Targa Resources Corp (TRGP) 2017 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Targa Resources Corporation Third Quarter 2017 Earnings Webcast and Presentation Conference Call. (Operator Instructions)

As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Mr. Sanjay Lad, Director of Investor Relations. Please go ahead, sir.

Thank you, Amanda, Good morning, and welcome to the Third Quarter 2017 Earnings 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 on the Investors section of our website at www.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 provision of the Securities Acts 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, 2016, and subsequently filed quarterly reports on Form 10-Q.

Our speakers for the call today will be Joe Bob Perkins, Chief Executive Officer; Pat McDonie, Executive Vice President of Southern Field Gathering and Processing; Scott Pryor, Executive Vice President of Logistics and Marketing, our Downstream segment; and Jennifer Kneale, Vice President of Finance, who is covering for the financial -- who is covering the financial section of the call for Matt this morning as he has another commitment. Other members of senior management will be available during the Q&A portion of the call.

Joe Bob will begin today's call, then turn over to Jennifer to discuss third quarter 2017 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 will turn the call over to Mr. Joe Bob Perkins.

Thanks, Sanjay. Good morning, and thanks to everyone for joining, especially given all the recent late-night Astros games. What a series! And I have to say it feels a whole lot better to be doing this call this morning rather than yesterday morning when I was a little bit grumpy. The Targa team is very proud of our hometown World Series champs. So let's get started.

First, I want to acknowledge the heroic efforts of many Targa employees during Hurricane Harvey. I'm inspired by the Targa team's dedicated efforts to ensure the continued safe operations of our facilities during and in the aftermath of the storm. And I am very thankful to those who worked tirelessly to communicate with our customers and to mitigate the impact of the storm for our customers and for our shareholders.

Our third quarter operating margin was reduced by approximately $11 million due to the impact from Hurricane Harvey, but we expect to recover and recognize approximately $7 million of that impact in the fourth quarter. And despite the approximately $4 million net impact of Harvey, our previously disclosed full year 2017 adjusted EBITDA guidance of $1.13 billion remains unchanged.

Given the catastrophic impact of Harvey on many of the communities around our assets and on the residences and cars of our employees, the modest impact on our results exemplifies the impressive efforts of our employees despite the storm. Similarly, our employees worked very hard to minimize the effects of Hurricane Nate on some of our Louisiana assets in early October, and we expect the impact of that hurricane on our fourth quarter to be negligible.

Other than Hurricanes Harvey and Nate, 2017 is largely playing out as forecasted for Targa, with the second quarter representing an expected trough of adjusted EBITDA for the year and with EBITDA sequentially increasing over the second half of the year, as we benefit from increasing volumes across most of our gathering and processing systems and across our downstream assets. We remain on track to meet or exceed all of the volume metric and financial guidance that we provided for this year. And fundamentals affecting Targa's day-to-day business continue to improve.

While backward dated, WTI crude oil prices for the balance of 2017 through 2021 are higher than the $50 per barrel flat that we assumed in the longer-term guidance that we provided in June. The current weighted average target NGL composite barrel is about $0.74, significantly above the $0.60 per gallon flat price assumed in our guidance and above the average approximately $0.60 per gallon we have seen for the first 3 quarters of this year. Obviously, higher NGL prices can provide our businesses with some additional tailwinds for the future.

We are also on track and remain focused on executing on our key strategic initiatives underway, including: first, investing in economically attractive projects that leverage our existing infrastructure and further strengthen our competitive advantage; adding over 1 billion cubic feet per day of incremental gas processing capacity in 2017 and 2018, with most of that, as you know, located in the Permian Basin; to handle increasing volumes that we are seeing around our assets across both the Midland and Delaware basins; and continuing progress on our 300,000 barrel per day Grand Prix NGL pipeline, retaining the strategic benefits and enhancing the economics and derisking the project by bringing in an attractive financial partner in Blackstone; and executing a long-term agreement for transportation and fractionation with an attractive strategic partner in EagleClaw.

Additionally, in early October, we announced that we executed a letter of intent with Kinder Morgan and DCP to jointly develop the proposed Gulf Coast Express Pipeline Project, also called GCX, which would provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast.

Assuming documents are finalized per the LOI, we would be a 25% equity partner in GCX, bringing significant residue gas volumes to the pipeline from our Delaware and Midland Basin footprints. For Targa, the fee-based returns on GCX would be attractive and meaningful once the pipeline is in service. And most importantly, the pipeline would provide reliable takeaways for our customers from the Permian Basin to premium markets along the Texas Gulf Coast.

As we've discussed previously, Targa is one of the largest daily movers of NGLs and residue gas out of the Permian Basin as a result of a great asset position and organic growth and third-party acquisitions that we have made across the Midland and Delaware basins over the last several years. And now, our Grand Prix NGL pipeline joint venture and our GCX residue gas pipeline joint venture leverage that franchise Permian position.

Executing our strategic objectives requires capital, and we currently estimate 2018 net capital expenditures to be approximately $1.6 billion for our currently announced major projects and associated infrastructure. There are a number of other potential capital projects that we're working on, which have not been announced. Some of these I'll continue to characterize as when and not if. Of course, including additional fractionation and not yet announced, but ultimately expected additional gas processing plants in the Permian. Such potential new projects are leveraged to Permian activity and leveraged to other Targa infrastructure, which provides attractive rates of return and continued best-in-class service offerings for our customers.

It is reasonable to assume that if the volume trends continue for Permian gathering and processing and for downstream fractionation, then some of these potential projects may have associated spending in 2018. And 2018 CapEx, in that instance, could be greater than $1.6 billion. We will, of course, provide a full CapEx update with 2018 guidance in February of 2018, and we will provide CapEx updates with any major new announcement.

This year, we raised a significant amount of public equity concurrent with the announcements of both our Permian acquisition and the Grand Prix project. And we raised equity through our ATM program earlier in the year. As we had signaled early in 2017, we overequitized. From our perspective, these were important steps to support our balance sheet and enhance our financial flexibility, as exemplified by our leverage ratio of 3.7x at TRP at the end of the third quarter, which is within our 3 to 4x long-term target range. That's been the range as long as I can remember.

For 2018, our financing plan is consistent with best practices -- best past practices. For 2018, our financing plan is consistent with best past practices. We will finance with a combination of debt and equity, consider public and private capital, continue to consider creative joint ventures and potential asset sales. And given the visibility we have to increasing EBITDA, we will also have the option to fund our capital program with more debt than equity, which will provide us with a favorable tailwind related to financing.

So given that we overequitized in 2017, we have a strong balance sheet, a very liquid public security and increasing EBITDA that allows us to potentially fund with more debt than equity, we believe that our equity needs for 2018 are very manageable.

Alternatively, there is a lot of appetite in the private capital markets, as demonstrated by our Grand Prix JV and other market transactions out there, appetite to fund a portion of Targa's growth or to purchase a portion of our assets. We, of course, are actively considering multiple alternatives and structures, which could supplement or replace our public equity capital needs at relatively attractive cost of capital.

Additionally, our ability to continue to raise attractive debt capital was highlighted by our notes offering that closed in October, as Targa issued $750 million of 5% senior notes due in 2028. Net proceeds from that offering were used to redeem our 5% senior notes due in 2018 and to reduce borrowings under the TRP revolver and accounts receivable securitization facility. Pro forma for the notes offering, our liquidity was approximately $2 billion.

For Targa, we believe that we are executing on strategic initiatives that will drive significant shareholder value over the longer term. As exemplified by the information that we presented in June of this year, a long-term outlook showing expected adjusted EBITDA to almost double over 5 years, growing from approximately $1.13 billion in 2017 to approximately $1.5 billion in 2019 and approximately $2 billion in 2021. And I'll tell you, we feel even better about that outlook today than we did in June.

The forecasted EBITDA growth is not predicated on a commodity price recovery and is supported by visible fundamentals continuing to provide tailwinds to our business. For example, continued Permian activity; for example, additional petrochemical capacity. We believe that we will outperform that EBITDA growth forecast on multiple dimensions.

In building that outlook, we assume no additional commercial execution over the time frame. I'll take the over, no additional gathering and processing contracts and no additional LPG export contracts. Also in building that outlook for EBITDA in that time frame, we assume we added one additional frac and built 2 processing plants to support contracts we already have in place. That was not an overly robust assumption. Please consider that since the June long-term EBITDA outlook, we potentially are adding the commercial opportunity in the GCF project. And we've also added attractive G&P in downstream contracts, and we expect to further enhance our positions going forward.

We are spending significant capital on our announced projects and have taken steps over the last 2 years to have the balance sheet strength, flexibility and demonstrated access to public and private capital that supports our attractive growth project opportunities as we complete them and they begin to generate significant incremental EBITDA.

Consistent with how we have previously described our financial priorities, our first priority is to take care of our balance sheet, providing us with stability and flexibility and to maintain or improve leverage and dividend coverage over time. We have told you, every quarter, we provide our board with a recommendation for the dividend for the quarter, which is based on our strategy, our long-term outlook and multiyear forecast.

Our quarterly dividend has been $0.91 per common share since the third quarter of 2015. And while we have not yet published specific guidance for 2018, assuming we will continue to recommend the quarterly dividend of $0.91 per common share in 2018, is consistent with our recent track record.

Looking forward over the longer term, we have significant visibility to increasing EBITDA. And as our growth projects underway begin operations and cash flows improve, our balance sheet will continue to strengthen, we'll reduce leverage and increase coverage. This improved leverage and coverage outlook will be taken into account in future dividend discussions with our board as will market-driven approaches to pay out and the best use of the higher coverage to most effectively provide our shareholders with attractive returns. That's our job and that's what we'll do.

With that, I will now turn the call over to Jen to discuss Targa's results for the third quarter.

Thanks, Joe Bob. Good morning, everyone. Before I get started, I'd like to recognize Sanjay for coming up with our new investor presentation look from scratch that you hopefully noticed in our materials posted on our website this morning.

Targa's reported adjusted EBITDA for the third quarter was $276.5 million, which was 13% higher than the same period in 2016. Continued strong volume growth in Permian G&P, complemented by higher volumes in the Badlands, SouthTX and SouthOK, along with higher commodity prices and higher fractionation volumes, drove the increase in adjusted EBITDA over the prior year.

Reported net maintenance capital expenditures were $24 million in the third quarter of 2017 compared to $20 million in the third quarter of 2016. We continue to estimate approximately $110 million of net maintenance CapEx for 2017.

Distributable cash flow for the third quarter was $186.6 million, resulting in dividend coverage of approximately 0.85x, which is consistent with the expectations that we had for the third quarter and includes the impact of Hurricane Harvey.

In October, we received the $43 million annual payment related to the Channelview crude and condensate splitter. So for full year 2017, we continue to expect adjusted EBITDA to be approximately $1.13 billion and full year 2017 dividend coverage to be between 0.95 and 1x.

Moving to our sequential results. Adjusted EBITDA for the third quarter increased 7% over the second quarter. In our Gathering and Processing segment, operating margin increased by $24.8 million in the third quarter when compared to the second quarter, primarily due to higher inlet volumes in the Permian, Badlands, SouthTX and SouthOK in addition to higher NGL prices.

Third quarter Permian inlet volumes sequentially increased 7% from growth in each of our Permian Midland and Permian Delaware systems. In the Badlands in North Dakota, third quarter natural gas volumes increased by approximately 17%. Inlet volumes in SouthTX sequentially increased 48% over the second quarter, as we benefited from full quarter operations of the new Raptor plant and higher volumes from Sanchez in addition to incremental volumes from the acquisition of Boardwalk's Flag City assets and fee-based contracts.

Volumes also sequentially increased in SouthOK, as we continue to benefit from incremental SCOOP volumes on our system that were more than sufficient to offset legacy production declines.

While we are only 1 month into the fourth quarter, our inlet volumes for overall Field G&P, driven by the Permian, SouthTX, SouthOK and Badlands are higher than our third quarter average Field G&P volumes, and we remain on track to meet our full year 2017 Field and Permian volume expectations that we provided earlier this year. More importantly, the trajectory also provides a strong outlook for 2018. While we are not providing formal guidance at this time, directionally, we expect significant year-over-year growth in total Permian volumes in 2018 and expect the positive volume momentum in SouthTX, Badlands and SouthOK to also carry into 2018.

Turning to the Bakken. Badlands crude oil gathered volumes were approximately 109,000 barrels per day in the third quarter, down slightly over the second quarter due to the timing of well completions. Permian crude volumes gathered in the third quarter were approximately 36,000 barrels per day, and we expect this positive trend to continue.

In our Downstream segment, operating margin sequentially increased $3.5 million in the third quarter when compared to the second quarter. The segment was essentially flat sequentially, as improved underlying business performance was partially offset by lower margins in our fractionation and LPG export businesses due to the impacts from Hurricane Harvey. Fractionation margin decreased largely due to the deferral of supply volume settlements resulting from temporary operational issues due to Hurricane Harvey. LPG export margin decreased sequentially, as some volumes were deferred to the fourth quarter due to the temporary closure of the Houston Ship Channel as a result of Hurricane Harvey.

When normalized for the effects of temporary operational issues attributable to Hurricane Harvey, third quarter fractionation volumes would have been approximately 359,000 barrels per day or 6% higher than the second quarter.

In our LPG export business, approximately 4.7 million barrels per month of propane and butanes were exported from our facility, and we received fees from 2 vessel cancellations during the quarter. LPG export volumes would have been approximately 5.1 million barrels per month or 8% higher than the second quarter when normalized for the effects of Hurricane Harvey.

Consistent with what we are seeing in Gathering and Processing, our fractionation and LPG export volumes for the fourth quarter are also expected to be higher than the third quarter averages. While we are still working through our planning process for 2018, the expected strength in exit rate volumes across our segments, coupled with strengthening fundamentals, provides us with a visibility to increasing year-over-year adjusted EBITDA.

Overall, operating expenses during the third quarter in both our G&P and Downstream segments were essentially flat to the second quarter. And looking forward, we expect OpEx to increase as new assets and facilities come online.

Moving on to 2017 capital spending and other financial matters, we expect 2017 net growth CapEx of approximately $1.3 billion based on our announced projects, inclusive of our Grand Prix joint venture with Blackstone.

We continue to get a lot of questions related to the earn-out structure of our Permian acquisitions that closed on March 1. After each quarter during the earn-out period, we update our estimates for the expected earn-out payments, comparing current expectations to the forecast developed prior to acquisition close. From our perspective, the volume growth that we expected when we closed the acquisition has materialized more slowly, which is a situation that we obviously contemplated in developing an earn-out structure where additional consideration accrues to the sellers only if the assets perform over the defined near-term earn-out period.

Currently, the aggregate earn-out payment is estimated to be approximately $291 million and is expected to be predominantly weighted towards the second payment due in April 2019, with a much smaller payment forecasted for April 2018. The reduced aggregate earn-out payment estimate is attributable to currently projected production from contracts that were executed prior to acquisition close being lower than our estimates at the time of the acquisition. While volumes are still expected to grow significantly over the earn-out period, the near-term growth is lower than our acquisition case. And the earn-out structure means that we would, therefore, pay less than previously forecasted for the earn-out payments.

Growth beyond the earn-out payments -- growth beyond the earn-out periods and margin from new contracts entered into after acquisition close accrued to Targa's sole benefit. Most importantly, we continue to feel very good about the long-term value of the acquisition to Targa.

During the third quarter, we also recorded a noncash pretax impairment charge of $378 million related to our North Texas operations. Obviously, we have seen volumes and activity levels continue to decrease in the Barnett, which are driving the impairment. The impairment does not impact Targa's cash flow, DCS, EBITDA, leverage ratios or any other meaningful metrics.

Turning to our corporate hedging program. We executed additional hedges during the third quarter, as we saw some price strength in certain commodities, particularly for the balance of 2017. We estimate that we have now hedged approximately 95% of natural gas volumes, 90% of NGL volumes and 75% of condensate exposure for the remainder of this year. For 2018, we estimate that we have hedged approximately 80% of natural gas volumes, 50% of NGL volumes and 50% of condensate exposure.

I will now turn the call over to Pat, who leads our Southern Field G&P business. Pat?

Thanks, Jen, and good morning, everybody. As Joe Bob mentioned, system volumes in our Gathering and Processing segment continue to increase, tracking our expectations for the year. And we expect this positive trend to continue.

In the Permian, we are working hard to keep pace with our producers, and we remain focused on continuing to add infrastructure to meet their growth needs.

Starting in the Permian Delaware, in addition to the adding gathering lines, compression and treating capabilities, we are on track to begin operations on our 60 million cubic feet per day Oahu plant in the fourth quarter. Construction also continues on our 250 million cubic feet per day Wildcat plant, which is expected online in the second quarter of 2018.

In the fourth quarter, all of our Delaware assets will be fully interconnected, increasing our operational flexibility as volumes continue to ramp.

In the Permian Midland, production growth continues at a rapid pace. And in October, we connected our recently acquired Midland assets to our WestTX assets. 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. We expect that both plants will be highly utilized when they come online, immediately contributing to our interconnected multiplant footprint across the Permian to provide significant additional flexibility as we are able to move volumes between systems and from Permian Midland to Permian Delaware and vice versa.

We have looped more gathering lines and added more compression in 2017 than originally expected as a result of producer volume growth. This incremental infrastructure will increase our long-term growth capability across our Permian assets, which is important based on our most recent conversations with our producers, who continue to forecast strong growth in both the Midland and Delaware basins beyond 2017.

Moving to our Oklahoma assets. Our outlook continues to strengthen as we benefit from commercial -- continued commercial success and increasing production on our dedicated acreage. Third quarter inlet volumes for SouthOK were approximately 8% higher than the second quarter, and we expect volumes to continue to increase through the fourth quarter and into 2018 due to continued commercial success, system expansion and a recently completed line that is bringing additional SCOOP volumes to our system.

In SouthTX, system inlet volumes increased 48% sequentially over the second quarter as we have benefited from a full quarter of operations of our new 200 million cubic feet per day Raptor plant that began flowing gas in late May and from incremental volumes from the second quarter acquisition of Broadwalk's Flag City assets and fee-based contracts. We decommissioned the Flag City plant and are processing volumes from the acquired Flag City contracts at our Silver Oak facilities. We expect to move the Flag City plant and the other acquired assets for use elsewhere in the Targa G&P business.

We also recently completed the 60 million cubic feet per day expansion of the Raptor plant and the additional capacity, now a total of 260 million cubic feet per day at Raptor, will help support the volume growth that we expect in South Texas through the fourth quarter in and through 2018.

I will now turn the call over to Scott Pryor, who leads our Downstream Business. Scott?

Thanks, Pat, and good morning to everyone. As we look forward into the rest of the fourth quarter and beyond, our Downstream Business continues to be very well positioned to benefit from a number of tailwinds.

First, we had higher sequential fractionation volumes, driven by higher Field G&P inlet volumes, a trend that we expect to continue. We also are seeing renewed interest in long-term fractionation deals, reflecting a tightening of capacity in Mont Belvieu. Secondly, greater ethane extraction as new Gulf Coast petrochemical demand continues to improve the ethane frac spread, which will drive higher fractionation volumes for Targa over time. We expect 150,000 barrels per day of new cracker demand by the end of this year, an incremental 300,000 barrels per day by the end of 2018 and additional growth in 2019 and beyond. And the vast majority of the expansions and newbuilds are located along the Gulf Coast.

And third, we currently are well positioned and will continue to strategically position ourselves to benefit from increasing upstream supply growth and increasing downstream demand growth, including via the Grand Prix NGL pipeline and by adding or expanding new connections to markets downstream from our fractionators.

Shifting to our LPG export business. We loaded 4.7 million barrels per month of LPGs for the third quarter, received cancellation fees for 2 vessels and had a couple of vessels move into the fourth quarter schedule as a result of Hurricane Harvey temporarily closing the Houston Ship Channel. For the fourth quarter, we expect LPG export volumes to increase versus the third quarter.

Looking forward, the long-term outlook for LPG export business is unchanged, given our substantial long-term contract position and favorable global fundamentals, driven by continued international demand growth and the U.S.'s position as the likely supplier to feed that growing demand. We expect U.S. upstream production to continue growing even without a significant increase in prices, creating a strong supply outlook for U.S. commodity exports.

Moving on to our Grand Prix NGL pipeline project. Grand Prix will connect our strong and growing franchise Permian Basin footprint to our very well positioned downstream assets at Mont Belvieu. It is a game-changer for Targa that bolsters our positioning by enhancing a highly competitive, fully integrated service offering to our current and future customers, leveraging each piece of the Targa value chain.

Over the long term, Grand Prix will provide significant and increasingly fee-based earnings, reducing our reliability and obligation to third-party pipelines, while helping to direct incremental volumes to our downstream facilities. Targa has the largest G&P position in the Permian Basin. And with good visibility on substantial growth in the future, significantly more NGLs will be directed to Targa's downstream assets. While further increasing the utilization of our existing downstream facilities, this presents attractive capital investment opportunities, including additional fractionation.

We believe that our partnership with Blackstone and NGL dedication and commitment from EagleClaw is a beneficial transaction for our shareholders and a great deal for Targa. We were very openly public that we were considering a number of different opportunities related to a joint venture on Grand Prix or alternative NGL pipes, and the transactions that we announced strongly fulfilled our stated goals to retain the strategic benefits of an NGL pipe connecting to our G&P and Downstream Business and to enhance target economics and to derisk the project.

We reduced our capital funding obligation and identified a committed strategic partner that will drive higher overall project returns as a result of dedicated and committed volumes they will bring to the pipeline over time. We also continue to add other third-party customers and are very pleased with our progress since announcing the project in May.

As the expected volumes flowing through Grand Prix increase over time, we will realize significant fee-based cash flow from the asset, with returns for the stand-alone project ultimately somewhere between 5 and 7x CapEx as a multiple of EBITDA, potentially reaching those levels more quickly depending on continued commercial success and pace of volume growth. These simplified multiples are not inclusive of any of the other strategic benefits of the NGL pipeline.

Overall, the outlook for Targa's Downstream Business is highly robust, driven by the continued integration with our growing G&P business and the flow of NGLs to our strong downstream asset position along the U.S. Gulf Coast.

And with that, I'll turn the call back over to Joe Bob.

Thanks, Scott. Hopefully, we were able to provide you with some color to support our view that there is a lot of positive momentum within Targa right now, supported by strengthening fundamentals and exemplified by the strong volume trends we are seeing in both our Gathering and Processing and Downstream segments at this point early in the fourth quarter.

The capital investment program that we have underway is expected to generate visible and significant growth in cash flows to our shareholders over the long term. And we believe that we have the balance sheet flexibility and demonstrated access to public and private capital to manageably fund our growth program. Our team at Targa remains focused on continuing to execute on our strategic objectives, and our team is working as a team better than I've ever seen it before, downstream with upstream, business units with other business units, commercial, engineering, operations, accounting, planning, it's inspiring. And that team is very excited about Targa's strong long-term outlook.

So with that, operator, please open up the lines for questions.

(Operator Instructions) Your first question comes from TJ Schultz from RBC Capital Markets.

I guess, first just funding plans, I appreciate the commentary for next year. The debt leverage at TRP at 3.7 now, I think, you said. What level are you comfortable taking this next year ahead of the cash flow ramp that you see in 2019?

I don't have a new guidance for you TJ. But if you've listened to us over the years, and I know you have, that 3 to 4x long-term target range is the zone that we try to stay in. It's not the monthly zone or the quarterly zone, but it is the zone we try to stay in. With a whole lot of visibility towards those future cash flows, increasing leverage at TRP, if it was 4.1 or something like that, I wouldn't feel any different, because it's improving over time.

But that is what we were talking about. Because we have visibility on increasing EBITDA, it gives us the option, the option over 2018 and into 2019 to fund our capital program with more debt than equity, unlike 2017 where we said we would overequitize it.

Got it. And then as we think about the ramp in 2019 with Grand Prix, with the JV in place now, your kind of current view on volumes, what's the time frame to get to that 5 to 7x targeted returns? Or just any general comments on the ramp we should expect?

Yes, general comment on the ramp. Take a little bit of a step back. When we first announced the project, what we told folks is that the Targa managed volumes by themselves were attractive economics. We didn't describe the exact ramp, but ramping Targa's managed volumes created attractive economics.

Since that time, the Blackstone and EagleClaw JV have added significant volumes, not near-term volumes, but longer-term volumes that make those economics a whole lot more attractive. And the addition of additional third-party volumes since we've announced the project are meaningful. If you've got attractive economics, an incremental barrel goes essentially straight to the bottom line, and that enhances our position.

I think what I'd say is we haven't pointed to the point where 5 to 7x, which is a simplified measure, as you know, of returns, occurs. But we went from nice economics to even nicer economics with the improving volume outlook, and we're continuing to add to that. Does that help?

No, that's good. I appreciate it. I'll just leave it there.

Your next question comes from the line of Shneur Gershuni from UBS.

I was wondering if we could sort of start off on the upside CapEx number of $1.6 billion. I was wondering if -- what would be the blue-sky scenario that would get us there? Does that include the participation net to Targa in the Gulf Coast pipeline as well as is Grand Prix adjusting for the investment that you got? I was wondering if you can also give us a sense on what type of volume growth we would need to see in 2018 that would give us that high end. If you can provide some sensitivities, that would be helpful.

I'll provide some additional color. First of all, the $1.6 billion is our current estimate of 2018 dollars for our currently announced major projects and associated infrastructure. It does not include GCX, which you mentioned. And I don't consider it to be blue-sky or upside. I consider it to be a good estimate of the currently announced projects at this time with the planning process still underway. And I said that there were other potential capital projects that we were working on that were not in that $1.6 billion 2018 estimate.

That -- those projects aren't really new or mysterious projects. They're projects that we've talked about in the past, and I was sort of laughing at myself for often saying, these projects are when and not if. That would include the very likely addition of more fractionation to keep up with those volumes.

You asked for a volume sensitivity relative to that. I would say if we continue on the range of forecast of current volume trends from the Permian Basin and the SCOOP/STACK and those resulting volumes as they go to ultimately our pipeline, but as they go to Mont Belvieu, that those projects, both on the G&P side and the fractionation side, are likely to create additional dollars in 2018. So it's not sensitivity, it's a direction. And that direction is we're very likely to spend more than $1.6 billion.

We're not trying to hide it from you. We believe that as we announce those projects in early 2018 or whenever they become done deals and ready for public exposure, we'll provide updates on our total CapEx at that time. And we'll provide sort of our traditionally detailed by major project and other related infrastructure summary in February of 2018. Is that helpful?

Yes, absolutely, it is helpful. As a couple of follow-ups, given where NGL prices and natural gas prices are today, do you have some sort of sensitivity on what you think the positive tailwind could be for 2018 versus 2017, given your current hedge position?

We show a -- 2017, I don't think we're sensitivity. I don't think we're yet showing a 2018 sensitivity. We did describe how much was hedged in 2018 versus 2017, so that probably gives you the ability to triangulate on it a bit.

Yes. And Shneur, the only other point that I would add is, for 2018, that's based on what our current equity volumes are. So to the extent that obviously we have more volumes running through our system, from our POP contracts, our equity volumes would be higher during 2018. So that would be additional potential upside that isn't reflected when we give you these hedge statistics.

Great. That makes perfect sense. And then one last follow-up. There's been a lot of talk about completion crews in the Permian being a challenge. I was wondering if you could opine on whether you think this issue is overreported as a bigger concern than it actually is. And maybe if you can talk to what you're seeing both on your legacy Targa footprints as well as on the Outrigger footprints in terms of rate of change on completion crews.

The completion crews on legacy assets versus recently acquired assets, I don't have a differentiation on it. Larger players have better access to crews than some of the smaller players. And if you've contracted for rigs or pumping equipment, you've also somewhat contracted for those crews.

We've said over previous quarters that we believe that there was issues with equipment and workforces. That was a frictional slowdown to the more robust forecast that you might read out there from various analysts. And that we, therefore, thought you don't want to be looking at the high size of all of those forecasts because of those frictional constraints. But the fact is excellent economics in the Permian Basin incent additional equipment and incent the people with the equipment to get the crews back to work. Ultimately, those problems get solved.

And so in the third quarter, was it any better than the second quarter?

That would -- I would be pretending to have a greater granularity than I've got to describe one quarter versus the other. By producers -- I know I heard some of the same issues in the third quarter that I heard in the second quarter.

And to be fair, no would be the answer. It's not materially different. And honestly, as Joe Bob mentioned, we have an awful lot of producers that have the longer-term agreements and have the ability to bypass the issue that some of the smaller players are experiencing. And certainly Pioneer has their own drilling rigs, their own completion rigs and their own sand mines.

So them being one of the bigger players in our system, the XTOs, the Chevrons, the COGs, the Parsleys, et cetera, all those guys have a lot of capabilities. Now we do have a lot of other players that are contracted to us. And some of the issues have been minimal, but have been there. But with that, they've also had better results than what were expected. So fewer wells are producing really lookalike volumes to what were expected relative to the slowdown they're seeing as far as completion rigs, et cetera.

Yes. That kind of punctuates the volume growth you're seeing quarter-over-quarter. And we certainly wouldn't be sounding the alarm that, that kind of quarter-to-quarter improvement can't continue. And we said, I hope loudly and clearly, that our 2017 volume expectations are on track, both for the Permian and for our overall Southern Field Gathering and Processing, overall Field Gathering and Processing.

Your next question comes from the line of Vikram Bagri from Citi.

I believe I heard a comment about market-driven approach for dividend going forward. I just wanted to better understand that comment, if you're maintaining a healthy coverage at all times, given the recent announcements by some of your peers? Or is it more of a function of capital needs and you're retaining more cash flows, potentially including the ATM if your capital programs grow significantly from $1.6 billion?

Understood, Vikram. I mean, there have been recent company-specific-driven announcements and approaches over the last quarter. And I guess, it all started some time ago when Kinder cut a dividend just day investment [grade]. And the dialogue has continued in between those points.

What we said was that our approach was not going to be any different than it has been in the past, that our improved leverage and coverage outlook will be taken into account in the future dividend discussions. And I hope what everybody heard was, EBITDA is increasing. It's very visible that it's an increase and when we're talking about that in 2019, we will have significantly improved leverage and significantly improved coverage to discuss with our board. And we will be looking for the best use of that higher coverage to most effectively provide for our shareholders.

And yes, we will take into account other market-driven approaches to pay out what other companies have done in the market and what the market's reaction is. But our signal is we're playing this game the way we played in the past. I said it would be a very appropriate assumption to assume that our $0.91 per common share dividend per quarter would be what we were recommending in 2018, all other things being equal.

And I said that it gets increasingly attractive after 2018 if you look at our projected long-term outlook and performance and the drivers behind that performance. And in fact I was telling you that since June, we feel better about that long-term outlook than we did in June. Does that help?

Understood, yes. The second question I have is about the Downstream Business. Excluding the impact of Harvey, it seems like frac business had sort of a record quarter. And as you mentioned, fractionation expansion is more likely now. I was wondering what -- given the visibility into growth in volumes, what keeps you from expanding -- announcing the expansion on frac?

And once you announce frac, I believe your capital program will get closer to $2 billion. So would you look to fund a portion of that through a preferred -- perpetual preferred sort of a security, given the gap in cost of capital between preferreds and commons? Or how would you look to fund the equity portion?

First, let's have Scott describe how he's thinking about the fractionation. Then I'll come back to the funding.

We certainly characterize that we believe, at least from the perspective of third quarter to fourth quarter, that volumes will be up on the fractionation side of our business from third quarter to fourth quarter. And with the continued growth that we see on our upstream business, feeding in from our G&P side and as well as success that we're having on the third-party front with fractionation agreements, we will continue to see growth in that.

We have continued to -- continuously characterize that it's a matter of when, not if, when we will add additional fractionation capacity. And as Joe Bob indicated, when we start looking at capital budgets and we make somewhat references to those when we start trying to lay out what we believe 2018 looks like going forward. So clearly for us, it is just a matter of time before we formalize some activity as it relates to fractionation.

And relative to the funding, I don't want to mischaracterize your question, but sort of simplifying it. Would we do a preferred, given the parent cost of capital of a preferred versus the parent cost of capital of a common equity, that's sort of 2 of the alternatives we mentioned. And I don't think I'll get in a debate on this call about what those specific costs of capital are.

But believe me, we're thinking about all kinds of alternatives. I believe what we said was that our traditional combination of public debt and public equity is part of the mix. We also said we would consider private capital and continue to consider creative joint ventures and potential sales of portions of our assets, as we've done in the very recent past, as illustrated by the Grand Prix JV. And I said, only because the incoming is pretty high, that there is a lot of appetite for private capital to participate in the Targa story.

So we will look at all of those various options and alternatives and recognize it maybe for a specific project, like the JV was for Grand Prix, or a discrete set of projects. And when we're thinking about our whole capital funding needs, it kind of becomes more homogenous. It's not this dollar for this project. We do believe that the 2018 capital lift of some portion of that $1.6 billion or more than $1.6 billion is very manageable, given the alternative sources of capital that we've got and our access to the public market. And we continue to demonstrate that.

Your next question comes from the line of Darren Horowitz from Raymond James.

Joe Bob, on Grand Prix. Just based on the 800 million cubic foot a day of processing capacity that you guys are adding and your math about what that translates to in terms of Y-grade plus EagleClaw's dedication growth and how that builds over time, how much more confident today are you that Grand Prix gets expanded up to 550 versus 6 months ago? And what would be the incremental CapEx to get it up there?

I congratulate you on the new ask of the question on what our volumes are going to be.

It's my job.

It made me smile. I've been careful not to create a volume ramp there. And the nominal 300 million a day -- 300,000 barrels a day, which doesn't require a whole lot of pumping, it doesn't require much capital to go above that. That's a high-class problem.

Our outlook, you mentioned EagleClaw, that's more back-end-loaded. It's not very near-term-loaded. And some of the Targa volumes take time to be moved from one pipe to the Targa pipe. We're very comfortable with the ramp. We haven't defined it for investors. We've defined it as a return that's attractive. And with very high visibility to that attractive return.

And each incremental deal we get done just makes it that much better. We are not ordering additional pumps yet. That's probably the best thing to say. But by the way, there's not a shortage of them.

And that's really all it takes is just additional pumps.

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

Just a -- I guess, one question just on leverage in light of your comments about kind of tilting the debt-equity funding back a little more towards debt versus over equitizing in '17. I think we all understand the -- the way you are versus your covenant. But you had in the last, I guess, few quarters talked about a goal of reducing your consolidated leverage over time. And so I just want to get your view on kind of where that stands vis-à-vis your comments about tilting more towards debt.

And I appreciate the question, because I would not want the comment to say, I don't have a longer-term goal of moving the consolidated leverage more to that 3 to 4. We did, but it is a longer-term goal. And the time to be moving that consolidated leverage to 3 to 4 is not during that time of rapid EBITDA build. It's after we get some of that rapid EBITDA build, it will become natural. So in terms of the funding lift, that's completing projects that bring the EBITDA. I would say that, that consolidated goal is outside of that strong initial ramp, and it's not part of my 2018 plan.

Yes. Right now, Michael, we're about 4.4x on a consolidated basis. And as the growth projects that are underway come online, we would sort of naturally get into that 3 to 4x if nothing else changed.

Your next question comes from the line of Colton Bean from Tudor, Pickering, Holt.

Just a quick one to clarify the -- I guess, clarify the comments on the financing plans. I think you mentioned the possibility of some farm-ins. Is that the thinking more along the lines of CapEx projects or potentially existing assets as well?

If I said the word farm-ins, I did not intend to. Sometimes I don't speak clearly. I spoke of the potential appetite of private capital. I spoke of potentially doing joint ventures like we did for Grand Prix. I spoke of lots of incoming, and therefore, we're paying attention to it. I don't recall something that was how I would define a farm-in. In the E&P world, a farm-in means that someone is coming into your assets, your properties, being the operator and working to earn an interest. I was not meaning to imply that.

Yes,that may be a poor choice of wording there. But more so the question around buying an interest in existing assets versus exclusively growth projects.

I think it's a broad category, the one I -- the only one I can point to is, where primarily growth projects, we've done a recent JV with Sanchez, we've got a JV in the Grand Prix pipeline, we're doing a JV for the GCX project. It's possible, you could have a similar kind of venture in and around an existing asset, or the utilization of an existing asset. To some extent, that's what we did in South Texas.

Right. Got it. I guess, one follow-up to -- so pretty strong volume performance across the G&P system. Specifically thinking on the Mid-Con assets here, the legacy system, probably say, is not in the prime positioning to capture some of the volume growth that we're seeing, and yet, the volumes are consistently showing up. Can you guys just touch on, I mean, without getting into too much competitive detail, what the commercial efforts are there and how you're securing volumes to your system?

You were pointing to the Mid-Con piece?

Yes, thinking SouthOK, WestOK.

Yes. Let's talk about Oklahoma broadly, both for the SCOOP and the STACK and sort of clarifying the question, I think Pat has got a handle on that one. All I would say is I really, really like it. Go ahead.

All right and you're right. We're seeing growth on what we call the Cardinal system, the old (inaudible) Cardinal system. We're seeing pretty good significant volume growth on that system. And then growth in the SCOOP. We mentioned in our prepared comments we had built a 24-inch pipeline that was bringing on a lot of incremental SCOOP volumes and it has, and those volumes are flowing. And it also was a component of positioning for a long-term acreage dedication that will get developed over time in the SCOOP that brings us some longer-term vision relative to volume growth on the Southern Oklahoma system. So we feel good about where we are at and the commercial efforts and what should develop over time on the SouthOK side of Oklahoma. On the Western Oklahoma side, we've also had really good commercial success. Certainly, the historic Mississippi line and the rate of growth that we had over several years when those assets were part of Atlas is not what we're seeing now. But the Meramec and the development south and east and west of our -- the western side of our WestOK system, we've been very successful in adding a lot of acreage dedication. And we're getting a higher activity level on that acreage. And where we have seen a decline in volumes across WestOK and we did for the calendar year '17, we will. In '18, I'm not going to tell you that we're going to grow, but certainly, we have stemmed the tide. And we see opportunity with the expected drilling level that has been talked with us about by our producers who we're very close with, that there is opportunity for good volumes added to that WestOK system.

I want to add a visual for everybody. When you take the legacy systems and you plot them against the map like the Mississippi line, you say, that's not where it's hot. The new pipe has been edging into where it's high into the Meramec, et cetera. Same thing is happening in SouthOK moving to the north. That extension of pipe is accessing the hot area gas. Now we can't get to all of it, but we're getting to some of it. That brings it back to our existing processing plants. Frankly, we're redeploying compression where it's not needed in a declining area and picking it up and moving it to where it's needed in a growing area. It's a redeployment that just makes me smile. And SouthOK going from declining to now positive, which is the net of the legacy assets, it's not a plan, it's not a goal, but boy, it would be good if we got WestOK to do that also, maybe in 2018, maybe in 2019.

Your next question comes from the line of Jeremy Tonet from JP Morgan.

This is Charlie in for Jeremy. Just back to Gulf Coast investment, just -- I guess, another way to look at it is the kind of net proceeds from Grand Prix and investment in Gulf Coast. What's the net number there? Is that 0, positive, negative?

Yes, that is another way to think about it. It's not how we're thinking about it. Kinder Morgan has not described the cost of the GCX project, to my knowledge. And as I read their transcripts, I think they said it was somewhere between $1 billion and $2 billion. And we've got 25% of that. The cost savings in our Grand Prix pipeline are meaningful to us. They're not of dissimilar magnitudes, I guess, if you were trying to link the 2 together. But the strategic decisions are completely independent. We did what we said we would do on our Grand Prix pipeline, which is maintain our strategic benefits, enhance the economics and derisk it. It's just the perfect thing to do. And we're doing what we need to do on the residue side, which is to get access or target in our customers from the Permian Basin to Gulf Coast markets. And believe this is the best project to do it with and we like having a aligning equity participation with our other partners. That's how it works out. Net-net, it's relative to some capital dollars, one went down and one went up. That's kind of good thing overall relative to our financing needs, but we weren't trying to match the 2.

Okay. I guess, just 2 quick questions. The $40 million of cash from Noble, did you get that -- did you get that payment for this quarter yet?

Yes.

Yes, we did.

Okay, great. And then just lastly on -- just any commentary on -- and I apologize if I missed it. But just kind of looking at general ethane rejection levels relative to last quarter and kind of what you're seeing so far this quarter?

Yes. We actually look at ethane level graphs and that certainly moved all over the place. You know it was just the hurricane that we had enormous ethane rejection as a function of operational needs and requirements. And now it's at relatively high levels for the -- incoming to our facilities combined. And that was over a very short period of time. Every operator has the ability to turn those knobs on a weekly, if not daily, basis. And we sort of catch the result of that. I believe there is a trend. I believe there is a trend towards us receiving a higher and higher percentage of ethane as a part of the stream. That's a natural economic trend. That trend is somewhat times distorted by economic decisions that have to do with some costs. And every individual player can be in a different position, and we received the aggregate amount of that.

Yes. The only thing that I would to that, Joe Bob is just somewhat paraphrasing, the trend is moving upwards, albeit you might see distinctions from day-to-day a little bit different, up, down. But again, when you point to the expansion growth that we're seeing on the petrochemical side of our business, you would expect that trend to continue, albeit we will see increased production during those same time frames. So we are seeing from day-to-day different types of anomalies in the marketplace as it relates to ethane recovery, but in general, the trend is moving with more increased recovery.

I guess, one more on to that. I know that you have ethane, propane feedstock agreement that will start with one of your customers that should be starting up their plant this quarter. Are conversations about additional back-end capacity, are those happening with any of the plants that are coming on between '18-'19 or are the conversations more so further dated or any of the second wave of crackers?

No. There are continuous conversations going on with all of the petrochemical expansions that are going on. We obviously have a significant connectability to existing plants. As plants are expanding, they're looking to upsize their capacities into the facilities to ramp up over time relative to what the demands look like. You would expect as a result of Hurricane Harvey that some of those expansions might be slightly delayed, but overall, increase connectability or enhanced connectability are -- is happening. We allude to that when we talk about some of our CapEx spending that we are doing some things on the downstream side to enhance those types of deliveries.

Your next question comes from the line of Danilo Juvane from BMO Capital.

Just as a follow-up on the conversation around a potential incremental frac facility, just want to understand the utilization is actually still roughly 75% in Mont Belvieu, maybe low 60s overall. Is the need for an incremental frac facility imminent or is this something that we're thinking about doing over the next 2 to 3 years?

I would say that it is highly likely that fractionation expansion will happen in and around our assets and that it is just highly likely. Again, restating what we've continuously said and that it's a matter of when, not if. But again, certainly when you look at the growth that we've got with our own assets on the G&P side and the increased production across the Permian and other areas, we will see fractionation expansion happening.

Yes, on the fractionation utilization number you're looking at is a little bit of a rearview mirror. We gave you -- you may not have done the calculation yet, but we gave you what the normalized fractionation would have been in the third quarter without the impact of Hurricane Harvey. Those kind of quarter-to-quarter increases -- and they're not magic. They are coming from the Permian primarily and other basins that are growing create or increase the utilization fairly quickly.

Fair enough. I appreciate that. And secondly, Joe Bob and maybe Jen can chime in as well. Just it looks like 2018 gross CapEx maybe north of $1.6 billion. And I'm thinking about, I guess, bringing the conversation back to funding, does it make sense, Joe Bob, to maybe revisit a potentially rebasing the dividend, keeping the debt metrics where they are, and lessen the need for equity next year, just given how people are migrating towards more of a self-funding model?

There has not been a lot of migration to a self-funding model. I was trying to remember, I think you're around that dinner a couple of years ago, at the Wells Fargo conference, right after Kinder who wasn't there, reduce their dividend. I've had some of the same investors giving me both sides of what to do with the dividend since then. Our discussion today was supposed to be clear that whereas in the long-term future, we'll look at what to do with the higher coverage, lower leverage. And yes, we'll be paying attention to what other market-driven volumes are, that we do not have an intention or that it will not be a better assumption for 2018 to assume that we were still recommending the $0.91. Financial theory says you might slightly modify or optimize the cost of your capital by funding less with the dividend. At the same time, our attention is primarily on the projects, which are well above the cost of capital for a model that included this dividend, a slightly higher dividend or a slightly lower dividend. And that's what our focus is on. I also believe that in this space, the impact of a decreased dividend cut has an amplifier that we certainly aren't looking to baying on. We have maintained the $0.91 dividend since 2015 and I forgot the month, third quarter of 2015. Through some much more difficult times than we're currently in. For Targa, we believe that it is the right answer.

There are no further questions at this time. I turn the call back to the presenters.

Thank you very much, operator. If you should have any other questions, please feel to reach out to Sanjay, Jen or any of us. We appreciate your time and attention today. Go Astros.

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