Good day, ladies and gentlemen, and welcome to date Targa Resources Corporation Third Quarter 2018 Earnings Webcast and Presentation. [Operator Instructions]. It is now my pleasure to turn the conference over to your host Sanjay Lad, Director of Investor Relations. Please proceed.

Thank you, Haley. Good morning, and welcome to the Third Quarter 2018 Earnings Conference Call for Targa Resources Corp. The third quarter earnings release for Targa Resources Corp., Targa, TRC or the company along with the third 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. Any statements made during this call that might include the company's expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provisions of the Securities Act of 1933 and 1934. Please note that actual results could differ materially from those projected in any forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our recent SEC filings, including the company's annual report on Form 10-K for the year ended December 31, 2017, and subsequently filed reports with the SEC. Our speakers for the call today will be Joe Perkins, Chief Executive Officer; Matt Meloy, President; and Jennifer Kneale, Chief Financial Officer. We'll also have the following senior management team members available for the Q&A session: Pat McDonie, President, Gathering and Processing; Scott Pryor, President, Logistics and Marketing; and Bobby Muraro, Chief Commercial Officer. Joe Bob will begin today's call with a few highlights, followed by Matt, who will provide an update on commercial developments and business outlook, and then Jen will discuss third quarter 2018 results and wrap it up before we take your questions. And with that, I will now turn the call over to Joe Bob.

Thanks, Sanjay. Good morning, and thank you to everyone for joining. For the third quarter, Targa achieved its best operational and financial quarter in our history, positioning us to exceed the top end of our previously disclosed full year 2018 financial guidance and more importantly, providing positive momentum for 2019 and beyond. It's been a busy couple of months at Targa since our last call. During that short time, we successfully brought online our 200 million cubic per day Johnson Plant in the Midland Basin. The Johnson Plant was highly utilized at Targa. We continue to start off activities that are crude and condensate splitter at Channelview. We are now start-up. We closed $116 million asset sale of some of our petroleum logistics business. We raised about $200 million from the issuance of common equity under our ATM program, and we recently began strata of our 150 million cubic feet per day Hickory Hills Plant in the SouthOK system. Our major projects underway remain on track and many of these projects will be completed by the end of the first half of next year, which is now less than eight months away. We are working to complete all of our projects as quickly as practicable to help meet the increasing gas processing, NGL pipeline takeaway, fractionation and export services needs of our customers. Fundamentally, the robust near- and longer-term outlook for domestic production volumes from our basins and the outlook for crude and NGL commodity prices are providing continued tailwinds for our business and are leading to the high utilization of Targa projects we recently completed and those underway. Those same tailwinds are expected to continue to drive the need for additional Targa infrastructure. And on that note, today, I'm sure you noticed that we announced we are moving forward…

Thanks, Joe Bob, and good morning, everyone. Commercial activity and production in many of our operating regions is continuing to increase, and we expect this positive trend to continue. In the Permian and Midland, our Johnson Plant came online late September and was quickly highly utilized with 750 million cubic feet per day Plant remains on track to begin operations in the first quarter of 2019 and is also expected to be highly utilized at strata. The next 250 million cubic feet per day Plant is expected to be completed in the second quarter of 2019. With continued strong production growth outlook in the Permian and Midland, we have been proactively ordering long lead items for the next plant. Each of these plants will be interconnected to our multi-plant multisystem Permian footprint with the majority of the NGL volumes flowing through Grand Prix and to our fractionators in Mont Belvieu. In the Permian and Delaware, producer activity remains robust with inlet volumes increasing 13% over the second quarter, construction continues on our 220 mile high-pressure rich gas system, which will run through the heart of the Delaware Basin. A significant portion of this pipeline will be complete by the end of this year with the remainder being completed in phases throughout 2019. In the Badlands, our little Missouri complex is operating at capacity and our LM4 plant is expected online in the second quarter of 2019, as the timing of critical equipment availability pushed on site into the winter months. Gas gathering and processing, include gathering are expected to remain strong in the current commodity price environments. Turning to the Downstream Business, construction on our Grand Prix NGL pipeline continues and the project remained on time and on budget with the pipeline expected to be fully operational in the second…

Thanks, Matt. Good morning, everyone. Targa has reported record quarterly adjusted EBITDA for the third quarter of $358 million, which was 29% higher than the same period in 2017, driven by continued strong gathering and processing volume growth, higher commodity prices and higher downstream fractionation and LPG export volumes. Sequentially, adjusted EBITDA for the third quarter increased 10%. We received the annual $43 million payment related to our crude and condensate splitter agreement in late September, increasing distributable cash flow for the third quarter to $287 million, resulting in dividend coverage of 1.24x. Without recognition of receipt of this payment, which has previously been paid and recognized in the fourth quarter, dividend coverage for the third quarter would have been 1.05x. The sequential increase in operating expenses was attributable to system expansions we have underway and the staffing of our new facilities. In our Gathering and Processing segment, operating margin increased $13 million in the third quarter when compared to the second quarter, driven by higher natural gas inlet volumes in the Permian, Badlands, SouthOK, WestOK and Coastal regions and higher crude oil gathered volumes in both the Badlands and Permian. Third quarter Permian inlet volumes increased 6% over the second quarter from growth in each of our Permian Midland and Permian Delaware systems. Badlands' natural gas volumes increased 5% over the second quarter with our little Missouri facility is operating at full capacity. Inlet volumes in SouthOK increased 3% over the second quarter as a result of continued growth in the Arkoma and SCOOP regions. WestOK inlet volumes increased 2% from increasing volumes from the STACK. During the third quarter, South Texas inlet volumes decreased 12% as a result of flooding from a high-level of rainfall. Volumes have since return to levels prior to the flooding. Our third quarter…

[Operator Instructions]. Our first question comes from Shneur Gershuni of UBS.

With all the great information that you put out today, I kind of hate to start with such a technical question. But when I look at your guidance for 2020 and 2021, as I believe you said in the prepared remarks, this doesn't assume they out of the JV. So if we were to compare it to your original DevCo original guidance of to DevCo, this on an apples-to-apples basis, the number would actually be higher than where it is today. Who knows $100 million-or-so, but is that sort of the correct way to look at it if you sort of look at it compared to how it was before you let everything out with the DevCo?

That is exactly right. So if you think about the DevCo interest, obviously and some of the JV partially in the sales that we've done, or JVs of assets, those were not factored in previously. And so obviously on an apples-to-apples basis, this outlook would be higher if we assume that we haven't done any of those joint ventures or also we haven't executed any asset sales, obviously.

Thanks for the clarification. Just two quick questions here. Given our environment is today, specifically on the fracs, but in other areas as well. As you FID new assets and are added to the backlog, how have contract discussions gone? Are you getting longer terms in the higher fees? Are you sort of able to translate this market into better terms and ultimately higher returns overall?

Yes. Good question. We are getting obviously a lot of incoming with regards to fractionation related services for our downstream assets, and we are more focused on long-term. But fractionation deals that we have currently are typically longer-term by nature, 10 years or longer for some. For Grand Prix, there are long-term contracts as well. So we are working with our customers that may have short-term needs, made our longer-term needs and trying to work with them to provide the fractionation or transportation services, but do that for a longer period of time. Not just shorter time.

That makes sense. And just one last follow-up. Several of your peers during earnings season have talked about, you've able to turn screws to eat out some more capacity out of frac, work around on the NGL lines. I assume you're doing the same as evidenced by your LPG announcement today. Do you see any additional Brownfield opportunities in your fries or elsewhere you can achieve those very high returns that are better than your typical 5 to 7 average?

Yes. So we're always looking at our assets to see how we can potentially increase capacity. We are utilizing our Lake Charles frac even more, a wide range over there to frac. But we've also done just a minor in turnarounds or additional work our Mont Belvieu facility as well. We did a small in the summer way to get done a little while able to increase reliability and run time. So we have some other things like that on the drawing board, which we may be able to do as well. Those are relatively small incremental fractionation capacity, but with how tight the market is, we are turning over all the rock to see where we find any additional capacity.

We refer to some of those project in the previous call, and we didn't talk about the multiple, I think we would go so far as to say almost infinite returns.

Yes. Not much capital, bring the frac down for the

Our next question comes from Colton Bean of Tudor Pickering Holt.

Looks like 2019 EBITDA should been somewhere in the range of 15 to 17, can you just provide a bit more color as to what would one end of the range versus the other?

I mean, I think from our perspective, we spent a lot of 2018 talking about tightness in various places around the country that could potentially impact part of the business. So it is being about Permian constraints and issues that can potentially slowdown producer activity. That could be one. Obviously, commodity prices are big variables, if you think about some of the higher commodity prices that we experienced in Q3 to the extent that we enjoyed similar appreciation of prices throughout 2019. Obviously, that will trend towards the higher end of guidance and then obviously just activity levels around our system and our assets.

Okay. Makes sense. Then Matt may be just circling back to the comments on Galena Park. Do you anticipate the 10 million barrels a month capacity has been sufficient to handle the volumes coming out of the fracs? And just looking at the expansion there, it was 320,000 barrels a day frac capacity if C3, C4 is kind of give or take 40% of that, it seems like you can nearly fill the expanded capacity, just with the fractionators?

Yes. I'll actually turn it over to Scott to kind of give a little more color on that.

Yes. I think the way you guys should look at it from a perspective, the announcement of ordering long lead items for increased refrigeration capacity at Galena Park is in line with a number of other projects that we've already announced. One of which was a pipeline from Mont Belvieu down to Galena Park as well as a refurbishment of our dock at Galena Park, which was one of our older docs. The pipeline should be online in the first quarter of 2019. The refurbishment of the docs to be online mid-2019. That basically debottlenecks a lot of our capacity on behind the refrigeration unit to open up opportunities for increased moments of butanes, specifically but also enhances our ability for propane. Those types of projects and then moving forward with further refrigeration that would be adjacent to our existing footprint gives us significant refrigeration capacity. And nominally speaking, we are saying that gives us an increase of about 50%. We're spending dollars that moderate dollars in 2018, 2019 and 2020 in order to reach those types of capacities. But again to Matt's points in our script was that depending upon what types of products we are loading, whether it's butanes, propanes or loading both as well as the types of ships that we are learning, we see that we've got sufficient capacity based upon what we're seeing today. Now we will continuously look for opportunities to expand, add additional refrigeration if necessary over and above what we have announced today in order to handle those. The one thing that we get with our facility is and the reason why it's always depending upon the types of products we are loading is we can simultaneously refrigerate through our existing footprint and an expanding footprint both propanes and butanes at the same time. So you can see the reason why there is a varying degree of how much volume you put across the doc relative to those types of variables.

Got it. That's helpful. And then, Jen, I guess, the final question...

Two quick adds. One, in case lost in our script, the capital, Scott referred to as moderate highly leverages our existing investment already in place and is in the forecast for 2018, 2019 and 2020 outlook. So the numbers are already in there making it kind of lonely moderate in my opinion. And secondly, there is a great deal of leverage by having the other infrastructure already in place and making incremental investments to expand our capacity. We had a really good about that, and it's power of the asset investment we've already made.

Yes. That's helpful. And then, Jen, just any clarify on the Badlands or the potential Badlands minority sale? Is that G&P, G&P plus crude? Or are you guys looking at that?

Yes. We're looking at it as a partial minority interest sale Badlands LLC entity, which is the entity that owns all of both the crude and the natural gas gathering and processing assets up in the North Dakota.

Our next question comes from Jeremy Tonet [ph] of JPMorgan.

I just have one question on the guidance assumptions. So looking at the Slide 9, can you provide some more color on the timing assumptions behind the incremental processing plants here? And also are there any other growth opportunities within these assumptions? And just as a follow-up to that, given the lot of processing expansions being added to the backlog, do you see any potential for pulling forward that Grand Prix mainline expansion ahead of 2021 at this point?

I guess, I'll start Jen and then maybe you can go from there. So the underlying assumptions and then some of the upsides, we have our base volumes going through gathering and processing down Grand Prix in the fractionation, but will drive this higher if we get incremental deals with third-party, customers, producers, midstream companies. So this continued commercial success is something that could potentially drive those higher and could lead even more volumes on Grand Prix and into our fractionation facilities. We did talk about putting the lead times for the which would expand the capacity from the initial about 300,000 up to about 400,000 barrels. So that would be needed in this forecast.

In 2021, you said as early as 2020.

Yes. Just to be clear, I said, we could have early as 2020. And in this forecast, we would need within that time period of 2021. We didn't give exact timing of when those three other plants that we mentioned on the processing side would be coming online, and you can think of it is kind of ratably after the announced plans come on kind of through that period. It is a reasonable estimate.

And the other fraction we did mention we did say 2021.

Yes. And Train 9, I assume, that 2021. That's right.

Yes. That will contribute to EBITDA and forecast to 2021. We haven't described the timing of when the additional 3 Permian plans will come online, but obviously if you're modeling our expected growth out of the Permian should hopefully be fairly easy to predict when we need additional processing.

The way you asked the question, I also want to emphasize that there is no unknown, unidentified wage built into that, invest the additional upside, some of which are mentioned in the column to the right of Page 9.

That's really helpful color. Just a follow-up on those assumptions here. How are you guys looking at the volume guidance in Permian, like processing, - just the Permian volume guidance assumptions behind this, like until 2021? Is it going to be like 20% or sub like any color you can provide there?

Yes. We haven't given the detailed guidance for '19 yet. We anticipate giving you more full summary view of how we see '19 shaking out the next quarter's earning call in February. So we'll probably provide some more blender information regarding '19. We wanted to give the early look for '19, but there are significant growth assumed in the Permian for this forecast, but we'll give you a little more detail in February.

Our next question comes from Spiro Dounis of Crédit Suisse.

Just wanted to start off with funding all this growth and getting to that cash flow inflection that's coming. You guys appear to have a high visibility here just on the EBITDA itself given the nature of these products. Just curious to make sense to run maybe at higher leverage, know you talked about multifaceted approach, but could we see a little bit more going forward?

Spiro, this is Jen. I think certainly when we think about 2019, 2020 and beyond, obviously in the visibility that we have to ramp EBITDA gives us a lot more flexibility and one that gives us more leverage capacity as it is, but also I think would potentially give us additional comfort in letting leading leverage on a little bit higher for the quarter or quarters if we want to do. So we think about historically we funded call it 50%, 50% debt and equity, I think obviously we talked about 2018, we felt like we had a little bit more flexibility to potentially issue less equity than 50%. And going forward, I think, we have that same flexibility to go lower than that if we want, but obviously are always focused on prudently manage the balance sheet.

Okay. And then just on LPG exports, you're obviously talking pretty positively about the outlook going forward we heard that from others as well. Just wonder if color on that market trying to give a sense of sentiment of the buyer side? And how much of that rate is really still arbitrage, driven or just may be more sticky type demand from things like eating and cooking?

It's a number of things obviously that would add into that. We look at it from a couple of different angles. One of which, when you think about just look at from a domestic fundamental growth perspective. The growth that we're seeing on the upstream side, our gathering system, our gas processing plants, our long haul pipeline, the expansion that we see at our fractionation footprint and all this increase production that we're going to see domestically, while not seeing increased demand domestically for propanes and butanes means it has to find its way to the water. Because of our integrated footprint that allows us to make sure that, that doesn't have to jump off of our footprint in order to find whether the market place is. We have all the way down to the water's edge. As a result of that, that increase production will move that direction. So we're in a great position from that perspective. On the demand side, we're continuing to see growth obviously predominantly in the Far East. We've mentioned it before in other calls, if you think about the demand opportunities in Africa and India and certainly the continued growth that we're seeing in China and other areas in the Far East, those types of demand pools will obviously complement the increase production that we have through domestically within the U.S. And the U.S. is the only one that is growing with the needed supply to feed that marketplace. So it's a little bit of a supply push and a demand pull to a certain degree. And the marketplaces are becoming more and more accustomed to origination of supply out of the U.S. So it's both - it's domestic demand, its other fees to market basis, it's PDH demand. There's a lot of things that feed that, and obviously availability supply helps that growth from demand side, grow from there.

Our next question comes from TJ Schultz of RBC Capital Markets.

Just first on your currently operated fracs, Matt, I think you mentioned the 10-year agreements. And I think you hit the end of the some of the current 10-year agreements through your 2021 outlook. But just how much of the contracted base agreements are expiring through that outlook? And what's expected in dealing with those as far as renewal expectations or trying to quantify the potential upside to raise just given the

Yes. We have a portfolio of agreements, both T&F and Really in the short term, we provided this a few years ago and we said, we have a long-term contracts and there is really not that much of rolling coming up for renewal in the next 12, 24 months. So there is not a lot of contract that's going to able to come up to extend on the fractionation side. But with Train 6 coming on with 7 and 8, we do have obviously more capacity coming on. So we'll able to continue to execute longer-term agreements to satisfy that demand.

Okay. And then if we just think about the NGL volume growth for transport and frac beyond - if we think about beyond payments coming online and third parties, is some of the existing transport commitments or other contractual invitations start to roll off by 2021? Or if you could just provide any context to when some of that occurs?

So we have on the transportation side, we have a makes some volumes that we're going to be able to move off other pipes kind of Day 1 when Grand Prix comes on, some are shorter term, some made and some are very long term. So it's going to be - there is some that kind of moving over that we're going to get the benefit of that transportation in this time frame, but it is a portfolio that. So it's going to be moving overtime more and more to Grand Prix.

In reality, most of our new stuff, the vast most of our new stuff should be assumed as going on to Grand Prix.

Our next question comes from Dennis Coleman of Bank of America Merrill Lynch.

Just a lot of focus here on liquids, obviously and that's the opportunity, but I wonder if you might talk about, as you bring all this processing capacity on, obviously that's a lot of gas that needs to get the market as well. Is there capacity locked up for that gas? Or anything you can talk about there? I know you have the GCX interest, but anything additional opportunities there?

I'm going to turn it over to Pat to answer that one.

Yes. We did participate in GCX and obviously everybody in the world is talking about the Permian residue gas takeaway situation. GCX comes along in October of next year, as we also announced that too far in the distant past, we are working on the project Wister pipeline, which would move an additional to BCF day out of the Permian. We are very active. We have a lot of contracts and markets to take away our gas and make sure that our customer's gas. Our customers also have contracts to get it through those short period of potential interruptions across the Permian. If you think about it throughout the winter time, you got a lot of consumption of gas both well sites and obviously consumption of gas from the general population out there. It helps alleviate some of that problem. April through October of next year prior to DCX coming online, it's going to be an interesting time frame. We like we position ourselves to make sure. But everyone moves, there will be issues in the Permian and less America that haven't seen yet, and we will continue to work on Wister and that project forward and obviously that's hopefully the next solution for continued growth over there coming years of residue gas in the Permian.

Dennis, your question about how much is firm has a multiyear component, has a short term. In the short term, we have the vast, vast majority of our of what we characterized the spot. We have to have a little bit of flexibility, because there is variability in producer supply across days and across weeks. But we are managed that for a long time and we're far more than we have ever been and have flexibility with gas daily type stuff to manage always unexpected variations in producer volumes. So we're in a good position. We think our customers are in a better position with Targa than with most other players in the Permian, for example.

Great. That's very helpful. My follow-up, if I can, just a question on cost of capital. Obviously, you've talked about using a variety of funding method, the DevCo you used this year. I wonder is that still part of the arsenal? Is the Badlands potential sale? Would it have any kind of potential buy back? Is it similar? Or is it right sale? And then lastly, it does look like you assume a fairly high interest expense as you go across your renewed or updated budget. I just wonder as the S&P leading on positive, is there a thought that you will more towards investment grade and that while it's not a EBITDA impact it should could be a DCF impact of that interest expense ended up being lower?

So it's a quite a follow-up question, Dennis. I think that from our perspective, obviously we entered 2018 describing a multifaceted approach to financing. And frankly spend a lot of time in 2018 end of 2017 describing what that could mean in terms of public capital, common and preferred or private capital or potential asset sales. And then obviously go through 2018, really utilizing a number of those different tools that were in our toolbox. So as we look forward to '19 and beyond, obviously the increasing EBITDA, I think, is partially what will be very advantageous to us as we think about how to finance this growth program. We also announced the partial interest sale in the Badlands. Obviously, that would potentially help from a financing perspective. Related to the DevCo, that was a very nice structure that we did and we got four years of flexibility to buy back those JV interest, which I think is a very favorable structure to us. I think that if I had to rank where that is on the list right now, we'll probably a little bit further down just because we've already done it. And so when we think about our outlook and our increasing EBITDA, I'm not sure that would be #1 on my list in terms of what we may do next. Obviously, we're announcing today that given we're evaluating a minority interest sale in the Badlands, that's potentially first on my list here. And then related to your follow-up question part about the interest expense that we assume just in EBITDA or reconciliation the backhaul presentation, obviously rates are going higher, LIBOR is higher. So we're just taking a conservative approach to those assumptions there. I think we're very pleased with the S&P upgrade and motive positive outlook as well. try to spend a lot of time with the rating agencies over the last couple of years to make sure that they understand the story that's unfolding here, and I think we've done a good job of working together with them and so ultimately we'll see where the path takes us, but obviously the outlook that we have put in front of you last June and then now refreshed year stronger in November of 2018 highlights the fact that we're going to have a very flexible balance sheet going forward. And obviously that could mean that in the future investment grade is a step that we take, but it's obviously one that we want to take when the company is good and ready. And I think it will frankly, be much more a factor related to our results, getting us there more so than anything else.

Our next question comes from Tristan Richardson of SunTrust.

Just circling back to the announcing LPG export capabilities with the refrigeration and the regional line Mont Belvieu. Is there a feeling to think about in terms of export capabilities before more significant capital deployment would be required?

In our outlook, we're really expanding in phases, right. And Scott talked about we're putting in the end each line between Belvieu and Galena Park and we are going to add refrigeration. We're doing some doc work. I don't know that we have done engineer this thing to say what the ceiling is. I mean, we can keep wondering to incrementally remove bottleneck. So we see this type of adding refrigeration gives us good run rate 200 additional liquids coming off of fractionation. If we need to do more, we can continue to expand those bottlenecks.

That's helpful. And then should we think about the enhancement underwritten by customers or more just general optimization to accommodate the supply push?

It's both. When you got a facility as large as you have a role of contracts that are coming up and we are entering into a new one. So it's hard to necessarily poise this contract with the expansion of the business and how things are running. We're continuing to add contracts. We're working to add more than add more term. So we're not fully contracted, but given the volumes that we see coming across our facilities and the outlook and discussions we're having for additional contracts, we feel really good about the returns about this expansion. We didn't really talk about the capital, but it's probably around $100 million, $125 million of total capital for this refrigeration. So we're going to see good returns depending upon how you think about the time line for going forward.

Our next question comes from Keith Stanley of Wolfe Research.

Sorry, if I missed this. But is the 2021 outlook include or exclude the Whistler pipeline?

The 2021 outlook does not include the pipeline.

Okay. And just a follow-up on that pipeline. With moving forward on 2 pipes now, are you seeing less urgency from customers to kind of act and commit now to Whistler? Or is that still being actively developed?

The answer is no. We're not seeing less interest, and it is being actively develop.

And our last question for today is from Sunil Sibal of Seaport Global Securities.

Couple of questions for me in the marketing and logistics segment, quarter three seems like you had a pretty strong quarter and typically you've seen a fair bit of a seasonal uptick in that segment going into the winter months. I was wondering how should we kind of think about that in the next couple of quarters considering what you reported today.

Good question. We do have some seasonality in our wholesale business, which has led to typically stronger Q4 and Q1 relative to 2 and 3. So we still have some seasonal factors in there. What we saw in Q3 though was just really strong volume across both our fractionation facilities and our export doc, and we did have some short-term opportunities in the fractionation business, which helped us as well. And it's tougher to say what that's going to look like in Q4, but we still do have some of the same seasonal factors, wholesale business and then we will just have to see how Q4 shakes out. We would certainly expect volumes across the fractionation across exports to continue to be strong, and this is really shorter-term and opportunities play out in Q4.

Okay. And then in terms of the longer-term guidance that you laid out, couple of clarifications on that. What's sort of commodity price assumptions underlying that?

There's a footnote on the page assumes $50 per barrel of crude WTI, $2.75 per MMBtu and natural gas and $0.70 per gallon for NGLs.

Got it. And then just lastly in terms of the leverage metrics, where do you see exiting 2021 in terms of the leverage with all the guidance that you laid out?

I think from our perspective, when you think about this outlook and think about our goal of having consolidated leverage in the 3 to 4x range, we are not going to give additional guidance or clarification on exactly what we expect sort of point in time leverage to be at the end of this forecast. But this is a very strong forecast with a lot of additional free cash flow beginning in '19 and '20 and then 2021. So I think from our perspective, when you think about us delivering there is on term outlook that we have no refreshed again this morning, it would mean that our balance sheet is in very, very good shape at the end of this outlook.

Thank you. Ladies and gentlemen, this concludes today's question-and-answer session. I would like to turn the call back over to Sanjay Lad for any closing remarks.

Great. Thanks everyone that was on the call this morning, and we appreciate your interest in Targa Resources. Jen and I will be available for any follow-up questions you may have. Thanks, and have a great day.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program and you may all disconnect. Everyone have a great day.