Kinder Morgan Inc (KMI) Q2 2019 Earnings Call Transcript
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Kinder Morgan Inc (NYSE: KMI)
Q2 2019 Earnings Call
Jul 17, 2019, 4:30 p.m. ET
Contents:
Prepared Remarks
Questions and Answers
Call Participants
Prepared Remarks:
Operator
Welcome to the Quarterly Earnings Conference Call. [Operator Instructions]
I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Sir, you may begin.
Richard D. Kinder -- Executive Chairman
Thank you. Brandon. Before we begin, as usual, I'd like to remind you that today's earnings releases by KMI and KML. And this call includes forward-looking at financial outlook statements within the meaning of the Private Securities Litigation Reform Act of 1995 the Securities and Exchange Act of 1934, now for both Canadian provincial and territorial securities laws, as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to reasonable [Technical Issues] disclosures on forward-looking and financial outlook statements and use of non-GAAP financial measures set forth at the end of KMI's and KML's earnings releases and to review our latest filings with the SEC and Canadian Provincial and Territorial Securities Commissions for a list of important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking and financial outlook statements.
Before we turning the call over to Steve and the management team, I usually begin these quarterly earnings calls with a few words about our financial strategy at Kinder Morgan. I hope by now we've made it very clear that we are managing our assets and the substantial cash flow they generate, the financially responsible way that maximizes returns to our shareholders. That said, it's important to understand and appreciate what underpins that cash flow and whether that business will continue to generate strong and growing returns with the opportunity to expand our asset base.
As you know, majority [Phonetic] of our segment earnings before DD&A comes through our natural gas segment. Through our 70,000 plus miles of natural gas pipelines. We handle about 40% of all the gas consumed in this country. In addition, the bulk of our current and projected capital expansion dollars are also devoted to the natural gas segment. We are very bullish on the future of natural gas from both the supply and demand perspective, natural gas is critical to our American economy to satisfy the growing energy needs around the world. Very importantly to reducing our greenhouse gas emissions in a cost effective manner. Our optimism is borne out by actual results over the last few years and by the consensus estimates of those firms and governmental agencies, which follow the energy feel most closely.
Sometimes we lose sight of the actual facts involve, so looking first through the rear view mirror, US demand in 2018 was up 12% from 2017, 44% above demand of the decade earlier. 2019 is shaping up to be another strong year. Looking forward, as we've previously said, US demand is projected to grow by over 30% between now and 2030, the demand growth is being driven by LNG power and industrial demand and by exports to Mexico.
Turning to the supply side, the US is projected by 2025 to be producing one quarter of all the natural gas in the world and accounting for over 50% of the growth in supply -- in global supply by that year. Now look, I am aware of Mark Twain saying that making predictions is very difficult, particularly when they concern in the future. But I believe that under almost any scenario natural gas is a winner for years to come. Connecting these vast supplies, these best US suppliers to growing demand markets will drive new infrastructure and higher utilization of existing assets. KMI is very well positioned to take advantage of these opportunities, especially in Texas and Louisiana, where our extensive network of pipelines is very well situated to serve the rapidly growing LNG export and petrochemical facilities. That's a big reason why we feel good about the long-term future of this company.
Then I'll turn it over to Steve.
Steven J. Kean -- Chief Executive Officer
Alright. Thanks, Rich. We will be updating you on both KMI and KML this afternoon. I'm going to start with KMI, then turn it over to our President, Kim Dang, give you the update on our segment performance. Our CFO, David Michels will take you through the numbers; Dax Sanders will update you on KML and then we'll take your question.
The summary on KMI is this, we've been adhering and continue to adhere the principles that we've laid out for you. We have a strong balance sheet, having that are approximately 4.5 times debt-to-EBITDA target and with ratings upgrades now from all three ratings agencies [Phonetic].
We're maintaining our capital discipline through our return criteria, a good track record of execution and by self funding our investments. We are returning value to shareholders with the 25% year-over-year dividend increase and we continue to find attractive growth opportunity. Again, strong balance sheet, capital discipline, returning value to our shareholders and finding additional growth opportunities. Those are the principles we operate by. Our performance this year so far has been solid and we projected to be solid. We've had headwinds on commodity prices on our CO2 segment and we've had a delay in the in-service of our Elba LNG facility.
Also, as we said at the beginning of the year we did not budget for rate case settlements resulting from the 501-G process. But we are pleased with the settlements we were able to obtain. We had tailwinds in terms of lower interest rates and good performance in our West, North and Midstream gas groups helping to offset these negatives, putting it altogether as we said last quarter, we expect to be slightly under plan on an EBITDA basis but on plan from a DCF standpoint.
So here are some updates on a few key projects starting with our Permian natural gas pipeline projects. Our customers are anxious to have us get the gas out of the Permian, so that they can get their oil and NGLs out as well. We've got two projects to get the gas out, Gulf Coast Express and Permian Highway, and we are in discussions on a possible third pipeline, which we're calling Permian Pass.
GCX and Permian Highway are each about 2 Bcf a day of capacity. Both are secured by long-term contracts and both are in the execution stage. GCX is expected to be in service slightly ahead of schedule. The original schedule was October 1 of this year, we now expect to be in the full 2 Bcf a day, the in-service level in the last week to 10 days of September. The pipe is in the ground, there is still commissioning work going on the compressor [Phonetic] and meter stations, but our expectation is for a slightly early in-service date.
Permian Highway is receiving pipe and acquiring right of way, we hired our pipeline construction firms and we are on schedule for completion in October 2020. We had a significant court decision last month, which essentially affirm the existing eminent domain process that has been used -- in use for decades in the state of Texas. We feel confident in our legal position, but it is nevertheless a good thing to have prevailed in the case. The both of our current projects are on schedule. Both projects are at attractive returns and both projects bring us additional opportunity in our downstream pipelines combined they bring 4 Bcf a day of incremental gas to system, it moves about 5 Bcf a day today. Those projects bring opportunities for downstream expansion and optimization as we find homes for all that incremental gas through our connectivity with LNG facilities, Texas Gulf Coast power, industrial and petchem demand.
We are working with customers on a third 2 Bcf a day pipeline in the Permian past pipeline. This is a work in progress. It's not in the backlog at this point, certainly, but it is moving along. These Permian project shows taking advantage of a very positive situation. There is large supply growth in Texas and large demand growth in Texas. We can bridge the two and connect to our premier Texas Intrastates pipeline network and stay entirely within the state of Texas where we have more commercial flexibility.
As we pointed out the conference this year, 70% of natural demand, natural gas demand growth between now and 2030 is expected to be in Louisiana and Texas and our systems are well positioned to benefit from that. On another key project Elba, our Elba Liquefaction facility, we are closing in on in service. We are now mechanically complete on four of the 10 MLS units. The call box on the first unit is now uniformly cold at cryogenic temperatures and we are ramping up the volume. We are producing LNG. Unevenness in the temperatures between the bottom and the top of the coal box had been plaguing our start-up over the last several weeks. We are now past that and ramping up to full service. We expect to be in service on unit one soon and that unit represents 70% of project revenue. I'd like to be more definitive about the exact in-service date, but it is a function of whether we have to suspend the production of LNG for additional troubleshooting. The delay we've experienced certainly unwelcome. But the risk allocation between us and our contractor in our customer provides significant protection and mitigates the impact to our internal rate of return. The impact of the delay is expected to be approximately 100 basis points unlevered after tax on a still attractive returns. We'll make a separate announcement when we have the first unit in service.
Also of note, we added $400 million worth of projects in the backlog this quarter, partially offsetting $800 million with the projects are placed in service or removed from the backlog. Most of what we removed from the backlog within CO2 segment. We remain on our team, CO2 remains very disciplined here and we reduced capital spend when we [Indecipherable] the economics do not justify the expenditure. The backlog now stands at $5.7 billion, and most of the new capital investment is in natural gas, which now makes up nearly 80% of our total backlog.
And with that, I'll turn it over to Kim.
Kimberly Allen Dang -- President
Thanks, Steve. Natural [Phonetic] gas had another outstanding quarter, it was up 7% from the underlying market fundamentals remain very strong between 2018-2019 natural gas demand is expected to increase by over 5 Bcf a day. Almost 60% of KMI segment earnings for DD&A come from our natural gas business and of the natural gas consumed in the US. We move about 40% on our pipeline. The fundamentals underlying our largest business are very strong.
Transport volumes on our transmission size increased approximately 3.1 Bcf a day, second quarter versus the second quarter of 2018 about 10%. This is a sixth quarter in a row in which volumes exceeded the comparable period by 10% or more. If you look at where these volume showed up in our transmission pipes. CNG volumes were up 760 million cubic feet per day due to increased Permian volumes and increased California demand. KMLA volumes were up 670 million cubic feet per day due to LNG export, and overall for Kinder Morgan deliveries to LNG export plants increased approximately 1.4 Bcf a day.
CIG volumes were up approximately $500 million a day due to increased DJ Basin production and colder weather. Ruby volumes were up 370 million [Phonetic] cubic feet per day did colder Western's weather an outage in the Pacific Northwest with volumes were up $370 a day due to increase DJ production. On a gathering assets volumes were up approximately 16% or 450 million cubic feet per day, and that was primarily due to higher volumes on our Haynesville and our Eagle Ford gathering system.
Overall, natural gas wellhead volumes out of the key basins that we serve continue base [Phonetic]. Permian natural gas wellhead volumes increased approximately 30% versus the second quarter of 2018. Haynesville increased approximately 27%. Bakken increased approximately 27% [Phonetic] and Eagle Ford increased approximately 5%. Overall, the higher utilizations on our system. A lots of which came without the need to spend significant capital resulted in nice bottom line growth for the segment in the quarter and longer-term will drive expansion opportunities as the market continues to grow and our pipes reach capacity. Our product segment was down in the quarter slightly, here increased contributions from our Southeast refined products terminal. Our Central Florida pipeline, our Double Eagle pipeline -- and our condensate quarter were more than offset by lower contribution from KMCC from SFPP.
Volumes on KMCC were actually up 12%, but that was more than offset by lower rate. SFPP was impacted by higher operating expenses. Overall, crude and condensate volumes were up 2% refined product volumes were flat in the quarter and EIA refined products volume, the estimate is that they were down approximately 0.9% is a little bit better than the national average.
On our terminal business was down in the quarter, the liquid business which accounts for about 80% of this segment had nice increases from expansion projects. The largest of which was our baseline terminal expansion projects in Edmonton. We also saw higher throughput and ancillary charges in our Houston Ship channel facilities. However, these increases were more than offset by the lease expense at our Edmonton South Terminal became a third party application post our Trans Mountain sale, and impacts from historically high water levels on the Mississippi River that resulted in reduced volumes and contributed to off-hire time on our Jones Act tankers. We added approximately 1.2 million barrels of tankage in the quarter versus the second quarter of 2018. Now it's primarily result of the baseline project and that brings our total leasable capacity to around 89 million barrels.
The board business was also down in the quarter due to lower volumes, both volumes were down approximately 11% due to lower coal, pet coke and steel. Our CO2 segment was down in the quarter and that was primarily due to lower crude and NGL prices. Our net realized crude oil price was down about $8 per barrel for the quarter and that's largely driven by our Mid/Cush basis hedges. NGL prices were down approximately $9 per barrel.
On the crude oil production side, volumes were down approximately 2% primarily due to lower production at Katz and Goldsmith. Tall Cotton production increased 8% versus the second quarter of 2018. But with steps substantially below our plan. The reservoirs processing slower than we expected and until we can determine how to address this issue started to reduce 2019 capital expenditures associated with this asset. Largely as a result of this decision, free cash flow from our CO2 business has increased by approximately $80 million for 2019. As almost all the production associated with these customer benefit future years. And CO2 as with all our assets, we diligently monitor our investments to make sure that they are going to achieve our projected return. The extent that we think there is a material risk with returns [Phonetic] either take steps to mitigate our downside or we do not move forward with those investments as we did here.
At SACROC, which accounts for almost two-thirds of our current production. Production was up 1% in the quarter and we expect to be above budgeted volumes for the year. So nice current performance of SACROC. When you look at the longer term, the story has also improved. In our mid-year reserve review SACROC proved reserves increased by about 5.5 million barrels represents approximately 33% increase in proved reserves. This was driven primarily by increased recovery factors as a result of increased performance.
On our CO2 sales and transport business it was up slightly in the quarter. And that was driven by an 11% increase in CO2 volumes, which more than offset a 4% decrease in price.
with that, I'll turn it over to Dave Michels.
David P. Michels -- Vice President and Chief Financial Officer
Kim, today we are declaring a dividend of $0.25 per share, same as last quarter and in line with the budget or a $1 per share for the [Indecipherable] 25% increase over the dividends 2018. KMI's adjusted earnings and DCF grew from last year's second quarter. Generated DCF per share of $0.50, two times or approximately $560 million in excess of the declared dividend.
Revenues were down 6% this quarter compared to the second quarter in 2018. The decline in cost of sales more than offset our lower revenues. Our gross margin was up relative to the prior period. Some of that came from the benefit of a non-cash, losses on derivative contracts during the second quarter of 2018. We treat a certain items and excluded from our non-GAAP metrics. Excluding certain items, gross margin was in-line period over period. Net income available to common stockholders is $518, up 388% better than the second quarter of 2018 largely to impairments taken during the second quarter of 2018, which we treat a certain items. Before certain items, net income available to comments stockholders was up $34 million or approximately 7%. That includes the benefit of euro preferred dividend payments down from $39 million as a result of the conversion of our preferred equity secure October of last year. Adjusted earnings per share was $0.22 for the quarter, up $0.01 or 5% from the prior period.
Moving on to distress distributable cash flow performance. Our Natural Gas business, which you've already heard was up nicely $73 million or 7% we saw greater performance versus last year across multiple assets. EPNG was up driven by Permian supply growth more than offsetting the impacts that asset received related to our 501-G settlement. We had increased contribution in multiple expansion, financial projects [Phonetic] in-service.
KinderHawk and South Texas G&P assets were up driven by increased volume. Kinder Morgan Louisiana pipeline was up due to our the being passed expand. And Kim provided the main drivers for our products terminal the CO2 segment. Moving onto our Kinder Morgan Canada segment that was down 100% as a result of our sale of the Trans Mountain pipeline.
G&A expense was lower by $8 million due to greater overhead capitalized growth projects. As well as lower G&A from the Trans Mountain sale. Partially offsetting those is higher pension expenses rolls in the last year. Those pension expenses that hit G&A are non-cash and we add them back through our DCF and replace those with our actual cash contribution pension. Interest expense was $22 million lower and that was driven by a lower debt balance and greater interest capitalized to projects as well. Those are partially offset by higher LIBOR rate versus last year which impact our interest rate swaps.
Preferred stock dividends are down $39 million as a result of the conversion of our preferred securities. Cash taxes were higher by $18 million [Phonetic] and that's related to payments at Citrus, grater taxable income there versus last year and higher taxes at KML which tax will walk through. Those impacts were expected our cash tax forecast is actually slightly favorable to our budget for the full year.
[Indecipherable] capital was $26 million higher versus the second quarter 2018, mainly due to pipeline integrity work in our Natural Gas segment. Again we have budgeted for a greater expenditure, in fact, our full-year forecast is slightly favorable budget versus [Phonetic] total DCF of $1,128 million was up $11 million or 1% summarize the main drivers greater contributions from our natural gas segment. Lower interest expense, preferred stock dividends, mostly offset by our sale of Trans Mountain lower commodity prices impacting our CO2 segment, higher sustaining CapEx and higher cash tax payments.
DCF per share $0.50 per share was in line with last quarter. Same drivers as DCF, but it includes the impact from incremental shares that were issued as a result of our preferred securities conversion.
Moving onto the balance sheet. We ended the quarter at 4.6 times debt-to-EBITDA, which is consistent with our budget and slightly higher than where we were at year-end 4.5 times. End of the year leverage is forecasted to be 4.6 times, which is just slightly unfavorable to our budget of 4.5 times [Phonetic] and is consistent our long-term leverage target of approximately 4.5 times.
As we said last quarter, forecast for that full year EBITDA to be slightly lowered spend budget or a little less than 2% below budget. Drivers there include the FERC 501-G impacts the Elba delay, lower commodity prices impacting CO2 higher pension expenses, partially offset by the very strong Permian supply growth.
All of those items impact DCF as well, but DCF includes the benefit of favorable interest expense is expected for the year and it also adds back the non-cash pension expense. As a result, we expect our full year DCF to be in line with budget. Items to note on the balance sheet. With regard to some of the larger changes from year-end cash, it has a $3.1 billion use driven by a $1.3 billion pay-down of bonds, which happened in the first quarter $800 million distribution to our public -- KML shareholders and $340 million of Canadian cash taxes related to the sale of Trans Mountain. Other current liabilities this is where we booked payable for the KML public shareholders distributor also includes movements in accrued interest and taxes.
Long-term debt was down mainly due paying off the $1.3 billion of bond. Adjusted net debt ended the quarter at $34.8 billion or about flat with last quarter and increase of $689 million from year-end. Reconcile the quarter of [Technical Issues] $1.128 billion of DCF, that growth capital and contributions to JV's $770 million pay dividends of $570 million we had a working capital source $200 million mainly interest expense accruals that gets us to about flat net debt for the quarter. To reconcile from year-end, we had about $2.5 billion of DCF [Phonetic], $1.52 billion [Indecipherable] in growth CapEx and contribution [Technical Issues] paid dividends of $1.020 billion [Technical Issues] a $340 million of taxes at working capital use approximately $300 million, which would mainly interest payments, bonus payroll and tax very close to [Technical Issues] year-to-date.
Finally, we're posting or we have posted to our website. Supplemental earnings information that include an alternative format for our financial presentation. Also includes some commodity hedging information [Technical Issues] modeling. Beginning in the third quarter we plan to use that new format in our earnings release. I think it represents an enhanced presentation of our financial.
Now, it's just being provided in addition to our standard format and you can read ahead of our implementation. With that, I will turn it back to Steve.
Steven J. Kean -- Chief Executive Officer
All right, thank you. So turning now to KML. On KML we had strong performance during the quarter. We continue to advance our expansion projects that are Vancouver Wharves facility. We have a good business here. Good midstream assets and a good team, and we'll continue to manage it and look for opportunities to grow it for the benefit of all of our shareholders.
Dax will give you an update on our financial and commercial performance for the quarter.
Dax Sanders -- Executive Vice President and Chief Strategy Officer
Thanks, Steve. Before I get into the results, I do want to update you on a couple of general business filings. First, as we announced the KML Board approved stock repurchase plan that will allow us to repurchase up to 2 million restricted voting shares over the next 12 months. We will use selectively and opportunistically. This is the maximum number of shares allowed under the Canadian Normal Course Issuer Bid rules, taking into account 10% more. On our announced these export project were we received all material permits and commence construction activity. Consistent with previous statements this is an approximately $43 million project contemplates two [Indecipherable] tax with combined storage capacity of 200,000 barrels underpinned by a 20-year take-or-pay contract that we expect to put in service during the first half [Technical Issues].
On the reactivation project that we have discussed, which is -- which as a reminder that $8 million expansion project in Vancouver Wharves. We continue to expect to have that in service in Q2.
Now moving forward to the result. They became our Board declared a dividend for the second quarter of $0.1625 per restricted voting share of $0.65 [Technical Issues]. Earnings per restricted voting share from continuing operations for the second quarter of 2019 or $0.12 and that's derived from approximately $22 million income from continuing operations, which same as net income.
Income from continuing operations was down approximately $2 million versus the same quarter in [Technical Issues]. Looking at the largest drivers of that variance, revenue increased across most of KML that and was led by the contribution from the baseline tank terminal assets coming online, but the increase in revenue was more than offset by the non-recurrence of a gain on the sale of small Edmonton area pipeline asset 2018 [Technical Issues] than the other income expense line [Technical Issues].
DCF and continuing operations for the quarter is $28.3 million down approximately $7.8 million durable period of '20 that reflects coverage with approximately $2.8 million and reflects the DCF payout ratio approximately [Technical Issues]. Cash taxes unfavorable $9 million, as we discussed previously, we were not required to make cash tax payments in 2018, for 2018 operations for rather we're able to defer them until the first quarter of [Technical Issues].
However, we were required to make installment for this year, which is driving that year-to-year. As a relevant aside our ultimate cash tax obligation for 2018 was lower than we expected and as such we expect a refund later in this year for [Technical Issues]. Looking at the other significant part of the DCF variance, segment EBITDA before certain items is up $7.6 million [Phonetic] terminal segment of $6.5 million and the pipeline segment of [Technical Issues]. Terminal segment was higher due primarily to baseline coming online, which accounted for about $5.4 million. The Pipeline segment was higher, primarily due to higher revenue will coach both at the index adjusted rate and timing of volumes. Finally, sustaining capital was negative $3.9 million due to several planned tank inspections that we did in the second quarter that were fully [Technical Issues] Looking forward, as we said in the release, we expect to meet our budget of approximately $213 million of EBITDA and approximately $109 million [Technical Issues].
With that, just a couple of quick comments on the balance sheet around the [Technical Issues]. We ended the quarter with approximately $33 million in cash and significant available liquidity as we only had $35 million drawn out of the $500 million revolver. Our debt for last 12 month adjusted EBITDA ratio was approximately 1.3 times. However, as we've said in the past, given potential rating agency adjustments on operating leases and other items, this ratio is not necessarily indicative of our debt raising capacity at our current rating.
With that, I'll turn it back to Steve.
Steven J. Kean -- Chief Executive Officer
Okay. Brandon, if you come back on, we'll take questions.
Questions and Answers:
Operator
Thank you. We will now begin the question-and-answer session. (Operator Instruction) Our first question is from Jeremy Tonet with JPMorgan. Your line is open.
Jeremy Tonet -- JPMorgan -- Analyst
Hi. Good afternoon. Good news there with DCX. It sounds like coming online early. I just wanted to kind of touch on that a little bit more and see is that pipe able to flow gas even before the compressors are online. It's [Indecipherable] be line fill with just the force from the plants kind of pushes a certain level of gas through and could you guys get paid on that or how should I think about that line fill that start-up process?
Steven J. Kean -- Chief Executive Officer
Yeah. So this is over 500-mile pipeline. We are starting the process of packing it. Now the pipe is in the ground as I said. The compressor stations are the part that really causes the ramp up to occur. And you know look, commissioning compressor stations can be dicey. We are pretty comfortable with these units and I think we'll be able to get them -- get them going and get them ramping up and -- but it's a process, it takes some time. And as we look out over that -- over the period, it's going to take us through to tag line, ramp up all the compression and get to the 2 Bcf. We think we'll be done that in a week to 10 days early, that's kind of what we're looking at.
In the meantime, yeah, we'll be buying gas, we will be delivering what gas we can -- we can deliver. There is some value in that, but we are in a hurry to get this on for our customers and we are moving with all deliberate speed to get it up to full service.
Jeremy Tonet -- JPMorgan -- Analyst
Got it. That's helpful. Thanks. And realize the Permian Pass being early stages here, you probably don't want to talk too much about it, but just see what I can gather here and want to see if you could comment on end markets that this would target -- this leverage your footprint and you've lifted I think the CapEx spend $200 million there. Is this kind of in there -- part of that spend, what type of developmental expenses would you be incurring at this point?
Steven J. Kean -- Chief Executive Officer
I'll start with the last. First, we're not incurring a lot of developmental expenses. We're doing a lot of research on the routing and and making sure that we've got a good route and we think we do have a very good route. I think the easiest way to think about this is no GCX kind of it hits Agua Dulce which serves Corpus and serves the the Mexican market and some industrial demand down in that part of the state. BHP kind of comes into the middle of our system and will serve, I think -- I'm not talking about shippers here, I'm talking about markets, OK. The gas will end up in Freeport and at the LNG facility there as well as industrial demand that's in that area. And the third pipe, well the fourth pipe. If you count at Whistler, the fourth pipe will go around to East Texas and serve LNG demand around to be.
Operator
Our next question is from Shneur Gershuni with UBS. Your line is open.
Shneur Gershuni -- UBS Investment Bank -- Analyst
Good afternoon everyone. Maybe just to follow-up on the last question on Permian pass a little bit here. Do you expect to have partners on this project, similar to how you have it with GCX in sort of benefit from the operating leverage, once it hits the eastern part of your system. And I was wondering as part of it. Can you also talk about the analysis that you're doing. I mean you didn't note the three other pipes about whether there is enough gas demand or need for a fourth pipe?
Steven J. Kean -- Chief Executive Officer
OK. So like the previous projects, I think it's reasonable to expect a similar pattern which is that very large shippers will want to participate in the ownership of the pipeline and we welcome that to a certain extent, while we would like to own more of these projects. It's good to have your shippers and there with you. I think so I would expect the same -- We would expect the same pattern is going to hold on on Permian pass and yeah that the proof of the demand is in the shipper sign up and -- but again I mean kind of another producer push sort of pipeline here. People are looking for opportunities to get that growing associated gas supply out of the Permian, so that they can produce their oil and the NGLs too and the proof will be in the site from our standpoint, the proof will be in the sign ups.
Now the projections are, you know a need for a 2 Bcf a day pipeline really essentially every year, all the way through this 4th pipeline and then there is some expectation that there'll be another one needed beyond that, that's all very, very early, but the supply growth out of the Permian and the expected demand growth primarily a function of LNG demand is still very robust and it should translate itself into for a long-term commitment.
Shneur Gershuni -- UBS Investment Bank -- Analyst
Okay, great. And as a follow-up, just wanted to sort of chat about the CapEx in your backlog for a second year. You're taking CO2 CapEx, I think comes then in your prepared remarks it treated and any million dollar positive on free cash flow, can we assume that that $80 million of the reduction in CapEx. And then I was wondering if you can comment on the project that you're evaluating with Tallgrass. The language in your press release was kind of a little interesting as this will evaluate and you've received indications. I'm trying to understand, are you saying that its likely moving forward or you're kind of a sort of new tooling it a little further
Steven J. Kean -- Chief Executive Officer
Okay. Let's start with CO2. Yeah, primarily the source of the additional free cash flows associated with the dialing back of CapEx -- the capital expenditures. So that $80 million is primarily a result of that.
On the Tallgrass projects. So there are two things to think about here. One is that we have an existing pipeline system, the Double H Pipeline and then that flows into it serves, some other markets do, but it's primarily flows into Tallgrass as Pony Express Pipeline system. We announced an open season -- we and Tallgrass announced an open season including the potential for an expansion there, but really certainly from our perspective, the right way to think about that on Double H [Phonetic] as we've signed up some customers on a firm basis and in order to firm those commitments up and be able to provide firm service to those customers, we need to make it available to everybody. So we're doing an open season to make the capacity available to all customers, but we're going through that process in order to firm up the commitments we've already made.
The second piece is the potential to use our existing natural gas, underutilized natural gas assets in our Western region and use them for crude takeaway out of the Bakken and DJ and that's still something that we are exploring the opportunity for -- but we don't really have any kind of definitive update before you launch.
Operator
Our next question is from Jean Ann Salisbury with Bernstein. Your line is open.
Jean Ann Salisbury Bernstein -- Bernstein -- Analyst
Hi. I just wanted to follow-up on the Tallgrass project. It seems like with Liberty and [Technical Issues] both going forward it might be tough to get other people to sign up for another market expansion to Cushing. A while ago, I think maybe at your Analyst Day last year, you mentioned looking into the possibility of converting Double H to NGL service. Can you provide any color on why you ultimately decided not to go that route. Is there any chance for?
Steven J. Kean -- Chief Executive Officer
Yeah. So we didn't ultimately get the commitments that we would require there and the competing project was announced in FID. And so, it kind of soaked up that opportunity that demand.
Jean Ann Salisbury Bernstein -- Bernstein -- Analyst
Okay, got it. And just as a quick follow-up. When Gulf Coast Express starts up, are you concerned about any near-term cannibalization of your existing gas pipelines out of the Permian or pretty much everything that you have already on take-or-pay?
Steven J. Kean -- Chief Executive Officer
Well, we have a lot that's under take-or-pay. I think what we would expect is we've generated a lot of incremental opportunity out of our west gas pipelines this year associated with very short-term transaction parks of loans and things like that and there will be some relief which will reduce those opportunities for us for some period after GCX comes online. But I think it's a reduction, not an elimination, and I think we were expecting for what it's worth, we're expecting the GCX is going to -- when you look at how much gas is being flared in the Permian 700 a day or something and the gas that's available to be brought online. We expect GCX to fill up very quickly, and we'll find a constraint out of the Permian [Indecipherable]. But it does have, it does have a reduction of the opportunity that we're experiencing today on short-term transactions over the last.
Operator
Our next question is from Spiro Dounis with Credit Suisse. Your line is open.
Spiro Dounis -- Credit Suisse -- Analyst
Hey, good afternoon, everyone. Follow-up on GCX, it looks like you're now investing about $250 million downstream there to facilitate a lot of the influx of gas that's coming. I guess you could give us a little bit color in terms of what's the timing on that, and I asked because we continue your concerns that once the gas serve initially hit [Indecipherable] with those in September has no where to go. So just how you're thinking about problem solving for that?
Richard D. Kinder -- Executive Chairman
Yeah. So it's about $250 million. We're going to get about 1.4 Bcf out of additional takeaway there which is a very capital efficient capacity expansion. And I think, so that we were, we talk about that as our crossover two project. We've already done one crossover project. I think we're evaluating other additional -- the need for other additional debottlenecking projects on our Texas intrastate as we continue to see the waves of gas coming in from the Permian. So that's the current investment, and that's what we get for it and it takes -- it takes that gas and enable us to distributed throughout the industrial areas downstream of Katy really toward the coast and there are probably more of those to come in terms of the timing, Tom, on the completion of crossover too next year.
Spiro Dounis -- Credit Suisse -- Analyst
Great. Appreciate that. And Just think about CapEx from a higher level. When you consider growth over the next two years. Is it right at this point in the market to get more aggressive here and try and capture more market share or does the commodity tape and slowdown in producer activity tell you to be maybe slightly more defensive here in the near term. How are you guys thinking about that generally speaking?
Steven J. Kean -- Chief Executive Officer
I think we're thinking about it the way we always do, which is that, we look for our shippers to come forward when they need the capacity sign up for firm commitments that justify the capital on reasonable assumptions, including terminal value assumptions et cetera. And I think we're just going to keep doing things that way conservatively.
Richard D. Kinder -- Executive Chairman
Again, we are living within our means. So to speak, and so we anticipate our CapEx expenditures will stay in the range we previously going over with your name in the [Technical Issues] range per unit.
Operator
Our next question is from Colton Bean with TPH. Your line is open.
Colton Bean -- Tudor, Pickering, Holt & Co. Securities, Inc -- Analyst
Good afternoon. Switch over to the crude side of this. I just wanted to touch on the KMCC [Indecipherable] of JV's. Given the varying diameters there between the Helena lateral and then the trunk line of Houston. Do you have a plan for specifically where that interconnect would be?
Steven J. Kean -- Chief Executive Officer
That's starting to be really at [Technical Issues].
Colton Bean -- Tudor, Pickering, Holt & Co. Securities, Inc -- Analyst
Into the 30. Okay. And so in terms of thinking about ultimate capacity there. I mean, is it right to think about if you're tying 30-inch degree of pipe into the 30-inch of KMCC that ultimately you could match capacity.
Steven J. Kean -- Chief Executive Officer
Possibly could right now the expansion projects where we [Technical Issues] 1,000 barrels a day.
Colton Bean -- Tudor, Pickering, Holt & Co. Securities, Inc -- Analyst
Okay. And with the main consideration just be incremental horsepower?
Steven J. Kean -- Chief Executive Officer
Yeah, that's right.
Colton Bean -- Tudor, Pickering, Holt & Co. Securities, Inc -- Analyst
Perfect. And I guess just as a segue on that. Would there be any consideration here in terms of Double Eagle or maybe looping Double Eagle to give you ultimately if you went through with that 30 interconnection maybe you could get more barrels up from Corpus as well and have a little bit of a bidirectional header there?
Steven J. Kean -- Chief Executive Officer
Double Eagle was a joint ventures that we'd have to exploit it with our joint venture [Technical Issues].
Colton Bean -- Tudor, Pickering, Holt & Co. Securities, Inc -- Analyst
Understood. I guess if the quick one on the Haynesville or if you think you guys have called out pretty strong volume growth there. With the reduction in counterparty rig count there just to execute to, has that outlook shifted at all for the back half of 2019? Or is that [Indecipherable].
Steven J. Kean -- Chief Executive Officer
We're still seeing very strong volumes there. We've had the benefit of being able to ramp up without substantial additional capital investment. We're probably going to have to invest some capital to debottleneck that system further accommodate what we see as continued growth in that area. But still very, very attractive return projects. But our volumes remain strong.
Operator
Our next question is from Tristan Richardson with SunTrust. Your line is open.
Tristan Richardson -- SunTrust Robinson Humphrey, Inc. -- Analyst
Hey, good afternoon. Just thinking -- we'd love to hear your views on strategic opportunities and priorities for capital. Looking forward, I think with GCX and BHP rolling off over the next 18 months and combined with the dividend growth next year that your planned rate both of those combined to suggest that there is a real opportunity for free cash flow in the out years. Again, just thinking about priorities and what that could be used for?
Steven J. Kean -- Chief Executive Officer
Yeah, we'll continue to obviously the first priority is maintain the balance sheet at the investment grade level we've gotten there. We'll make sure that we stay there. Then we've laid out our dividend plan and we will adhere to that. And then in terms of the free cash flow that's available from there we will put it toward the highest return use for our shareholders. We think and when we look ahead and our shadow backlog and other things that are on the horizon. As Rich said, we think the $2 billion to $3 billion range is probably that's been the range for quite a while. We think that's a reasonable range of opportunities for us as we build off of our network, but to the extent that those opportunities are not there. We always have the option to buy back shares.
Tristan Richardson -- SunTrust Robinson Humphrey, Inc. -- Analyst
Helpful. Thank you guys very much.
Operator
Our next question is from Keith Stanley with Wolfe Research. Your line is open.
Keith Stanley -- Wolfe Research -- Anlayst
Hi, good afternoon. I just wanted to talk you got your FERC approval recently on the Gulf LNG export project. Just any update on commercial discussions there and potential timeline and viability of the project.
Steven J. Kean -- Chief Executive Officer
Not really. And I would say it, so it's quite a ways off. You're right, we did -- we had applied for and we did receive our FERC approval on that asset and that's a nice steps, but there is nothing imminent there.
Keith Stanley -- Wolfe Research -- Anlayst
Thank you.
Operator
Our next question is from Christine Cho with Barclays. Your line is open.
Christine Cho -- Barclays -- Analyst
Good evening, I wanted to actually maybe start on Permian Highway. We just all the challenges you're having with right-of-way permitting, because again, an update on how that's tracking relative to budget.
Steven J. Kean -- Chief Executive Officer
Yeah, we're still on schedule. So piece of this pipeline is going through the hill country, which we knew was going to be a challenge. And so we allowed for extra time in the acquisition of the right-of-way. And we had a good victory and expected victory. But we had a good victory in the attempt to challenge the project and our use of eminent domain and our discussions with landowners in the area are continuing, and I think continuing at a decent pace. So we expect that with the extra time that we allowed to get through this process that we will on schedule.
Christine Cho -- Barclays -- Analyst
What about on the cost side?
Steven J. Kean -- Chief Executive Officer
On the cost side, we still look, we still look very good. We expect to be on budget as well.
Christine Cho -- Barclays -- Analyst
Okay. And then, with the Philadelphia refinery closing down. We just be curious to your thoughts on how we should think about the impacts for your product pipelines or your New York Harbor business, if any ?
Steven J. Kean -- Chief Executive Officer
Go ahead, John.
John W. Schlosser -- President, Terminals
We think net-net it will be positive in the long run because we expect to see more imports coming in your Carper [Phonetic] it will have a momentary short-term impact. We do have 200,000 -- 210,000 to be exact barrels with them in New York right now, but we expect to be able to release that they do supply 0.3 truck rack, but we expect that additional volumes off the quality. So it may have impact for the next month or so negative and in the long run we think it will be positive. It's coming into [Technical Issues].
Christine Cho -- Barclays -- Analyst
And then just last one from me, quick one. For the KMCC project, what's the cost that project. I'm guessing it's not that much, because it's a pump. But the term of the contract and should we think that the benefit will offset the rate recontracting headwinds that yields talked about in recent quarters.
John W. Schlosser -- President, Terminals
Yeah, So the initial cost of the project right now, we're going to spend about $10 million this year. And so with that, we will be able to get to $100 million -- I'm sorry, the 100,000 barrel a day and we've got some initial agreements that really kick us off at $75,000 [Technical Issues].
Dax Sanders -- Executive Vice President and Chief Strategy Officer
And for the term of -- up to three years.
Steven J. Kean -- Chief Executive Officer
Up to 3 years on the term and it'll be a partial offset but not a complete offset. The real objective here is we wanted to find a way to get Permian barrels into KMCC and that's what this interconnect accomplishes.
Operator
Our next question is from Dennis Coleman with Bank of America Merrill Lynch. Your line is open.
Dennis Coleman -- Bank of America Merrill Lynch -- Analyst
Hi, everyone. Thank you. I want to go back to the Permian Pass project if I can. You talked a little bit about this being mostly up, it sounds like a producer push project, but given where you talked about the targets or the target area, you deliver a lot of gas already there for LNG. I wonder if there is sort of LNG pull demand and if it relies on any particular projects above and beyond what's happened there that have been announced?
Steven J. Kean -- Chief Executive Officer
I mean, clearly observing the LNG projects are going forward on the side of Texas, East Gulf Coast of Texas [Technical Issues] Golden Pass I think one potential customer. Port Arthur LNG [Technical Issues] that is not FID [Technical Issues] promising. But there's also connectivity back into our intrastate network for a portion of this volume, but we would expect that volume to go and serve industrial customers on the side of our system, and we will be crossing several intrastate pipelines farther east and so that will also be an alternative market.
Dennis Coleman -- Bank of America Merrill Lynch -- Analyst
Okay. And then maybe just if you can give a couple of quick comments on how you think about returns versus the two projects that you've already have under development. It's just, -- it's becoming harder and harder to build these pipelines, I think we can all agree on that. We just talked about some of the issues with Permian highway. Is there a time where you as a pipeline developer are able to capture high returns from producers or demand it because of the greater sort of project risk effects?
Steven J. Kean -- Chief Executive Officer
The returns are in line with what we've been experiencing on the previous projects and the good returns. We've got competition. So we don't talk about them in specifics, but they're good double-digit unlevered after-tax returns with long-term contract securing or underpinning those cash flows. In terms of -- and those are pretty good returns, I mean, and we're glad to be able to get them and we try to manage our project risk to the other part of your question by making sure that we adequately account for what we are seeing in the environment in which we are building these projects. And so that factors into how we schedule the permitting process and the right-of-way acquisition process, it goes into how we select the route, it goes into all of those things. So we think we manage the risk by casting it right, scheduling it right, and the returns that we're getting compensate us for the [Technical Issues].
Operator
Our next question is from Michael Lapides with Goldman Sachs. Your line is open.
Michael Lapides -- Goldman Sachs -- Analyst
Hey guys, just a question on the gas pipeline business. Where do you stand or what remains left in terms of the 501-G process for you and does that $100 million number you put out at the Analyst Day still hold. And then how are you thinking about traditional recontracting risk for the projects that have negotiated rates kind of back half of this year and going in the 2020?
Steven J. Kean -- Chief Executive Officer
Okay. So what we talked about on the 501-G which is an exposure that we believe we have behind us or largely behind us. We have two remaining pipes with smaller amounts that issue that we're waiting on final decisions on. But with the ones that we've done, it was $50 million for this year growing to $100 million next year for the full year effect of both of those settlements. And so as we've said, we didn't budget. They're very hard to predict. We didn't budget for them, but we were happy to get them because we believe they resolved a longer-term risk and a headwind to the company. So it's $50 million this year and a $100 million next year.
In terms of your contract roll off questions, I think where that risk is really concentrated is in our FEP, Fayetteville Express Pipeline and in -- and the Ruby Pipeline and the time frame there is 2021-2022.
Michael Lapides -- Goldman Sachs -- Analyst
Got it. And then a question, I noticed the contract with Con Edison to add a little bit of capacity via compression in the Northeast. Obviously it's borderline impossible to get new pipeline built into the Northeast. How much incremental opportunity do you see to this similar type of projects to help adding incremental capacity into the region?
Steven J. Kean -- Chief Executive Officer
Okay. I think this is the second one. So we've got -- we've got one -- our line 261 project in Massachusetts, that's the first one, and then this one. And what we're trying to do is find those opportunities where we can get pipelines permitted and we think these are very formidable pipelines where we can to get them permitted to build debottlenecking expansions to help our customers, for example, lift moratoria that they have in place on signing up new customers. These are very valuable projects that are very much in the public interest and we think that the way we've been very careful and thoughtful about how we're putting them together because of the permitting risk in the Northeast. So we'll continue to look for those. We've already had two.
Michael Lapides -- Goldman Sachs -- Analyst
Got it. Thanks, Steve. Much appreciated.
Operator
Our next question is from Becca Followill with US Capital Advisors. Your line is open.
Becca Followill -- US Capital Advisors -- Analyst
Thank you. Good afternoon. How much of the $800 million delta in the backlog is due to taking out the CO2 projects?
Dax Sanders -- Executive Vice President and Chief Strategy Officer
$500 million.
Becca Followill -- US Capital Advisors -- Analyst
$500 million. And then second on the FERC NOI and ROE, you guys put out some comments there which were very thoughtful. Any thoughts on timing of the process with the FERC?
Steven J. Kean -- Chief Executive Officer
Nothing. Nothing sort of proprietary. They've gone through a similar kind of macro evaluation like this on the certificates policy. And I think we're still waiting to see if there's anything, final that's going to come out of that. And on this, it's a little hard to project exactly. I think from the comments that we and others filed, I think, hope it's apparent to the commission, there are a lot of differences in circumstances. There is not really a one size fits all. I think that they would probably, I'm guessing, that that's what they would come away from looking at the record that's in front of them and I would hope also that they would find there is a pretty clear distinction between the electric side and the natural gas side in terms of the competitive environment that we operate in in the natural gas sector. So we made those points, other people made those points too. I think it's hard to craft from the circumstances that have been laid out, a one size fits all policy. So we would be [Indecipherable].
Becca Followill -- US Capital Advisors -- Analyst
Thanks.
Operator
Our next question is from Robert Kwan with RBC Capital Markets. Your line is open.
Robert Kwan -- RBC Capital Markets -- Analyst
Good afternoon. Just looking at the KML share buyback. First, mechanically, is there going to be a pro rata buyback of the KMI shares?
Steven J. Kean -- Chief Executive Officer
No this is -- this is a buyback programs that applies to the public float.
Robert Kwan -- RBC Capital Markets -- Analyst
Okay. And then you've cited it as an attractive opportunity. I'm just wondering what types of things and metrics are you looking at? Is it kind of DCF accretion on an absolute basis or would you also look at the MCIB versus potential new projects, acquisitions or other growth initiatives?
Steven J. Kean -- Chief Executive Officer
Yeah, I mean we'll certainly be evaluating what other opportunities there are to -- for that capital. We do look at DCF accretion is being kind of the primary -- the primary thing that we focus our attention on, but we don't have anything formulaic here Robert. We're going to be very opportunistic about -- about the use of the program, but we thought that it was good to put in place. Certainly the Board agreed and it was a good thing to have in place for our KMI shareholders. And we will put it the right what we do is the right time economically for our shareholders.
Robert Kwan -- RBC Capital Markets -- Analyst
Got it. And I guess just that kind of selectively and opportunistic language. I assume that the Board also examined something larger like a substantial issuer bid, but decided tactically, the NCIB is kind of the right thing at this point.
Steven J. Kean -- Chief Executive Officer
Nice, that's a fair conclusion.
Robert Kwan -- RBC Capital Markets -- Analyst
Okay. That's great. Thank you.
Operator
Our next question is from Rob Catellier with CIBC Capital Markets. Your line is open.
Robert Catellier -- CIBC Capital Markets -- Analyst
Thank you just answered my question. I was curious about the evaluation of a substantial issuer, but thank you.
Steven J. Kean -- Chief Executive Officer
Thank you.
Operator
Our next question is from Spiro Dounis with Capital Suisse. Your line is open.
Spiro Dounis -- Credit Suisse -- Analyst
Hey, guys. Thanks for squeezing me back in. So one follow-up. So the answer is, might be a bit obvious, but just given the rapid pace of buying the sheer still kind of compelled to ask. Rich, can you just comment a little bit on the uptick you're buying so far this year the stock, maybe what changed since last year and how you're thinking about valuation at this point, just given the nice run up year-to-date.
Richard D. Kinder -- Executive Chairman
I don't really have much to say on that, obviously I'm a huge believer in the upside opportunities for this company and the kind of dividend policy, we have makes it even more attractive. So an interest in shareholder and will continue to be.
Spiro Dounis -- Credit Suisse -- Analyst
Fair enough. Appreciate the color.
Operator
Our next question is from Jeremy Tonet with JPMorgan. Your line is open.
Jeremy Tonet -- JP Morgan -- Analyst
Hi, thanks for squeezing me in as well. Just wanted to come back to Elba. I think you had touched on it briefly there. But I was wondering if you could dive in a little bit more as far as what was causing the issues with the cryogenic temperatures there. What do you learn to get that solved, is there going to be any issues with subsequent trains and I guess what gives you confidence that everything is good at this point.
Steven J. Kean -- Chief Executive Officer
Yeah, so as I mentioned the issue that we had was making sure that we had at uniformly cold box where we make the LNG, then we had some mechanical issues associated with having LNG at actually to lower the temperature and solidifying it and so we needed to get the top of the box cold uniformly with the bottom of what that required was a slower start-up. So I would say, essentially we were trying to start too fast and so as we gradually stepped into it and we're making very, very good progress. Now with the uniformly called cold box, it's about turning it up, and turning it up as we speak. And then we have an 8-day performance test and then in service.
I think as we've gone through this, we've observed where we had issues like with the valve or a CEO and those sorts of things and so we're working ahead on the other units to make sure that those are all addressed and so, we've got kind of one, one final operational issue that we're dealing with and it seems to be our approach to it [Technical Issues] working fine and so if that's the case, will be up very soon.
If we have to slow down for a bit to fix a problem then it could cause a little bit further delay, but the way we've narrowed down the problems. Now, we're confident in its start-up, that start-up will be soon, and that -- it will be operable once up and running and that the lessons from the start-up on the first unit, which is the critical unit, as we've said commercially for the contract that the lessons that we've learned from the start up of the first unit are being applied to the remaining units as I said for including the first one for mechanically read. All of the units are on Elba Island and we're going through the assembly and then the Commission process on that well over the course of this year with maybe a slight maybe one of the drifting into [Technical Issues].
Jeremy Tonet -- JP Morgan -- Analyst
That's very helpful, thanks. And with the EOR , just wanted to come to that real quick is, is there more that that could be reduced if pricing and economics just as part of the CapEx spend there or is there certain level of kind of the base spend, where you don't want to fall below because that could lead to kind of decline curves picking up or anything like that. We are not able to maintain production at the levels you want.
Steven J. Kean -- Chief Executive Officer
As always, we look at every one of these projects on a return basis. So we invest this, we can identify the incremental oil that's associated with investing this and at reasonable range of prices that will produce an economic return at our hurdle rate is higher than our other remaining businesses. That's how we do it. And so there is not a base level of capital that we feel we have to spend for some operational or other reason we do it, each project on a project-by-project basis and on a return basis. And I think the team there, the CO2 team has done a really fine job of knowing when capital is not going to be effectively deployed and finding other places to deploy that provide attractive returns, or if we can't find that, then we don't spend it. And that's the way we're going to proceed. We have a lot of discipline, I believe around here. On the capital that we deploy and the confidence that we have to have in the returns being adequate to our investors and I think the CO2 group demonstrate that.
Operator
At this time, I'm showing no further questions.
Richard D. Kinder -- Executive Chairman
All right, well thank you all very much. Have a good evening.
Operator
[Operator Closing Remarks]
Duration: 65 minutes
Call participants:
Richard D. Kinder -- Executive Chairman
Steven J. Kean -- Chief Executive Officer
Kimberly Allen Dang -- President
David P. Michels -- Vice President and Chief Financial Officer
Dax Sanders -- Executive Vice President and Chief Strategy Officer
John W. Schlosser -- President, Terminals
Jeremy Tonet -- JPMorgan -- Analyst
Shneur Gershuni -- UBS Investment Bank -- Analyst
Jean Ann Salisbury Bernstein -- Bernstein -- Analyst
Spiro Dounis -- Credit Suisse -- Analyst
Colton Bean -- Tudor, Pickering, Holt & Co. Securities, Inc -- Analyst
Tristan Richardson -- SunTrust Robinson Humphrey, Inc. -- Analyst
Keith Stanley -- Wolfe Research -- Anlayst
Christine Cho -- Barclays -- Analyst
Dennis Coleman -- Bank of America Merrill Lynch -- Analyst
Michael Lapides -- Goldman Sachs -- Analyst
Becca Followill -- US Capital Advisors -- Analyst
Robert Kwan -- RBC Capital Markets -- Analyst
Robert Catellier -- CIBC Capital Markets -- Analyst
Jeremy Tonet -- JP Morgan -- Analyst
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