Kinder Morgan, Inc. (KMI) Q2 2019 Earnings Report, Transcript and Summary

Welcome to the Quarterly Earnings Conference Call. At this time, all participants are in a listen-only mode. At the end of today's presentation we will conduct the question-and-answer session. [Operator Instructions] Today's conference is being recorded, if you have any objections you may disconnect at this time. I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Sir, you may begin.

Thank you, Brendon. 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 and financial outlook statements within the meaning of the Private Securities Litigation Reform Act of 1995, the Securities and Exchange Act of 1934, and applicable Canadian provincial and territorial securities laws, as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking and financial outlook statements and use of non-GAAP financial measure 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 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 in a 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 of our segment earnings before DD&A comes from our natural gas segment, and 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 a supply and demand perspective. Natural gas is critical to our American economy to satisfy the growing energy needs around the world, and 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 estimate of those firms and governmental agencies which follow the energy field most closely. Sometimes we lose sight of the actual facts involved, so looking first through the rearview mirror U.S. demand in 2018 was up 12% from 2017 and 44% above the demand of a decade earlier. 2019 is shaping up to be another strong year. Looking forward, as we previously said U.S. demand is projected to grow by over 30% between now and 2030 that demand growth is being driven by L&G, power and industrial demand and by exports to Mexico. Turning to the supply side, the U.S. 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’m aware of Mark Twain saying that making predictions is very difficult, particularly when they concern the future. But I believe that under almost any scenario natural gas is a winner for years to come. Connecting these vast supplies -- these vast U.S. supplies 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. With that, I'll turn it over to Steve.

All right thanks, Rich. We will be updating you on both KMI and KML this after afternoon I am going to start with KMI and turn it over to our president Kim Dang, to 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 number, and then we’ll take your questions. The summary on KMI is this we’ve been adhering and continue to adhere to the principles that we've laid out for you. We have a strong balance sheet having met our approximately 4.5 times debt to EBITDA target and with rating upgrades now from all three ratings agencies. We're maintaining our capital discipline through our return criteria, a good track record of execution and by self-funding our investments. We're returning value to shareholders with the 25% year-over-year dividend increase and we continue to find attractive growth opportunities. We have a strong balance sheet, capital discipline returning value to our shareholders and finding additional growth opportunities those are the principles we operate by. Our performances this year so far has been solid and we project it to be solid. We’ve had headwinds on commodity prices in 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. Now 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 all together, as we said last quarter, we expect to be slightly under plan on an EBITDA basis, but on plan from a DCS 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 their gas out of the Permian so they can get their oil and NGLs out as well. We 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 were 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 at 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 on the compressor 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 and construction firms and we are on schedule for a completion in October 2020. We had a significant court decision last month, which essentially affirms the existing eminent domain process that has been used in use for four decades in the state of Texas. Felt confident in our legal position, but is nevertheless a good thing to have prevailed in the case. So both of our current projects are on schedule, both projects are at attractive returns, and both projects bring us additional opportunities in our downstream pipelines. Combined, they bring 4 BCF a day of incremental gas to a system that 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 the Permian Pass pipeline. This is a work in progress. It's not in the backlog at this point, certainly, but it is moving along. These Permian projects show us taking advantage of a very positive situation. There's large supply growth in Texas, and large demand growth in Texas, we can bridge the two and connect to our premier Texas Intrastate Pipeline Network and stay entirely within the state of Texas, where we have more commercial flexibility. As we pointed out at 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 4 of the 10 MMLS units. The cold 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 cold box had been plaguing our startup 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 is certainly unwelcome, but the risk allocation between us and our contractor and 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 return. We'll make a separate announcement when we have the first unit in service. Also of note we added $400 million worth of projects to the backlog this quarter, partially offsetting $800 million worth of projects that are placed into service or removed from the backlog. Most of what we removed from the backlog was in CO2 segment, we remain - our team in CO2 remains very disciplined here and we reduced capital spend when we find 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.

Hey, thanks Steve. Natural gas had another outstanding quarter, it was up 7% and the underlying market fundamentals remain very strong. Between 2018 and 2019 natural gas demand is expected to increase by over 5 BCF a day. Almost 60% of KMI segment earnings before DD&A come from our natural gas business and of the natural gas consumed in the U.S. we move about 40% on our pipeline. So the fundamentals underlying our largest business are very strong. Transport volumes on our transmission pipes increased approximately 3.1 BCF a day second quarter versus the second quarter of 2018 are about 10%. This is the 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 pipe PNG volumes were up 760 million cubic feet a day due to increased Permian volumes and increased California demand. KMLA volumes were up 670 million cubic feet a day due to LNG exports. And overall for Kinder Morgan's deliveries to LNG export plants increased approximately 1.4 BCF a day. CIG volumes were approximately 500 million a day due to increased DJ Basin production and colder weather. Ruby volumes were up 370 million cubic feet a day due to colder West Coast weather and outages in the Pacific Northwest. And rig volumes were up 370 a day due to increased DJ production. On gathering assets, volumes were up approximately 16% or 450 million cubic feet a 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 to increase. Permian Natural Gas wellhead volumes increased approximately 30% versus the second quarter of 2018, Haynesville increased approximately 27%, Bakken increased approximately 27%, and Eagle Ford increased approximately 5%. Overall, the higher utilization on our systems a lot 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 in our [indiscernible] 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 splitter were more than offset by the lower contribution from KMCC and SFPP. Volumes on KMCC were actually up 12%, but that was more than offset by lower rates. 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. Terminals business was down in the quarter. The liquids business which accounts for about 80% of the segment had nice increases from expansion projects, the largest of which was our baseline thermal expansion projects in Edmonton. We also saw higher throughput and ancillary charges in our Houston ship channel facility. However, these increases were more than offset by the lease expense in our Edmonton South Terminal which became a third party obligation posts our Trans Mountain sale and impact 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 results with a baseline project and that brings our total leasable capacity to around 89 million barrels. The bulk business was also down in the quarter due to lower volume. Bulk 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 a 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. While cotton production increased 8% versus the second quarter of 2018. But offset substantially below our plan. The reservoir is processing slower than we expected and until we can determine how to address this issue starting 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 investments benefited future years. In CO2 as with all our assets we diligently monitor our investments to make sure that they're going to achieve our projected return. To the extent that we think there's a material risks with its return 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 in 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, which represents approximately 33% increase improved 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 the price. With that, I'll turn it over to Dave Michels.

Thanks, Kim. Today we are declaring a dividend of $0.25 per share, same as last quarter and in line with the budget, $1 per share for the fourth [Technical Difficulty] 25% increase over dividends 2018. KMI’s adjusted earnings in DCF grew from last year’s second quarter [Technical Difficulty] generated DCF per share $0.50 two times or approximately $560 million in excess of the declared dividends. Revenues were down 6% this quarter, compared to the second quarter in 2018. But a decline in cost of sales more than offset our lower revenues that our gross margin was up relative to the prior period. Some of that came from the benefit of non-cash losses on derivative contracts during the second quarter of 2018. We treat as certain items and exclude from our non-GAAP metric. Including certain items gross margin was in line period over period. Net income available to common stockholders was $518 million, were 388% better than the second quarter of 2018, largely to impairments taken during the second quarter of 2018, which we treat as certain items. Before certain items, net income available to common stockholders was up $34 million or approximately 7%. That includes the benefit of zero preferred dividend payments down from $39 million as a result of the conversion of our preferred equity securities in 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 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 that asset received related to our 501-G settlement. We had increased contribution from multiple expansion projects placed in-service, KinderHawk and South Texas GMP assets were up driven by increased volume. Kinder Morgan Louisiana pipeline was up due to our Sabine Pass [indiscernible]. And Kim provided the main drivers for our products terminal and CO2 segments. Moving on to 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 Tran Mountain sale. Partially offsetting those was higher pension expenses relative to last year. Those pension expenses that hit G&A or non-cash, can we add them back to our DCF and replace those with our actual cash contribution to our pension fund. Interest expense was $22 million lower and that was driven by lower debt balance and greater interest capitalized to projects as well. Those are partially offset by a higher LIBOR rate versus last year would 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 and that’s related to payments at citrus, greater taxable income there versus last year and higher taxes at KML, which Dax will walk through. Those impacts were expected and our cash tax forecast is actually slightly favorable to our budget for the full year. Sustaining capital was $26 million higher versus the second quarter of 2018, mainly due to pipeline integrity work in our natural gas segments. Again, we have budgeted for greater expenditure [Technical Difficulty] in fact our full year forecast is slightly favorable budget [Technical Difficulty]. Total DCF of $1.128 billion was up $1 million or 1%, to summarize the main drivers greater contributions from our natural gas segments, lower interest expense, preferred stock dividend, mostly offset by our sale of Trans Mountain, lower commodity prices impacting our CO2 segments, higher sustaining CapEx and higher cash tax payments. DCF per share $0.50 per share was in line last quarter, same drivers as DCF, but it includes the impact from the incremental shares that were issued as a result of our preferred security conversion. Moving on to 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 at 4.5 times. At the end of the year leverage is forecasted to be 4.6 times, which is just slightly unfavorable to our budget of 4.5 and is consistent with 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 than budget or a little less than 2% below budget. Drivers there include the first 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 impact DCF as well, but DCF includes the benefit of favorable interest expenses expected for the year and it also adds backs 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 has $3.1 billion use, driven by a $1.3 billion pay down of bonds which happen in the first quarter, $800 million distribution to the public AML shareholders and $340 million of Canadian cash taxes related to the sale of Trans Mountain. Other current liabilities [Technical Difficulty] this is where we booked payable for the public shareholders distribution for the quarter also includes movements in accrued interest and taxes. Long-term debt was down mainly due to us paying off $1.3 billion of bond. Adjusted net debt ended the quarter at $34.8 billion or about flat with last quarter and an increase of $689 million from year-end. Reconcile the quarter change [Technical Difficulty] the $1.128 billion of DCF, had growth capital and contributions to JVs $770 million, paid dividends of $570 million, we have a working capital source of $200 million mainly interest expense accrual that gets us to about flat net debt for the quarter. To reconcile from year-end, we had about $2.5 billion of DCF, paid $1.52 billion out in growth CapEx and contributions to [Technical Difficulty] paid dividends of $1.20 billion, paid $340 million of taxes [the Mountain sale][ph] and working capital use of approximately $300 million, which were mainly interest payments, bonus payroll and tax very close to [Technical Difficulty] 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, it also includes some commodity hedging information [Technical Difficulty] for your modeling. Beginning in the third quarter, we plan to use that new format in our earnings release, it represent an enhanced presentation of our financial. For now it just been provided an addition to our standard format so you can [indiscernible] of our implementation [Technical Difficulty]. With that, I will turn it back to Steve.

All right thank you. So turning now to KML, in KML we had strong performance during the quarter, we continue to advance our expansion projects at our Vancouver Works facility. We have a good business here, good midstream assets and a good team and we will 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.

Thanks, Steve. Before I get into the results, I want to update you on a couple of general business items. First as we announced the KML Board purpose 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% [Technical Difficulty]. On our announced diesel export project we received material permits and had commenced construction activity. Consistent with previous statements this is an approximately $43 million project that contemplates two distillate tanks 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 of 2021. On the shed six reactivation projects that we have discussed, which as a reminder is an $8 million expansion project at Vancouver Works, we continue to expect to have that in-service in [Technical Difficulty]. Now moving forward to the results. Today the KML Board declared a dividend for the second quarter of $0.1625 per restricted voting share and $0.65 annual [Technical Difficulty]. Earnings per restricted voting share from continuing operations for the second quarter of 2019 are $0.12 and that’s derived from approximately $22 million income from continuing operations, which is same as net income. Income from continuing operation was down approximately $2 million versus the same quarter in 2018. Looking at the largest drivers of that variance, revenue increased across most of KML’s assets and was led by the contribution from the baseline tank and terminal assets coming online, but the increase in revenues was more than offset by the non-recurrence of a gain on the sale of small Edmonton area pipeline asset in 2018 [Technical Difficulty] than the other income expense line and treated as a certain item on the DCF. DCF from continuing operations for the quarter is $28.3 million, down approximately $7.8 million comparable period in 2018 that reflects coverage of $2.8 million and reflects the DCF payout ratio of approximately [Technical Difficulty]. Cash taxes of unfavorable $9 million, as we discussed previously we were not required to make cash tax payments in 2018 for 2018 operations, but rather we’re able to differ them until the first quarter of [Technical Difficulty]. However we're now required to make installments for this year which is driving that year-to-year [Technical Difficulty]. As a relevant [upside] [ph] our ultimate cash tax obligation for 2018 was lower than we expected and as such we expect to refile later in this year form [Technical Difficulty]. Looking at the other significant component of the DCF variants segment EBITDA before certain items is up $7.6 million [Technical Difficulty]. Terminal segment up $6.5 million and the pipeline segment up $1 million. Terminal segment was higher due primarily to baseline coming online, which accounted for about 5.4 [Technical Difficulty]. The pipeline segment was higher primarily due to higher revenue on [indiscernible] as a result of the index adjusted rate and timing on volumes. Finally sustaining capital was negative $3.9 million due to several plant tank inspections that we did in the second quarter that was [Technical Difficulty]. Looking forward as we said in the release, we expect to meet our budget of approximately $213 million of EBITDA and approximately $109 million of [Technical Difficulty]. With that just a couple of quick comments on the balance sheet around liquidity situation. We ended the quarter with approximately $33 million cash and significant available liquidity as we only have $35 million drawn out of the $500 million revolving. Our debt the last 12 months adjusted EBITDA ratio of approximately 1.3 times. However as we 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 ratings. With that, I will turn it back to Steve.

Okay Brandon, if you come back on we will take questions.

Thank you. We will now begin the question-and-answer session. [Operator instructions] Our first question is from Jeremy Tonet with J.P. Morgan. Your line is open.

Good afternoon.

Hi, good afternoon. Good news there with GCX it sounds like coming online early. Just want to touch on a little bit more and see is that pipe able to flow gas even before the compressors are online, could there be line fill where just the force from the plant 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 startup process?

So this is an over 500 mile pipeline we’re 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 look commissioning compressor stations can be dicey, we are pretty comfortable with these units and think will be able to get them going and get them ramping up. And -- but it's a process it takes time. And as we look out over the period it’s going to take us to pack the line, ramp up all the compression and get to the 2 BCF. We think will be done that a week to 10 days early that’s kind of what we're looking at. In the meantime, we will be buying gas, we will be delivering what gas we can deliver. There is some value in that. But we're 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.

Got you. That’s helpful, thanks. And realize that Permian Pass being early stages here 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 if this leverage your footprint and you lifted I think the CapEx spend $200 million there is this kind of in there part of that spend what type of product developmental expenses would you be incurring at this point?

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 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, GCX kind of it hits Agua Dulce, which serves Corpus and serves the Mexican market and some industrial demand down in that part of the state. PHP kind of comes into the middle of our system and we’ll serve I’m not talking about shippers here I'm talking about markets, okay, 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 Whistler, the fourth pipe will go around to East Texas and serve LNG demand around Sabine.

Our next question is from Shneur Gershuni with UBS. Your line is open.

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 and 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 did note the three other pipes about whether there's enough gas demand or need for a fourth pipe?

Okay. 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 in there with you, I think. So I would expect the same -- we would expect that same pattern is going to hold on Permian Pass. And yes, the proof of the demand is in the shipper sign up and expect again 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 their NGLs too. And the proof will be in the -- from our standpoint, the proof will be in the sign ups. Now the projections are a need for a 2 BCF a day pipeline really essentially every year, all the way through this fourth pipeline. And then there's some expectation that there will 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.

Okay great. And as a follow up, just wanted to sort of chat about the CapEx in your backlog for a second here. You're taking down CO2 CapEx, I think Kim said in her prepared remarks that created an $80 million positive on free cash flow. Can we assume that that $80 million is 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 [indiscernible] perceived indications. Trying to understand are you saying that it's likely moving forward? Or you're kind of -- sort of noodling it a little further?

Okay, let's start with CO2. Yes, primarily the source of the additional free cash flow is associated with the dialing back of the capital expenditures. So that $80 million is primarily a result of that. On the Tallgrass project, so there are two things to think about here. One is that we have an existing pipeline system, the HH pipeline, and then that flows into it serves some other markets too, but it primarily flows into Tallgrass’s Pony Express pipeline system. We announced in open season, we and Tallgrass announced in open season, including the potential for an expansion there. But really certainly from our perspective, the right way to think about that on HH is 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 for you on.

Our next question is from Jean Ann Salisbury with Bernstein. Your line is open.

Hey, I just wanted to follow up on the Tallgrass project. It seems like with Liberty and [Dapo] [ph] both going forward, it might be tough to get other people to sign up for another Bakken expansion to Cushing. A while ago, I think maybe at your Analysts Day last year, you'd mentioned looking into the possibility of converting HH to NGL service. Can you provide any color on why you ultimately decided not to go that way And is there any chance for it still?

Yes, so we didn't ultimately get the commitments that we would require there. And a competing project was announced in FID. And so it kind of soaked up that opportunity that demand.

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 it’s pretty much everything that you have already on take-or-pay?

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 and 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're expecting for what it's worth, we're expecting that 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 burning. But it does have reduction of the opportunity that we're experiencing today on short-term transactions out of the West.

Our next question is from Spiro Dounis with Credit Suisse. Your line is open.

Hey, good afternoon, everyone. Just a follow up on GCX, 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 just give us a little bit color in terms of what's the timing on that? And I asked because I -- we can see your concerns that once the gas serve initially hits Agua Dulce in September has nowhere to go, so just how you’re thinking about problem solving for that?

So it's about $250 million, we're going to get about 1.4 BCF out of additional take away there, which is a very capital efficient capacity expansion. And I think -- so that's -- we talk about that as our crossover two projects, we've already done one crossover projects. 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. And so that's the current investment and that's what we get for it. And it takes that gas and enables us to distribute it throughout the industrial areas downstream of [KD] [ph] really toward the coast. And there are probably more of those to come. In terms of the timing, time on the completion of crossover two, next year.

Great, appreciate that. Just thinking 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 you guys thinking about that generally speaking?

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 to 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.

Again, we're living within our means so to speak. And so we anticipate our CapEx expenditures will stay in the range we've previously gone over with you namely in the $2 range.

Our next question is from Colton Bean with TPH. Your line is open.

Good afternoon. Just to switch over to crude side of this. I just wanted to touch on the KMCC and Gray Oak JVs. Given the varying diameters there between the Halene [ph] lateral and then chunk lines Houston, do you have a plan for specifically where that interconnect would be?

Yes, that’s going to be really at the station [Technical Difficulty].

Into the 30, okay. And so in terms of thinking about ultimate capacity there, I mean, is it right to think about if are tying a 30-inch [Technical Difficulty] pipe into the 30-inch KMCC that’s ultimately you could match capacities.

Possibly could, but right now the expansion project where we [Technical Difficulty] barrels a day.

Okay. And with the main consideration just the incremental horsepower?

Yes, that’s right.

Perfect. I guess just as a segue on that would there be any consideration here in terms of Double Eagle and maybe looping Double Eagle to give you ultimately if you went through with that 30-inch connection maybe you could get more barrels up from corpus as well and have a little bit of bidirectional header there.

Double Eagle was a joint venture so we’d have to kind of explore it with our joint venture partner.

Understood. I guess just a quick one, on the Haynesville I do think you guys have called out pretty strong volume growth there with the reduction in counterparty rig count there just to execute two, has that outlook shifted at all for the back half of 2019 or statuesque?

We are still seeing very strong volumes there, we have 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 to accommodate what we see as continued growth in that area. But still very, very attractive return projects, but our volumes remains strong.

Our next question is from Tristan Richardson with SunTrust. Your line is open.

Hey, good afternoon. Just thinking would love to hear your views on strategic opportunities and priorities for capital looking forward, I think with GCX and PHP rolling off over the next 18 months, and combined with the dividend growth next year at your planned rate both of those combined to suggest that there is a real opportunity for free cash flow in the out years and again just thinking about priorities and what that could be used for?

Yes, we will 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. And 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 towards the highest return use for our shareholders we think when we look ahead in 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.

Helpful, thank you guys very much.

Our next question is from Keith Stanley with Wolfe Research. Your line is now open.

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?

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 that’s a nice step, but there is nothing eminent there.

Thank you.

Our next question is from Christine Cho with Barclays. Your line is open.

Good evening. I wanted to actually maybe start on Permian Highway, with just all of the challenges with right-of-way permitting. Can we get an update on how that’s tracking relative to budget?

We're still on schedule. So the 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 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 imminent 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.

What about on the cost side?

On the cost side, we still look very good, we expect to be on budget as well.

Okay. And then with the Philadelphia refinery closing down, would just be curious as to your thoughts on how we should think about the impact for your products pipeline in your New York Harbor business, if any.

Go ahead John.

We think it will be positive in the long run, because we expect to see more imports coming in, in New York Harbor it will have a momentary short term impact. We do have 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 are important three [Technical Difficulty], but we expect the additional volumes off the quality there. So maybe have an impact for the next month or so. Negative and in the long run, we think it'll be positive for us coming into New York.

And then just last one for me, quick one, for the KMCC project what's the cost of that project? I'm guessing it's not that much because it's just pumps, but the term of the contracts? And should we think that the benefit will offset the re-contracting headwinds that you talked about in recent quarters?

Yes, so the initial cost of the project right now we're going to spend about $10 million this year. And so with that, we'll be able to get $100 million -- I'm sorry, 100,000 barrels a day in [Technical Difficulty] and get some initial agreements that really kick us off at 75,000.

And for the term of up to three 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.

Our next question is from Dennis Coleman with Bank of America Merrill Lynch. Your line is open.

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 it sounds like a producer push project. But given where you talked about the target or the target area, you deliver a lot of gas already there for LNG. Wonder if there is sort of LNG pull demand. And if it relies on any particular projects above and beyond what's happened or been announced.

I mean, clearly it's serving the LNG projects are going forward on the side of Texas, East Gulf Coast of Texas. Golden pass where we won potential customer, Port Arthur LNG and other that is not FID just pretty promising. But there's also connectivity back into our intrastate network proportion of this volume so we would expect that volume to go and serve industrial customers on the side of our system. Then we will be crossing several interstate pipelines farther east. And so that will also be an alternative market.

Okay. And then maybe just if you can give a couple quick comments on how you think about returns versus the two projects that you've already have under development. Just it's becoming harder and harder to build these pipelines. I think we can we can all agree on that. We just talked about some of the issues with Permian Highway. Is there as a time where you as a pipeline developer are able to capture higher return from producers or demand it because of the greater sort of project risk that you face.

The returns are in line with what we've been experiencing on the previous projects, and they're good returns, we've got competition so we don't talk about them in specifics, but they're good double digit levered after tax returns with long-term contracts 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 acquisitions process, it goes into how we select the route, goes into all of those things. So we think we manage the risk by costing it right, scheduling it right and the returns that we're getting compensate us for the risk.

Our next question is from Michael Lapides with Goldman Sachs. Your line is open.

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 Analysts Day still hold? And then how are you thinking about traditional weak and tracking risk for the projects that have negotiated rates, kind of back half of this year and going into 2020?

Okay. So what we talked about on the 501-G which is an exposure that we believe we have behind us are largely behind this. We have two remaining pipes with the smaller amounts at 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 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 $100 million next year. In terms of your contract roll off question, I think where that risk is really concentrated is in our FEP, Fayetteville Express Pipeline and the Ruby Pipeline, and the time frame there is 2021, 2022.

Got it? And then a question -- I noticed the contract with Con Edison had a little bit of capacity via compression in the Northeast. Obviously, it's borderline impossible to get new pipelines built into the Northeast. How much incremental opportunity do you see to do similar type of projects to help add incremental capacity into the region?

Okay, I think this is the second one. So 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’t get pipelines permitted. And we think these are very formidable pipelines. Where we can 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, 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.

Got it. Thanks, Steve. Much appreciate it.

Our next question is from Becca Followill with U.S. Capital Advisors. Your line is open.

Thank you. Good afternoon. How much of the $800 million delta in the backlog is due to taking out the CO2 projects?

Yes, $500 million.

And then second on the FERC NOI and ROE. You guys put up some comments here, which were very thoughtful. Any thoughts on timing of the process with the FERC?

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's 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 us. And I would hope also, that they would find there's 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 wouldn’t expect one.

Thanks.

Our next question is from Robert Kwan with RBC Capital Markets. Your line is open.

Good afternoon. Just looking at the KML share buyback. First mechanically, is there going to be a prorata buyback of the KMI share?

No this is the buyback program that applies to the public flow.

Okay. And then you 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 do you also look at the MCIB [ph] versus potential new projects, acquisitions or other growth initiatives?

Yeah, I mean, we will certainly be evaluating what other opportunities there are to -- for that capital. We do look at DCF accretion as being kind of 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 the use of the program. But we thought that it was good to put in place certainly the board agreed and it was thing to have in place for our KML shareholders. And we will did it the right. But we use the right time, economically for our shareholders.

Got it. And I guess just that kind of selectively an opportunistic language. I assume that the Board also examines something larger, like a substantial issuer bid but decided technically the MCIB is kind of the right thing at this point.

I think that's a fair conclusion.

Okay, that's great. Thank you.

Our next question is from Rob Catellier with CIBC Capital Markets, your line is open.

Thank you. Just answered my question, I was curious about the evaluation of a substantial issuer bid. Thank you.

Thank you.

Our next question is from Spiro Dounis with Capital Suisse Your line is open.

Hey, guys. Thanks for squeezing me back in just had one follow up. So the answer this might be a bit obvious, but just given the rapid pace of buying this year, still kind of compelled to ask Rich, can you just comment a little bit on the uptick that 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?

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 I am interested shareholder and will continue to be.

Fair enough. Pretty good color.

Our next question is from Jeremy Tonet with JPMorgan. Your line is open.

Hi, thanks for squeezing in as well, Just want 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?

Yes, so as I mentioned, the issue that we had was making sure that we had a uniformly cold box where we make the LNG, and we had some mechanical issues associated with having LNG at actually too low of a temperature and solidifying it. And so we needed to get the top of the box cool uniformly with the bottom and what that required was a slower startup. So I would say essentially, we were trying to start it too fast. And so as we gradually stepped into it, and we're making very, very good progress. Now, with the uniformly cold box, it's about turning it up, and we’re turning it up as we speak. And then we have an eight 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 seal, 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 final operational issue that we're dealing with, and it seems to be our approach to so it’s 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, it could cause a little bit further delay. But the way we’ve narrowed down the problems now we're confident in its startups, that that startup will be soon, and that it will be operable once up and running. And that the lessons from the startup 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 startup with the first unit are being applied to the remaining unit. As I said, for including the first one for mechanically complete, all of the units are on the Elba Island and we're going through the assembly, and then the commission process as well over the course of this year, with maybe a slight -- maybe one of them drifting into that.

That's very helpful. Thanks. And with the EOR [ph] just wanted to come to that real quick is there more that that could be reduced that pricing and economic just as far as the CapEx spend there? Or is there a certain level of kind of base spend where you don't want to fall below because that could lead to kind of a decline curves picking up or anything like that where you not able to maintain production at the levels you want?

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 that’s higher than our other remaining businesses. That's how we do it. And so there's not a base level of capital that we feel we have to spend for some operational or other reasons. 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 it 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 demonstrates that.

At this time I'm showing no further questions.

All right. Well, thank you all very much. Have a good evening.

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