Genesis Energy, L.P. (NYSE: GEL) today announced its second quarter results.

We generated the following financial results for the second quarter of 2021:

• Net Loss Attributable to Genesis Energy, L.P. of $41.7 million for the second quarter of 2021 compared to Net Loss Attributable to Genesis Energy, L.P. of $326.7 million for the same period in 2020, which was inclusive of non-cash impairment charges of $277.5 million.

• Cash Flows from Operating Activities of $111.0 million for the second quarter of 2021 compared to $62.6 million for the same period in 2020.

• Total Segment Margin of $152.1 million for the second quarter of 2021.

• Available Cash before Reserves to common unitholders of $49.6 million for the second quarter of 2021, which provided 2.70X coverage for the quarterly distribution of $0.15 per common unit attributable to the second 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 $140.9 million in the second quarter of 2021.

• Adjusted Consolidated EBITDA of $606.6 million for the last twelve months ended June 30, 2021 and a bank leverage ratio of 5.47X, both calculated in accordance with our credit agreement and are discussed further in this release.

Grant Sims, CEO of Genesis Energy, said, “The second quarter was in line with our expectations, but more importantly, the longer term Genesis story continues to improve as we move through 2021 and into 2022 and beyond. Our two contracted upstream developments in the Gulf of Mexico remain on track for first oil in the front half of 2022. We expect a continuing recovery in our soda ash business with longer term growth driven by a combination of a return to pre-pandemic economic activity, a resumption of normalized GDP growth, and the expected demand growth for soda ash given its critical importance as a fundamental building block for many activities in the unfolding energy transition. As a result, we believe Genesis is very well positioned for substantial growth over the coming years.

Our offshore pipeline transportation segment performed slightly ahead of our expectations during the second quarter despite the increased level of maintenance and downtime from our producer customers. While we expect some producer maintenance from the second quarter to cross over into the third quarter, and assuming we experience no worse than a normalized hurricane season, we would reasonably expect our third quarter to come in towards the lower end of our previously announced range of $80 - $85 million of Segment Margin per quarter. The producer community in the Gulf of Mexico continues to operate business as usual and current activity levels continue to suggest that the Gulf of Mexico remains one of the most economically competitive and least emission intensive basins in North America that will be around for decades and decades to come.

As we look forward to 2022, our two large contracted upstream developments, Argos and King’s Quay, remain on track for first oil in the first half of 2022. In fact, Murphy recently announced the King's Quay floating production platform is scheduled to sail away to its final home in the Gulf of Mexico sometime this quarter. In anticipation of first oil, BP and Murphy both have a number of wells pre-drilled at each of their respective fields which should allow for a rapid ramp in the anticipated production over a 6-9 month period. We continue to expect these two fields, when fully ramped up, will generate in excess of $25 million a quarter, or over $100 million a year, in additional Segment Margin and free cash flow.

Additionally, we remain in active dialogue and continue to advance our discussions to provide midstream services using our existing footprint, along with the potential to deploy new capital at contracted low single digit build multiples, with three new stand-alone deepwater developments in various stages of sanctioning with anticipated first oil starting in the late 2024-2025 time frame. These developments represent up to approximately 200,000 barrels per day of incremental production in the central Gulf of Mexico, and we would anticipate the producers of each of these projects will make their respective final investment decisions in the second half of this year.

Turning to our sodium minerals and sulfur services segment. In our alkali business, while we were successful in raising export prices in the second quarter, our results were negatively impacted by increased operating expenses. During the quarter, we successfully completed our scheduled long-wall move and started certain planned maintenance activities at our Westvaco production facility. The long-wall move had the practical effect of disrupting our normal production activities for the equivalent of roughly 3 or 4 days (net of the inventory we built up prior to the move). Upon completing the long-wall move and re-starting production activities after certain scheduled maintenance items, we experienced some operational challenges that further negatively impacted our production volumes for the quarter. The lower production volumes limited our fixed cost absorption and, when combined with an increase in certain operating expenses due to operational inefficiencies, further exacerbated the volumetric impact of our maintenance work during the quarter. In the second half of the year, we could see potential cost pressure from higher natural gas prices and some potential rail movement delays for our export volumes as the Union Pacific has experienced some temporary damage to their system in the Pacific Northwest due to the wildfires.

Despite these increased costs, the overall macro story in soda ash remains intact with, by our estimation, all natural producers being sold out and higher cost synthetic production needing to come online to support rapidly increasing demand as we continue to recover from the shut-down of economic activity resulting from the public policies to deal with Covid-19. In response to the supply and demand dynamic further tightening and lower export volumes of synthetic soda ash from China, ANSAC announced another price increase for soda ash in early June for the third quarter on all of their non-contract sales of soda ash and on contracted sales when contracts allow. Due to the nature of our contract structures and geographic sales mix, we do not realistically expect to see a material financial impact of these increasing prices in 2021. However, there is no question in our minds that this increasingly tight supply and demand dynamic will continue to support prices rising through the remainder of the year. This is very important, especially towards the end of the year when we would otherwise re-determine most of our contract prices for the majority of our sales for calendar year 2022 for both our domestic sales, representing approximately fifty percent, and our international sales through ANSAC, including to Latin America and Asia, representing the balance of our total annual sales. Accordingly, we expect soda ash prices to be sequentially higher in 2022, but our weighted average price will likely not return to pre-pandemic levels next year, primarily due to our longer term domestic contracts containing caps and collars, which not only protect us in a falling price environment, but also limit our ability to increase prices beyond a certain point in an improving market.

However, we continue to believe the market dynamic exists where our weighted average price should move increasingly closer to pre-pandemic levels as we enter 2023, or we would suppose 2024 at the latest, which would coincide with our Granger expansion coming online and be at or above the price deck we originally assumed when we sanctioned the project in the third quarter of 2019. We remain on schedule for first production from Granger in the third quarter of 2023 and we would expect production to ramp to its design capacity of 1.3 million tons a year over the subsequent 12-15 months. As mentioned on our last earnings call, we continue to evaluate the anticipated cadence of the future spend on the project and the potential to deploy some of our anticipated free cash flow to fund portions over and above the $250 million, which we are obligated to draw under our asset-level preferred funding arrangement. We would expect to make this decision in the second half of this year.

Our legacy refinery services business performed in line with our expectations.

Our onshore facilities and transportation segment performed in line with our expectations. We did not see any crude-by-rail volumes at our Scenic Station during the second quarter, but did see steady levels of activity at our Port of Baton Rouge terminal. If current market conditions and the WCS to Gulf Coast differentials persist, we would not reasonably anticipate any crude-by-rail volumes for the remainder of the year and any such pre-paid credits that have been generated and not used by our main customer would otherwise expire by the end of 2021. The remainder of our onshore facilities and transportation segment performed in line with our expectations.

As we look forward in this segment, margin will be driven by increasing offshore volumes moving through our Texas City and Raceland facilities along with continued activity around our Port of Baton Rouge terminal, which primarily serves the ExxonMobil refinery complex. Given the expected additional pipeline capacity out of Canada, we are not expecting any crude-by-rail activities over the coming years unless there is a delay in such pipeline capacity coming online. Longer term, for minimal capital and a satisfactory commercial arrangement, there is the potential to upgrade our Scenic Station rail unloading facility to be able to handle raw bitumen that could be available in the market, as a non-hazardous material that could be transported by rail, as several diluent recovery units get developed in Canada. It is also worth noting that payments associated with the exit of our legacy CO2 pipeline business will end in the fourth quarter of 2021.

Our marine transportation segment continues to be negatively impacted by lower refinery utilization and, in general, a lighter crude slate being run at many refineries. While refinery utilization numbers have increased in recent months, they still remain below pre-pandemic levels which has suppressed our brown water barge utilization and ultimately our ability to increase day rates. We also had several scheduled dry-docks of certain of our blue water vessels in the quarter. However, the majority of our scheduled maintenance work is now behind us and demand for our blue water vessels is quite strong. We continue to believe as the US returns to more normalized, pre-pandemic levels of economic activity, the Jones Act tonnage supply and demand dynamic will continue to tighten, and we should benefit across all of our classes of marine assets as we progress through 2021 and into 2022.

During the quarter, we successfully refinanced our senior secured credit facility extending the tenor to March 2024 and completed a tack-on offering of our 2027 notes. We used the proceeds from the tack-on offering for general partnership purposes, including repaying a portion of the borrowings under our recently extended senior secured facility to further improve our liquidity position. We currently have no unsecured maturities until 2024 and ample availability under our senior secured credit facility to manage the current operating environment. During the quarter we were also able to reduce our total Adjusted Debt, as calculated under our credit agreement, by $38 million.

Given the near term dynamics in our base businesses, and specifically our expectation of no crude-by-rail activity in the second half of the year, a slower than previously expected recovery in our marine segment and a non-cash increase in general and administrative expenses associated with long-term incentive-based compensation, we currently expect to come in towards the low end of our previously announced guidance range for full year Adjusted Consolidated EBITDA of $630 and $660 million¹, which includes approximately $30-$35 million of pro-forma adjustments. As we work through the trailing effects of the pandemic and 2020 hurricane season, we remain confident that we have a clear path to tangible growth in our Adjusted Consolidated EBITDA, increasing levels of free cash flow and continued debt reduction. Our top priority remains our balance sheet and the combination of these items will help accelerate our ability to achieve our long-term leverage ratio of 4.0x in the coming years.

I would like to once again recognize our entire workforce, and especially our miners, mariners and offshore personnel who live and work in close quarters during this time of social distancing. I am extremely proud to say we have safely operated our assets under our own Covid-19 safety procedures and protocols with no impact to our business partners and customers. As always, we intend to be prudent, diligent and intelligent and focus on delivering long-term value for everyone in our capital structure without ever losing our commitment to safe, reliable and responsible operations."

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

Financial Results

Segment Margin

Variances between the second quarter of 2021 (the “2021 Quarter”) and the second quarter of 2020 (the “2020 Quarter”) in these components are explained below.

Segment Margin results for the 2021 Quarter and 2020 Quarter were as follows:

Offshore pipeline transportation Segment Margin for the 2021 Quarter increased $8.0 million, or 11%, from the 2020 Quarter primarily due to higher crude oil and natural gas transportation volumes. During the 2021 Quarter, we transported higher volumes on our 100% owned SEKCO pipeline as a result of increased production activity from the Buckskin and Lucius fields, which are fully dedicated to SEKCO and further downstream to Poseidon. Additionally, we experienced less downtime during the 2021 Quarter, as the 2020 Quarter was impacted by extended downtime due to the economic environment from the Covid-19 pandemic and as a result of weather interruptions from Tropical Storm Cristobal.

Sodium minerals and sulfur services Segment Margin for the 2021 Quarter increased $13.4 million, or 54%. This increase is primarily due to higher soda ash volumes and favorable export pricing in our alkali business and higher NaHS sales volumes in our refinery services business during the 2021 Quarter. During the 2020 Quarter, volume demand in our alkali business was significantly impacted by the worldwide economic shutdowns and uncertainty from the Covid-19 pandemic. As economies have continued to open up and reduce restrictions, we have seen demand recovery, both domestically and internationally through ANSAC. We continued to produce at a high rate at our Westvaco facility during the 2021 Quarter, despite a short halt in production for our long-wall move and certain other planned maintenance activities. Additionally, we saw slightly favorable export pricing in the 2021 Quarter relative to the 2020 Quarter and sequentially from the first quarter of 2021, which is evidence that the supply and demand balance is becoming more balanced. These increases were partially offset by lower domestic pricing and lower sales volumes associated with our Granger facility, as it was put in cold standby during the second half of 2020. Our Granger facility is expected to come back online during the second half of 2023 upon the completion of the granger expansion. In our refinery services business, we reported higher NaHS volumes in the 2021 Quarter due to improved volume demand from our domestic pulp and paper customer base that was negatively impacted in 2020 as a result of the timing of spring turnarounds and outages due to the Covid-19 pandemic.

Onshore facilities and transportation Segment Margin for the 2021 Quarter increased $1.2 million, or 5%. This increase is primarily due to higher cash receipts received during the 2021 Quarter from Denbury of approximately $12.3 million associated with our previously owned NEJD pipeline as a result of our agreement reached during the fourth quarter of 2020. This increase was partially offset by: (i) lower contracted minimum volume commitments with our main customer associated with our Baton Rouge corridor assets (including rail, terminal and pipeline volumes), as these commitments stepped down beginning in 2021, and the use of built up prepaid transportation credits during the 2021 Quarter by our main customer; and (ii) the divestiture of our Free State pipeline during the fourth quarter of 2020, which contributed positively to Segment Margin in the 2020 Quarter.

Marine transportation Segment Margin for the 2021 Quarter decreased $9.7 million, or 53%, from the 2020 Quarter. This decrease is primarily attributable to lower utilization and day rates in our inland business during the 2021 Quarter and lower rates in our offshore barge operation, including our M/T American Phoenix tanker. During the 2021 Quarter, we began to see sequential improvement in the offshore barge spot market pricing, but we expect to see continued pressure on our utilization, and to an extent, the spot rates in our inland business as Midwest and Gulf Coast refineries have continued to run at lower utilization rates to better align with overall demand as a result of Covid-19 and the current operating environment. 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 have yet to fully recover from their cyclical lows.

Other Components of Net Income

We recorded Net Loss Attributable to Genesis Energy, L.P. of $41.7 million in the 2021 Quarter compared to Net Loss Attributable to Genesis Energy, L.P. of $326.7 million in the 2020 Quarter.

Net Loss Attributable to Genesis Energy, L.P. in the 2020 Quarter was negatively impacted by impairment expense of $277.5 million associated with the rail logistics assets included within our onshore facilities and transportation segment and a one-time charge of approximately $13 million associated with certain severance and restructuring costs included within general and administrative costs and expenses. Additionally, the 2020 Quarter included cancellation of debt income of $18.5 million, which is recorded within "Other income (expense)" on the Unaudited Condensed Consolidated Statements of Operations, associated with the open market repurchase and extinguishment of certain of our senior unsecured notes.

Net Loss Attributable to Genesis Energy, L.P. in the 2021 Quarter was impacted, relative to the 2020 Quarter, by: (i) lower depreciation, depletion and amortization expense of $12.6 million primarily due to lower depreciation expense on our rail logistics assets as they were impaired during 2020; (ii) an unrealized (non-cash) loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of $14.3 million in the 2021 Quarter compared to an unrealized (non-cash) loss of $21.8 million during the 2020 Quarter recorded within Other income (expense); and (iii) higher interest expense of $7.6 million.

Earnings Conference Call

We will broadcast our Earnings Conference Call on Wednesday, August 4, 2021, at 9:15 a.m. Central time (10:15 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.

This press release includes forward-looking statements as defined under federal law. Although we believe that our expectations are based upon reasonable assumptions, we can give no assurance that our goals will be achieved. Actual results may vary materially. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that we expect, believe or anticipate will or may occur in the future, including but not limited to statements relating to future financial and operating results and compliance with our credit facility covenants, the anticipated benefits of our transactions with Denbury, our expectations regarding the potential impact of the Covid-19 pandemic, and our strategy and plans, are forward-looking statements, and historical performance is not necessarily indicative of future performance. Those forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside our control, that could cause results to differ materially from those expected by management. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for products (which may be affected by the actions of OPEC and other oil exporting nations) and a reduction in demand for our services resulting in further impairments of our assets, the outbreak or continued spread of disease (including Covid-19), the timing and success of business development efforts and other uncertainties, and the realized benefits of the preferred equity investment in Alkali Holdings Company, LLC 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, 2020 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:

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:

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:

SEGMENT MARGIN

Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and capital investment. We define Segment Margin ("Segment Margin") as revenues less product costs, operating expenses, and segment general and administrative expenses, 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/20210804005379/en/