterly payout. At this point, we have budgeted approximately $25 million of growth capital outside of the Granger expansion, which dollars are paid via the redeemable preferred structure at the soda ash operational level, which requires no cash payments from Genesis during the 36 month estimated construction period. We do have approximately $20 million of non-recurring asset retirement obligations (“ARO”) budgeted in 2020. However, we reasonably expect to be able to monetize one of the retired assets by the end of this year or certainly sometime in 2021 for a multiple of these 2020 ARO expenditures.
As we look beyond 2020, we have a very good line of sight on significantly improving financial performance. First, we would reasonably expect our existing soda ash operations to return to trend and add some $40-$50 million a year by 2022 at the latest. Argos is scheduled to come on-line in the second half of 2021, which represents potentially $30-$40 million of incremental annualized EBITDA. King's Quay is scheduled to come on-line in the first half of 2022, which represents potentially $50-$60 million of incremental annualized EBITDA. Finally, assuming a return to trend on soda ash pricing, the Granger expansion is expected to add potentially $60 million of incremental annualized EBITDA beginning in mid-2022. Therefore, given a starting point of being very close to cash flow neutral this year and taking into account the meaningful new EBITDA discussed above, we believe we will be able to de-lever our balance sheet and restore and maintain our financial flexibility to capitalize on future discretionary opportunities, without ever losing our commitment to safe, reliable and responsible operations."

1 EBITDA and Adjusted EBITDA are non-GAAP financial measures. We are unable to provide a reconciliation of the forward-looking EBITDA and Adjusted EBITDA projections contained in this press release to their respective most directly comparable GAAP financial measure because the information necessary for quantitative reconciliations of the EBITDA and Adjusted EBITDA measures to their respective most directly comparable GAAP financial measures is not available to us without unreasonable efforts. The probable significance of providing these forward-looking EBITDA and Adjusted EBITDA measures without the directly comparable GAAP financial measures is that such GAAP financial measures may be materially different from the corresponding non-GAAP financial measures.

3


Financial Results
Segment Margin
Variances between the fourth quarter of 2019 (the “2019 Quarter”) and the fourth quarter of 2018 (the “2018 Quarter”) in these components are explained below.
Segment margin results for the 2019 Quarter and 2018 Quarter were as follows:
 
Three Months Ended
December 31,
 
2019
 
2018
 
(in thousands)
Offshore pipeline transportation
$
86,045

 
$
69,276

Sodium minerals and sulfur services
52,306

 
67,613

Onshore facilities and transportation
25,060

 
36,296

Marine transportation
16,356

 
12,272

Total Segment Margin 
$
179,767

 
$
185,457


Offshore pipeline transportation Segment Margin for the 2019 Quarter increased $16.8 million, or 24%, from the 2018 Quarter, primarily due to higher volumes on our crude oil pipeline systems. These increased volumes are the result of (i) the ramping of volumes from the Buckskin and Hadrian North production fields to expected levels in the second half of 2019, both of which are fully dedicated to our SEKCO pipeline and further downstream, to our Poseidon oil pipeline system, and had first oil flow in 2019, and (ii) the continued receipt of volumes on our CHOPS and Poseidon pipeline systems due to deliveries from a third party pipeline that has insufficient capacity to deliver its committed volumes to shore. During the second half of 2019, we entered into agreements to move forty thousand barrels per day on CHOPS and twenty thousand barrels per day on Poseidon that are delivered to us by a third-party pipeline that has insufficient capacity. The agreements include ship-or-pay provisions, have terms as long as five years and required no additional capital on our part.
    Sodium minerals and sulfur services Segment Margin for the 2019 Quarter decreased $15.3 million, or 23%, from the 2018 Quarter. This decrease is primarily due to lower NaHS volumes during the 2019 Quarter in our refinery services business and weakened export pricing in our Alkali Business due to supply and demand imbalance. The lower volumes in our refinery services business are attributable to supply chain disruptions some of our customers experienced during the 2019 Quarter along with production issues at several of our host refineries. Soda ash volumes slightly increased in the 2019 Quarter relative to the 2018 Quarter, but were offset by the lower pricing we received on our ANSAC volumes, which negatively impacted margin during the 2019 Quarter.
Onshore facilities and transportation Segment Margin for the 2019 Quarter decreased $11.2 million, or 31%, from the 2018 Quarter. This decrease is primarily due to lower crude oil pipeline and rail unload volumes during the 2019 Quarter. The lower volumes in the 2019 Quarter are primarily due to the continued effects of production curtailments by the Canadian government during 2019 impacting our Louisiana pipeline and rail unload volumes, and our lower rail unload volumes at our Raceland facility in the 2019 Quarter. This was partially offset by our increased volumes on our Texas system during the 2019 Quarter, which led to increased margin contribution as our main customer utilized all of its prepaid transportation credits prior to December 31, 2019.
Marine transportation Segment Margin for the 2019 Quarter increased $4.1 million, or 33%, from the 2018 Quarter. This increase in Segment Margin is primarily attributable to higher average day rates in the inland and offshore markets that have been advantageous for both spot and term contracts, while our utilization was relatively flat between the 2019 Quarter and 2018 Quarter. While we have seen a slight uptick in day rates, we have continued to enter into short term contracts (less than a year) in both the inland and offshore markets because we believe the day rates currently being offered by the market are still near cyclical lows. This was partially offset by an increase in operating costs during the 2019 Quarter relative to the 2018 Quarter due to an increase in dry-docking costs in both our inland and offshore fleet.


4


Other Components of Net Income
In the 2019 Quarter, we recorded Net Income Attributable to Genesis Energy, L.P. of $22.4 million compared to Net Loss Attributable to Genesis Energy, L.P. of $24.8 million in the 2018 Quarter. The 2018 Quarter was negatively impacted by impairment expense of $120.3 million. The 2018 Quarter also included gains on asset sales of $38.9 million primarily due to the closing of our Powder River Basin asset sale during the period and $5.7 million higher segment margin than the 2019 Quarter as discussed above, which partially offset the impairment expense recorded. Additionally, the 2019 Quarter included an unrealized loss of $9.3 million on the valuation of the embedded derivative associated with our Class A Convertible Preferred Units recorded in other income (expense), compared to an unrealized gain of $8.6 million recorded during the 2018 Quarter.
Earnings Conference Call
We will broadcast our Earnings Conference Call on Wednesday, February 19, 2020, at 9 a.m. Central time (10 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
 
2019
 
2018
 
2019
 
2018
REVENUES
$
604,329

 
$
689,296

 
$
2,480,820

 
$
2,912,770

 
 
 
 
 
 
 
 
COSTS AND EXPENSES:
 
 
 
 
 
 
 
Costs of sales and operating expenses
441,507

 
511,931

 
1,835,624

 
2,278,416

General and administrative expenses
12,590

 
17,486

 
52,687

 
66,898

Depreciation, depletion and amortization
79,293

 
74,401

 
319,806

 
313,190

Impairment expense
—

 
120,260

 
—

 
126,282

Gain on sale of assets
—

 
(38,901
)
 
—

 
(42,264
)
OPERATING INCOME
70,939

 
4,119

 
272,703

 
170,248

Equity in earnings of equity investees
16,611

 
15,238

 
56,484

 
43,626

Interest expense
(53,559
)
 
(56,327
)
 
(219,440
)
 
(229,191
)
Other income (expense)
(9,332
)
 
8,627

 
(9,026
)
 
5,023

INCOME (LOSS) BEFORE INCOME TAXES
24,659

 
(28,343
)
 
100,721

 
(10,294
)
Income tax (expense) benefit
1

 
(584
)
 
(655
)
 
(1,498
)
NET INCOME (LOSS)
24,660

 
(28,927
)
 
100,066

 
(11,792
)
Net loss (income) attributable to noncontrolling interests
(331
)
 
4,144

 
(1,834
)
 
5,717

Net income attributable to redeemable noncontrolling interests
(1,961
)
 
—

 
(2,233
)
 
—

NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.
$
22,368

 
$
(24,783
)
 
$
95,999

 
$
(6,075
)
Less: Accumulated distributions attributable to Class A Convertible Preferred Units
(18,684
)
 
(18,021
)
 
(74,467
)
 
(69,801
)
NET INCOME (LOSS) AVAILABLE TO COMMON UNITHOLDERS
$
3,684

 
$
(42,804
)
 
$
21,532

 
$
(75,876
)
NET INCOME (LOSS) PER COMMON UNIT:
 
 
 
 
 
 
 
Basic and Diluted
$
0.03

 
$
(0.35
)
 
$
0.18

 
$
(0.62
)
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
 
 
 
 
 
 
 
Basic and Diluted
122,579

 
122,579

 
122,579

 
122,579







6


GENESIS ENERGY, L.P.
OPERATING DATA - UNAUDITED

 
Three Months Ended
December 31,
 
Year Ended December 31
 
2019
 
2018
 
2019
 
2018
Offshore Pipeline Transportation Segment
 
 
 
 
 
 
 
Crude oil pipelines (barrels/day unless otherwise noted):
 
 
 
 
 
 
 
CHOPS 
234,989

 
202,008

 
234,301

 
202,121

Poseidon (1)
291,992

 
251,512

 
264,931

 
234,960

Odyssey (1)
132,441

 
131,088

 
144,785

 
115,239

GOPL
5,283

 
8,485

 
8,845

 
10,147

    Offshore crude oil pipelines total
664,705

 
593,093

 
652,862

 
562,467

 
 
 
 
 
 
 
 
Natural gas transportation volumes (MMbtus/d) (1)
365,424

 
421,104

 
400,770

 
432,261

 
 
 
 
 
 
 
 
Sodium Minerals and Sulfur Services Segment
 
 
 
 
 
 
 
NaHS (dry short tons sold)
29,367

 
36,125

 
126,443

 
150,671

Soda Ash volumes (short tons sold)
944,098

 
929,953

 
3,590,680

 
3,669,206

NaOH (caustic soda) volumes (dry short tons sold) (2)
18,756

 
22,917

 
78,927

 
110,107

 
 
 
 
 
 
 
 
Onshore Facilities and Transportation Segment
 
 
 
 
 
 
 
Crude oil pipelines (barrels/day):
 
 
 
 
 
 
 
Texas
95,546

 
48,877

 
59,435

 
33,303

Jay
9,916

 
12,733

 
10,461

 
14,036

Mississippi
6,014

 
5,879

 
5,994

 
6,359

Louisiana (3)
125,417

 
165,426

 
117,130

 
159,754

Wyoming (4)
—

 
—

 
—

 
33,957

Onshore crude oil pipelines total
236,893

 
232,915

 
193,020

 
247,409

 
 
 
 
 
 
 
 
Free State- CO2 Pipeline (Mcf/day)
132,388

 
125,213

 
97,912

 
107,674

 
 
 
 
 
 
 
 
Crude oil and petroleum products sales (barrels/day)
28,973

 
37,617

 
31,681

 
45,845

 
 
 
 
 
 
 
 
Rail unload volumes (barrels/day) (5)
55,155

 
165,902

 
79,530

 
89,082

 
 
 
 
 
 
 
 
Marine Transportation Segment
 
 
 
 
 
 
 
Inland Fleet Utilization Percentage (6)
94.9
%
 
97.0
%
 
96.8
%
 
95.2
%
Offshore Fleet Utilization Percentage (6)
96.0
%
 
96.5
%
 
94.6
%
 
93.5
%

(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)
Total daily volume for the three and twelve months ended December 31, 2019 includes 42,704 and 51,267 barrels per day, respectively, of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines. Total daily volume for the three and twelve months ended December 31, 2018 includes 49,802 and 55,202 barrels per day, respectively, of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines.
(4)
Our Powder River Basin midstream assets were divested during the fourth quarter of 2018. Volumes presented for the twelve months ended December 31, 2018 represent actual throughput as of September 30, 2018.
(5)
Indicates total barrels for which fees were charged for unloading at all rail facilities.
(6)
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,
2019
 
December 31,
2018
ASSETS
 
 
 
Cash, cash equivalents and restricted cash
$
56,405

 
$
10,300

Accounts receivable - trade, net
417,002

 
323,462

Inventories
65,137

 
73,531

Other current assets
54,530

 
35,986

Total current assets
593,074

 
443,279

Fixed assets and mineral leaseholds, net
4,850,300

 
4,977,514

Investment in direct financing leases, net
107,702

 
116,925

Equity investees
334,523

 
355,085

Intangible assets, net
138,927

 
162,602

Goodwill
301,959

 
301,959

Right of use assets, net
177,071

 
—

Other assets, net
94,085

 
121,707

Total assets
$
6,597,641

 
$
6,479,071

LIABILITIES AND CAPITAL
 
 
 
Accounts payable - trade
$
218,737

 
$
127,327

Accrued liabilities
196,758

 
205,507

Total current liabilities
415,495

 
332,834

Senior secured credit facility
959,300

 
970,100

Senior unsecured notes, net of debt issuance costs
2,469,937

 
2,462,363

Deferred tax liabilities
12,640

 
12,576

Other long-term liabilities
393,850

 
259,198

Total liabilities
4,251,222

 
4,037,071

Mezzanine capital:
 
 
 
Class A convertible preferred units
790,115

 
761,466

Redeemable noncontrolling interests
125,133

 
—

 
 
 
 
Partners' capital:
 
 
 
Common unitholders
1,443,320

 
1,690,799

Accumulated other comprehensive income (loss)
(8,431
)
 
939

Noncontrolling interests
(3,718
)
 
(11,204
)
Total partners' capital
1,431,171

 
1,680,534

Total liabilities, mezzanine capital and partners' capital
$
6,597,641

 
$
6,479,071

 
 
 
 
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,
 
2019
 
2018
Net income (loss) attributable to Genesis Energy, L.P.
$
22,368

 
$
(24,783
)
Corporate general and administrative expenses
12,877

 
16,997

Depreciation, depletion, amortization and accretion
74,865

 
70,816

Impairment expense
—

 
120,260

Interest expense, net
53,559

 
56,327

Income tax expense (benefit)
(1
)
 
584

Gain on sale of assets
—

 
(38,901
)
Equity compensation adjustments
—

 
(126
)
Provision for leased items no longer in use
(534
)
 
(434
)
Redeemable noncontrolling interest redemption value adjustments (1)
1,961

 
—

Plus (minus) Select Items, net
14,672

 
(15,283
)
Segment Margin (2)
$
179,767

 
$
185,457

(1)
Includes distributions paid in kind 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,
 
2019
 
2018
Net income (loss) attributable to Genesis Energy, L.P.
$
22,368

 
$
(24,783
)
Interest expense, net
53,559

 
56,327

Income tax (benefit) expense
(1
)
 
584

Depreciation, depletion, amortization, and accretion
74,865

 
70,816

Impairment expense
—

 
120,260

EBITDA
150,791

 
223,204

Redeemable noncontrolling interest redemption value adjustments (1)
1,961

 
—

Plus (minus) Select Items, net
14,877

 
(10,024
)
Adjusted EBITDA, net(2)
167,629

 
213,180

Maintenance capital utilized(3)
(7,500
)
 
(5,755
)
Interest expense, net
(53,559
)
 
(56,327
)
Cash tax expense
(231
)
 
(301
)
Cash distributions to preferred unitholders(4)
(18,684
)
 
—

Available Cash before Reserves(5)
$
87,655

 
$
150,797

(1)
Includes distributions paid in kind attributable to the period and accretion on the redemption feature.
(2)
The 2018 Quarter includes a gain on sale of assets of $38.9 million related to the sale of our Powder River Basin midstream assets.
(3)
Maintenance capital expenditures in the 2019 Quarter and 2018 Quarter were $33.8 million and $27.3 million, respectively. Our maintenance capital expenditures are principally associated with our alkali and marine transportation businesses.
(4)
Distributions to preferred unitholders that is attributable to the 2019 Quarter were paid on February 14, 2020 to unitholders of record at the close of business on January 31, 2020.
(5)
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,
 
2019
 
2018
Cash Flows from Operating Activities
$
50,558

 
$
82,475

Adjustments to reconcile net cash flow provided by operating activities to Adjusted EBITDA:
 
 
 
Interest Expense, net
53,559

 
56,327

Amortization of debt issuance costs and discount
(2,701
)
 
(2,676
)
Effects of available cash from equity method investees not included in operating cash flows
2,918

 
2,937

Net effect of changes in components of operating assets and liabilities
65,454

 
29,482

Non-cash effect of long-term incentive compensation expense
(2,198
)
 
(832
)
Expenses related to acquiring or constructing growth capital assets
333

 
2,970

Differences in timing of cash receipts for certain contractual arrangements (1)
2,408

 
(1,358
)
Other items, net
(2,702
)
 
4,954

Gain on sale of assets
—

 
38,901

Adjusted EBITDA
$
167,629

 
$
213,180

(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.


11


GENESIS ENERGY, L.P.
ADJUSTED DEBT-TO-ADJUSTED CONSOLIDATED EBITDA RATIO - UNAUDITED
(in thousands)

 
 
December 31, 2019
Senior secured credit facility
 
$
959,300

Senior unsecured notes
 
2,469,937

Less: Outstanding inventory financing sublimit borrowings
 
(4,300
)
Less: Cash and cash equivalents
 
(8,412
)
Adjusted Debt (1)
 
$
3,416,525

 
 
 
 
 
Pro Forma LTM
 
 
December 31, 2019
Adjusted Consolidated EBITDA (per our senior secured credit facility) (2)
 
$
668,595

 
 
 
Adjusted Debt-to-Adjusted Consolidated EBITDA
 
5.11X


(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)
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 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, 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, 2018 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;


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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.
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


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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.
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.


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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(loss):
 
 
Three Months Ended
December 31,
 
 
2019
 
2018
I.
Applicable to all Non-GAAP Measures
 
 
 
 
Differences in timing of cash receipts for certain contractual arrangements (1)
$
2,408

 
$
(1,358
)
 
Adjustment regarding direct financing leases (2)
2,183

 
1,979

 
Certain non-cash items:
 
 
 
 
Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value
8,394

 
(11,288
)
 
Adjustment regarding equity investees (3)
2,662

 
1,442

 
Other
(975
)
 
(6,058
)
 
             Sub-total Select Items, net (4)
14,672

 
(15,283
)
II.
Applicable only to Adjusted EBITDA and Available Cash before Reserves
 
 
 
 
Certain transaction costs (5)
333

 
2,970

 
Equity compensation adjustments
—

 
(151
)
 
Other
(128
)
 
2,440

 
Total Select Items, net (6)
$
14,877

 
$
(10,024
)
(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)
Represents the net effect of adding cash receipts from direct financing leases and deducting expenses relating to direct financing leases.
(3)
Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
(4)
Represents all Select Items applicable to Segment Margin, Adjusted EBITDA and Available Cash before Reserves.
(5)
Represents transaction costs relating to certain merger, acquisition, transition, and financing transactions incurred in acquisition activities.
(6)
Represents Select Items applicable to Adjusted EBITDA and Available Cash before Reserves.
SEGMENT MARGIN
Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and capital investment. We define Segment Margin 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.

# # #
Contact:
Genesis Energy, L.P.
Ryan Sims
SVP - Finance and Corporate Development
(713) 860-2521



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