[Technical Difficulty] You may resume.

Okay, we apologize for the delay. We believe we've got – the offshore pipeline transportation segment is engaged in providing the critical infrastructure to move oil produced from the long-lived world-class reservoirs from the Deepwater Gulf of Mexico to onshore refining centers. The sodium minerals and sulfur services segment includes trona and trona-based exploring, mining, processing, producing, marketing and selling activities as well as the processing of sour gas streams to remove sulfur at refining operations. The onshore facilities and transportation segment is engaged in the transportation, handling, blending, storage and supply of energy products including crude oil and refined products. The marine transportation segment is engaged in the maritime transportation of primarily refined petroleum products. Genesis operations are primarily located in Wyoming, Gulf Coast States and the Gulf of Mexico. During this conference call management may be making forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. The law provides Safe Harbor protection to encourage companies to provide forward-looking information. Genesis intends to avail itself of those Safe Harbor provisions and directs you to its most recently filed and future filings with the Securities Exchange Commission. We also encourage you to visit our website at genesisenergy.com where a copy of the press release, we issued today is located. The press release also presents a reconciliation of non-GAAP financial measures to the most comparable GAAP financial measures. At this time, I would like to introduce Grant Sims, CEO of Genesis Energy, L.P. Mr. Sims will be joined by Bob Deere, Chief Financial Officer; and Ryan Sims, Senior Vice President, Finance and Corporate Development.

Good morning and again, apologies for the technical difficulties. We provided a significant amount of detail around this quarter in this morning's earnings release. I thought it would be more helpful to provide more detail on the macro themes and encouraging dynamics around each of our market leading business segments as we look towards 2020 and beyond. In the Gulf of Mexico, which according to some was a dead and declining basis as of a few years ago, we continue to see robust activity which should drive production growth in the coming years. According to the EIA at the end of 2018 Deepwater Gulf of Mexico production has grown approximately 24% from 2015. Furthermore, as of October 2019, the EIA is forecasting total Gulf of Mexico production to grow to roughly 2 million barrels a day in 2020 and approximately 33% higher – approximately 15% higher just since the end of 2018. Specific to our footprint is compared to the first nine months of 2019 volumes on our main pipelines to shore CHOPS and Poseidon have increased 13% since 2015 and are up approximately 12% since the end of 2018. These volumes along with the continued development drilling and various recently sanctioned developments further provides evidence that Gulf of Mexico is not dead and will drive significant volume growth in our offshore pipeline transportation segment in the coming years. As mentioned in this morning's release, we recently entered into agreements to move 40,000 barrels per day on our CHOP System and 20,000 per day on our Poseidon. They're delivered to us by a third party pipeline that has insufficient capacity to deliver such volumes all the way to shore. The agreements include ship-or-pay provisions, have terms as long as five years and require no capital on our part. Most of…

[Operator Instructions] Your first question comes from the line of Shneur Gershuni with UBS.

Good morning guys with the new ones for me. Just a few questions to start off, you just ended your prepared remarks talking about you know being cash flow positive next year and not seeing a lot of incremental CapEx along the lines or in view, I guess. And so your focus seems to be to get your leverage down as low as possible. At the same time, there's a lot of volatility in the markets and with your guidance we've obviously some volatility in your earnings as well, too. Is there an appetite to try and take down some of the balance on the credit facility and just term it out? Or do you see yourself getting all the way to four times by the end of next year and there's absolutely no need for that?

I don't think that there's a path to get to four times by the end of next year, because that's a leverage ratio on the basis federal funded that including senior unsecured, but I think that our view is that – again, it's on an opportunistic basis that we would look at terming out some of the outstanding from the revolver. We do think that over the next several years, including within the industry perimeter revolver that was a net payer down of outstandings. We've had a number of discussions with our large banks, we feel that for businesses as ours, that the risk of renewing the credit facility beyond its current data, I think it's August of 2022, might be May or something, but we should have no problem of renewing that for another four or five year term.

Okay. Just shifting a little bit to the Granger transaction, if I remember at the time of the announcement, you talked about it being a mid five to EBITDA multiple. There was a financing agreement that was attached to it as well too with some, I think if I remember correctly, an IRR component. When you sort of think about the cost of that, where do you think that project ultimately ends up on an EBIT-to-EBITDA basis or project-to-EBITDA basis and kind of like more of a seven times multiple or an eight times multiple, just trying to understand the cost of that IRR component of the partner.

Yeah, I mean, sure, I know that I'm mixing metaphors and stuff but we have no cash pay obligations during the construction period and therefore it's kind of capitalize and the implicit cost of the capital is capitalized into the overall project. We think that on a cumulative basis that that kind of runs the – in a flat static environment of taking that capital as the value instead of the raw $330 million, which includes a contingency that we're right at the seven times multiple.

Okay, so pretty low IRR. Okay, excellent. Just two more quick questions, just with respect to your guidance, can you talk about the volume growth assumed in the offshore segment, you're talking here, expecting at least $20 million to $30 million of year-over-year growth.

Yeah, I think that it's a function of the new volumes or the new dedications which are coming on which I mentioned. It's a function of also a continued in field development drilling that we haven't talked about, but that's just kind of a normal course of business that we think could have any kind of decline still net 20 or 30 KBD on average increase in 2020 over 2019 and then, a full year of the Buckskin subsea development, this tie and the development drilling that occurred in and around the Lucius facility which is restored that total production off of that facility from indigenous productions as well as the subsea tie-backs to be in excess of 80,000 barrels a day. We think that that's a pretty conservative view of how we view the ramp in 2020 over 2019.

Okay and one final question. Can you give a little bit of color around the stable to slightly up the year-over-year sulfur services and sodium minerals agreement guide, given the impacts that occurred in 2019, everything resolved? I'm just trying to understand kind of the stability of that guide.

As we mentioned, we are seeing a little bit of softness and in export pricing on the soda ash business and we're taking a conservative view of that as we go into 2020. We did have production hiccups in the first and second quarter which everything else the same probably bedded close to $10 million worth of unexpected negatives and in 2019 hopefully that gets behind us and so we're hopeful that we're being conservative and discussing that we think that it's stable to marginally improve.

Perfect. Thank you very much and thank you for all the color today.

Thank you.

Your next question comes from a line at TJ Schultz with RBC Capital Markets.

Hey, good morning. I think just one for me, an offshore question, just trying to understand your need or outlook for potentially any meaningful capital projects to keep kind of your competitive position there. Or do you expect your existing footprint and the requirement of producers to spend to connect the sufficient to capture all the opportunities that you kind of mentioned are relatively cost free to you? Thanks.

Thanks TJ, we have in our view adequate capacity on the main lines if you will to CHOPS and Poseidon to handle the choice set, there are certain scenarios developing that there might be some expansions in the 2021, '22, '23 type timeframe require to – necessary to facilitate the hard pipe passing of incremental production that we see coming on, but we would have incremental ship-or-pay agreements associated with that. So we think that those would be very extremely attractive. It could be easily financed under the revolver to the extent that they materialize because of the mechanics under our revolver we get the in essence, the proportional take-or-pay credit if we were to spend money on, so if we fashion everything in less than five times deal, it's basically a credit neutral to the extent that they come up.

Okay, but that is the kind of increased outlook into 2020. That's not required for that outlook. There's nothing firm as far as –

Yeah, we don't have to spend any money for that outlook, yeah, even in 2020.

Okay, appreciate it. Thanks, Grant.

Sure thanks.

[Operator Instructions] Your next question comes from Ethan Bellamy with Baird.

Hey, guys, good morning. One housekeeping question on the GSO preferred. Could you confirm that you're using 50-50 treatment on that in terms of your reported leverage and in covenant?

It doesn't we're going as zero debt treatment for the calculation of our coverage. The calculation of our bank covenant has nothing to do with – it's not treated as debt.

Okay, alright. That's helpful. Thank you. And then we've seen some trepidation in the markets, I think justifiably so about comments from Elizabeth Warren about potentially ending oil and gas leasing on federal lands, which I presume would mean the Gulf of Mexico. Can you guys through what the implications would be fundamentally, if we had a leasing ban and effect as of the first quarter of 2021. How long would something like that take to show up in your volume numbers, considering how long the Gulf of Mexico project lead times are?

I mean, obviously, there's a lot of political rhetoric and I don't think that we're necessarily going to weigh in on a lot of that, but the law, which governs activities in the Gulf of Mexico is the Outer Continental Shelf Lands Act which requires a Department of Interior to maintain an oil and gas leasing program. Thus, our opinion, and there's a lot of people and I'm not a lot there's a lot of people researching it, but that complete and permanent ban on all new leases in the Gulf of Mexico is not possible without Congress passing a law and changing the legislation. So I mean, I think that's the reality of the situation once – as we're reminded by Madam Speaker, there are three branches of government, but the legislature has put the laws on the books. So I don't know that it can be done. B, I think that the existing leases which are held by production and still under primary term, I think would generate a significant which was 10 years by the way the primary term from the date that is leased, I think that taking so to speak of private property back, retaking by the government would be a very difficult and expensive thing to do. So I don't know what else to weigh in on that, but we're certainly monitoring it. We think it is political rhetoric. And if that and fracking were somehow to come to pass, then I think that would be the equivalent of the largest tax increase and most regressive tax increase known in American history if they were to come to pass.

Thank you, Grant. I appreciate that context. One more question on Granger. If you guys are the low cost producer and you have an excess of 100 year reserve life, what dictates or governs the size of the expansion that you guys are willing to do, why not say a million and a half tons for example?

In particular in Granger, Granger was a standalone facility that our predecessor companies FMC purchased in the late 90s that had historically produced 1.2 to 1.3 million tons a year with dry mining given this location which is about seven miles to the northeast of our Westvaco facility, which is our main facility where we produce about three and a half a million tons currently. It ran out of dry ore in the seam, there's 26 stack seams, so the trona there it ran out of dry ore and we converted it once we acquired it to secondary recovery as solution mining facility. So long story short the infrastructure and this is why we refer to a fixed cost absorption, Ethan and lowering the cost of the existing ton. The infrastructure exists to handle 1.2, 1.3 million tons. We don't have – for the lack of a better description since it was a dry mining facility. And now we're converting it to the larger – or putting it back to its nameplate capacity using solution mining, we have to add a backward capacity to get rid of the water, if you will, that we use to sort of solution mine the soda. So it was a very cheap cost effective way to return the Granger facility to its nameplate capacity of 1.2 to 1.3. And I would also point out that I mentioned a minimum of 125 years that in particular in Granger that assumes only – that's the reserves on the two seems that we are currently solution it that you added the other stack seams it's probably three to 400 years.

Okay, very helpful. Thank you very much Grant. Appreciate it.

Thank you.

And there are no further questions at this time.

Okay, well thanks everyone and we appreciate and again I apologize for the start and the technical difficulties at the first and we'll talk to you all soon. Thank you.