Kinder Morgan Inc - Class P (KMI) — Q2 2019 Earnings Call Transcript

Thank you, Brendon. Before we start, I want to remind you that today's earnings releases by KMI and KML and this call contain forward-looking and financial outlook statements as defined by the Private Securities Litigation Reform Act of 1995, the Securities and Exchange Act of 1934, and relevant Canadian securities laws, along with certain non-GAAP financial measures. We strongly encourage you to read our full disclosures on these statements and non-GAAP measures included at the end of KMI's and KML's earnings releases, and to review our latest filings with the SEC and Canadian securities commissions for important material assumptions, expectations, and risk factors that could cause actual results to differ significantly from those forecasted. Before I hand it over to Steve and the management team, I typically start these quarterly calls by discussing our financial strategy at Kinder Morgan. We aim to manage our assets and the substantial cash flow they produce responsibly to maximize shareholder returns. It's essential to understand what drives that cash flow and whether the business will continue to deliver strong and growing returns with opportunities for asset expansion. The majority of our segment earnings before DD&A comes from our natural gas segment, and through our extensive network of over 70,000 miles of natural gas pipelines, we transport about 40% of the gas consumed in this country. Furthermore, most of our current and anticipated capital expansion investments are also focused on the natural gas segment. We are very optimistic about the future of natural gas from both supply and demand perspectives. Natural gas is vital to the American economy to meet increasing energy needs globally and importantly, to help reduce greenhouse gas emissions effectively. Our optimism is supported by the actual results of recent years and the consensus estimates from firms and government agencies closely monitoring the energy sector. Sometimes we overlook the facts, so let’s take a look at the past: U.S. demand for natural gas rose 12% in 2018 compared to 2017 and was 44% higher than a decade ago. 2019 is also expected to be a strong year. Looking ahead, we previously indicated that U.S. demand is projected to grow by over 30% by 2030, driven by LNG, power, and industrial demand, as well as exports to Mexico. On the supply side, by 2025, the U.S. is expected to produce a quarter of the world's natural gas, accounting for over 50% of global supply growth by that year. I recognize that predicting the future can be quite challenging, as Mark Twain famously noted. However, I believe that natural gas will perform well in the coming years under almost any scenario. Connecting these abundant U.S. supplies to growing demand markets will necessitate new infrastructure and increase the utilization of existing assets. KMI is well positioned to capitalize on these opportunities, especially in Texas and Louisiana, where our expansive pipeline network is ideally located to support the rapidly growing LNG export and petrochemical sectors. This is a significant reason for our confidence in the long-term future of the company. Now, I will turn it over to Steve.

All right thanks, Rich. We will be updating you on both KMI and KML this 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 numbers, 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. 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-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 have two projects to get the gas out: Gulf Coast Express and Permian Highway, and we are in discussions on a possible third pipeline, which we are 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 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 for four 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 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 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 the CO2 segment; 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 in the second quarter versus the second quarter of 2018, 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 volumes 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. Overall, 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. 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 capacity. Our product segment was down in the quarter slightly. There were increased contributions from our Southeast Refined Products Terminal, our Central Florida Pipeline, our Double Eagle Pipeline, and our Condensate splitter which 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% which is a little better than the national average. The terminal 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 post 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 the 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, it was offset substantially below our plan. The reservoir is processing slower than we expected and until we can determine how to address this issue, we are 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 risk with its return, we 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, the same as last quarter and in line with the budget, $1 per share for the fourth quarter, representing a 25% increase over dividends 2018. KMI’s adjusted earnings in DCF grew from last year’s second quarter, generating DCF per share of $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 the decline in cost of sales more than offset our lower revenues so 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, which is 388% better than the second quarter of 2018, largely due 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 activities. 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 Trans Mountain sale. Partially offsetting those was higher pension expenses relative to last year. Those pension expenses that hit G&A are 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 which 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. In fact our full year forecast is slightly favorable to budget. 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 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 4.6 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, the forecast for that full year EBITDA to be slightly lower 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, and 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 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 decreased to $3.1 billion, driven by a $1.3 billion pay down of bonds which happened 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 include the booking of payables for the public shareholders' distribution for the quarter, and also include movements in accrued interest and taxes. Long-term debt was down, mainly due to us paying off $1.3 billion of bonds. 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. To reconcile the quarter change, the $1.128 billion of DCF had growth capital and contributions to JVs of $770 million, paid dividends of $570 million, and 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 JVs, paid dividends of $1.20 billion, paid $340 million of taxes related to the Mountain sale, and a working capital use of approximately $300 million, which were mainly interest payments, bonus payroll, and tax very close to the 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 for your modeling. Beginning in the third quarter, we plan to use that new format in our earnings release, it represents an enhanced presentation of our financials. For now it just been provided in addition to our standard format so you can evaluate our implementation. 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 proposed a stock repurchase plan that will allow us to repurchase up to 2 million restricted voting shares over the next 12 months, which 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%. 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 the near future. 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 payout. 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 the 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 a small Edmonton area pipeline asset in 2018 from the other income expense line and treated as certain items on the DCF. DCF from continuing operations for the quarter is $28.3 million, down approximately $7.8 million compared to the comparable period in 2018, that reflects coverage of $2.8 million and reflects the DCF payout ratio of approximately 102%. Cash taxes were unfavorable at $9 million. As we discussed previously, we were not required to make cash tax payments in 2018 for 2018 operations, but rather we were able to defer them until the first quarter of the current year. However, we're now required to make installments for this year, which is driving that year-over-year increase. As a relevant upside, our ultimate cash tax obligation for 2018 was lower than we expected and as such we expect to refile later this year for the prior year's taxes. Looking at the other significant component of the DCF variance, segment EBITDA before certain items is up $7.6 million. Terminal segment is up $6.5 million and the pipeline segment is up $1 million. Terminal segment was higher due primarily to baseline coming online, which accounted for about 5.4 million. The pipeline segment was higher primarily due to higher revenue on adjusted rates as a result of index adjusted rates and timing on volumes. Finally, sustaining capital was negative $3.9 million due to several plant tank inspections that we conducted in the second quarter. 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 DCF.

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 credit facility. 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.

Good afternoon.

Hi, good afternoon. Good news there with GCX, it sounds like coming online early. Just want to touch on that a 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 and 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. Commissioning compressor stations can be dicey, but we are pretty comfortable with these units and think we will be able to get them going and get them ramping up. It's a process that takes time. 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 2 BCF. We think we’ll be done 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 in the 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 leverages your footprint and you lifted, I think, the CapEx spend $200 million. Is this kind of in that part of that spend? What type of product development 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 hits Agua Dulce, which serves Corpus and serves the Mexican market and some industrial demand down in that part of the state. Permian Highway kind of comes into the middle of our system and it will 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. 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.

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 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. 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. 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 long-term commitment.

Okay, great. And as a follow-up, just wanted to 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 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 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 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. 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 that.

Hey, I just wanted to follow up on the Tallgrass project. It seems like, with Liberty and another competitor 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. A competing project was announced and reached FID. So it kind of soaked up that opportunity that demand.

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