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

HOUSTON--(BUSINESS WIRE)--Feb 19, 2020--

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.

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.

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.

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.

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   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  

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 (MMBBtus/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.

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  

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.

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 (in thousands) 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.

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.

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; 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 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.

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.

View source version on businesswire.com:https://www.businesswire.com/news/home/20200219005284/en/

CONTACT: Genesis Energy, L.P.

Ryan Sims

SVP - Finance and Corporate Development

(713) 860-2521

KEYWORD: TEXAS UNITED STATES NORTH AMERICA

INDUSTRY KEYWORD: ENERGY UTILITIES OIL/GAS

SOURCE: Genesis Energy, L.P.

Copyright Business Wire 2020.

PUB: 02/19/2020 06:10 AM/DISC: 02/19/2020 06:10 AM

http://www.businesswire.com/news/home/20200219005284/en

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