Good day, ladies and gentlemen. Welcome to the Targa Resources Corporation's third quarter 2018 earnings webcast and presentation. At this time, all participants are in a listen only mode. Following management's prepared remarks, we will have a question and answer session. Instructions will be given at that time. If anyone should require assistance during today's conference, please press star then zero on your telephone keypad. It is now my pleasure to turn the conference over to your host, Sanjay Lad, Director of Investor Relations. Please proceed.
Thank you, Hailey. Good morning. Welcome to the third quarter 2018 earnings conference call for Targa Resources Corp. The third quarter earnings release for Targa Resources Corp., Targa, TRC or The Company, along with the third quarter earnings supplement presentation are available on the investor section of our website at targaresources.com. In addition, an updated investor presentation has also been posted to our website. Any statements made during this call that might include the company's expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor 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 31st, 2017. Subsequently filed reports with the SEC. Our speakers for the call today will be Joe Bob Perkins, Chief Executive Officer; Matt Meloy, President; and Jennifer Kneale, Chief Financial Officer. We will also have the following senior management team members available for the Q&A session: Pat McDonie, President, Gathering and Processing; Scott Pryor, President, Logistics and Marketing; and Bobby Muraro, Chief Commercial Officer. Joe Bob will begin today's call with a few highlights, followed by Matt, who will provide an update on commercial developments and business outlook. Jen will discuss third quarter 2018 results and wrap it up before we take your questions.
With that, I will now turn the call over to Joe Bob.
Thanks, Sanjay. Good morning. Thank you to everyone for joining. For the third quarter, Targa achieved its best operational and financial quarter in our history, positioning us to exceed the top end of our previously disclosed full year 2018 financial guidance, and more importantly, providing positive momentum for 2019 and beyond. It's been a busy couple of months at Targa since our last call. During that short time, we successfully brought online our 200 million cubic feet per day Johnson plant in the Midland Basin. The Johnson plant was highly utilized at startup. We continued startup activities at our crude and condensate splitter at Channelview. We are now in hot startup. We closed on a $160 million asset sale of some of our petroleum logistics business. We raised about $200 million from the issuance of common equity under our ATM program.
We recently began startup of our 150 million cubic feet per day Hickory Hills plant in our South Oak system. Our major projects underway remain on track, and many of these projects will be completed by the end of the first half of next year, which is now less than 8 months away. We are working to complete all of our projects as quickly as practicable to help meet the increasing gas processing, NGL pipeline takeaway, fractionation, and export services needs of our customers. Fundamentally, the robust near and longer term outlook for domestic production volumes from our basins and the outlook for crude and NGL commodity prices are providing continued tailwinds for our businesses and are leading to the high utilization of Targa projects recently completed and those underway. Those same tailwinds are expected to continue to drive the need for additional Targa infrastructure.
On that note, today, I'm sure you noticed that we announced we are moving forward with the construction of 2 new fractionation trains in Mont Belvieu, Targa train 7 and 8, which will add an incremental 220,000 barrels per day of much needed frack capacity in the year 2020. We recently received permits for the fractionators and, as discussed in our last earnings call, have already ordered long lead time items to prepare for this. These additional projects align with our key strategic focus to continue to invest in attractive projects that leverage our existing infrastructure and further strengthen our competitive advantage and to continue to identify and pursue additional opportunities to further integrate our existing asset base. Both of these further enhance our attractive long-term outlook.
The combination of our integrated asset footprint and our continued commercial success drive the need for incremental growth projects, which underpin the attractive long-term outlook that we first presented in June of 2017. Since that time, as we previously described and listed, Targa continued to execute on commercial agreements and added projects that were additive to that published outlook. I'll resist the urge to repeat the long list of published deals and projects since June 2017, and of course, there were other smaller projects and deals that we didn't publish. With that progress over the last 17 months, we now estimate adjusted EBITDA to be significantly higher than shown in the June 2017 outlook. We have now provided you with a refreshed November 2018 outlook posted to our website this morning.
For example, if you look at that outlook, this November 2018 version has estimated 2020 adjusted EBITDA of about $2 billion. That about $2 billion level in 2020 is occurring one year earlier than when we first published in June of 2017. We are also providing our preliminary 2019 estimated net growth CapEx of about $2 billion, with growth CapEx declining significantly in 2020 and 2021. We are currently forecasting 2020 plus 2021 CapEx to be about an aggregate of $1.8 billion total. That $1.8 billion two-year forecast total is inclusive of spending on three more processing plants after the Pembrook plant and one additional frack after recently announced train seven and eight. We are providing this update to help investors better understand the significant incremental and aggregate growth from the previous outlook and from the incremental announced projects and commercial success since that time.
My bet is that consistent with the stated assumptions of this outlook, it will confirm the modeling of those who study us closely. The outlook update also shows our hardworking Targa employees what they have accomplished together over the last 17 months. This is a really exciting time to be an employee at Targa, and it is also a really exciting time to be a long-term shareholder in Targa. With that, I'll now turn the call over to Matt.
Thanks, Joe Bob, and good morning, everyone. Commercial activity and production in many of our operating regions is continuing to increase, and we expect this positive trend to continue. In the Permian Midland, our Johnson plant came online late September and was quickly highly utilized. The 250 million cubic feet per day Hobson plant remains on track to begin operations in the first quarter of 2019 and is also expected to be highly utilized at startup. The next 250 million cubic feet per day Pembrook plant is expected to be complete in the second quarter of 2019. With continued strong production growth outlook in the Permian Midland, we have been proactively ordering long lead items for the next plant.
Each of these plants will be interconnected to our multi-plant, multi-system Permian footprint, with the majority of the NGL volumes flowing through Grand Prix and to our fractionators in Mont Belvieu. In the Permian Delaware, producer activity remains robust, with inlet volumes increasing 13% over the second quarter. Construction continues on our 220-mile high-pressure rich gas header system, which will run through the heart of the Delaware Basin. A significant portion of this pipeline will be complete by the end of this year, with the remainder being completed in phases throughout 2019. In the Badlands, our Little Missouri complex is operating at capacity, and our LM4 plant is expected online in the second quarter of 2019 as the timing of critical equipment availability pushed on-site construction into the winter months. Gas Gathering and Processing and crude gathering are expected to remain strong in the current commodity price environment.
Turning to the downstream business, construction on our Grand Prix NGL pipeline continues. The project remains on time and on budget, with the pipeline expected to be fully operational in the second quarter of 2019 to support NGL takeaway from the Permian, Southern Oklahoma and North Texas. Our outlook for Grand Prix continues to strengthen, and we have begun ordering long lead items for the pipeline's prospective expansion. Which we expect will increase capacity of the segment originating from the Permian to approximately 400,000 barrels per day in as early as 2020. We will significantly expand Grand Prix's capacity with low-cost pump station additions incrementally as required, which further enhances the project's long-term value. The fractionation market is extremely tight. Our facilities in Mont Belvieu continue to run at capacity.
We are utilizing our Lake Charles facility to enhance our operational flexibility. We welcome the addition of our train 6 fractionator, which will begin operations in the early second quarter of 2019. Train 6 was targeted to start operations in the last part of Q1 and has now shifted to the first part of Q2. We expect the fractionator will be fully utilized at startup. With a robust outlook for increasing Y-grade NGL supply to Mont Belvieu, especially from the Permian Basin, and accelerating customer demand for fractionation services, as Joe Bob mentioned, we are moving forward with construction of two new 110,000 barrel per day Targa fractionation trains. Trains 7 and 8 are expected to be online in the first and second quarter of 2020, respectively.
Trains 7 and 8 and related infrastructure are estimated to have a total cost of $825 million, a little higher than our previous average fractionator cost. These expenditures also include some infrastructure for the future. We expect to generate very attractive fee-based returns on these projects, supported by increasing Targa Gathering and Processing volumes, complemented by long-term contracts with producers and other third parties. In addition, much of the volume feeding our fractionator expansion will be supplied by our Grand Prix Pipeline, underpinned by long-term contracts. During this period of market tightness for fractionation services, we are continuing to provide flow assurance for our Gathering and Processing and downstream customers. We expect frac market tightness to persist into 2020. Given the strong outlook for continued volume growth thereafter, we expect the frac market to remain strong going forward.
In support of continued supply growth of NGLs, we are ordering long lead time items to increase our refrigeration capacity and load rates to further enhance our LPG export capabilities at our Galena Park facility. We now estimate that this enhancement, along with previously announced additional pipeline between Mont Belvieu and Galena Park, our effective export capacity of 7 million barrels per month, would increase by approximately 50%, depending upon the mix of propane butane demand, vessel size, and availability of supply, among other things. Given our existing capabilities, this enhancement would come with relatively low cost and is already included in our 2018 and 2019 growth capital guidance. We remain in active dialogue with existing and prospective customers for additional contracted offtake. We have added some additional contracted volumes and are working to add additional volume and term.
Construction on the Gulf Coast Express residue gas pipeline, or GCX, continues, and the project remains essentially on time and on budget, with the pipeline expected to be fully operational in the fourth quarter of 2019. Additionally, we are continuing to make progress on commercializing the Whistler Pipeline, which would provide incremental residue gas takeaway from the Permian to support the forecasted infrastructure needs of the basin and provide strategic receipt, delivery, and access to premium markets for our customers. Our projects underway bolster our integrated midstream service offering to our customers. We remain on track to bring online a substantial portion of our organic growth projects currently under construction, including a number of processing expansions, Grand Prix, and Frac Train Six over the next eight months, which provides us with increasing line of sight to significant growth in adjusted EBITDA and cash flow in 2019, 2020, and beyond.
Targa remains committed to continuing to provide our customers with best-in-class service and reliability. With that, I will now turn the call over to Jen to discuss Targa's results for the third quarter and provide a financial update.
Thanks, Matt. Good morning, everyone. Targa's reported record quarterly adjusted EBITDA for the third quarter, $358 million, which was 29% higher than the same period in 2017, driven by continued strong gathering and processing volume growth, higher commodity prices, and higher downstream fractionation and LPG export volumes. Sequentially, adjusted EBITDA for the third quarter increased 10%. We received the annual $43 million payment related to our crude and condensate splitter agreement in late September, increasing distributable cash flow for the third quarter to $287 million, resulting in dividend coverage of 1.24 times. Without recognition of receipt of the splitter payment, which has previously been paid and recognized in the fourth quarter, dividend coverage for the third quarter would have been 1.05 times. The sequential increase in operating expenses was attributable to the system expansions we have underway and the staffing of our new facilities.
In our gathering and processing segment, operating margin increased $13 million in the third quarter when compared to the second quarter, driven by higher natural gas inlet volumes in the Permian, Badlands, South Oak, West Oak, and coastal regions, and higher crude oil gathered volumes in both the Badlands and Permian. Third quarter Permian inlet volumes increased 6% over the second quarter from growth in each of our Permian Midland and Permian Delaware systems. Badlands natural gas volumes increased 5% over the second quarter, with our Little Missouri facility operating at full capacity. Inlet volumes in South Oak increased 3% over the second quarter as a result of continued growth in the Arkoma and Scoop regions. West Oak inlet volumes increased 2% from increasing volumes from the STACK. During the third quarter, South Texas inlet volumes decreased 12% as a result of flooding from a high level of rainfall.
Volumes have since returned to levels prior to the flooding. Our third quarter crude oil gathered volumes in the Badlands increased 16% over the second quarter, driven by strong production growth across our dedicated acreage. Permian crude volumes gathered in the third quarter were up 13% over the second quarter. The improved performance in our coastal G&P business has been predominantly driven by higher inlet volumes, richer gas, higher recoveries, and higher NGL prices. In our logistics and marketing segment, operating margin increased $44 million in the third quarter when compared to the second quarter, driven predominantly by higher fractionation margin and higher LPG export margin. Fractionation volumes increased 10% sequentially, averaging 455,000 barrels per day in the third quarter. At our Galena Park facility for the third quarter, we averaged 6.4 million barrels per month of LPG exports.
We are very pleased with our operational and financial performance year to date and expect to exceed the top end of our previously disclosed full year 2018 adjusted EBITDA guidance. With full year 2018 dividend coverage also on track to exceed 4.0 times. Moving to other finance-related matters, the fair value of the earn-out payments for our Permian acquisition is currently estimated to be $329 million, with the payment payable in May 2019. The $17 million increase in the contingent consideration compared to the second quarter estimate was driven by a shorter discount period. During the third quarter, we executed additional hedges for Targa's percent of proceeds equity commodity positions. Based on our estimate of current equity volumes from field gathering and processing, for the remaining quarter of 2018, we have hedged approximately 95% of condensate, 80% of natural gas, and 75% of NGLs.
For 2019, we estimate that we have hedged approximately 75% of condensate, 65% of NGLs, and 60% of natural gas volumes. At the end of the third quarter, our consolidated liquidity was approximately $2.6 billion. On a debt compliance basis, TRP's leverage ratio at the end of the third quarter was approximately 3.8 times versus a compliance covenant of 5.5 times. Our consolidated reported debt-to-EBITDA ratio was approximately 4.5 times. In October, Standard & Poor's upgraded our credit rating to double B flat and raised the outlook to positive. Given the new projects announced today, we now expect 2018 net growth CapEx to be approximately $2.4 billion, with about $1.9 billion spent through September 30th. Full year 2018 net maintenance CapEx is now forecasted to be approximately $110 million, with $79 million spent through September 30th.
Looking forward, as Joe Bob mentioned earlier, our preliminary estimate for 2019 net growth CapEx is around $2 billion. Year-to-date, we have raised about $1 billion of capital through a combination of joint ventures, asset sales, and common equity issuance under our ATM programs. Similar to 2018, looking forward to 2019, we expect to continue to utilize a multifaceted approach to fund our growth capital program with the benefit of having additional flexibility from higher EBITDA year-over-year, as many key projects come online over the relative short term, and we will also have greater flexibility given our visibility to EBITDA continuing to increase beyond 2019. Additionally, as announced this morning, we are already in process with a select small group of counterparties to potentially sell a minority interest in our Badlands assets. Targa will continue to operate and commercialize the assets.
We have a very strong team of employees in North Dakota and a very attractive long-term growth outlook for the business. Given the fee-based nature and long-term nature of our Badlands contracts, the strong performance of the assets, and the improving outlook in the Bakken, we believe that monetizing a minority interest portion of this asset provides significant potential benefit to Targa without sacrificing operation or strategic control of the assets. We remain focused on continuing to proactively finance our growth program to maintain balance sheet strength and flexibility.
As Joe Bob described earlier, if we look back to June 2017, when we first published a long-term outlook that illustrated that Targa's EBITDA was expected to double from 2017 to 2021. Consider all that we have executed on since then, including some minuses to help finance that growth, like asset sales and joint venture interest sales, it is fair to say that the outlook for Targa is very strong. Our long-term outlook refresh, published this morning, highlights an expectation of rapidly increasing EBITDA from 2019 through 2021. The forecast assumptions are consistent with what we put out last June and do not include any unidentified projects, any assumed continued commercial success, or any assumed continued spot contract margin in our LPG export business.
We are including three not yet announced but highly likely incremental Permian plants over the forecast period and an additional fractionation train, Train 9, estimated online in mid-2021, reflecting the need to handle expected volumes from already existing commercial agreements. We also highlight a list of additional growth opportunities which are not included in the outlook for beyond 2021. Some of which are very tangible, like the acquisition of our DevCo JV interest, and others that are less tangible sitting here in 2018, but are wholly expected that will require continued strength in fundamentals, Targa execution, and commercial success. This outlook reflects our expectation of rapidly increasing EBITDA, which will result in a stronger balance sheet with increasing dividend coverage and additional free cash flow.
Our current focus remains on executing on what we control, getting our projects in service on time and on budget, continuing to perform commercially to add incremental opportunities in our underlying businesses, and financing our growth in a prudent manner. With that, Hailey, please open the line up for questions.
Thank you. Ladies and gentlemen, at this time, if you would like to ask a question, please press star then one on your telephone keypad. If you would like to remove yourself from the question queue at any time, please press the pound key. Once your question has been stated, we ask that you please place your line on mute to prevent any background noise. In the interest of time, we ask that you please limit yourself to one question and one follow-up question only, and to re-queue if you have any additional questions. Our first question comes from Shneur Gershuni of UBS. Your line is now open.
Hi, good morning, guys.
Hey, good morning.
With all the great information that you've put out today, I kind of hate to start with such a technical question. When I look at your guidance for 2020 and 2021, as I believe you said in the prepared remarks, this doesn't assume the buyout of the JV. So if we were to compare it to your original guidance pre to DevCo, on an apples-to-apples basis, the number would actually be higher than where it is today by, who knows, $100 million or so. Is that sort of the correct way to look at it, if we were to sort of look at it compared to how it was before you laid everything out with the DevCo?
That's exactly right, Shneur. If you think about the DevCo interests, obviously, and some of the JV partial interest sales that we've done or JVs of assets, those were not factored in previously. Obviously, on an apples-to-apples basis, this outlook would be higher if we assumed that we hadn't done any of those joint ventures, or also if we hadn't executed any asset sales, obviously.
Perfect. Thanks for the clarification on that. Just two quick questions here. Given how tight the environment is today, specifically on the fracs, but in other areas as well. As you FID new assets and are added to the backlog, how have contract discussions gone? Are you getting longer terms and higher fees? Are you sort of able to translate the strength of this market into better terms and ultimately higher returns overall?
Yeah. Good question. We are getting, obviously, a lot of incoming with regards to fractionation and related services for our downstream assets. We are more focused on long term. The fractionation deals that we have currently are typically longer term by nature, 10 years or even longer for some. For Grand Prix, they're long-term contracts as well. We are working with our customers that may have short-term needs, mid or longer-term needs, and trying to work with them to provide the fractionation or transportation services, but do that for longer periods of time, not just shorter term.
That makes sense. Just one last follow-up. Several of your peers during earning season have talked about they've been able to turn screws to eke out some more capacity out of their fracs and some workarounds on their NGL lines. I assume you're doing the same as evidenced by your LPG announcement today. Do you see any additional brownfield opportunities in your fracs or elsewhere where you can achieve those very high returns that are better than your typical five to seven average?
Yeah. We're always looking at our assets to see how we can potentially increase capacity. We are utilizing our Lake Charles frac even more, so we're moving more wide open there to frac. We've also done just some minor, you can call it turnarounds or additional work on our Mont Belvieu facility as well. We did a small one this summer when we took it down for a little while to be able to increase reliability and runtime. We have some other things like that on the drawing board, which we may be able to do as well. Those are relatively small increments of fractionation capacity, but with how tight the market is, we are turning over all the rocks to see where we can find any additional capacity.
We actually referred to some of those projects in a previous call, and we didn't talk about a multiple metric. I think we would go so far as to say it was almost infinite returns.
Yeah. It's not much capital. It's just bringing the frac down for a little while.
Perfect. Thank you very much, guys. Really appreciate the color.
Okay, thanks.
Thank you. Our next question comes from Colton Bean of Tudor, Pickering, Holt & Co. Your line is now open.
Morning. Just to start off with the updated financial outlook, looks like 2019 EBITDA should be somewhere in the range of $1.5-$1.7. Can you just provide a bit of color as to what would bias you to one end of the range versus the other?
I think from our perspective, we've spent a lot of 2018 talking about tightness in various places around the country that could potentially impact part of the business. If you think about Permian constraints and issues that could potentially slow down producer activities, that could be one. Obviously, commodity prices are a big variable as well, Colton. If you think about some of the higher commodity prices that we experienced in Q3, to the extent that we enjoyed similar appreciation of prices throughout 2019, obviously, that would trend towards the higher end of guidance. Obviously just activity levels around our system and around our assets.
Okay. Makes sense. Matt, maybe just circling back to the comments on Galena Park. Do you anticipate the 10 million barrels a month of capacity as being sufficient to handle the volumes coming off the fracs? Just looking at the expansions there with 320,000 barrels a day of frac capacity, if C3, C4 is going to give or take 40% of that, it seems like you can nearly fill the expanded capacity just with the fractionators.
I'll actually turn it over to Scott Pryor to kind of give a little more color on that. I think the way you guys should look at it from the perspective, the announcement of ordering long lead items for increased refrigeration capacity at Galena Park is in line with a number of other projects that we've already announced, one of which was a pipeline from Mont Belvieu down to Galena Park, as well as a refurbishment of our dock at Galena Park, which was one of our older docks. The pipeline should be online in the first quarter of 2019. The refurbishment of the dock should be online mid-2019. That basically de-bottlenecks a lot of our capacity behind the refrigeration unit to open up opportunities for increased movements of butanes specifically, but also enhances our ability for propane.
Those types of projects, then moving forward with further refrigeration that would be adjacent to our existing footprint, gives us significant refrigeration capacity. Nominally speaking, we're saying that gives us an increase of about 50%. We're spending dollars, they're moderate dollars, in 2018, 2019, and 2020 in order to reach those types of capacities. Again, to Matt's points in our script was that depending upon what types of products we're loading, whether it's butanes, propanes, or simultaneously loading both, as well as the types of ships that we're loading, we see that we've got sufficient capacity based upon what we're seeing today. We will continuously look for opportunities to expand, add additional refrigeration if necessary, over and above what we've announced today in order to handle those.
The one thing that we get with our facility is, and the reason why it's always dependent upon the types of products we're loading is that we can simultaneously refrigerate through our existing footprint and an expanding footprint, both propanes and butanes at the same time. You can see the reason why there's a varying degree of how much volume you can put across the dock relative to those types of variables.
Got it. That's helpful. Jen, I guess just the final clarification.
Two quick adds. One, in case it was lost in our script, the capital, which Scott referred to as moderate, highly leverages our existing investment already in place and is in the forecast for 2018, 2019, 2020 outlook. The numbers are already in there, making them kind of lowly moderate, in my opinion. Secondly, there is a great deal of leverage by having the other infrastructure already in place and making incremental investments to expand our capacity. We feel really good about that, and it's the power of the asset investment we've already made.
Got it. That's helpful. Jen, just to clarify on the Badlands or the potential Badlands minority sale, is that G&P, G&P plus crude, or how are you guys looking at that?
Yeah, we're looking at it as a partial minority interest sale of the Badlands LLC entity, which is the entity that owns all of both the crude and the natural gas gathering and processing assets up in North Dakota.
Okay, great. Thank you.
Yep.
Thank you. Our next question comes from Jeremy Tonet of J.P. Morgan. Your line is now open.
Good morning, guys. This is Rahul on for Jeremy. Thanks for all the color you guys provided today. I just have one question on the guidance assumptions. Looking at the slide nine, can you provide some more color on the timing assumptions behind the incremental processing plans here? Also, are there any other growth opportunities baked within these assumptions? Just as a follow-up to that, given the lot of processing expansions being added to the backlog, do you see any potential for pulling forward the Grand Prix mainline expansion ahead of 2021 at this point?
I guess I'll start, Jen, and then maybe you can go from there. The underlying assumptions in there and some of the upsides, we have our base volumes going through gathering and processing down Grand Prix and into fractionation. What could drive this higher is we get incremental T&F deals with third-party customers, producers, midstream companies. Just continued commercial success is something that could potentially drive this higher and could lead to even more volumes on Grand Prix and into our fractionation facilities. We did talk about, we're ordering the long lead times for the pumps, which would expand the capacity from the initial about 300 up to about 400,000 barrels. That would be needed in this forecast.
You said 2021. You said as early as 2020.
Yeah. Just to be clear there, I said we could have that ready as early as 2020. In this forecast, we would need it within the time period of 2021. We didn't give exact timing of when those three other plants that we mentioned on the processing side would be coming online. You can think of it as kind of ratably after the announced plants come on, kind of through that period. It is a reasonable estimate.
The other fractionator we mentioned, we did say 2021.
Yeah, Frac Train Nine is assumed in 2021. That's right.
Yeah. That'll contribute to EBITDA in this forecast in mid-2021. We haven't described the timing of when the additional three Permian plants would come online. Obviously, if you're modeling our expected growth out of the Permian, it should hopefully be fairly easy to predict when we need additional processing.
Right.
All right.
Because of the way you asked the question, I also want to emphasize that there is no unknown, unidentified wedge built into that. That's the additional upsides, some of which are mentioned in the column to the right of page nine.
Got you. That's really helpful color, guys. Just to follow up on those assumptions here. How are you guys looking at the volume guidance in Permian, sorry, just the Permian volume guidance assumptions behind this until 2021? Is it going to be 20% or sub? Any color you can provide there?
Yeah. We haven't given the detailed guidance for 2019 yet. We anticipate giving a more fulsome review of how we see 2019 shaken out at the next quarter's earnings call in February. We'll probably provide some more granular information regarding 2019. We wanted to give the early look for 2019. There is significant growth assumed in the Permian for this forecast. We'll give you a little more detail in February.
Sounds good. Thanks, guys. That's it for me.
Okay, thanks.
Thank you. Our next question comes from Spiro Dounis of Credit Suisse. Your line is now open.
Hey, good morning, everyone. Just want to start off with funding all this growth and getting to that cash flow inflection that's coming. You guys appear to have a lot of high visibility here just on the EBITDA itself, given the nature of these projects. Just curious if it makes sense to run maybe at a higher leverage temporarily to bridge you there. I know you've talked about multifaceted approach, but could we see you lean there a little bit more going forward?
Spiro, this is Jen. I think certainly when we think about 2019, 2020, and beyond, obviously the visibility that we have to ramping EBITDA gives us a lot more flexibility. One, it just gives us more leverage capacity as it is, but also I think would potentially give us additional comfort in letting leverage run a little bit higher for a quarter or quarters if we wanted to. If you think about historically, we funded it, call it a 50%-50% debt and equity. I think obviously we talked about 2018. We felt like we had a little bit more flexibility to potentially issue less equity than 50%. Going forward, I think we have that same flexibility to go lower than that if we want. Obviously, are always focused on trying to prudently manage the balance sheet.
Okay. Then just on LPG exports, you're obviously talking pretty positively about the outlook there going forward. We've heard that from others as well. Just wonder if you could provide a little more color on that market, trying to get a sense for sentiment on the buyer's side and how much of that trade is really still arbitrage driven versus maybe more sticky type demand from things like heating and cooking.
It's a number of things, obviously, that would add into that. We look at it from a couple different angles, one of which when you think about, let's look at it from a domestic fundamental growth perspective. The growth that we're seeing on the upstream side, our gathering system, our gas processing plants, our long-haul pipelines, the expansion that we see at our fractionation footprint, and all this increased production that we're going to see domestically, while not seeing increased demand domestically for propanes and butanes, means that it has to find its way to the water. Because of our integrated footprint, that allows us to make sure that that doesn't have to jump off of our footprint in order to find its way to the marketplace, as we have it all the way down to the water's edge.
As a result of that increased production will move that direction. We're in a great position from that perspective. On the demand side, we're continuing to see growth, obviously, predominantly in the Far East. We've mentioned it before in other calls, if we think about the demand opportunities in Africa and India, and certainly the continued growth that we're seeing in China and other areas in the Far East. Those types of demand pools will obviously complement the increased productions that we have here domestically within the U.S. The U.S. is the only one that is growing with the needed supply to feed that marketplace. It's a little bit of a supply push and a demand pull to a certain degree. The marketplaces are becoming more and more accustomed to origination of supply out of the U.S. It's both.
It's domestic demand, it's other feeds to marketplaces, it's PDH demand. There's a lot of things that feed that. Obviously the availability of supply helps that growth on the demand side grow from there.
Yeah. I appreciate all that color. Thanks, everyone.
Okay, thanks.
Thank you.
Thank you. Our next question comes from TJ Schultz of RBC Capital Markets. Your line is now open.
Hey, good morning. Just first, at your currently operated fracs, Matt, I think you mentioned the tenure agreements. I think you hit the end of some of the current tenure agreements through your 2021 outlook. Just how much of the contracted firm space agreements are expiring through that outlook and what's expected in dealing with those as far as renewal expectations or trying to quantify the potential upside to rates just given the current tightness?
Yeah. We have a portfolio of agreements, both T&F and F deals. Really in the short term, we provided this a few years ago, we said that we have long-term contracts. There's really not that much rolling and coming up for renewal in the next 12, 24 months. There's not a lot of that recontracting that is going to be able to come up to extend on the fractionation side. With train six coming on with seven and eight, we do have obviously more capacity coming on, so we'll be able to continue to execute longer-term agreements to satisfy that demand.
Okay. Then if we just think about NGL volume growth for transport and frac beyond, if we think about beyond plants coming online and new third parties, do some of the existing transport commitments or other contractual limitations start to roll off by 2021? If you can just provide any context to when some of that occurs.
We have on the transportation side, we have a mix of some volumes that we're going to be able to move off other pipes kind of day one when Grand Prix comes on. Some are shorter term, some mid, and some are very long term. There's some that are kind of moving off other, and we're going to get the benefit of the transportation in this time frame, but it is a portfolio there. It's going to be moving over time more and more to Grand Prix.
Great. Thanks.
Then in generality, most of our new stuff, the vast most of our new stuff should be assumed as going on to Grand Prix.
Yes.
Makes sense. Thank you.
Okay, thanks.
Thank you. Our next question comes from Dennis Coleman of Bank of America Merrill Lynch. Your line is now open.
Thank you. Just a lot of focus here on liquids, obviously, and that's the opportunity. I wonder if you might talk about as you bring all this processing capacity on, obviously that's a lot of gas that needs to get to market as well. Is there capacity locked up for that gas or anything you can talk about there? I know you have the GCX interest, but anything additional or opportunities there?
I'm going to turn it over to Pat to answer that one.
We did participate in GCX, obviously everybody in the world is talking about the Permian residue gas takeaway situation. GCX comes on in October of next year. As we also announced, not that too far in the distant past, we are working on a project called the Whistler Pipeline, which would move an additional two BCF a day out of the Permian. We're very active. We have a lot of contracts and markets to take away our gas and make sure that our customers' gas moves. Our customers also have contracts to get us through this short period of potential interruptions across the Permian. If you think about it throughout the wintertime, you've got a lot of consumption of gas, both at the well sites and obviously consumption of gas from the general population out there. It helps alleviate some of that problem.
April through October of next year prior to GCX coming online, it's going to be an interesting timeframe. We like the way we position ourselves to make sure that everything moves. There will be issues in the Permian unless there's a miracle that I haven't seen yet, we will continue to work on Whistler and move that project forward. Obviously, that's hopefully the next solution for continued growth over the coming years of residue gas in the Permian.
Dennis, your question about how much is firm has a multi-year component, has a short-term component. In the short term, we have the vast majority of ours covered with what we would characterize as firm. We have to have a little bit of flexibility because there's variability in producer supply across days and across weeks. We've managed that for a long time, and we're firmer than we've ever been and have flexibility with gas daily type stuff to manage the always unexpected variations in producer volumes. We're in a good position. We think our customers are in a better position with Targa than with most other players in the Permian, for example.
Great. That's very helpful. My follow-up, if I can, just a question on cost of capital. Obviously, you talked about using a variety of funding methods, the DevCos you've used this year. I wonder, is that still a part of the arsenal? Is the Badlands potential sale, would it have any kind of potential buyback? Is it similar or is it an outright sale? Lastly, it does look like you assume a fairly high interest expense as you go across your net renewed or updated budget. I just wonder as with S&P leaving you on positive, is there a thought that you'll move towards investment grade and that while it's not an EBITDA impact, it certainly could be a DCF impact if that interest expense ended up being lower?
That was quite the follow-up question, Dennis.
Sorry. There's a lot of things in there.
Let me try to make sure that I cover all of them off. I think that from our perspective, obviously, we entered 2018 describing a multifaceted approach to financing, frankly, spent a lot of time in 2018, really the end of 2017, describing what that could mean in terms of public capital, common and preferred, or private capital or potential asset sales. Obviously you saw us go through 2018 really utilizing a number of those different tools that were in our toolbox. As we now look forward to 2019 and beyond, obviously the increasing EBITDA, I think is partially what will be very advantageous to us as we think about how to finance this growth program. We also announced the partial interest sale in the Badlands. Obviously, that would potentially help from a financing perspective.
Related to the DevCo, that was a very nice structure that we did, we've got four years of flexibility to buy back those JV interests, which I think is a very favorable structure to us. I think that if I had to rank where that is on the list right now, it would probably be a little bit further down just because we've already done it. So when we think about our outlook and our increasing EBITDA, I'm not sure that would be number one on my list in terms of what we may do next. Obviously, we're announcing today that given we're evaluating a minority interest sale in the Badlands, that's potentially first on my list here. Then related to your follow-up question part about the interest expense that we assume just in the EBITDA reconciliation at the back of our presentation.
Obviously, rates are going higher, LIBOR is higher, so we're just taking a conservative approach to those assumptions there. I think that we're very pleased with the S&P upgrade and the move to positive outlook as well. I've tried to spend a lot of time with the rating agencies over the last couple of years to make sure that they understand the story that's unfolding here, and I think that we've done a good job working together with them. So ultimately, we'll see where the path takes us. Obviously, the outlook that we have put in front of you last June and then now refreshed here stronger in November of 2018, highlights the fact that we're going to have a very flexible balance sheet going forward.
Obviously, that could mean that in the future, investment grade is a step that we take, but it's obviously one that we'll want to take when the company is good and ready. I think it will frankly, be much more a factor related to our results getting us there more so than anything else.
Thanks. You hit them all. I really appreciate it.
All right. Thanks.
Hit all those.
Thanks, Dennis.
Thank you. Our next question comes from Tristan Richardson of SunTrust. Your line is now open.
Hey, good morning, guys. Just circling back to the enhancing LPG export capabilities with the refrigeration and the additional line from Mont Belvieu. Is there a ceiling to think about in terms of export capabilities before more significant capital deployment would be required?
In our outlook, we're really expanding in phases, right? Scott talked about, we're putting in the 20-inch line between Mont Belvieu and Galena Park, then we're going to add refrigeration. We're doing some dock work. I don't know that we've engineered this thing to say what the ceiling is. We can keep continuing to incrementally remove bottlenecks as we go along. We see this step of adding refrigeration gives us good runway to handle the additional liquids coming off of fractionation. If we need to do more, we can continue to expand those bottlenecks.
That's helpful. Should we think about the enhancements as underwritten by customers or more just general optimization to accommodate the supply push?
Yeah, it's both. When you've got a facility as large as ours, you have a constant roll of contracts that are coming up, and we're entering into new ones, so it's hard to necessarily place this contract with the expansion or the base business and how things are going. We're continuing to add contracts. We've added contracts. We're working to add more and add more term. We're not fully contracted, but given the volumes that we see coming across our facilities and the outlook and discussions we're having for additional contracts, we feel really good about the returns about this expansion. We didn't really talk about the capital, but it's probably around $100 million, $125 million of total capital for this refrigeration. We're going to see good returns, depending on how you think about the terminal fee going forward.
Very helpful. Thank you guys very much.
Okay, thanks.
Thank you. Our next question comes from Keith Stanley of Wolfe Research. Your line is now open.
Hi. Good morning. Sorry if I missed this, does the 2021 outlook include or exclude the Whistler Pipeline?
The 2021 outlook does not include the Whistler Pipeline.
Okay. Just a follow-up on that pipeline. With Kinder moving forward on two pipes now, are you seeing less urgency from customers to act and commit now to Whistler, or is that still being actively developed?
The answer is no, we're not seeing less interest, and it is being actively developed.
That was it. Thank you.
Okay, thanks.
Thank you. Our last question for today is from Sunil Sibal of Seaport Global Securities. Your line is now open.
Hi, Sunil.
Yes. Hi, good morning, guys, congrats on the quarter, thanks for all the clarifications on the call. A couple of questions from me. In the marketing and logistics segment, quarter three seems like you had a pretty strong quarter. Typically, you've seen a fair bit of seasonal uptick in that segment going into the winter months. I was wondering, how should we think about that in the next couple of quarters, considering what you reported today?
Good question. We do have some seasonality in our wholesale business, which has led to typically stronger Q4 and Q1 relative to two and three. We'll still have those same seasonal factors in there. What we saw in Q3, though, was just really strong volume across both our fractionation facilities and our export dock, and we did have some shorter-term opportunities in the fractionation business, which helped as well. It's a little tougher to say what that's going to look like in Q4. We still do have some of those same seasonal factors at play in the wholesale business, and then we'll just have to see how Q4 shakes out. We would certainly expect volumes across the fractionation and across exports to continue to be strong, and then it's just really sort of the shorter-term opportunities play out in Q4.
Okay. Thanks for that. In terms of the longer-term guidance that you've laid out, a couple of clarifications then on that. What's the commodity price assumption underlying that?
Yeah. There's a footnote on the page, Sunil, that we assume $60 per barrel crude WTI, $2.75 per MMBtu natural gas, and $0.70 per gallon for NGLs.
Oh, got it. Thanks for that. Just lastly, in terms of the leverage metrics, where do you see exiting 2021 in terms of the leverage with all the guidance that you laid out?
I think from our perspective, when you think about this outlook and think about our goal of having consolidated leverage in the three to four times range, we're not going to give additional guidance or clarification on exactly where we expect point-in-time leverage to be at the end of this forecast. This is a very strong forecast with a lot of additional free cash flow beginning in 2019, then 2020, and then 2021. I think from our perspective, when you think about us delivering this long-term outlook that we have now refreshed again this morning, it would mean that our balance sheet is in very, very good shape at the end of this outlook.
Okay. Thanks for that. That's all I had.
Thanks, Sunil.
Yeah, thanks.
Thank you. Ladies and gentlemen, this concludes today's question and answer session. I would like to turn the call back over to Sanjay Lad for any closing remarks.
Great. Thanks to everyone that was on the call this morning, and we appreciate your interest in Targa Resources. Jen and I will be available for any follow-up questions you may have. Thanks, and have a great day.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program, and you may all disconnect. Everyone, have a great day.