Targa Resources Corp. (TRGP) Q2 2017 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Targa Resources Corporation Second Quarter 2017 Earnings Webcast and Presentation. [Operator Instructions] I would now like to introduce your host for today’s presentation, Mr. Sanjay Lad. Sir, please begin.

Great. Thank you, Howard. Good morning, and welcome to the second quarter 2017 earnings call for Targa Resources Corp. The second quarter earnings release for Targa Resources Corp, Targa, TRC or the company is available on the investor section of our website at www.targaresources.com. We also posted the new quarterly earnings supplement presentation to our website, that provides perspectives on our longer-term outlook and additional detail related to the second quarter and sequential results. As always, we welcome your feedback on whether this additional information is helpful. 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 Acts of 1933 and 1934. Please note that actual results can 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, 2016, and subsequently filed quarterly reports on Form 10-Q. Our speakers for the call today will be Joe Bob Perkins, Chief Executive Officer; Matt Meloy, Chief Financial Officer; Patrick McDonie, Executive Vice President of Southern Field Gathering and Processing; and Scott Pryor, Executive Vice President of Logistics and Marketing, our Downstream segment. Other members of senior management will be available during the Q&A portion of the call. Joe Bob will begin today’s call and then turn it over to Matt to discuss second quarter results, and then Pat and Scott will discuss their respective business segments. After closing remarks from Joe Bob, we’ll then open up the call for questions. With that, I’ll now turn the call over to Mr. Joe Bob

Thanks, Sanjay. Good morning, and thanks to everyone for joining. I’m going to start with an update on Targa’s strategic initiatives underway -- initiatives underway which are positioning us for longer-term EBITDA growth. It was another busy quarter for Targa employees, with our day-to-day business activities augmented by progress on a number of impactful initiatives. For example, we continued the integration of our Permian assets acquired on March 1 and had the first full quarter of operating and improving those assets. We brought on growing volumes across our strong Midland and Delaware Basin positioning. Our 200 million cubic feet per day Raptor plant in South Texas came online. We made an acquisition of Boardwalk Pipeline Partners’ Flag City assets and contracts in South Texas, and then immediately integrated those volumes into our existing facilities. We continued progress on adding 710 million cubic feet per day of processing capacity in the Permian Basin, which will bring us to a total of approximately 2.5 billion cubic feet per day of gross processing capacity across the basin by next year. And Targa announced our Grand Prix pipeline, a $1.3 billion, 300,000 barrel per day on initial capacity, common carrier NGL pipeline from the Permian Basin to Mont Belvieu. Let’s discuss Grand Prix in a little more detail. Grant Prix will connect our strong and growing franchise Permian Basin footprint to our downstream assets at Mont Belvieu. Our processing footprint translates into Targa moving significant daily volumes of NGLs out of the Permian with good visibility on substantial growth in the future. For Targa, Grand Prix enhances our positioning by bolstering our premier midstream gathering and processing position in the Permian Basin with a secure and reliable takeaway solution connected to our premier downstream footprint, by enhancing a highly competitive, fully integrated service offering to our current and future customers, and leveraging each piece of the Targa value chain. And Grand Prix enhances our positioning by providing significant and increasingly fee-based earnings over the longer term, increasingly paying ourselves for NGL transport instead of renting it from others and helping to direct incremental volumes to our downstream facilities. Grand Prix is expected to be operational in the second quarter of 2019 and we will begin to move significant NGL volumes to Grand Prix on day one. NGL volumes from additional Targa processing plants in progress or those needed in the future will flow to Grand Prix, which will provide significant margin expansion and fee-based growth looking forward. We’ll also move volumes to Grand Prix over time as our existing third party NGL obligations expire, providing visibility on growth into the future. We announced and are proceeding with a stand-alone project because we have visibility on the volumes on Grand Prix that will provide us with an attractive return and significant strategic value. And because we often get the question, we will repeat what we have stated publicly before, which is that our Permian Basin position and the aggregated NGL volumes associated with it are very attractive to our stand-alone project and to potential partnering opportunities. Of course, we remain open to potential partner opportunities that would enhance our economics on the project while retaining the strategic benefits. On our first quarter conference call we announced that we were moving forward with construction of an incremental 450 million cubic feet per day of processing capacity in the Permian Basin. That newly announced capacity is from the Johnson and Wildcat plants, one in the Midland Basin and one in the Delaware Basin, and they are in addition to the 260 million cubic feet per day of new plant capacity that was already well underway before we announced them. By the third quarter of 2018, we will have approximately 2.5 billion cubic feet per day of gross processing capacity in the Permian Basin, positioning us to continue to capture producer volumes on our dedicated acreage and to successfully compete for additional opportunities. Including the spending associated with Grand Prix, approximately 80% of Targa’s current capital spending is related to the Permian, highlighting that Targa’s attractive investment opportunities are being primary driven by volumes from arguably the most prolific basin in the world. We believe that the combination of our legacy Permian systems, combined with new plants, our newly acquired assets in the Delaware and Midland Basin and a Permian NGL takeaway solution in the form of Grand Prix is a platform for sustainable, long term Targa growth. In late June we published an investor presentation outlining some of Targa’s longer term financial expectations. The purpose of providing more of a long term view, a long term outlook, of our expectations was to highlight that we believe we have strong visibility into significant EBITDA growth between now and 2021 even if we are in an environment with crude, NGL and natural gas prices around today’s levels. We estimated in that outlook that adjusted EBITDA will increase from our approximately $1.13 billion in 2017 to approximately $1.5 billion in 2019 and approximately $2 billion in 2021. We also believe that there is more upside than downside to our longer-term financial outlook. Because, for example, we only included LPG export volumes that are already contracted, and we only included estimated volumes available from acreage already dedicated to Targa using recent historical type curves and recovery assumptions without continued improvements in completion performance. Of course, despite those outlook assumptions, our commercial teams in both the Gathering and Processing segment and the Downstream segment continue to work on a number of very interesting and attractive contracts and projects, and we certainly expect that others will be identified over the forecast period, none of which are included in our expectations. With that, I will now turn the call over to Matt to discuss Targa’s results for the second quarter.

Thanks, Joe Bob. Targa’s reported adjusted EBITDA for the second quarter was $258 million, which is comparable to the same period in 2016. Continued strong volume growth in Permian G&P, higher commodity prices and higher fractionation volumes were offset by lower volumes in our other G&P regions and lower margins in our Downstream Business. Reported net maintenance CapEx were $23 million in the second quarter of 2017, compared to $19 million in the second quarter of 2016. We continue to estimate approximately $110 million of net maintenance CapEx for 2017. Distributable cash flow for the second quarter was approximately $196 million, resulting in dividend coverage of approximately 0.9x. Given some seasonality in our Downstream businesses, we expect the second quarter to be the weakest quarter of the year and expect our operating margin to ramp up in the second half of the year. For full year 2017, as Joe Bob mentioned, we continue to expect adjusted EBITDA to be approximately $1.13 billion and full year 2017 dividend coverage to be between 0.95 and 1.0x. Also, I would like to point out that during the second quarter we benefited from a cash tax addback to distributable cash flow of approximately $31 million that includes an adjustment reflecting the benefit from a net operating loss carryback to 2014 and ‘15. Previously, we expected to collect the remaining refund on or before the fourth quarter of this year, but received the entirety of the remaining refund during the second quarter and recognized it in DCF. Turning to our segment-level results for our Gathering and Processing segment, reported operating margin for the second quarter of 2017 increased by 25% compared to last year, primarily due to higher commodity prices and higher inlet volumes in the Permian Basin despite lower Field G&P inlet volumes in other areas. Natural gas prices were 65% higher; NGL prices, 28% higher; condensate prices were 13% higher when compared to the second quarter of 2016. Second quarter reported 2017 field natural gas plant inlet volumes were approximately 2% higher when compared to the second quarter of 2016. Permian inlet volumes reported in the second quarter of 2017 were 18% higher when compared to the prior year, with increases in both Permian Midland and Permian Delaware. As a reminder, volumes from our recently acquired Delaware assets are reported as part of Sand Hills and volumes from our recently acquired Midland assets are reported in SAOU. Year-over-year second quarter inlet volume decreases in South Texas, North Texas and WestOK partially offset the overall increase in Field G&P natural gas inlet volumes. You may recall that in the second quarter of 2016 our South Texas volumes increased significantly as we benefited from some interruptible low margin volumes. Now moving to our sequential second quarter 2017 as compared to the first quarter of 2017 results, Permian inlet volumes grew 9.5%, partially driven by a full quarter of volumes from our newly acquired Permian assets and growth in our Permian Midland systems. Inlet volumes in South Texas were sequentially higher as a result of volumes from the acquisition of Boardwalk’s Flag City assets and fee-based contracts and higher volumes from Sanchez on the system as wells that were shut in during the first quarter for nearby well fracking returned to production. Volumes also increased sequentially in SouthOK as we continued to benefit from incremental SCOOP volumes on our system that were more than sufficient to offset legacy production declines. Now let’s discuss our results compared to our previously disclosed volume guidance. First half 2017 Permian inlet volumes, as reported, were 14% higher than 2016 as compared to our expectations of 15% growth. Overall, Field G&P system inlet volumes were flat versus 2016, consistent with our expectations. Looking forward, we expect inlet volume growth in the Permian, South Texas, SouthOK and the Badlands to continue in the second half of 2017, providing us with momentum in 2018. While we are only one month into the quarter, our July inlet volumes for overall Field G&P, driven by the Permian, South Texas, SouthOK and Badlands are all meaningfully higher than our second quarter average Field G&P volumes. For example, our recent volumes were up significantly through July. On an as-reported basis, WestTX volumes were over 600 million cubic feet per day at the end of July versus the second quarter average of 542 million cubic feet per day. Badlands July volumes were approximately 30% higher than the second quarter average, and South Texas volumes at the end of July were approximately -- or were higher by approximately 40%. And SouthOK volumes were also showing a solid uptick. While it is early in the third quarter, the positive volume trends are in line with our second half volume ramp expectations and we remain on track to meet our full year 2017 field and Permian volume expectations provided earlier this year. The trajectory also provides a positive outlook for the beginning of 2018. Now shifting to the Bakken, Badlands crude oil gathered volumes were approximately 113,000 barrels per day for the second quarter, up approximately 7% versus same time period last year. Second quarter natural gas volumes increased 2% when compared to the prior year and, more notably, increased 14% over the first quarter as weather conditions normalized and producer activity around our system continued. As I mentioned earlier, we are already seeing a nice increase in July volumes in the Badlands and we continue to expect that average 2017 natural gas and crude volumes will exceed average 2016. Permian crude gathered in the second quarter were approximately 29,000 barrels per day as we benefited from a full quarter of our recent Permian acquisition. In our Downstream segment, second quarter reported operating margin declined 21% over the comparable period in the prior year, primarily due to lower LPG export margin and lower margin from our domestic marketing and commercial transportation businesses, partially offset by higher fractionation margin. Sequentially, fractionation volumes increased 11% over the first quarter due to increased supply, largely driven by higher volumes from our Permian systems. In our LPG export business, we exported approximately 4.7 million barrels per month of propane and butane and received fees from 2 cancellations at our facility during the quarter. Moving to capital spending, we expect 2017 net growth capital expenditures of approximately $1.4 billion based on announced projects. The $165 million increase in our 2017 estimated capital spend compared to our previous estimate is attributable to a shift in timing of spending for Grand Prix from 2018 to 2017, additional Permian spending in both the Midland and Delaware Basins, and a shift in timing of spend of the Johnson plant some from ‘18 to 2017. Our total expected cost for Grand Prix continues to be approximately $1.3 billion and we currently estimate $330 million of that in 2017 and the majority of the balance of the spending in 2018. Grand Prix is expected to be fully operational in the second quarter of 2019. Our growth capital related to the Permian increased for the year due to additional infrastructure, primarily in the Delaware, as we build out the system for future growth. The additional capital is primarily related to shifting additional infrastructure buildout spending into 2017 from future periods without increasing total expected costs of the projects. Now let’s discuss our capital structure and liquidity. As of June 30 we had no borrowings outstanding under TRP’s $1.6 billion senior secured revolving credit facility, due October 2020. On a debt compliance basis, TRP’s leverage ratio at the end of the second quarter was 3.4x versus a compliance covenant of 5.5x. We also had borrowings of $250 million under our accounts receivable securitization facility. As of June 30, TRC had $435 million in borrowings outstanding under our $670 million senior secured credit facility and availability at quarter-end was approximately $235 million. Including about $99 million in cash, our total available liquidity at the end of the second quarter was approximately $1.9 billion. During the second quarter, we raised approximately $880 million of public equity from a 17 million common share secondary offering and our ATM program. Proceeds from our 17 million share secondary offering in June are expected to fund the equity component of our Grand Prix project in addition to satisfying our remaining equity requirements for our current 2017 net growth CapEx program. We also have expected spending in April 2018 and April 2019 related to the earnout payments associated with our March 1 Permian acquisition. Given the volume ramp on our acquired Permian asset has been slower than expected over the first five months that we have owned the asset, our current expectation is for a modest earnout payment in April 2018. For 2018 and beyond, with longer-term expectations positive relative to our preannouncement forecast, we continue to forecast significant growth on those acquired assets and expect to pay a more sizeable final earnout payment in April 2019. In our corporate hedging program we executed additional hedges during the second quarter. We added some balance of the year 2017 through 2019 natural gas and NGL swaps. Pro forma, as of June 30, 2017, for non-fee-based operating margin, relative to the partnership’s current estimate of equity volumes from our Field G&P segment, for 2017 we estimate we’ve hedged approximately 85% of natural gas, 70% of condensate and 60% of NGL volume. For 2018, we estimate we’ve hedged approximately 60% of natural gas, 50% of condensate and 30% of NGL volumes. I will now turn the call over to Pat, who leads our Southern Field G&P business. Pat?

Thanks, Matt, and good morning, everyone. As Joe Bob mentioned, it was a busy second quarter in the Gathering and Processing segment -- busy in a good way. And as Matt mentioned, if the first month of the third quarter is any indication, that trend will continue for the foreseeable future. We are focused on continuing to add infrastructure around our newly acquired Permian assets, particularly in the Delaware, where those assets have now been integrated into our Sand Hills system and where we are working hard to keep pace with our producers. In addition to adding gathering lines, compression and treating capabilities, we are continuing construction on our 60 million cubic feet per day Oahu gas processing plant, expected online early in the fourth quarter of 2017, and the 250 million cubic feet per day Wildcat gas processing plant, which is now expected online in the second quarter of 2018. We are also connecting our Versado and Sand Hills systems with the new Delaware assets, which we expect to be completed in the fourth quarter. This interconnectivity across the entire Permian Basin will benefit our customers with increased system flexibility, reliability and optionality, supporting our continued efforts to provide best-in-class services to our producer. In the Permian Midland, customer activity around our WestTX, SAOU and newly acquired systems continues. During the second quarter we restarted the 45 million cubic feet per day Benedum plant and completed the 20 million cubic feet per day expansion at the Midkiff plant. While these are relatively small projects, they provided much needed relief to our WestTX system as were able to shift rapidly increasing volumes around, which enabled us to operate the overall system more efficiently while awaiting the next plant. The next plant in West Texas, the much needed 200 million-cubic-feet-per-day Joyce plant, is on track to begin service in the first quarter of 2018, and the 200 million cubic feet per day Johnson plant is expected to begin service shortly thereafter in the third quarter of 2018. Given our expectations and daily realization of volume growth at WestTX, the in service dates of these additional plants are timely, as the remainder of the system will be largely full, with good visibility on continued volume. As noted earlier, we have seen an increase in volume since the second quarter ended, and we expect this trend to remain in place through the balance of the year, resulting in continued volume growth and positive momentum heading into 2018. Importantly, we also believe that with the addition of the Grand Prix NGL pipeline and the resulting ability for us to offer our existing and future customers a fully integrated Targa suite of services, we will be able to incredibly grow our Gathering and Processing business. Our G&P and Downstream commercial teams are working extremely well together to jointly provide producers with creative, efficient and attractive service offerings, and are supported by exceptional engineering and operational teams focused on delivering creative and reliable solutions. The combination of the resource potential of the 2-million-plus acres dedicated to us in the Midland and Delaware Basins with Targa’s integrated assets and our commercial operational and engineering capabilities really positions us well for significant volume growth from our G&P segment, and consequently NGL volume growth on Grand Prix. Moving to our Oklahoma assets, our outlook continues to strengthen as we benefit from continued commercial success and producer activity on our dedicated acreage. Second quarter inlet volumes for SouthOK were approximately 9% higher than the first quarter, and we expect that trend to continue in the second half of 2017 as we finish construction on our line that will bring additional SCOOP volumes to our system. In SouthTX, system inlet volumes sharply increased 30% sequentially over the first quarter from a couple of catalysts. First, our acquisition of Boardwalk’s underutilized 150 million cubic feet per day Flag City plant and associated assets, that include fee based contracts for $60 million; and soon after the acquisition, we shifted producer volumes previously being processed at the Flag City plant to our Silver Oak facilities for processing. We are decommissioning the Flag City plant and expect to move the plant and the other acquired assets for use elsewhere in the Targa G&P business. While this was a relatively small acquisition, it was an opportunity to take advantage of our relatively strong position to rationalize excess capacity in the Eagle Ford and acquire attractive fee-based contracts and additional assets at a low multiple. Second, we also benefited from additional volumes as production resumed from wells that had been shut in for nearby well fracking. Additionally, our new 200 million cubic feet per day Raptor plant began flowing gas in late May and we shifted volumes from our Silver Oak facilities to Raptor. The 60 million cubic feet per day expansion of the Raptor plant is expected to be completed in September and we continue to work closely with our JV partner on additional Eagle Ford opportunities. Overall, in SouthTX, we continue to expect higher 2017 volumes versus the average 2016. To echo what Matt described in his remarks, the first half presented some unexpected pluses and minuses across the Gathering and Processing segment, but our long-term expectations remain on track and extremely positive. For 2017, we expect average Field G&P inlet volumes to be 10% higher than 2016, driven by year-over-year inlet volume growth of 20% in the Permian Basin and higher year-over-year volumes in SouthTX, SouthOK and the Badlands. I will now turn the call over to Scott Pryor, who leads our Downstream Business. Scott?

Thanks, Pat. Our second quarter results in the Downstream segment were consistent with our expectations that seasonality in some business areas would result in quarterly operating margin being the lowest for the year. As we look forward into the second half of 2017 and beyond, I want to reiterate Joe Bob’s statement, that there is upside potential in some of our key Downstream areas. Our sequential increase in fractionation volumes was largely driven by higher field G&P inlet volumes, which we expect to continue, resulting in increasing NGL volumes downstream. Ethane extraction is expected to increase, and over time this will drive higher fractionation volumes for Targa, and needed supply to feed a growing petrochemical demand. By the end of 2017 we expect an increase of 150,000 barrels per day of new ethane demand, driven by new ethylene crackers coming online along the U.S. Gulf Coast and, in 2018, another 300,000 barrels per day of new ethane demand from additional new ethylene crackers coming online. Importantly, the vast majority of announced ethylene cracker expansions and new builds that should be online by 2020 are located along the Gulf Coast. These facilities will not only increase the demand for purity products around our fractionation assets to use as feedstock, but will also draw Y-grade volumes to Mont Belvieu, also benefiting our Downstream Business. We continue to add or expand connections to existing, expanding and new petrochemical crackers, leveraging our premier NGL hub location to increase our access to growing demand. As mentioned earlier, we moved a reduced amount of short-term LPG export volumes in the second quarter and received fees from two vessel cancellations. Global LPG market dynamics for the second quarter were similar to second quarter 2016, when we also experienced lower demand after coming off a period of higher demand in the fourth and first quarters of 2016. We loaded 4.7 million barrels per month of LPGs for the quarter, which was consistent with the assumption made in June when we provided additional financial expectations for 2017 and beyond. As we think about the balance of 2017 and our published outlook for adjusted EBITDA through 2021, let me reiterate that for those published perspectives we will -- we are assuming no short-term LPG exports over the forecasted period. It is my expectation, however, that we will significantly outperform those export assumptions over the outlook period, as the team continues to work very hard globally to add incremental short- and long-term contracts to our portfolio. Looking forward, our outlook for LPG export business is unchanged given our substantial long-term contract position and favorable long-term global fundamentals for U.S. LPG exports, driven by continued global demand growth and the U.S.’s position as the likely supplier to feed that demand growth. Finally, the addition of Grand Prix really is a game-changer for our Downstream Business. Even as one of the largest daily shippers of NGLs out of the Permian Basin, we have historically had to pay third parties to move those volumes on our behalf. Grand Prix removes that leakage, provides fee-based cash flow and fully integrates Targa’s G&P assets with our downstream footprint, which further enhances our competitive capabilities to move volumes from the wellhead through the entire NGL value chain. The volumes that Targa manages at the tailgate of our current and future processing plants are substantial, and we have also secured third party commitments on Grand Prix that will result in incremental volumes on day 1 of operations in the second quarter of 2019. There are tremendous demand growth drivers on the U.S. Gulf Coast from export facilities moving products to global markets and petrochemical crackers which will create additional demand for liquids production upstream of Grand Prix. As the expected volumes flowing through Grand Prix increase over time, we expect significant fee-based cash flow from the asset, which ultimately should drive returns for the project to between 5 to 7x CapEx as a multiple of EBITDA, and potentially lower, depending on continued commercial success and pace of volume growth. Overall, the outlook for Targa’s Downstream Business remains highly robust, driven by the continued integration with our growing G&P business and the flow of NGLs to our strong asset position along the U.S. Gulf Coast. And with that, I’ll turn the call back over to Joe Bob.

Thanks, Scott. While our second quarter financial performance is expected to be the lowest quarter for the current year, we are confident in the continued second half 2017 acceleration in Permian volume growth complemented by increasing supply being directed to our Downstream businesses. We are on track to meet or exceed our full year 2017 operational and financial expectations and, importantly, are very well positioned for the longer term. I hope you made note of the July volumes updated by Matt. They’re providing significant growth from Q2 averages. Those impressive volumes certainly validate our expectations for the second half and how well we feel we are positioned for the longer term. Our longer-term outlook beyond 2017 continues to strengthen as our visibility around volumes and projects supports our expectation for significant margin expansion for our G&P segment in 2018 and beyond, and that is complemented by the addition of the Grand Prix NGL pipeline and by other opportunities in our Downstream Business. Our strong liquidity position and demonstrated access to the capital markets positions us well as we execute on our projects underway. Our commitment to maintaining the strength of our balance sheet to preserve Targa’s financial flexibility remains steadfast, as evidenced by the equity that we raised during the second quarter. Our team at Targa remains focused on continuing to execute on our strategic objectives, and we are excited about Targa’s strong long-term outlook. Thank you for your patience. There’s a lot going on and a lot that we wanted to update you about. So with that, operator, please open the line to questions.

[Operator Instructions] Our first question or comment comes from the line of T.J. Schultz from RBC Capital Markets. Your line is open.

First -- so, Pioneer talked about the higher gas-oil ratios, so more gas, and I appreciate the look at volumes in July. Can you just discuss if this higher GOR is additive to what you had expected with your volume original guidance, and the impact it may have on your pace of projects out there?

Higher GOR, I believe has been mentioned -- in the Permian, has been mentioned in our prior calls. It’s a trend we see really across both the Midland and our presence in the Delaware. And I won’t try to further describe Pioneer’s comments. We work closely with them and are aware of those trends. We are trying primarily to help with the gas and that higher GOR, which was described in their call, has already been worked into our expectations. Now we aren’t exactly precise and sometimes get surprised by upsides on GOR and numbers of wells, but it’s certainly within our outlook tolerance and conservatism.

Okay. Great. Thanks. And then, on Grand Prix, first, just any update or response to third party volumes so far? And then, as you consider JVs, is there an advantage in your mind one way or the other as you look to combine maybe with other midstream or similar projects versus going a different route by bringing in a producer equity partner for more commitment?

On the first part of that, we described the positive response to the announcement, though people in the industry were beginning to suspect that we had that project underway. And yes, we have added commitments since that announcement. We obviously were having those discussions beforehand. It’s now a real project. Secondly, in reference to potential ventures or agreements that would enhance it, there are a number of kinds. You picked on a couple of them. And we are interested in opportunities that improve our economics while retaining the strategic benefits of a Targa line. And if we meet those criteria, you could do either of those two, both of those two or something else. Economics and strategic benefit is what our criteria are.

Got it. Thanks. And just lastly, so Enterprise announced the potential for an ethylene export facility through a JV with Navigator. You all already export ethylene. What are your options or your interest to expand ethylene exports, and are there any limitations as it relates to vessel availability?

I’m going to answer the very last part first and then come back to your first part, T.J. Vessel availability on any export product is sort of a come and go. They can build them pretty quickly. And some of the vessels that used to be used for ethylene are being used for propane. But over a medium time frame, vessels can be added. Relative to our interest, we are the only export facility in the U.S. Gulf Coast right now with our partner CPC -- our very good partner CPC. I might interpret that the announcement by Enterprise was saying they’re interested also, and we’re probably talking to many of the same potential customers. If we were doing a press release, I think that Mark Lashier and I would say that if we had sufficient contractual backing to justify additional investment -- which would be incremental for us, because we already have 1 additional investment -- we would probably go forward with such a project as well. And our teams are working on it.

Our next question or comment comes from the line of Colton Bean from Tudor Pickering Holt.

I just wanted to circle up on the Outrigger contribution this quarter. So it looked like, with both SAOU and Sand Hills, pretty big volume ramp Q-over-Q, more than would be implied just for kind of the full quarter of contribution from Outrigger. So I just wanted to get your thoughts on how volumes are progressing there, and maybe versus your expectations earlier in the year.

Yes. So the volumes from the Delaware assets from the Outrigger acquisition are included in the Sand Hills, which is a large reason why those volumes are ramping. And then similar on the Midland side, those are included in SAOU and those were a significant piece of that growth as well. We said for this year the volume ramp is a bit slower than our original expectations. We’re building out initial infrastructure, getting to wells, and we’re trying to catch up and keep up with our producers. And we’re doing a good job of that, but it has been a bit slower than our original expectations. But the outlook and the discussions we’ve had with producers really is not impacting our 2018 and beyond outlook for activity in and around those assets. So the long-term value that we see remains intact, and growth out there -- we still see strong on both the Midland side and on the Delaware side.

This is Joe Bob. I think it’s a reasonable read through to say the Outrigger -- I said that on the call; I was trying not to. The recent Permian Basin acquisition, while a little bit lower, was already embedded in our previous guidance. Which means everything else is doing a little bit better. And then Matt says that after ‘17 we feel better about the acquisition. That’s all positive relative to our initial discussions at the beginning of the year.

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

Just a couple of questions just, sort of, to follow up on T.J.’s question just with respect to Pioneer and the gassier wells. So just to confirm what your response was, you had already seen that trend and had baked it into your guidance? Because I think that we’re sort of hearing it more from Pioneer for the first time, so that’s why I was trying to understand if there had been a shift there, and then there’s a corresponding positive impact for Targa, or if this has been kind of the expectation the whole time and Pioneer wasn’t really talking about it previously.

No. This call is not the call for providing more detail for my good customer and partner, Pioneer. I did say that GOR across the whole basin was a part of our broad outlook, and we had not provided any specific discussions about the Pioneer volumes. So I don’t really have more detail to add to that other than Pioneer has a terrific performance. And Pat’s showing me he wants to say something else about it.

And what you’ve got to realize is, this trend has been based on these longer laterals and the new frack techniques, and it’s really in the early stages of defining what it is and what it becomes. So when we say we have it baked into our numbers, we have adjusted type curves over time as we’ve seen an increase in GOR. We are always very conservative on the type curves that we utilize to predict volume growth across our system with our producers. And I would tell you that the GOR changes that are being talked about and seen are not baked into our numbers.

We typically use recent historical -- and I think that was even in our script, recent historical type curves, which for the most part get better and better for Targa over time.

Just following up, there’s been some comments on a bunch of different calls throughout the earnings season, both midstream and E&P, about completion crude tightness in the basin. My understanding, this has been going on for three to four months. Is it fair to assume that that has been taken into account into your forecast as well, also?

I think that if you went back to our -- the prior discussions, we’ve said we see limiting factors -- multiple limiting factors across the Permian Basin, relative to some of the more bullish projections. We talked about staffing for drilling rigs, completion rigs, pumping units. We talked about availability of equipment. I think we’ve described that it wasn’t too long ago, you couldn’t even get a high-pressure, long-lateral walking rig in the Permian. They were all done. So we’re trying to use realistic -- hate to use the word conservative, but informed, because we’re there all the time -- estimates about what sort of activity levels we believe will occur, not month by month and quarter by quarter, but over that multi-year outlook that we’re providing. We’re not getting carried with what those activity levels, completion rigs, pumping unit availability, sand constraints, water constraints might do to impact it to the downside, but we’re also definitely not getting carried away on them all being solved at one time.

[indiscernible] Fair enough. Yes. No. Absolutely. And just transitioning to Grand Prix for a second, kind of a two part question -- one, how much space do you expect Targa-associated processing plants will take up on the pipeline, I guess as a market share of the pipe itself once it comes online? And then, secondly, when you’re having discussions with others who might be interested in some JV negotiations, is being an operator a must-have, or are you indifferent to being an operator versus a non-operator owner?

I understand the desire to have more detail than we put in our scripted remarks, and we also described how we were approaching the pipeline when we first announced it. Market share initially of Targa volumes on the pipe is not something we’ve provided. I believe what we’ve said is, you’ve got attractive returns well below the initial capacity of 300,000 barrels per day, and that additional third party volumes and Targa’s continued growth would increase from our -- what we said were significant volumes, day 1, from Targa-managed volumes and new plants. It’s not ready for a while. And then, as terms of factors like operatorship, et cetera, we said that we wanted to retain strategic benefits, and I don’t really want to describe the elements underneath those strategic benefits. Just kind of broadly summed up of, own it instead of rent it, and then be able to put it into the value chain under our control.

Okay. Yes. That makes total sense, and I’m sure you understand why I’m asking, but I appreciate the color, guys.

Our next question or comment comes from the line of Darren Horowitz from Raymond James.

Joe Bob, I realize it’s early to put numbers around this, so conceptually speaking, when you look at the increased confidence that you guys have on field inlet G&P exiting this year, what you’ve talked about with regard to Permian inlet volumes obviously ramping into ‘18, how much of that for you is increased by more confidence off of the visibility you have in base asset throughput versus this "gassier" phenomenon of wells increasing versus what could be even a shift in well completions as some customers are adding additional casing to deal with some different pressures on shallower reservoirs.

You hit a lot of very interesting factors, and each one is difficult to quantify individually. We are working with our trends. Like Pat said a little while ago, really kind of using our rear-view mirror. It’s not the deep rear-view mirror, but recent GORs, recent type curves, in those outlooks. Part of our confidence is, in total, those factors you mentioned relative to when we did the outlook or recognized that we worked on that outlook well before we sort of presented it in June. Yes, our expectations keep going up on almost all factors. And that’s -- we never got to the point of saying exactly how many wells in the Permian. You’re going to see some little ups and downs, and a producer will use a price drop to let go of rigs and then bring them back on. We believe that we had a view of that for multiple years. So I’m not going to try to describe any 1 factor, but it’s hard for me to think of a factor right now that would be a negative to me feeling better about our long-term outlook.

Yes. And then if I could take that a step further, as the back half of the year really starts to get the benefit of field inlet being even more pronounced, specifically in 4Q, what do you think that might do, since it was in your slide deck, to utilization of Targa fractionators? Because obviously we saw a big sequential increase in frack volumes quarter-over-quarter that seems to be even more pronounced in 4Q versus 3Q. Can you give us a sense for what you’re expecting?

Yes. I think you just -- you kind of just answered it. It’s a pretty significant impact on our frack volumes over time as we follow that outlook. As -- we joked in preparation for this call that you all could probably draw the curve we’ve got driven for the second half. Don’t be drawing it by month. But we’re on track, and we’re going to meet or exceed our previous expectations. And that has a nice downstream benefit. Scott’s smiling.

Okay. And then last one for me. Just, Matt, a quick housekeeping question. On the Outrigger assets, where is the contingent consideration liability right now on the fair value of what you’d expect the earnout on those assets to be?

Yes. Sure, Darren. It’s about $417 million, and we’ll have more details on it when the Q gets filed. It should be out later today. We also included in there, in the footnotes, an amount for 2018 and 2019. So right now our estimate for 2018 -- so the first payment is approximately $40 million of that amount, and then the remainder about $377 million in 2019.

Our next question or comment comes from the line of Jeremy Tonet from JP Morgan. Your line is open.

Hi, this is Charlie, actually, in for Jeremy. Just first question real quick on logistics and marketing side. Just curious, have you received any revenue for the cancellations during the quarter, just given kind of what seemed like fairly good margins despite kind of the drop in volumes?

Yes, Charlie. We indicated both in our prepared remarks and discussions that we’ve had even at investor conference, that we saw during the second quarter two cancellations, and we did receive cancellation fees for those. Looking forward, at this point we’re not seeing cancellations. But again, time will tell relative to the overall global fundamentals that we see out there going forward. I would suggest to you that our belief is, when we look at the second quarter, it was very similar to what we saw in the second quarter of 2016. Somewhat of a trough in relative sense, when you look at the balance of the year. So again, with demand growing across the globe, production increases in the U.S. and the U.S. being really the preeminent supplier for incremental volume growth across the globe, we will be the supplier of that as a U.S. industry, and Targa sits well to benefit from that as well.

And Charlie, I haven’t found anyone who wants to take my bet on the over-under of zero exports in our long-term outlook. If you can find someone who wants those bets, I’ve got reserves.

Just one other real quick one. Just looking at the kind of plant utilizations, and specifically kind of looking at West Texas, I mean, they’re a little bit lower than some of the other Permian plants. Is that just kind of an age factor? I’m just trying to understand what sort -- how hard some of these plants can run given significant ramp-up in volumes in the second half.

Charlie, did you say WestTX?

Yes.

Okay.

Yes. It’s also related to part of where the gas comes on. We have offloads. We move some volumes to and from Sand Hills; some volumes to and from SAOU. So it’s also just dependent on where those volumes are coming on and where we can push it -- whether we can get the gas up to Buffalo or down to the Edward and Driver. So it’s a pretty integrated system we have with the WestTX, SAOU and even out through Sand Hills. We are adding additional capacity with the additional Benedum and Midkiff coming on in the second quarter -- is going to increase capacity there, and we’ll be moving volumes to those facilities, and I think you’ll start seeing that increase here.

And you asked about age of assets. The bulk of that portfolio -- I couldn’t give you a percentage right now -- is fairly new.

It’s pretty new, yes.

Yes, but 130 million a day.

Thank you.

The WestTX system assets are very new.

Very new, yes.

And we’ve got a recorded history of them being able to operate above nameplate for short periods of time.

Yes.

Our next question or comment comes from the line of Chris Sighinolfi from Jefferies. Your line is open.

Just want to ask a question -- I guess it’s for Matt -- on capital budget and expectations -- the movement higher for 2017 looks like it’s roughly split between an allocation for Grand Prix and additional gathering CapEx. I know there’s some other things in there, but that looks like the bulk of it. And as we think about 2018, clearly the majority of your CapEx budget, if there is no partner, would be Grand Prix. But I’m just kind of getting a sense, given the earlier conversations around gas cuts and type curves, kind of what we should be thinking about gathering CapEx-wise for 2018 based on your current plans. I think the separately identified figure you have on Slide 10 is about $475 million for 2017. Do you expect that to drop materially? Or can you just give us some color on current expectations, would be helpful.

Yes. I guess I would say we expect meaningful CapEx in 2018, and you’re right, from the -- Grand Prix will obviously be the largest piece of that. We do expect a meaningful amount of CapEx in the Permian, both the Delaware and the Midland, for that other infrastructure -- gathering lines, compression and the like. The largest chunk of that increase you saw for the Permian infrastructure this year was related largely to the acquired assets, and that’s more of a shift in timing rather than an increase in total expected spend. So we ran through and -- we go over our CapEx plans monthly and we’re seeing we’re getting some more of the work done this year that we were originally anticipating getting done in ‘18 and even some of it into ‘19. So you’re seeing a shift of that capital into 2017. So related to the infrastructure buildout for the new Permian assets, I’d say the lion’s share of that is going to be now shifted into ‘17 and it’ll be lower in 2018 and ‘19.

The lion’s share of the change, not...

Lion’s share of the change. And -- but we’re still going to have a significant amount of spending related to just our existing infrastructure on compression and gathering. We haven’t given that guidance yet. I guess all I’d say, to kind of preview that is I would expect it to be significant, and we’re still working through what we think that amount’s going to be.

Okay. No, that’s really helpful. I know this is somewhat contingent on what the producers decide between now and year-end as to what they’re planning for next year, so I realize I’m a little premature. I just wanted to get a sense of it. I guess as it relates, Matt, you list on Slide 10 some ancillary spending on Downstream on some identified projects. I think it’s around $90 million. Any help in terms of explaining what exactly sort of sits in that bucket, and whether or not it has recurrence in 2018 would also be helpful.

Yes. So we don’t break out a lot of the smaller projects in there, but I would say a lot of that has to do with connectivity further downstream to the ethylene plants coming online. So a lot of that are tens of millions or $5 million, $10 million, going to X, Y and Z additional infrastructure further downstream. I think we’ll continue to have some of that spending going forward. That’s a bit lumpier and a little bit tougher to forecast, but we’ll be working through that as well when we provide our 2018 guidance on CapEx.

No, this is all really, really helpful. Final question for me, and I trust this is not uniform; I’m just hopeful we can kind of get a sense of how to frame it up from an impact perspective, but when contracted LPG export shipment cancels, how does the cancellation fee received compare to, like, the net earnings or cash retention if the boat had arrived and you’d had -- you’ve been paid on the contract but also had to incur the operational costs of running the terminal? Is there a sense you can give us in terms of how this -- the ratio of that?

Our -- this is Scott, Chris. The -- our cancellation fees are different on each contract that we have across our portfolio. So giving you a sense of how all that breaks down would not be possible. We obviously know what this means and we are collecting for that [indiscernible]. When you look at it, the way you need to look at it is from the perspective of, we do not have any expense if we do not load the product itself. So operational expense is associated with that. With that said, and more from a positive perspective is, when we do receive a cancellation for a cargo and we collect that fee, obviously our team is working very hard to fill that void that might be in our schedule, whether it is a large vessel or a small vessel, in order to optimize the facility.

Thank you. Our next question or comment comes from the line of Sunil Sibal from Seaport. Your line is open.

A couple of questions from me. In terms of the Grand Prix NGL pipe, I was wondering, in terms of the next few steps, do you intend to do an open season on that pipe?

Yes. There will be a bit of an open season at an appropriate time for a portion of the capacity on the pipe.

And then I think on the -- originally, when you had announced the pipe and you had talked about it being routed to the North Texas also, and considering the amount of interest that you have seen right now, is that still the intent, and how should we kind of think about the relative contribution of Permian versus North Texas?

Yes. So what we included in the release, it is primarily a Permian pipeline, but we did say that we do plan to reach up into North Texas to connect to our North Texas assets. So that still is the scope of Grand Prix. But the lion’s share of the volumes that we would expect for the Grand Prix project we’ve announced so far is coming from the Permian.

And then on the Flag City processing plant that you guys acquired, I was wondering if you could give us some sense of what kind of volumetric contracts are there on that plant, and how do they roll out over the next few years?

We almost never describe the contractual terms of our customer contracts. What I would say is, it was an attractive acquisition for Targa. We’ve got a -- now, a new spare plant. Not new, but it’s a state-of-the-art spare plant that has operated and operated well. And those volumes were immediately integrated back to our Silver Oak facilities and are being processed there now. Customers don’t want me to describe those contractual terms and we just don’t do it for competitive reasons as well. But we did contrast it with volumes that sort of came in and out in a prior reported period as lower-margin IT contracts and that’s not what we acquired with the plant.

Okay. Got it. And then just lastly on the splitter project, considering all that’s been going on with Noble, I was just wondering if you had any thoughts on that project, especially if Noble were to declare, say, bankruptcy or something like that. How do you kind of think about that asset long-term?

It’s a terrific machine that we’re building. It will take condensate and crude and split it to valuable byproducts. Our byproducts -- valuable products. The contractual arrange with Noble -- I’m not describing anything different than you all read in the papers, and you know they’re taking measures of selling off certain businesses, and that helps the other businesses stay in place. You said, "If they go bankrupt." I’ve had a couple of people advise me, don’t anticipate getting your hands on -- it’s our asset -- getting your hands on that asset earlier than the multi-year term of the contract, because it’s valuable. And they -- any bankruptcy could probably figure out a way to finance that so as not to lose the ability to use it. Yes. If that were not the case, then we will either lease it out to someone else or commercialize it ourselves. I don’t anticipate that, even under a bankruptcy situation. I think that the asset -- their asset, the contract, would be maintained, they would continue to pay us and they would reap the rewards of continuing to pay us.

Our next question or comment comes from the line of Timm Schneider from Evercore.

Just a quick question on the LPG export side outlook. I know a lot of your volumes go to Latin America, but just over the next couple of years, what are your discussion with Asian counterparties -- specifically, Chinese PDH units? And then also, India -- obviously, there’s a tremendous amount for demand -- or potential for demand growth in India, but no one ever really seems to talk about it. Anything going on, on that end, at this point?

Yes. Timm, this is Scott. First off, we have, as we’ve described it before, a very diverse comp contract portfolio today, which is inclusive of waterborne traders, end users both in Latin America, South America, Europe and the Asian marketplace. So we are in contact, in discussions, with customers across the globe today and have contracts in place to supply those various markets. So we’re a part of that today. Clearly, we’ve stated in previous discussions and earnings calls that our supply is predominantly moving to the Americas today, but the growth is in Asia. It is in places like India as well. And whether it’s through direct contracts with those customers or with our contracts that we have with waterborne traders, we would anticipate in the future an ever-growing amount of our supply moving to markets such as that. So those are all good stories. The fundamentals are shaping up very strongly. And again, when you look at the availability of supply in markets outside of the U.S., they are not growing very much, whereas the U.S. does have a tremendous story of growth, and as the global demand increases, more and more of that supply will move to those markets -- India and other places.

Got it. And as far as you have the color, I mean, I was trying to some numbers around this. Do you guys have a sense as to how much these OPEC supply cuts have affected LPG supply coming out of Qatar and some of these -- and some of the other exporting countries there? And have you guys been able to take market share on that front?

I would say that we probably saw more impact of the market during the first quarter of 2017. There may be -- you may have seen a little bit of an oversupply product on the water as we rolled into the second quarter, which likely could have impacted some of the availability of spot volumes coming out of the U.S. Those cuts, they’re obviously hard to track, but I think that the Middle East suppliers have been more conservative in what they’ve been willing to contract as a result of the announced cuts. But at the same time, as they exceed those production levels over and above what they have contracted, those volumes are on the market as a spot coming out of the Middle East. They would be pointed toward predominantly a Far East-type-related market and/or an India growth story.

Our next question or comment comes from the line of Danilo Juvane from BMO Capital. Your line is open.

I realize you’re running long here, so I’ll try to be brief. Just as an expansion on Grand Prix, it seems that there’s enough of a demand there for the project. Do you foresee now -- and perhaps this is a question for Scott, do you foresee the project returns being within that 5 to 7x right at the beginning of the project startup?

We’ve described getting to that five to seven time over time. In 2019, we expected to come online, second quarter. So we’re going to get partial year credit in 2019, and we do expect to ramp from there. So we’re not going to get specific on volume ramp at this point, and when we see getting to five to seven time. We just say, over our forecast period, we see getting to five to seven, and even potentially under that.

Got it. By our math, in the Permian we estimate that you guys have the potential to produce a little more than 200,000 barrels per day of NGLs. Do you expect that to be roughly the amount that you will ship in the pipeline, longer-term, once your processing facilities come online?

So we have significant gross NGL production out of the Permian. I’m looking at for Q2 is give or take 155,000 barrels. We expect that to grow with the addition of our additional processing facilities. However, a lot of that existing production, we do have contracts with existing pipelines in that region. Some of them are longer. Some of them are rolling off, and some we can move under shorter term, move in the near term. So it’s a balance. So I wouldn’t just take the total gross NGL production and assume we can move it all on Grand Prix. But then we’ll have the addition of growing volumes plus third party volumes available for Grand Prix.

Got it. Within the logistics segment, I noticed that the quarter had pretty strong uptick in OpEx. Can you explain what the driver is there?

Yes. So when you look at the operating expense for the logistic -- quarter to quarter, so versus the first quarter, the total operating expense was actually a bit lower. When you look at it compared to last year, there’s a couple of drivers. One, the CBF Train 5 was online full quarter this year, and it was starting up about this time last year. And there’s also the variable component in our Downstream Business, and we saw higher commodity prices in the second quarter of this year versus the second quarter of last year.

Thank you. Appreciate that. Last one for me. I appreciate that your focus is on the Permian, but the Bakken is -- also has some pretty strong GORs lately. Can you talk about the possibility of potentially adding incremental processing capacity there?

Yes. As I mentioned in the scripted comments, the Badlands volumes -- they grew second quarter to first quarter of this year, but we’ve seen a relatively large uptick here in July. So with the growth number I gave you, that kind of puts it in the 65 million to 67 million a day at the end of July for the Badlands volume, so it’s up significantly. We still have some additional capacity there. But looking out, with our 90 million a day, that’s something that would have to be considered given the activity that we’re seeing up there. Thank you.

Our next question or comment comes from the line of Craig Shere. Your line is open.

Quickly on the guidance for industry ethane recovery that you gave, could you opine on your EBITDA growth outlook and vision through 2021? What portion might more generally be related to ethane recovery?

So when we looked at -- we did have some additional recovery going out in that forecast. But even in that forecast, we did not assume 100% at all of our plants over the entire forecast period. Our assumption -- it moved up over time. But -- so it was a piece of it, but it wasn’t the primary driver of that growth.

Okay. So you would envision additional running room without much or any CapEx spend, post the horizon period, just on full recovery?

I think another way of describing it is consistent with multiple elements of the forecast outlook. We were providing line of sight, not trying to crowd the assumptions, relative to an outlook that for multiple years, not each quarter, felt good to us, and that we could perform against. Therefore, we weren’t in total. Just like any other element, we would not -- we were not assuming a total ethane recovery scenario. That wouldn’t have been consistent with, for example, assuming zero spot volumes for exports.

Yes. And also, we assumed approximately a $0.60 NGL over that forecast period. So with that incremental demand Scott talked about ethane coming on, the average NGL price today for us is already over $0.60 if you look at today’s prices. So with recovering that additional amount of ethane, we would -- it would also likely result in an increased price for ethane. But we use $0.60 ethane over the whole forecast period. [Multiple Speakers] Thank you. I had a lot of correction.

People’s eyes were getting wide. And Scott probably should have been answering, because we also use a $3-per-MMBtu natural gas. And the relationship of gas and ethane makes all the difference, right? So you can tell that that’s not a super-strong ethane recovery scenario.

My last question -- after the last equity offering, I think you’ve kind of gotten your hands around the balance sheet. Are you thinking, as we move into 2018 and we have the Permian pipeline spend, the -- and also ultimately the Outrigger earnouts, that it will be a little more of an even debt and equity mix in terms of funding?

Yes. Good question. Our balance sheet right now, with the equity we’ve raised today, is in pretty good shape. The 3.4 times compliance ratio is right in the middle of our target zone of three to four times, and even on a reported LTM debt to EBITDA, we’re in the low 4s -- about 4.1 times. So as we go through our planning cycle for 2018 and firm up our CapEx estimates for that year, we will still likely need some additional piece of that to be equity financed. Typically we’ve financed our growth CapEx on a 50% debt, 50% equity basis. This year it’s been over-equitized for all the reasons that we’ve talked about. So I would expect a significant equity component in 2018. But I think you’re right, we’ll be closer to our normal 50% debt, 50% equity. Where exactly we shake out on there, I think will depend on the size of the overall capital budget.

Well, and we also have really good visibility on the EBITDA, which is part of maintaining that balance sheet. And that visibility, we -- if you heard, we feel even better about. So it’s that balance of debt to EBITDA as we finish our full process, which is not just on the cost.

And the total size of the capital [indiscernible].

Exactly.

And on the subject of the equity funding longer term, we’re hearing from more and more peers that they’re just comfortable having larger coverage. As you build, can you envision a consistent 1.2 times plus coverage, if you have plenty of running room on ongoing growth projects?

I have had people point to a comment in a script, and I think it was now three or four quarters ago, where through a series of questions we got talked through, it used to be 1.1 to 1.2. And I think Joe Bob said, I guess that it means 1.2-plus. I don’t come to a different conclusion than when that dialogue created the quote for Joe Bob of saying 1.2-plus. We’re just not saying, where is the range right now. We’re figuring it out. We’ve got a lot more scale, a lot more diversity, than we did as that MLP distribution coverage. But we’re probably more conservative, having gone through what we went. Still, there’s a reasonable signal. It’s not a new target. It’s not a new band. But you’re reading my quote from multiple quarters ago, and I wouldn’t say it’s directionally wrong.

Thank you. This concludes our Q&A session, and I’d now like to turn the conference back over to management for any closing remarks.

Thank you, Operator. Thanks to everybody who stayed on the phone for that -- the long call. We did want to be able to answer everybody’s questions. We hope we’ve done so completely and with at least interesting color. If you have any follow-up questions, please contact Sanjay, Jen or any of us. Thanks, operator.

Thank you. Ladies and gentlemen, this concludes today’s program. Thank you for your participation. You may now disconnect. Everyone, have a wonderful day.