Ladies and gentlemen, thank you for standing by, and welcome to the Targa Resources First Quarter 2020 Earnings Conference Call. [Operator Instructions]. I would now like to hand the conference over to Sanjay Lad, Senior Director of Finance and Investor Relations. Thank you. Please go ahead.

Thank you, Bridget. Good morning, and welcome to the First Quarter 2020 Earnings Call for Targa Resources Corp. The first quarter earnings release for Targa Resources, along with the first quarter earnings supplement presentation are available on the Investors section of our website at targaresources.com. In addition, an updated investor presentation has also been posted to our website. A reminder that statements made during this call that might include Targa Resources' expectations or predictions should be considered forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our latest SEC filings. Our speakers for the call today will be Matt Meloy, Chief Executive Officer; and Jen Kneale, Chief Financial Officer. We will also have the following senior management team members available for Q&A.: Pat McDonie, President, Gathering and Processing; Scott Pryor, President, Logistics and Transportation; and Bobby Muraro, Chief Commercial Officer. And with that, I will now turn the call over to Matt.

Thanks, Sanjay. Good morning, and thank you to everyone for joining. On behalf of the Targa team, we hope that you and your families are doing well and staying safe. The first quarter results show that our assets continue to perform well with solid operational and financial performance in the first quarter. We had $428 million of adjusted EBITDA, 32% growth in Permian volumes, 37% growth in fractionation volumes and 26% growth in export volumes versus last year despite significantly lower commodity prices. Our continued efforts to reduce commodity exposure across our G&P business by adding fees and fee floors allowed us to generate higher operating margin even as prices fell significantly. The financial performance of our G&P segment is now more driven by volume throughput and fees as opposed to direct commodity prices, which will serve us well going forward. With some of our fee-based contracts through our fee-floor structure, we will also benefit as prices begin to rise. Now moving on to the impacts of COVID-19. When it became clear that the pandemic was a significant risk to our employees and their families, we moved quickly to make sure that we took care of our employees, our facilities and our customers. We swiftly implemented important safety measures, including providing our employees with protective equipment and we are currently pleased with the minimal direct impact that the virus has had on our employees. I'd now like to thank all of our employees. We are especially proud of our frontline employees in the field who continue to safely and effectively operate our facilities every day. And thanks to our other employees who are operating at a high level of effectiveness, working remotely to ensure continued first-class service to our customers. Our industry continues to navigate through an unprecedented period as…

Thanks, Matt. Targa's reported quarterly adjusted EBITDA for the first quarter was $428 million. Our performance during the first quarter was driven by strong volumes across our Permian and Badlands G&P systems combined with strong asset performance through our integrated downstream value chain of NGL transportation, fractionation and LPG export services. We recently commenced operations on our new Frac Train 7 in Mont Belvieu and completed our new Peregrine gas plant in Permian Delaware. We remain on track to complete our remaining major growth capital projects underway this year, which means we will be well positioned to benefit when activity levels increase. Considering current market conditions in the low commodity price environment, during the first quarter, we recognized an approximate $2.4 billion noncash impairment charge. The impairment is primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our mid-continent G&P operations and full impairment of our coastal G&P operations. Turning to hedging. Based on a range of current estimates of producer customer activity levels, we remain substantially hedged for 2020. We have hedged approximately 85% to 100% of natural gas, approximately 75% to 100% of condensate and approximately 65% to 80% of NGL. Supplemental hedge disclosures, including 2021 hedge percentages by commodity, can be found in our earnings supplement presentation on our website. We continue to closely monitor and manage our credit exposure. We have a large diversified customer base across our operating businesses, which includes large integrated customers and other investment-grade counterparties. Approximately 75% of the revenue from our top 25 customers is from investment-grade counterparties or from customers which provide credit protections. We currently do not anticipate any material credit losses as we are largely in a net payable position in our G&P contracts. And in our downstream businesses, our counterparties are…

[Operator Instructions]. Bridget, can you please open the line to Q&A, please?

[Operator Instructions]. Our first question comes from the line of Christine Cho with Barclays.

Thank you for all the color. I just wanted to maybe touch upon the conversations that you're having with producers. Can you just give us some more color on what those conversations are like? And also recognizing that you have some large customers that are public, I would also be curious as to how the conversations with the smaller and private guys are going.

Sure. Yes, I'd characterize our producer conversation, as I kind of said in the script, very fluid. I'd say even just a few weeks or even a month ago, some producers were giving us estimates for what they believe they were going to shut-in. And this ranges across our systems, really large and small. And we've seen them shut some in only, maybe even a few days or weeks later to come back up and then shut-in a different amount. So we've seen variability even among some producers about what they're going to do and how they're going to execute their shut-in plan. And we've seen others say, we're getting ready to, here's what we're going to do, and we've even seen those plans change. So I'd say producers right now are trying to work through what best makes sense for them. And oil prices are moving around very quickly as well. So they're trying to best balance their downstream needs and obligations versus current prices, and where they're in kind of constant dialogue with them trying to figure out how best to make sure that we can handle the volume.

Would you say the conversations are different for the private guys because they're downstream constraints or downstream commitments might be different?

I'd say, really, and just when the management team here is talking to each one of our different leaders in the business segment, it really just more varies producer by producer. I don't know if I could aggregate that the publics are doing one thing versus the privates. I mean, there's significant variability across system, across region. Some producers have acreage positions in multiple basins and how they're acting in one basin versus another versus a producer who might be acting one way because their production is all in one basin, can be very different, even amongst the same basin. So I think it varies more unique to their acreage position and their economic situation as opposed to whether they're the publics or the privates or small or large.

Okay. Very helpful. And then you brought on a frac, and another one is set to come on later this year. Some of your peers have deferred the timing of their frac. So wondering if you're expecting more third parties to offload into your plans this year or next year? Or alternatively, were there volumes that you were expecting to move over to third-party plans that are maybe not happening under the scheduled time frame?

Yes. I'd say, when it comes to our fracs, we are planning on completing we're -- significant progress on Train 8. So we do plan to complete that. And I think you're right, there are some others who have either slowed down or canceled some of their fracs. So when volumes begin to grow, if they're in a position where they would need some frac capacity, there is that potential. We would welcome that opportunity. What we're looking at for 2020, I don't know that we would see a lot of that opportunity, but as we go out, certainly, that opportunity could present itself.

Our next question comes from the line of Shneur Gershuni with UBS.

I just wanted to start off by following up on the frac conversation. When I think about Frac 8 coming online, if it's the volumes that come into your system end up being below the capacity of your entire frac footprint, are there opportunities to optimize by shutting down an older inefficient frac temporarily and moving the volumes to the newer fracs? What if kind of the partial ownership sort of limit that opportunity from a margin perspective?

Shneur, this is Scott Pryor. We definitely look at our entire fractionation facility as a whole. But we will operate those based upon what is most efficient, what is based upon the economics of the inflow of volumes as well as the outflow of volumes needed to fulfill customer contracts. Again, both on the inbound side as well as the outbound side. As we supply customers downstream of that, as we supply export volumes from both propane and butane, we certainly look at it from an optimization perspective. And there's a variety of factors that flow through those analyses, but we are certainly looking at it to optimize what is most efficient and is -- what benefits us from an economic perspective.

Okay. That makes great sense. And maybe to follow-up on the G&P side. I definitely appreciated all the color that you gave about shut-ins and so forth. I was wondering if you can just give a little bit of color about what your underlying decline rate is for your Permian footprint. And how easy is it to bring shut-in wells back? Is it costly? Or is it something that's pretty straightforward across your footprint?

Yes. Good. Good question there on the shut-ins. We've had, I'd say, extensive conversations with our producers about that. So as we're trying to forecast when there's going to be shut-ins, what should we expect when it comes back. So again, we can be ready. I'd say for the most part, in those producer discussions, they feel like most of that production when they shut-in, we'll be able to bring it back without damaging the reservoir. Could there be some older, really low rate vertical wells and some things which they shut-in and just don't bring back? I think there could be some amount of those as well. But I think for the most part, we'd expect the shut-in volumes to come back and perform well when those volumes do come back. As far as the decline rates, that's tough. I don't have a crisp answer for you on that. I mean, it would be by system. Obviously, there's been a lot of growth in the Permian. So we have newer vintage on average production there where some of our older systems who haven't been growing as much. So it would be steeper there.

Okay. That makes sense. And just one final question. I was surprised to see how much you've been able to repurchase debt in the open market. Do you expect to continue to do so if the opportunities present itself, i.e. the debt trades below par? Or have we seen the sale end of that?

Shneur, this is Jen. I think, ultimately, it depends on opportunities that the market presents to us. And so we saw the opportunity when our debt started trading at a deep discount in early March to repurchase notes at a very attractive rate made all the sense in the world in terms of interest savings while also reducing our overall leverage. If we get that opportunity in the future, we'll certainly look to utilize some of our available liquidity to continue to execute on that, but ultimately, it just depends on the market opportunity.

Our next question comes from the line of Michael Blum with Wells Fargo.

So I apologize for harping on the fracs and all that. But I guess, maybe the questions everyone is trying to get at, and I'll try to ask it may be a little differently is -- so as you stated, you're expecting to see NGL volumes come down, but you also said at the sort of tail end of that, that you're contracted on your pipeline and the LPG exports and your frac. So can you just address the contracted position? Because I think what everyone's trying to figure out is why are you adding frac capacity and LPG export capacity when it seems like production is going down so how protected are you with contracts?

Sure. Yes, thanks, Michael. Yes, I'll start on the fracs and then hit on the exports as well, and then Scott, you can fill in too. On the fractionation side, we have significant number of third-party customers, we have long-term fractionation contracts with. A lot of those are transportation in fractionation and a lot of our simple, just fractionation agreements. And then we have additional volumes moving through our system, through our gathering and processing business, which are underpinned by acreage dedications and volumes coming from our processing plants. So when you look at our fractionation position, we're, obviously, anticipating there would be significant growth from our underlying acreage dedications, but we also have a ramp-up in our commitments in our MVCs. So whether they're T&F or fractionation, they're going to be ramping and these commitments ramp over time. And so that's what gave us the confidence to underwrite 2 trains, Train 7 and 8. So over time, we'll have our own volumes for ramping MVCs and commitments for highly -- a substantial majority, a very large portion of our fractionation position there. But it's going to take a little bit longer. The ramp is going to take a little bit longer than we estimated when we underwrote those facilities. And we are so far along on Train 8 that there's not much cost savings to be had by delaying that. We can do better on optimizing, as Scott talked about earlier, optimizing our fracs, trying to lower cost by running things a little bit better. So we think it makes sense for us to go ahead and continue with Train 8. And then moving to the export side, we have -- we're significantly contracted. We're highly contracted last year. We're highly contracted right now. And we do have forward contracts that ramp up as we bring LEP3. So as we increase our capacity on the export side, we have more contracts that start as well. So we're highly contracted this year, even when taking into account the increased capacity.

Great. I'm sorry, go ahead.

Michael, I'm sorry, this is Scott. Just to add to that a little bit. When you look at the volumes that we did across the fractionator in the first quarter, obviously, they were very strong. We appreciated the added capacity that came online during March with Frac Train 7. But as Matt alluded to, is we may see the ramp a little bit longer as we fill into the rest of the fractionation capacity that we're adding later this year. With that said, it also allows us the opportunity to reduce our capital exposure for 2020 as well as 2021, which we alluded to clearly in our script, as we talked about our capital spend. So we are positioned well as volume growth starts coming back to the marketplace over time. From the export perspective, we had a nice strong quarter. And you can see, if you look at the materials that we put out there on our pages, we've had strong quarters, really good dating back to early 2019, every quarter was stronger with the export volumes going across our dock. We continue to see good exports in the month of April, and things are shaping up well. There's still strong demand for exports across the world. And as markets recover in the East, that just actually provides more benefit to us over the long haul. And you've also seen, just from a market perspective, some of the pull-down in production with the OPEC+ nations that adds some benefit to U.S. Gulf Coast volumes going out. So we feel very fortunate to be in the position we are within a very diverse downstream market that supports our upstream production growth.

Great. I really appreciate it. One -- just 1 clarification question on something you said earlier. The shut-in numbers you put out there, the different percentages for the different patients, is that just for May? Or is that like what time period is that specifically?

Yes. The numbers I gave, the 10% for Permian and the like was our estimate for what's going to be shut-in in May, kind of relative to current. So if you take kind of April or just kind of where we are kind of entering May, we would estimate 10% of those volumes to be shut-in, in the Permian, 10% in central and then 30% to 40% of the Badlands.

Our next question comes from the line of Colton Bean with Tudor, Pickering and Holt.

I appreciate the comments on the NGL storage. I think you guys have something around 100 million -- or 50 million, sorry, in Belvieu and another 20 million in Louisiana. Can you just frame for us to what degree that's available to you versus leased out to third parties?

Yes. I'd say we have with 50 million in barrels in Belvieu, we have a lot of flexibility and capabilities to optimize our storage position. And you're right, a good portion of that is leased to third parties. A lot of it is for our own managing the engine out, the Y-grade coming in, the purity products, but we have a significant amount to move wells in from one purity product into another and have some flexibility and fungibility there as well. So I'd say, with our position, it just provides us a lot of ability to optimize that position. And so we feel good about that in this contango market.

Got it. And then I think even prior to the volume reduction, you were already hedged around 80% or so on natural gas, but still some spot and correct me here, but I believe Waha was assumed at $0.50 or so. So with the forward curve now looking like $2-plus for Waha, can you just update us on what's assumed in the new guidance range?

We don't have what I characterize as a single price assumption. We've got a wide guidance range, Colton, and that's reflective of the uncertainty in the current market. Prices are moving around on a daily basis as they do, but it's difficult to say that there's a certain commodity price that's running through our new updated guidance range. It's based on a range of estimates for prices, shut-ins, activity levels, et cetera.

Got it. I guess, directionally, is it fair to say that the Waha assumption may have moved higher? Or is that also still, I guess, included in that range?

So I think given our hedged position for gas, the amount that it's moved around is not a large variable in the guidance range. We have significant amount hedged for 2020. So there's -- it's not a large driver for us in that guidance range. But Jen is right, we looked at this around. We looked at strip pricing as we were going through the volumes and updating it, but we looked at many different cases and many different pricing assumptions. But the gas price variability was not one of the larger drivers in that range.

And our next question comes from the line of Jeremy Tonet with JPMorgan.

This is Charlie on for Jeremy. I just wanted to follow-up on the LPG export side. It sounded like volumes are still pretty strong through April and 2020 is pretty well contracted, but I was curious about how you think that trends kind of the balance of this year as we think about lower cost naphtha, just competing products? And then maybe how that leaks into 2021 and beyond. I don't know how low contracted you are there? How you feel about that? And if your strategy, how that's evolved?

Yes. Charlie, I would say -- this is Scott again. First off, when you look back at the fact that we're adding additional export expansion in the third quarter this year, we talked about that in our script as well. And that is supported by contracts that will be coming online that are tied to that expansion project. So that's the pieces that make us feel very good about the second half of 2020. Those contracts, obviously, flow into 2021, which are both supportive of propane exports as well as butane exports. And so from that perspective, we feel good about the growth. And again, like the fact that we're moving forward with that project coming online in the third quarter. As it relates to the naphtha-based products, there's been some refinery runs that have created some tightness in the marketplace. And some of the heavy-end derivatives that are impacted by that. So we continue to believe that we'll see strong exports for propane and butane, and there'll be limited, I guess, competition for that leading into '20 -- as the balance of '20 as well as 2021.

All right. That's helpful. And then just one other from me. The $100 million cost reductions, I know a lot of that was tied to compensation and headcount. Curious if there's anything operationally you're doing to kind of slim down costs or anything that you can do. I think you noted that -- is that this $100 million was at least so, I don't know if there's more to come there.

Yes. I'd say that a significant portion of the $100 million of expected savings is OpEx. And so that does include some reduction in headcount, both in existing positions and then also in a lower expectation for hiring throughout the year out in the field. But our supply chain group, our operations groups are incredibly focused and have been very successful in identifying opportunities to rationalize costs on basically every line item. So you heard Matt mentioned some of them, like chemicals and lubricants, but it's really every single item that we're purchasing, we are trying to purchase better at a lower cost to Targa. So that will continue to be a focus and has been a very big focus of our operations and supply chain group really over the last year, but certainly, that focus has heightened here recently.

And our next question comes from the line of Tristan Richardson with SunTrust.

Really appreciate all the commentary around shut-ins and just what you're seeing on the supply side. Just, with respect to the supply side, as you went through that range of what potential outcomes, on the base case, where do you guys see a general resumption that shut-in production occurring, either a time frame or a price signal?

Yes. I'd say in that downside scenario, which kind of got us to that low end 1.4 number, taking, call it, 30% shut-ins in the Permian for the rest of the year, that's not our base case. I just don't think it's going to be that severe for that long. I said in the script, it's probably more likely going to be a couple to a few months would be if you had to say what's a reasonable guess, maybe a couple to a few months seems like a reasonable guess. But we also qualify, I want to qualify that with we really -- there's a lot of uncertainty. And could it carry on much longer than a couple to a few months? That's certainly a possibility. When does worldwide demand come back? When do people start driving again? It's really hard to say when that demand comes back. So that's why we did want to kind of present a wider range and have a downside scenario that if this lasts longer and the cuts are even deeper than what we're likely going to see in May, how does Targa look? And that's why we kind of went with that wider range and did that. But ours would be -- our best guess would be something less than that downside case in terms of shut-in percentage.

I appreciate it. Very helpful. And then, Jen, you mentioned working with customers to reduce commodity exposure. I think we generally think of that as a long term initiative. But does the current market advance those discussions? I mean understanding it's difficult to open up an existing contract with a customer in this environment, but just any thoughts there.

We continue to be focused on trying to enter into, amend, have the best possible contracts. And so that's always a focus for our commercial teams and then for others across the organization that are entered -- involved in purchasing and other things like that. On the gathering and processing side, we've talked fairly consistently over the last several quarters about our efforts to enter into more fee-based arrangements, have more fee-based floors. I think the lower commodity price environment highlights why that's important to us, particularly if we are going to spend capital. Now clearly, we're rationalizing capital. So that's a little less applicable right now. But that continues to be a big focus of ours, really across the organization is trying to improve contracts when we are given the opportunity.

And our last question comes from the line of Keith Stanley with Wolfe Research.

Just a follow-up on the volume assumptions in the guidance. So the bottom end ties to 30% shut-ins through the rest of the year in the Permian, it sounds pretty conservative. What does it assume for other basins? And then what is the top end of the guidance range assumed for volumes, just at a high level?

Yes. In terms of the production, we wanted to give you some clarity around that downside scenario related to our most impactful basin, which to us is the Permian because then it moves through Grand Prix and fractionation and export. The other basins are, to some extent, tied in, but not as much. So we did pull the operational guidance for this year and don't want to get too specific on kind of each system, what we assumed for those. I'd say the most impactful one is Permian. And we wanted to give you a sense that it's a conservative range there. I'd just say directionally, it was a higher percentage in the Badlands, and it was a lower percentage in our other regions as the others are more gassy-weighted. So just kind of directionally for those other areas.

Okay. And the top end, can you comment at all, just Permian what you guys were planning?

Yes. So I mean we looked at shut-in cases. We looked at others where there was less. I think on the top end, we said it at the low end of our previous guidance range and said, let's look at a number of different volume cases, price cases, when things come back. So it's not a one street case, which was the low side, the mid and the high. It was a range of cases and we feel like in a number of those scenarios, they're going to shake out in that $1.4 billion to $1.625 billion. So to get up to the mid or higher, it would be less shut-ins percentage for less duration and doing well on optimization and cost savings and other items. So -- but it's not a discrete case tied to the high end, yes.

Okay. Follow-up question, just with any revised thoughts on what the company's leverage target would be? And how much of the priority it is to get there, I guess, quickly? I mean, it doesn't seem like the rating agencies are reacting very much to the sector as a whole with the downturn. So just how much of a priority is it if the rating agencies aren't really pressuring you? And just on capital allocation, would you expect looking forward beyond this year to be allocating most of the free cash flow to paying down debt on the balance sheet?

This is Jen. I think that for the last year-plus, we've talked very consistently about how reducing our overall leverage was the priority for us, the Paramount priority. And as we look forward and look at our profile of generating growing free cash flow as we move through time, it would be available for the repayment of debt just as a result of the dividend reduction plus lower capital spending. That means that we'll have a lot more flexibility than we would have previously prior to the dividend reduction to reduce our leverage more quickly. So I think that we feel very well positioned from that perspective. I think for anybody that's lived through the last couple of months, having lower leverage clearly would feel better than being in position of higher leverage. And so we've talked about 4x on a consolidated debt-to-EBITDA basis, being sort of a target for ours, but that it was going to take us some time to get there and that we're willing to be patient to get there. I think we have that same patience to get there. But again, the dividend reduction potentially allows us to get there more quickly. Now does 4x consolidated end-up being the right leverage ratio to target or is it lower than that? I think that remains to be seen a little bit, but it potentially could be lower than 4x. As you can imagine, after we reduced the dividend, we had calls with the rating agencies. And I think those were very constructive conversations, I think that they are appreciative of the steps that we have taken to shore up our balance sheet and to make sure that we have financial flexibility. So certainly, it doesn't feel like that's a catalyst that's pushing us to make different decisions than we otherwise might want to, but again, as we've consistently said for the last year, ideally, we would like for our business to grow into being an investment-grade business because that, again, enhances flexibility that we would have in difficult markets. And so that remains a priority, too.

I'm not showing any further questions. So I'll now turn the call back over to Sanjay for closing remarks.

Great. Thank you. We thank everyone for being on the call this morning and appreciate your interest in Targa Resources. We will be available for any follow-up questions over the course of the day. Thank you, and have a great day.

Ladies and gentlemen, this does conclude the program. You may now disconnect.