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 a question and answer session. 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, 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 and financial outlook statements within the meaning of the Private Securities Litigation Reform Act of 1995, the Securities and Exchange Act of 1934, 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 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 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're 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 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 and A comes through our natural gas segment and through our 70,000 plus miles of natural gas pipelines, 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, 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 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 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 2,030. That demand growth is being driven by LNG, power and industrial demand and by exports to Mexico.
Turning to the supply side, the U. S. Is projected by 2025 to be producing 1 quarter of all the natural gas in the world, 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 afternoon. I'm going to start with KMI, then turn it over to our President, Kim Dang, to give you the update on our segment performance. Our CFO, David Michaels, will take you through the numbers.
Zach Sanders will update you on KML, 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 4.5x debt to EBITDA target and with ratings 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 are returning value to shareholders with the 25% year over year dividend increase, and we continue to find attractive growth opportunities. 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 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 gs 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 that they can get their oil and NGLs out as well.
We've got 2 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. BCX 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. DCX is expected to be in service slightly ahead of schedule. The original schedule was October 1 this year.
We now expect to be at the full 2 Bcf a day 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 day. Permian Highway is receiving pipe and acquiring right of way. We've 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 affirmed the existing imminent domain process that has been used in use for decades in the state of Texas. Felt confident in our legal position, but it 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 2 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 gas demand growth between now and 2,030 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 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 1 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 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 $400,000,000 worth of projects to the backlog this quarter, partially offsetting $800,000,000 worth of projects that were placed in service or removed from the backlog. Most of what we removed from the backlog was in the CO2 segment.
We remain our team in CO2 remains very disciplined here, and we reduce capital spend when we find the economics do not justify the expenditure. The backlog now stands at $5,700,000,000 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.
Okay. Thanks, Steve. Natural Gas had another outstanding quarter. Was up 7%. 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 and A come from our natural gas business and of the natural gas consumed in the U. S, we move about 40% on our pipelines. So the fundamentals underlying our largest business are very strong. Transport volumes on our transmission pipes increased approximately 3.1 Bcf a day in the Q2 versus the Q2 of 2018 or about 10%.
This is the 6th quarter in a row in which volumes exceeded the comparable period by 10% or more. If you look at where these volumes showed up on our transmission pipe, PNG volumes were up 760,000,000 cubic a day due to increased Permian volumes and increased California demand. KMLA volumes were up 670,000,000 cubic a 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 approximately 500,000,000 a day due to increased DJ Basin production and colder weather.
RWBY volumes were up $370,000,000 a day due to colder West Coast weather and outages in the Pacific Northwest, and WIC volumes were up 3.70 a day due to increased DJ production. On our gathering assets, volumes were up approximately 16% or 450,000,000 cubic 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 continued to increase. Permian natural gas wellhead volumes increased approximately 30% versus the Q2 of 2018. Haynesville increased approximately 27%, Bakken increased approximately 27% and Eagle Ford increased approximately 5%.
Overall, the higher utilizations on our systems, a lot 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 terminals, our Central Florida pipeline, our Double Eagle pipeline and our condensate splitter were more than offset by 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 of which was our baseline terminal expansion project 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 at our Edmonton South terminal, which became a 3rd party obligation 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 1,200,000 barrels of tankage in the quarter versus the Q2 of 2018. That was primarily a result of the baseline project and that brings our total leasable capacity to around 89,000,000 barrels.
The bulk business was also down in the quarter due to lower volumes. Bulk volumes were down approximately 11%
due to lower coal, pet coke and steel.
Our City O2 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 percent versus the Q2 of 2018, but was set substantially below our plan. The reservoir is processing slower than we expected, until we can determine how to address this issue, we decided 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 $80,000,000 for 2019, as almost all the production associated with these investments benefit in future years. In CO2, as with all our assets, we diligently monitor our investments to make sure that they are going to achieve our projected return. To the extent that we think there's a material risk with the return, either take steps to mitigate our downside or we do not move forward with those investments as we did here. At Sacrock, which accounts for almost 2 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 at Saccarat.
When you look at the longer term, the story has also improved. In our mid year reserve review, SACR approved reserves increased by about 5,500,000 barrels, which 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 volumes, which more than offset a 4% decrease in price. With that, I'll turn it over to Dave for Michael.
Tim, today we are declaring a dividend of $0.25 per share, same as last quarter and in line with the budget there, dollars 1 per share for the 14% increase over the dividend 2018 and adjusted earnings and DCF grew from last year's Q2, generated DCF per share of $0.50 2 times or approximately $560,000,000 in excess of the declared dividend. Revenues were down 6% this quarter compared to the Q2 period. Some of that came from the benefit of a non cash losses on derivative contracts during the Q2 of 2018. We treated certain items and exclude from our non GAAP metrics. Excluding certain items, gross margin was in line period over period.
Net income available to common stockholders was 5.18 percent or 3.88%, better than the Q2 of 2018, largely to impairments taken during the Q2 of 2018, which we treated certain items. Before certain items, net income available to common stockholders was up $34,000,000 or approximately 7%. That includes the benefit of euro preferred dividend payment down from $39,000,000 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 $73,000,000 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 gs settlement. We had increased contributions from multiple expansion projects placed in service. Kinderhook and South Texas G and P assets were up, driven by increased volume.
Kinder Morgan, Louisiana pipeline was up due to our Sabine Pass expansion. And Kim provided the main drivers for our products, terminals and CO2 segments. Moving on to our Inter Morgan Canada segment that was down 100% as a result of our sale of the Trans Mountain pipeline. G and A expense was lower by 8 $1,000,000 due to greater overhead capitalized growth projects as well as lower G and A from the Trans Mountain sale. Partially offsetting those was higher pension expenses relative to last year.
Those pension expenses that hit G and A are non cash and we add them back to our DCF and replace those with our actual cash contribution to our pension funds. Interest expense was $22,000,000 lower and that was by a lower debt balance and greater interest capitalized projects as well. Those are partially offset by a higher LIBOR rate versus last year, which impact our interest rate swaps. Preferred stock dividends were down $39,000,000 as a result of the conversion of our preferred securities. Cash taxes were higher by $18,000,000 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 $26,000,000 higher versus the Q2 2018, mainly due to pipeline integrity work in our natural gas segment. Again, we have budgeted for greater expenditure and we expect our full year forecast to slightly favorable budget versus the Q1. Total DCF of $1,128,000,000 was up $11,000,000 or 1%. To summarize the main drivers, greater contributions from our natural gas segment, lower interest expense and preferred stock dividend, 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, 0.5 dollars per share was in line with 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 4.6x debt to EBITDA, which forecasted to be 4.6 times, which is just slightly unfavorable to our budget of 4.5 times and is consistent with our long term leverage target of approximately 4.5 times. As we said last quarter, our forecast for that full year EBITDA to be slightly lower than budget or a little less than 2% below budget. Drivers there include the FERC five zero one gs impacts, the Elda delay, lower commodity prices impacting CO2, higher pension expenses, partially offset by the very strong Permian supply growth that we saw
in the quarter. All of
those items impact DCF as well, but DCF includes the benefit of favorable interest expenses 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 has a $3,100,000,000 use, driven by a $1,300,000,000 pay down of bonds, which happened in the Q1, dollars 800,000,000 distribution to our public AML shareholders and $340,000,000 of Canadian cash taxes related to the sale of Trans Mountain. Other current liabilities, this was where we booked payable for the K and L public shareholders distribution quarter also includes movements in accrued interest and taxes.
Long term debt was down mainly due to to us paying off the $1,300,000,000 of bonds. Adjusted net debt ended the quarter at $34,800,000,000 or about flat with last quarter and an increase of $689,000,000 from year end. Reconcile the quarter change had the $1,128,000,000 of DCF, had growth capital and contributions to JVs of $770,000,000 paid dividends of $570,000,000 We had a working capital source of $200,000,000 mainly interest expense accrual. That gets us to about flat net debt for the quarter. To reconcile from year end, we had about $2,500,000,000 of DC dollars paid $1,520,000,000 out in growth CapEx and contributions to the balance sheet, paid dividends of 1,020,000,000 dollars paid $340,000,000 of taxes, fund sale, had working capital use of approximately $300,000,000 which was mainly interest payments, bonus, payroll and tax payments very close to 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 and modeling. Beginning in Q3, we plan to use that new format in our earnings release I think it represents an enhanced presentation of our financials. For now, it's just being provided in addition to our standard format, so you can review ahead of our implementation. With that, I'll turn it back to Steve.
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 at our Vancouver Wars facility.
We have a good business here, good midstream assets and 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.
Thanks, Steve. Before I get into the results, I do want to update you on a couple of general business items. First, as we announced, the KML Board approved a stock repurchase plan will allow us to repurchase up to 2,000,000 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% hold. On our announced diesel export project, we received all material permits and commenced construction activity.
Consistent with previous statements, this is an approximately 43 $1,000,000 project that contemplates 2 new distillate tanks with combined storage capacity of 200,000 barrels underpinned by a 20 year take or pay contract that we expect put in service during
the first half of twenty twenty.
On the Shed 6 reactivation project that we have discussed, which is which as a reminder is that $8,000,000 expansion project at Vancouver Wharf. We continue to expect to have that in service in Q3. Now moving forward to the results. Today, the KML Board declared a dividend for the Q2 of $0.1625 per restricted voting share of $0.65 annualized earnings per earnings per restricted voting share from continuing operations for the Q2 of 2019 are $0.12 and that's derived from approximately $22,000,000 income from continuing operations, which is the same as net income. Income from continuing operations was down approximately $2,000,000 versus the same quarter in 2020.
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 tanker terminal assets coming online, but the increase in revenue was more than offset by the non recurrence of a gain on the sale of the small Edmonton area pipeline asset in 20 18 than the other income expense line and treated as a certain item on the DCF. DCF from continuing operations for the quarter is $28,300,000 which is down approximately $7,800,000 in the comparable period of 2018. That reflects coverage of approximately $2,800,000 dollars and reflects the However, we were now we are now required to make installments 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 2020. Looking at the other significant components of the DCF variance, segment EBITDA before certain items is up $7,600,000 compared to the Terminal segment up $6,500,000 and the Pipeline segment up $1,000,000 The Terminal segment was higher due primarily to baseline coming online, which accounted for about $5,400,000 The pipeline segment was higher primarily due to higher revenue on coach units for both the index adjusted rate and timing on volumes.
Finally, sustaining capital was negative $3,900,000 due to several planned tank inspections that we did in the Q2 that were fully booked. Looking forward, as we said in the release, we expect to meet our budget of approximately $213,000,000 of EBITDA and approximately $109,000,000 of EBITDA. With that, just a couple of quick comments on the balance sheet and
our liquidity. We ended the
quarter with approximately $33,000,000 in cash available liquidity as we only had $35,000,000 drawn out of a $500,000,000 revolver. Our debt to 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.
Okay. Brandon, if you'll come back on, we'll take questions.
Thank you. We will now begin the question and answer session.
Good news there with GCX, it sounds like coming online early. Just want 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? Could there be line fill where 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?
Yes. 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 we'll be able to 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 to pack the line, ramp up all the compression and get to the 2 Bcf, we think we'll be done that week to 10 days early.
That's kind of what we're looking at. In the meantime, yes, we'll be buying gas. We'll 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, would this leverage your footprint? And you lifted, I think, the CapEx spend $400,000,000 there.
Is this kind of in there, part of that spend? What type of 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 at Agua Dulce, which serves Corpus and serves 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, 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 3rd pipe well, the 4th pipe, if you count Whistler, the 4th 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 3 other pipes about whether there's enough gas demand or need for a 4th 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 the same pattern is going to hold on Permian Pass.
And yes, the proof of the demand is in the shipper sign up. And we 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 4th pipeline.
And then there's 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 firm 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 $80,000,000 positive on free cash flow. Can we assume that, that $80,000,000 is the reduction in CapEx?
And then I was wondering if you can comment on the project that you're evaluating with Ballgrass. The language in your press release was kind of a little interesting. It says, we'll evaluate and you've received indications. I'm 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 $80,000,000 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 primarily flows into Tallgrass's 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 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 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 on.
Our next question is from Jean Ann Salisbury with Bernstein. Your line is open.
Hi. I just wanted to follow-up on the Tallgrass project. It seems like with Liberty and DAPL 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 Analyst Day last year, you'd mentioned looking into the possibility of converting WH to NGL service. Can you provide any color on why you ultimately decided not to go that route?
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 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 turning.
But it does have a 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. It looks like you're now investing about $250,000,000 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 we continue your concerns that once the gas sort of initially hits dock with oil in September, has nowhere to go.
So just how you're thinking about problem solving for that?
Yes. So it's about $250,000,000 We're going to get about 1.4 Bcf out of additional takeaway there, which is a very capital efficient capacity expansion. So that's we talked about that as our Crossover II 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 these 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 really toward the coast and there are probably more of those to come. In terms of the timing, Tom, on the completion of Crossover 2 next year.
Great. Appreciate that. Just thinking about CapEx from a higher level, when you consider growth over the next 2 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?
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, etcetera. And I think we're just going 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 to $2 range previously.
Our next question is from Colton Bean with TPH. Your line is open.
Good afternoon. So to switch over to the crude side of this, I just wanted to touch on the KMCC and Gray Oak JV. Given the varying diameters there between the Helena lateral and then the trunk line to Houston, do you have a plan for specifically where that interconnect would be?
Yes, that's going to be really at the station we call Louise down South Texas, we'll be really tying it 30.
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 a 30 inches gray oak pipe into a 30 inches KMCC that ultimately you could match capacities?
Possibly could, but right now the expansion projects will
be set at 1,000 barrels a day.
Okay. And with the main consideration just be incremental horsepower?
That's right. Perfect.
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 inches connection, maybe you could get more barrels up from Corpus as well and have a little bit of a bidirectional header there?
Double Eagle is a joint venture, so we'd have to kind of exploit it with our joint venture.
Understood. I guess just a quick one. On the Haynesville, I think you guys have called out pretty strong volume growth there. With the reduction in counterparty rig count there just to exit Q2, has that outlook shifted at all for the back half of twenty nineteen or status quo?
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 to accommodate what we see as continued growth in that area, but still very attractive return projects. But our volumes remain 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 and PHP rolling off over the next 18 months and combined with the dividend growth next year that at your planned rate, both of those combined to suggest that there's a real opportunity for free cash flow in the out years? And again, just thinking about priorities and what that can be used for?
Yes. Well, 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 at our shadow backlog and other things that are on the horizon, as Rich said, we think the $2,000,000,000 to $3,000,000,000 range is probably that's been the range for quite a while. We think that 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 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'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 imminent 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 the challenges you're having with right of way permitting, could you give an update on how that's tracking relative to budget?
Yes, we're still on schedule. So a 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, an 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 be 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 impacts for your product pipelines or your New York Harbor business, if any?
Go ahead, John. We think net to net it
will be positive in the long run because we expect to see more imports coming into New York Harbor. 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 our 0.3 truck rack, but we expect they will be able to get additional volumes off the Colonial River.
So it may have an impact for the next month or so, negative
and in
the long run, we think it
will be positive towards coming into the
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 contract? And should we think that the benefit will offset the rate re contracting headwinds that you've talked about in recent quarters?
Yes. So the initial cost of the project, right now, we're going to spend about $10,000,000 this year. And so with that, we'll be able to get to 100,000,000 I'm sorry, the 100,000 barrels a day in and we've got some initial agreements that really kick us off at $75,000
And for the term of up to 3 years. Up to 3 years. Up to 3 years on the term. And it will 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 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 or been announced?
I mean, clearly it's serving the LNG projects are going forward on side of Texas, East Gulf Coast of Texas. Golden Pass would be one potential customer. Port Arthur LNG would that is not FIP yet, pretty promising. But there's also connectivity back into our intrastate network, for a portion of this volume. So we would expect that volume to go and serve industrial customers on the side of our system.
Then we'll be crossing several interstate pipelines farther east. And so that would also be an alternative market.
Okay. And then maybe just if you can give a couple of quick comments on how you think about returns versus the 2 projects that you've already have under development. 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 higher returns 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 unlevered 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 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 costing it right, scheduling it right and the returns that we're getting compensate us for the risk we take.
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 five zero one gs process for you? And does that $100,000,000 number you put out at the Analyst Day still hold? And then how are you thinking about traditional re contracting 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 gs, which is an exposure that we believe we have behind us or largely behind us, we have 2 remaining pipes with smaller amounts at issue that we're waiting on final decisions on. But with the ones that we've done, it was $50,000,000 for this year, growing to $100,000,000 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 this year and 100 next year. In terms of your contract roll off questions, I think where that risk is really concentrated is in our FVP, Fayetteville Express Pipeline and in the Ruby pipeline and the timeframe 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 pipeline 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 get pipelines permitted, and we think these are very permittable 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.
They're 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 2.
Got it. Thanks, Steve. Much appreciated.
Our next question is from Becca Followill with U. S. Capital Advisors. Your line is open.
Thank you. Good afternoon. How much of the $800,000,000 delta in the backlog is due to taking out the CO2 projects?
5,000,000. 5,000,000. 5
100,000,000. And then second on the FERC NOI on ROE, you guys put out some comments there 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 them. 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 1.
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 pro rata buyback of the KMI shares?
No, this is a buyback program that applies to the public float.
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 DCF accretion on an absolute basis? Or do you also look at the NCIB versus potential new projects, acquisitions or other growth initiatives?
Yes. 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 a good thing to have in place for our KML shareholders. And we will sit at the right what we view as the right time economically for our shareholders.
Got it. And I guess just that kind of selectively and opportunistic language, I assume that the Board also examines something larger like a substantial issuer bid, but decided tactically the NCIB 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 to this might be a bit obvious, but just given the rapid pace of buying this year, I feel kind of compelled to ask risk. 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, given the nice run up year to date?
Well, 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'm an interested shareholder and I will continue to be.
Fair enough. Appreciate the color.
Our next question is from Jeremy Tonet with JPMorgan. Your line is open.
Hi. Thanks for squeezing me in as well. Just want to come back to Elva. I think you had touched on it briefly there, but I was wondering if you could dive in a little bit more far as what was causing the issues with the cryogenic temperatures there. What did you learn to get that solved?
Is there going to
be any issues with subsequent 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 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 start up. 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 a uniformly cold box, it's about turning it up we're 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 a 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 it working fine. And so if that's the case, we'll 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, 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 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, 4, including the first one, 4 are mechanically complete. All of the units are on Elba Island, and we're going through the assembly and then the commissioning process on those wells as well over the course of this year, with maybe a slight maybe one of them drifting into net.
That's very helpful. Thanks. And with the EOR, I just want to that real quick. Is there more that, that could be reduced if pricing and economics adjust 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're 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 a reasonable range of prices that will produce an economic return at a 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 reason. We do it each project on a project by project basis 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 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.
Thank you for participating in today's conference. All lines may disconnect at this time.