Targa Resources Corp (TRGP) 2017 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Targa Resources Corp. Fourth Quarter 2017 Earnings Conference Call. (Operator Instructions).

And as a reminder, today's conference call is being recorded.

I'd now like to turn the conference over to Sanjay Lad, Director of Investor Relations. Please go ahead.

Thank you, Candice. Good morning and welcome to the Fourth Quarter 2017 Earnings Call for Targa Resources Corp. The fourth quarter earnings release for Targa Resources Corp., Targa, TRC or the company, along with the fourth quarter earnings supplement presentation are available 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 Act of 1933 and 1934. Please note that actual results could differ materially from those projected in any forward-looking statement. 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.

I will now turn the call over to Mr. Joe Bob Perkins. Targa's Chief Executive Officer.

I thought Mr. Joe Bob Perkins was not in the script.

Thanks, Sanjay. Good morning and thank you to everyone for joining. At the beginning of this month, you probably noticed that we announced some executive leadership promotions, reflecting the significant leadership capabilities within the company and the increasing leadership roles that these individuals have continued to take on at Targa.

Although their official new title date is March 1, they're really acting in those roles today and on this call. Today, I'm going to begin the call with a strategic update. I'll then turn it over to Matt Meloy, our new President, who will give an update on commercial developments and business fundamentals and then Jen Kneale, our new CFO, will discuss fourth quarter 2017 results and present our financial and operational expectations for 2018.

We're also joined in the room by Pat McDonie, newly promoted President of our Gathering and Processing segment; Scott Pryor, promoted to President of our Logistics and Marketing segment; and Robert Muraro, our new Chief Commercial Officer, and Robert wants you to call him Bobby. We will collectively handle Q&A.

The investor and industry feedback since the announcement of the promotions has been very positive. We have a very talented team. These individuals and their teams are working very well together.

2017 was one of our busiest years at Targa, and what will potentially be viewed as another transformational year for the company. Over the course of 2017, we added approximately 325 million cubic feet per day of incremental natural gas processing capacity, approved and began construction on another 710 million cubic feet per day of incremental processing capacity additions, acquired under an earnout structure and quickly integrated additional Delaware and Midland Basin midstream assets, commercialized and started construction on our 300,000 barrel per day Grand Prix NGL pipeline, entered into a strategic joint venture with Blackstone for Grand Prix, secured a long-term NGL dedication and commitment from EagleClaw, and also continued to secure incremental third-party commitments to transport volumes on Grand Prix.

We acquired the Flag City assets and related commercial contracts from Boardwalk Pipeline Partners in South Texas, executed definitive agreements with Kinder Morgan and DCP Midstream to jointly develop the Gulf Coast Express Pipeline, raised $1.6 billion of equity and $750 million of debt over the course of the year.

And Targa ensured the continued safe operations of our facilities for our customers and for our shareholders, with heroic individual efforts by some of our employees to mitigate the impact of the tropical storms we experienced on the Gulf Coast this fall.

2017 was a busy and impactful year. Now, we're only 1.5 months into 2018, and we have already announced the formation of a 50-50 joint venture with Hess Midstream to construct a new 200-million-cubic-feet per day processing plant in the Bakken, enhanced our Centrahoma joint venture with MPLX in Oklahoma and are adding processing capacity with the Flag City plant relocated from South Texas to Oklahoma, announced construction of 2 new 250 million cubic feet per day processing plants in the Midland Basin, announced a new 100,000-barrel per day fractionator connected to our Mont Belvieu complex, created and announced an innovative development company joint ventures, or so called DevCos, that provided $190 million of capital reimbursement at closing and total potential capital savings of up to about $960 million.

And we have continued executing on the 2017 and 2018 projects announced to date. So far, 2018 activity has been on a similar pace to 2017 and I don't see any signs of it slowing down.

Our activity levels and execution in 2017 and year-to-date 2018 support our key strategic initiatives, including; number one, to invest in our businesses, investing in attractive projects that will leverage our existing infrastructure and further strengthen our competitive advantage; number two, to proactively finance our growth program underway and to maintain balance sheet strength and flexibility; and number three, to continue to identify additional opportunities to further integrate, strengthening our asset base to further enhance an attractive long-term outlook.

Now from where we sit today, the long-term outlook for Targa is better than ever, better than ever because of excellent execution and because opportunities that we are seeing around our gathering and processing and our downstream assets are robust. Our focus remains on execution and continuing to provide best-in-class midstream service to our customers.

For Targa, 2018 will look a lot like 2017 in many ways, as we expect to spend at least another $1.6 billion of net growth CapEx on investment opportunities and we are still a year or more away from some of our key projects like Grand Prix coming online and contributing to EBITDAs. Our current investment cycle positions us for significant visible EBITDA growth in 2019 and beyond which is why this is a very exciting time at Targa.

With that, I'll now turn the call over to Matt, and Matt will provide an update around the execution of our strategic priorities and an update on our business fundamentals. Matt?

Thanks Joe Bob, and good morning, everyone. Commercial activity and production in many of our operating regions continues to increase, and we expect this positive trend to continue through 2018 and beyond.

Overall, 2017 inlet volumes in the Permian increased 19% over the previous year. Our fourth quarter Permian inlet volume increased an average of 300 million cubic feet per day over the fourth quarter 2016, and would have been even higher, but we temporarily offloaded an average of about 30 million cubic feet per day to third-party processors in the fourth quarter, given system capacity constraints that will be improved when the Joyce Plant comes online. Inlet volumes for 2017 total field gathering and processing increased 7% over 2016's average.

This growth was slightly less than our guidance as a result of steeper volume declines in North Texas and WestOK and the fourth quarter Permian offloads. Back to the Permian, we continue to execute on our growth program and remain on track to add an incremental 710 million cubic feet per day of new processing capacity in 2018.

In the Delaware, we expect to begin operations on our 60 million cubic feet per day Oahu Plant later this month, and construction continues on our 250 million cubic feet per day Wildcat plant, which is expected to begin operations in the second quarter of 2018. These plants are interconnected with multiple other plants and systems across the Delaware and Central Basins.

In Permian Midland, production growth continues at a rapid pace. We are currently running some of our West Texas facilities above nameplate capacity to meet the processing needs of our customers and have been offloading to other third party midstream providers. Our 200-million-cubic-feet per day Joyce plant is expected to be operational in late March. And while providing some much-needed system release, we expect the Joyce plant essentially will be full from the first day of operations. Our expectations for our 200-million-cubic-feet per day Johnson Plant are similar and is anticipated to begin service in the third quarter and is also expected to be highly utilized when it comes online.

We announced publicly a couple of weeks ago that as a result of the production trends that we are experiencing and continued production growth forecast from our customers, we are moving forward with construction of 2 new 250-million-cubic-feet per day cryo plants in the Permian Midland.

The first plant will begin operations in the first quarter of 2019 and the second plant in the third quarter of 2019. Similar to our other plants currently under construction, these plants will be interconnected with multiple other plants and systems. Based on all of the Midland Basin trends and forecasts that we're seeing from our producers and from the broader industry, we expect to add future processing capacity beyond these announced plants.

Volumes from our newly announced Targa plants will be transported on Grand Prix to our fractionation asset and LPG export facility in Mont Belvieu, which mean substantial organic growth across Targa's integrated footprint.

Moving to our Oklahoma assets. Our outlook is generally improving, as we benefit from continued commercial success. The expansion of our Centrahoma JV with MPLX includes the addition of another 150 million cubic feet per day of capacity with our relocated Flag City plant becoming the Hickory Hills plant, which will support growing natural gas production from the Arkhoma Woodford basin.

The Hickory Hills plant is expected to begin operations in the fourth quarter of 2018. Similarly in the Bakken, our outlook continues to strengthen, as activity continues on our dedicated acreage and as we benefit from volumes from our producers' pad drilling. Given our forecast for production growth on our dedicated acreage and other activity in the area, we are very pleased to enter into a 50-50 JV with Hess Midstream to construct a 200 million-cubic-feet per day plant at our existing Little Missouri facility to help meet our and Hess's growing processing needs.

We have also executed an NGL takeaway -- sorry, we have also executed an agreement for NGL takeaway with ONEOK. That argument will also allow us to direct growing volumes from our Bakken assets to our fractionation footprint in Mont Belvieu. This is another example of our continuing focus to integrate our G&P volumes through our downstream assets.

Continuing more broadly in our Downstream Business, the long-term outlook for our Logistics and Marketing continues to strengthen, as we are well positioned to benefit from strong supply and demand fundamentals. First, higher field G&P inlet volumes are driving higher fractionation volumes and we expect this trend to continue in 2018 and beyond. Adjusting fourth quarter volumes for the shift related to the impact from Hurricane Harvey, we saw an average increase of 115,000 barrels per day of Y-grade volumes available for fractionation when compared to the fourth quarter of 2016. Additionally, we are also seeing a trend of more ethane recovery in the Permian and Mid-Continent regions which is driving higher fractionation volumes. New Gulf Coast petrochemical demand supports a positive ethane frac spread which may result in higher fractionation volumes for Targa over time.

The U.S. had approximately 150,000 barrels per day of new petrochemical industry ethane demand commence operations in late '17. We expect an incremental 300,000 barrels per day by the end of '18 and additional growth in 2019 and beyond, with the vast majority of the expansions and new builds located along the Gulf Coast.

Likely as a result of the factors just mentioned, we are currently seeing some tightness in the fractionation market in Mont Belvieu, with demand for long-term contracts increasing. We have also continued to add third-party contracts for both transportation and fractionation services. As a result, we are moving forward with construction of an additional fractionation train in Mont Belvieu. The fractionation tower and pipelines into and out of the tower will be owned 100% by the fractionation DevCo, with an estimated cost of approximately $270 million, and Targa will fund 20% under the DevCo structure. Then Targa will fund 100% of the cost, or approximately $80 million, associated with other infrastructure required for the additional fractionation train that is interwoven across our Mont Belvieu footprint.

We also recently submitted permitting for additional fractionations in Mont Belvieu to proactively prepare for expected future NGL volume growth. Shifting to our LPG export business, our long-term outlook is largely unchanged. We have an attractive multiyear contract position. Higher propane prices in the U.S. in the fourth quarter and early 2018 have not slowed the amount of propane and butanes leaving the dock and interest in multiyear contracts continues. And the long-term fundamentals remain robust for U.S. LPG exporters, driven by international LPG demand growth and continued strength in growing LPG supply from the U.S.

We currently have the most flexible export facility on the Gulf Coast, with the ability to load multiple products and vessel sizes, and we continue to work to further enhance our capabilities and flexibility to meet customer demand. Ongoing enhancements include rebuilding and upgrading our oldest dock and adding infrastructure at Mont Belvieu and Galena Park, including a new pipeline between Mont Belvieu and Galena Park to improve the load rate efficiency, especially related to the export of butanes. These enhancements give us additional capability to export more LPG volumes, depending upon vessel size and product mix. These enhancements have been staged for minimal impact Targa's operational capacity at Galena Park during the dock rebuild which is concentrated during the second and third quarters this year and no impact on our ability to meet our contractual obligations. The capital cost associated with these improvements is already included in our $1.6 billion of net growth CapEx, and we expect that these projects will be fully completed during the second quarter of 2019.

Moving on to our Grand Prix pipeline. This asset is a game changer for Targa over the long term, as it provides significant and increasing fee-based earnings, reduces our reliance and obligation to third-party pipelines and helps direct incremental volumes to Targa's downstream facilities.

Our outlook for Grand Prix continues to strengthen as a result of our commercial success, securing incremental third-party volumes for both transportation and fractionation, and increasing G&P volumes outlook, driving additional plants across our footprint. Construction of Grand Prix continues, and we expect the pipeline to be fully operational in the second quarter of 2019.

At our Channelview Terminal, we expect our 35,000-barrel-per-day crude and condensate splitter to be completed in the second quarter of 2018. As many of you are aware, our splitter is underpinned by a long-term fee-based contract with Vitol, after they completed their acquisition of Noble Americas in January. And we look forward to a continued relationship with Vitol.

With that, I will now turn the call over to Jen to discuss Targa's results for the fourth quarter and our operational and financial expectations for 2018.

Thanks, Matt. Good morning, everyone. Targa's reported adjusted EBITDA for the fourth quarter was $328 million which was 10% higher than the same period in 2016. Continued strong volume growth in Permian G&P, complemented by higher volumes in Badlands, SouthTX and SouthOK along with higher commodity prices and higher fractionation volumes, drove the increase in adjusted EBITDA over the prior year, offset by declining WestOK and North Texas volumes.

Reported net maintenance CapEx was $27 million in the fourth quarter of 2017 compared to $28 million in the fourth quarter of 2016, and total net maintenance CapEx for full year 2017 was $99 million.

Distributable cash flow for the fourth quarter was $275 million, resulting in dividend coverage of 1.24x, consistent with our expectation that dividend coverage would be highest in the fourth quarter.

For full year 2017, adjusted EBITDA of $1.14 billion increased 7% over 2016 and exceeded our previously communicated full year adjusted EBITDA guidance of $1.13 billion. Full year dividend coverage was approximately 1x, as anticipated.

Moving to our sequential results. Adjusted EBITDA for the fourth quarter increased 19% over the third quarter. In our Gathering and Processing segment, operating margin increased by $36 million in the fourth quarter when compared to the third quarter, primarily due to higher NGL prices and higher inlet volumes in the Permian, Badlands, SouthTX and SouthOK.

Fourth quarter Permian inlet volumes sequentially increased 4% from growth in each of our Permian Midland and Permian Delaware systems. And as Matt mentioned, volumes would have been higher pro forma for offloaded volumes. Inlet volumes in SouthTX sequentially increased 11%, as we benefited from higher volumes from Sanchez through the Raptor Plant.

In the Bakken, Badlands crude oil gathered volumes were approximately 120,000 barrels per day in the fourth quarter, increasing 10% over the third quarter and fourth quarter natural gas volumes increased by approximately 9% over the third quarter. Volumes also sequentially increased in SouthOK, as incremental SCOOP volumes offset legacy production declines. Permian crude volumes gathered in the fourth quarter were approximately 45,000 barrels per day.

In our Logistics and Marketing segment, operating margin increased $38 million in the fourth quarter when compared to the third quarter. As estimated, approximately $7 million of operating margin in our Downstream segment shifted into the fourth quarter as a result of temporary operational disruptions related to the impacts of Hurricane Harvey. Strong volume growth in Permian G&P predominantly drove fourth quarter fractionation volumes to average 443,000 barrels per day, including 29,000 barrels per day that shifted into the fourth quarter as a result of the impact of Hurricane Harvey.

LPG export volumes were also strong in the fourth quarter, as we averaged 6.4 million barrels per month of exports at Galena Park including about 380,000 barrels per month that were attributable to cargoes that were deferred into the fourth quarter, again, as a result of the impact of Hurricane Harvey.

Overall, operating expenses during the fourth quarter in both our G&P and Downstream segments were essentially flat to the third quarter despite increasing volumes.

Full year 2017 average fractionation volumes increased 15% over average 2016. And average 2017 LPG export volumes of 5.6 million barrels per month were roughly in line with average 2016. Moving now to other financial-related matters. The reported aggregate fair value of the earnout payments for our Permian acquisition are currently estimated to be about $317 million, with a $7 million payment forecasted for April 2018 and $310 million estimated to be paid in April 2019.

During the fourth quarter, we executed additional hedges, as we benefited from forward price strengths in certain commodities. For 2018, we estimate that we have hedged approximately 85% of natural gas, 75% of NGLs and 75% of condensate volume, based on our estimates of current equity volumes from Field G&P. Our natural gas hedges include regional basis hedges.

For 2019, we estimate that we have hedged approximately 65% of natural gas, 40% of condensate and 35% of NGL volumes, again, based on our estimate of current equity volumes from Field Gathering and Processing.

Our consolidated liquidity as of year-end was approximately $1.9 billion including approximately $137 million in cash. On a debt compliance basis, TRP's leverage ratio at the end of the fourth quarter was 3.8x versus a compliance covenant of 5.5x. Our consolidated reported debt-to-EBITDA ratio was approximately 4.4x. Since year-end, we improved our financial position further for execution of the DevCo JVs which increased our current liquidity to $2.1 billion, given $190 million of proceeds received from Stonepeak at close.

The DevCo JVs demonstrate our access to private capital at an attractive cost and they significantly reduce our equity funding needs for 2018 and also for 2019, while preserving our balance sheet strength and flexibility. Some of the other benefits of the DevCo JV structure include: no dilution to Targa's existing shareholders and no reduction in dividend coverage during the construction period; the flexibility to acquire Stonepeak's interest over 4 years, beginning at the earlier of the commercial operations date of the final project, currently estimated to be GCX in October 2019 or January 1, 2020; the flexibility to acquire the first 50% of Stonepeak's interest in minimum increments of $100 million and then acquire the remaining 50% in one purchase; we maintain Targa control of the management, construction and operations of Grand Prix and the additional fractionation train; and finally, we retain a residual upside, as we contributed projects for Targa shareholders given the purchase option. And to be clear, our base case assumptions are that we will acquire Stonepeak's interest.

Let's now turn to our expectations for 2018 which assume NGL composite barrel prices to average $0.67 per gallon, crude oil prices to average $58 per barrel and natural gas prices to average $2.75 per MMBtu for the year.

Beginning with our G&P segment, we expect total Permian natural gas inlet volumes for 2018 to average between 1.55 billion to 1.65 billion cubic feet per day, with the midpoint of the range representing a 25% increase in average 2018 Permian inlet volumes over the 2017 average. We expect Permian inlet volumes to sequentially ramp, with average fourth quarter 2018 inlet volumes being the highest quarter of the year.

We also expect average 2018 inlet volumes in SouthOK, SouthTX and the Badlands to be higher than average 2017. Collectively, we expect total Field G&P natural gas inlet volumes for 2018 to average between 3.15 billion to 3.35 billion cubic feet per day, with the midpoint of the range representing an 18% increase in average total Field G&P inlet volumes over the 2017 average. We also expect total crude gathered volumes in both the Badlands and Permian to be higher on average in 2018 than average 2017.

Downstream, we expect fractionation volumes to significantly increase year-over-year, largely driven by growth in Permian G&P volumes. While ultimately, we expect that increase in Permian volumes for Targa and others will be constructed for additional LPG exports, our financial expectations for 2018 only include currently contracted volumes. We expect more than contracted volumes, but our overall guidance again, only includes those that are contracted.

We expect full year 2018 adjusted EBITDA to be between $1.225 billion to $1.325 billion, with the midpoint of the range representing a 12% increase over 2017 adjusted EBITDA. Similar to 2017, we expect full year 2018 dividend coverage to be about 1x, assuming a flat $3.64 annual dividend. We expect 2018 quarterly adjusted EBITDA to increase sequentially, with fourth quarter 2018 adjusted EBITDA and fourth quarter dividend coverage being the highest for the year.

First quarter adjusted EBITDA is expected to be the lowest, as our volumes are expected to ramp throughout 2018 and because we are also impacted by freeze-offs in January.

As announced recently, in pro forma for the DevCo JVs, our current 2018 net growth CapEx estimate is approximately $1.6 billion. And it is reasonable to assume that 2018 CapEx will be higher than that, as we move through the year and continue to execute commercially.

Full year 2018 maintenance CapEx is forecasted to be approximately $120 million.

Given the financing steps that we took in 2017 and the steps that we have already taken in 2018, we believe that our remaining financing needs for 2018 are very manageable. In 2017, we over equitized when we announced the Permian acquisition and also when we announced Grand Prix and then later reduced our overall capital obligations to our Grand Prix strategic JV with Blackstone. Our recent execution of the DevCo JVs will provide approximately $550 million of capital in 2018 and additional significant capital savings in 2019.

We announced 2 strategic JVs in January with Hess Midstream and MPLX that also resulted in Targa being reimbursed for capital RE spent and reduced our funding obligations for the assets under construction going forward. We continue to evaluate and have opportunities for asset sales, additional asset and/or development joint ventures, preferred equity and common equity. And we, of course, also consider other alternatives, including utilizing more leverage than a 50-50 debt/equity capital funding model, given our current balance sheet strength and visibility to increasing EBITDA in the future.

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

Thanks, Jen. Thank you, Matt. I'm sure that the listeners can tell that there is a lot of enthusiasm and positive momentum for our Targa team right now. Enthusiasm and momentum as exemplified by our comments, demonstrated by recent commercial traction and financial creativity, and supported by strong business fundamentals and the strong volume trends in both our Gathering and Processing and Downstream segments.

The capital program that we have underway is expected to generate significant cash flow growth when the assets are operational, and we expect to continue to fund our CapEx to maintain balance sheet strength and flexibility and to maximize long-term shareholder returns.

Our outlook will continue to strengthen, enhanced by stronger fundamentals and continued commercial and operational execution. The longer-term outlook that we provided last June is better today for 2021. Since providing that outlook, we have announced additional commercial success and announced additional growth projects from our project backlog. And we are well positioned to continue to outperform that EBITDA growth outlook on multiple dimensions as we move through time.

For example, any commercial execution is accretive to that forecast. We assumed no growth wedge over that time frame. We assume no additional gathering and processing contracts. We assume no additional LPG export contracts and we assume less growth projects than we have in progress today. In closing, our team at Targa remains focused on continuing to execute on our long-term strategic objectives, and we are very excited about Targa's strong long-term outlook.

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

(Operator Instructions) And our first question comes from Colton Bean of Tudor, Pickering, Holt.

Just wanted to start it off on the LPG export side of things. So you mentioned a bit of the dock enhancement work, and I apologize if I missed this. But did you guys quantify what impacts that may have to nameplate capacity?

Yes. We did. This is Matt here, I'll take a stab at this and then -- we did talk quite a bit about whether we should be increasing the nameplate or effective capacity. In our previous press release or presentations, we showed nameplate capacity of effectively 9 million, but said our effective operational capacity was 7 million barrels a month. What this project is going to do is it's going to add flexibility for us to load butanes at a faster rate. So it really depends on the product demand from the customers, whether it's more propane or butane. And then refurbishing the dock or really redoing the dock and upgrading the dock will allow us to have more flexibility on what ships we can load out of there. So it really depends on the vessel size demand and the demand for the products. So we think it's -- we could likely do more than the 7 million, so maybe it's a 7 million-plus. But we aren't going to try and quantify exactly what that could be because it is so dependent on customer demand.

And the only thing I would add ... I'm sorry, go ahead.

Colton, that's Scott Pryor trying to add-on to the answer. So we won't cut you off. Go ahead, Scott.

What I was going to add to that is, obviously, our customers have grown to expect a high service level from us, and this is a way for us to continue that level of service and flexibility at our dock. The enhancements to that particular dock, as Matt mentioned in his prepared remarks, it is one of our older docks and coming back in and repairing it, doing some things to upgrade loading arms improves the efficiency of that. And then the items that we've chosen to upgrade at our Belvieu facility to debottleneck our ability to move butanes quicker will help us provide efficiencies at the dock as well. The other thing I would remind of is that when we look out into the forecast and obviously, the growing market that we've got behind our gas processing plants and then into global demand that's out there, much of that global demand is both a complement of propane and butanes. So this will provide us opportunities again to be more flexible and more serviceable to our customers.

That's helpful. I mean, to follow through on that. Given the growth that you guys see on the NGL production front, is there kind of rough parameters that you would need to see to ultimately expand that capacity, either closer to that 9 million or even beyond that, I mean, whether it be in terms of loading rates or volume commitments? Just any sort of parameters that you guys might need to see to take a more dramatic expansion project on.

I think the way we're thinking about it is that we're doing some of these enhancements at the dock and adding the pipeline to position us for that future growth. So I think we're already working on some of those things because the fundamentals are so strong.

And it's -- we've also included the amount of capital for the project within our $1.6 billion net CapEx number that we gave you. So this work was kind of already going on. We're always looking for ways to improve our dock efficiency and be able to improve the capacity of our facilities.

Understood. And I guess, just to continue on the NGL side of things. So this may be a bit premature, but any sort of ballpark estimates on what capital needs may be if you guys were to choose to go ahead and add pump stations to Grand Prix to bring that up to full design capacity?

We haven't described -- and this is Joe Bob. We haven't described the incremental required to go from, nominally, 300,000 barrels a day to 550,000 barrels a day or more. I think we have been quoted multiple times as saying, it's pretty marginal. Pumps don't cost very much. We already know where they need to be placed and it's rounding there frankly for your modeling.

And our next question comes from Vikram Bagri of Citi.

Congratulations for the recent promotions. My first question is on the guidance you provided this morning. What are the drivers behind high-end, low-end of guidance? Is high-end driven by higher dock utilization, largely? And how much of the upside is from G&P volumes, Permian surprising to the upside, and so forth?

I think, ultimately, the guidance is really going to be driven by what we see from volumes really across our footprints. If you think about the growth that we're expecting to experience not in the Permian, but also in some of our other systems. So that's certainly part of it. Obviously, the high-end to the low-end could be impacted by commodity prices. It also could be impacted by just continued commercial execution, particularly when we think about the LPG export business, where we have essentially said that we're assuming that we do not move one additional cargo across the dock beyond what is contracted today. I'd certainly take the over on that. So I think those are some factors that ultimately will impact where we shake out, either in the range or above the range. But it's largely growth on the Permian and elsewhere in field and how that's going to translate to frac growth downstream.

Great. And then a question on Mont Belvieu, I apologize I missed that. The frac volumes were much higher than we expected. How much of the total volumes reported were one-time volumes that were shifted from third quarter to fourth quarter?

Yes. We have that in the supplemental presentation, it's in our script. It's 29,000 barrels moved into Q4 essentially from Q3.

29,000 bbl/d.

Yes. 29,000 bbl/d. Thank you.

Okay. And then just lastly on the Stonepeak transaction, we have much more clarity on Grand Prix pipeline than we did 7 or 8 months ago. So the threshold for someone to participate in the project at this stage was -- I understand, was high. I was wondering how did you decide what assets to contribute and how much of the assets to contribute to the JV. Did you have a number in mind in terms of capital you wanted to raise from the transaction and more predictable but lower return projects were contributed first and then remainder of the capital was raised by contributed -- contributing Grand Prix pipeline?

No, I mean, I think that, ultimately, this was a structure that we put together and was really driven initially -- our thinking was driven by number of different factors in terms of how we wanted to think about cost and some of the flexibility around what we are looking for in the structure. Basically, the structure serves as a bridge for us between -- for 2018 and 2019, while we're in this period of high capital spend before we're really benefiting from significantly ramping EBITDA. And so when we looked across our platform of assets, we were really trying to identify honestly assets that we thought would be most attractive to the capital providers that we have been talking to over the last many, many months to really structure something that was as cost efficient as possible. So when you think about the projects that we dropped in, the relatively easy projects to sort of cordon off and be able to track the cash flows associated with them. And I think that's important. If you think about the fractionation, we basically have dropped the tower and the pipelines in and out of the tower into the DevCo, and we have removed some of the noise that would have been created if we had dropped in some of the storage and other things that are very much interwoven with the rest of our footprint. So we tried to be very thoughtful around that. Obviously, these are fee-based assets, attractive, they're supported by take-or-pay. And so that had a lot of to do with it as well. So there were a lot of different factors that sort of went into, ultimately, what assets got [involved in it].

And our next question comes from Shneur Gershuni of UBS.

Just the -- I just wanted to start off, I guess with Joe Bob. Your closing remarks, you talked about kind of the 5-year plan that you had laid out and that there have been some incremental opportunities, be it Gulf Coast Express, and so forth. When we sort of think about sensitizing the upside potential of that, are we talking something like north of 10% or 15% versus kind of how you were thinking about the end of the 5-year plan? Or is it more in the sub 10% or sub 5% range?

It's Joe Bob. It's definitely taking the over on what we put out there in June. And how much over is a function of how successful we continue to be on the projects that we've already announced and the work that's going on that hasn't been announced. I feel really good about it. You should not be marginalizing the small percentage above that I was implying, and I don't think we're going to stop working on making it even better. For a continuing outlook of the pricing that we put into that and the activity levels, without giving you a percentage, I'm a lot more comfortable with something into significant and not something that's essentially insignificant.

Okay. Fair enough. Just a couple of quick follow-ups. Strategically in 2020, when you rolled down the DevCo or you were able to buy back the assets strategically, how do you approach it? Do you buy back the expected highest IRR projects first and leave lower IRR projects to be acquired last? Just trying to understand the strategy there. Jen had mentioned that you guys -- the plan is to, obviously, buy everything. Or does it just all happen at once? I'm just kind of wondering on the cadence and thought process strategically for that.

Sure, Shneur. So structurally, the way it's set up is effectively Stonepeak can't be left with ownership in one of the single assets. So the way it works is, if we obviously have the flexibility to call the part of the acquired -- part of the drop down interest back in $100 million minimum increments. And so if we do that, it's effectively $100 million across the 3 projects. And so we can do that in increments until we get to effectively 50% of Stonepeak's interest remaining, and then we'd have to do that acquisition of the interest in a single bullet.

Got it. Okay, I appreciate the color there. And then finally with respect to the Outrigger assets, my understanding is that there is an emerging issue with sour gas there. Is that a potential revenue-generating opportunity for Targa, where you were able to handle that for them? And as you answer that, if that was to be the case, would that be excluded from the earnout structure if that's an incremental revenue source?

I want to start yes and then Pat -- pass it to Pat McDonie for more color.

The yes that he is starting with is it is an incremental and it is excluded. But -- the answer is yes. There is sour gas in and around the Outrigger assets. It's not fully delineated but there's pockets of very sweet gas, and then there's some pretty nasty stuff, and then there is some pretty mild stuff. We do have the capabilities to handle sour gas. Honestly, it gives us a competitive advantage as we add incremental acreage and where the sour gas is going to be located, it gets better to find. We have an AGI well existing in our Central Basin platform assets which we connected the Outrigger assets too. We are building the Wildcat plant which was announced and it will be on in April. And with that, we will have sour gas capabilities at that facility and plans to add incremental capabilities at that facility in the future. So yes, it is an income-generating, very nice rate of return capability that we do have. And again, it gives us a competitive advantage to add incremental acreage and volumes.

And given the amount of acid gas we've handled in our Versado -- legacy Versado and Sand Hills systems, we're probably as experienced as anyone in the basin to handle kind of that newly forming natural gas in the Delaware Basin.

And our next question comes from TJ Schultz of RBC Capital Markets.

Just first on some of the offloaded volumes that you guys talked about. Could you just repeat some of those volumes, I think, in the fourth quarter? But I guess more importantly what impact may be in the first quarter? And then after Joyce, is there still going to be a need ahead of Johnson and kind of any color on what's assumed there in your '18 guidance?

Yes. TJ, just to clarify, it was 30 million a day in the fourth quarter that was impacted and offloaded to other systems. And I'll now turn it over to Pat to give more color.

Yes. I mean, when the Joyce Plant comes on, as Matt said in his prepared remarks, it'll be full. Obviously, right now, we're operating most of our plants on the WestTX system over nameplate capacity. And with that, we have a lot of incremental growth in -- from drilling results from our producer customers. And so as we look forward as to our offload needs, the initial needs will be done by offloading into our SAOU system, utilizing Targa-owned facilities to facilitate offloads from the WestTX system. We would expect, as we approach the startup of Johnson, that we're going to be once again in that position where we're above nameplate capacity across most of our facilities. Obviously, Joyce is filled. We'll be reaching the limit as to what we can offload in the SAOU. And Johnson will be just in time. We may have to offload some volumes to third parties. We have the capabilities of doing that. It'll be close. We'll see.

And if it's not clear to everybody, those are temporary offloads.

Yes.

Just getting us to the plant startup and additional capacity, and then we get those volumes back the first of the very next month.

Got it. Okay. And then the next question is just on CapEx this year. You're still biased higher just with new projects that are expected to be added. So where is the commercial focus most intensive here that would be additive this year? I guess, considering that current guidance, I think, already considers the recent Permian capacity addition announcements and you mentioned the dock work is already in there?

The current guidance has -- our currently expected, currently contracted ramp up of all assets, I guess, you would say. And additional commercial efforts, whether it'd be on gathering and processing, the pipeline or the downstream will add to those volumes causing them to ramp up faster, and that's all good news.

And Our next question comes from Chris Sighinolfi of Jefferies.

It's Corey filing in for Chris. I just wanted to quickly ask about that ONEOK agreement that you guys had mentioned in the prepared remarks. I'm sorry, if that was already discussed. But is there any more color you can give on that?

We -- as you guys know, we announced the JV with -- a 50-50 JV with Hess. And what we're referring to is our Little Missouri 4 Plant up in the Bakken. As a result of that, there was a need for us to acquire an NGL takeaway. We did so, executed a contract with ONEOK for the purposes of that to basically take away the volume that would be produced -- the NGL volumes that would be produced at the Little Missouri 4 plant. The good news about that for us is, is that we were able to approach it in a unique fashion whereby we can actually, over time as the volume increases, exchange those volumes back and have them redeliver to us at our Mont Belvieu facility to feed our fractionation footprint downstream.

Okay. Now that's interesting. And then just second question. The frac train, the one that's in the DevCo with Stonepeak which will be ultimately fed from Grand Prix and obviously, your processing facilities. What percentage of that train is contracted through third parties? Or can you provide a split [of what's been] underpinned by TRGP equity volumes?

Yes. As we're thinking about that next fractionation train, it's a mix of existing customers and future growth. So we've added third-party contracts, as we've talked about, for Grand Prix. Those are -- we have significant commitments for both transportation and fractionation. So it's the growth along our Grand Prix pipeline plus our existing that is really giving us comfort that not only are we going to need Train 6, but we're going to have future growth above and beyond that as well. So it's a combination of both.

Got you. Okay. And then just last one from us. The 4Q EBITDA sort of $328 million, that's $7 million positive you guys are talking about for rollover from 3Q to 4Q, was that all frac? Or was that frac and LPG?

No. There was some LPG as well. So we had a little bit of rollover related to LPG and then frac as well.

Got you. And Jen, can you quantify the LPG? Or is it not material?

No, it's not material. I mean, less than $7 million.

And Our next question comes from Jeremy Bonet (sic) [Tonet] of JPMorgan.

It's Jeremy Tonet from JPMorgan here. I just had a question -- one of your competitors earlier was talking about the ability to kind of use technology to really optimize the G&P business and really wring out cost. Just wondering if you guys see the same -- a similar type of potential at Targa. Or have you already done things like this? Or any thoughts that you can share on the topic?

I'll weigh in on that one. That should not be a new topic. We've been doing that since we founded the company. And at any point in time, we've acquired assets that weren't as well integrated to things like the SCADA systems and automatic data recovery, and we very quickly get that to Targa standards. And that kind of technology is the current Targa standard. When we find additional applications, we try to employ them and that should be business as usual. I didn't hear the comments or listen to whatever competitor you're talking about. But if we're not talking about it, it's like other business as usual that we aren't putting on our call.

Okay. Great. And just wondering, as you look at the guidance here and you think about the Permian growth, I was just wondering if you could share with us any thoughts as far as how you think kind of production ramps up across the years? Is it more back-end loaded? Or is there any conservatism built in with kind of completion delays? Or just any color you can provide on this topic to help us kind of think through your guidance here.

Yes. Good question. We got a similar question last year when we talked to Permian growth and how it's going to ramp. We see continued growth quarter-to-quarter. So our internal forecast has Q1 higher than Q2, Q3 and Q4, just ramping through the year. That said, sometimes when compressor stations or parts of one system come on and ramp up, it can kind of be lumpy. So it might not actually happen that way. So we try and put our best guess on it, but we aren't that good at forecasting each and every well connect and when it's going to come on. So we're internally forecasting it to kind of ramp throughout the year. I would expect some lumpiness, but we don't have great visibility into that lumpiness. But I'd say, Q4, we expect to be the highest, and Q1, we'd expect to be lowest.

Yes, I think, I'd bet on that one.

That's helpful. And then maybe just expanding beyond to the other systems, if you have any thoughts that you could provide as far as the different systems out there, kind of where you're seeing more growth versus less.

Our guidance to some extent describes that. And I'm not looking back at the script, I'm going from my head, highest growth is the Permian and then there are pieces within the Permian, of course. We also expect growth in portions of Oklahoma, WestOK is more challenged than SouthOK. I look forward to the day when with the entire Oklahoma complex has offset legacy production by the new SCOOP/STACK. We said the South Texas would be up. We said that the Bakken would be up. North Texas will be down. [What have you got?]

We didn't guide to it but Coastal will probably be down.

Definitely. But lots of liquids because that's where we make our money.

And Our next question comes from Darren Horowitz of Raymond James.

Jen, just a quick question from a financial optionality perspective, your comment on utilizing additional leverage. What magnitude of additional leverage are you comfortable with on a consolidated debt-to-EBITDA perspective exiting this year? And from a timing perspective, once you get to that 50% capital threshold, how does that -- the use of leverage, how does that factor into buying back those assets from Stonepeak?

Yes. And I mean, I think, from our perspective, we don't really have, what I call, sort of a line in the sand related to leverage. Its partially going to depend on what we see during the year related to fundamentals and volumes and sort of where we are on our expected EBITDA and not only for this year, obviously, but beyond this year. So I think that given that we over equitized significantly in 2017, that means we're better positioned now in 2018, and especially as a result of the DevCos as well taking significant funding out of 2018 and 2019. So the current leverage is about 3.8x at TRP versus a compliance covenant of 5.5x. I mean, I think, we're willing to take it a little bit higher. I think it's largely dependent on how long it will be higher for us. So the number of periods that we expect it to be elevated before the EBITDA really started to ramp in and bring it back down to where we're ultimately more comfortable operating in that sort of 3 to 4x range.

Also I just like get to the math on your question. Everyone should not forget the wonderful thing about that debt-to-EBITDA ratio is, in this current environment, we're spending the dollars upfront and then comes the EBITDA. So the denominator is going to get a whole lot better, if you look at that long-term forecast we're talking about. And it's that denominator getting better, that lets us buyback the Stonepeak interest. It's not increasing leverage at that point, it's decreasing leverage because EBITDA is growing.

Right. I appreciate that. And if I could, one quick follow-up, Jen. From a cost of capital perspective, how much do you calculate that the structure of the Stonepeak JV DevCo structure benefited you, even building in a predetermined rate of return that's kept low single-digit plus or minus any contingency? How much savings do you think you got relative to doing a more traditional JV structure like what you did with Blackstone on Grand Prix initially?

Yes. I mean, we're not going to quantify the savings. We've sort of characterized it as what will ultimately -- what the structure will ultimately cost as is based on a predetermined fixed return that we certainly think is incredibly attractive even versus our current common. If you look at our yield and then assume some sort of a growth component on it. And there are the other facets related to the DevCo that I alluded to earlier in terms of flexibility and some other things that are incredibly important to us. When we looked at it, it was really the temporary nature of the DevCo structure. That was a big focal point for us. That was part of how we designed the structure was, was we were thinking about what could we put in our capital structure that was temporary. And so when we think about our long-term outlook for EBITDA growth, there is a chance that given that increasing EBITDA and given where we expect our leverage to be over that sort of time frame that we could take this out and we could take it out with, obviously, some equity, leverage, a mix of the two. I think that, that's part of what ultimately could result in this being a significantly lower cost than certainly issuing something like common -- that amount of common at today's price would have been.

And our next question comes from Christine Cho of Barclays.

I just have one question. With your Permian volumes being a mix of fee and POP and Permian gas base is flowing out, can you give us an idea of what your exposure to that is? And how easy is to hedge that, at least, until Gulf Coast Express is online?

Sure. I'll start with that. So on the Midland Basin side, it's primarily POP. We have some fee-based contracts over there too, but it's primarily POP. On the Delaware side, it's a mix. The Outrigger acquisition was primarily or almost entirely fee-based. So we have a mix of both. For our POP component, we are exposed, as we get our percentage of proceeds of the gas to basis. So one of the points we made when we were talking about hedging, when we hedge our exposure under those POP contracts were along gas, we don't just hedge Henry Hub, we hedge basis. So we'll hedge Waha and El Paso Permian. So our '18 numbers do reflect that and even our hedges beyond there, we do hedge at Waha and El Paso Permian. So -- but over time -- we think with GCX, over time that large basis that we see now is going to start [to -- start tightening].

There was a piece of the question that said how easy it is to hedge that? Point 1, it's very easy and very liquid and very transparent to what the market believes that is at any point in time and far more liquid than our NGL hedges. On the other hand, our investment in GCX helps change that equation. It gets an important pipe done, to some extent, hedges our position and definitely will reduce basis. Good thing about high basis is it solves high basis, and that's good for our interest as a processor and in our producers' interest as from their position.

And actually, I have one follow up. Do you guys foresee gas residue issues for STACK/SCOOP? More specifically, is there talk that -- or expectations that, that gas is going to go to Waha and then get to the Gulf Coast from there?

I don't think, it's expected that it will get to Waha. In the interim, there'll be some issues seasonally and in particular areas of the SCOOP/STACK. But Cheniere announced a pipeline. It's getting built. That will relieve those issues in the interim period. Gas will move to traditional ways it has through the pipes that try to move it to the upper Midwest or to the East. So didn't make a lot of sense when Waha is growing and oversupplied for Mid-Continent gas to show up at Waha. So the expectation will anything that can be moved down to North Texas will be moved down to North Texas and everything else will go in traditionally where it has gone.

And Our next question comes from Sunil Sibal of Seaport Global Securities.

Congratulations for everybody on the promotions. Yes, a couple of questions for me. So when I look at the Permian, Delaware volumes in the Q4, seems like they were flat sequentially. I was kind wondering was there any kind of onetime issues that impacted that. And I know you mentioned a lot of freeze-offs. How should we kind of think about Delaware portion of the Permian in the next couple of quarters?

Sure. We were impacted by some maintenance events at Versado in the fourth quarter relative to the third. So those were relatively flat, actually down a couple million a day. The longer term, if you look through 2018 and beyond, we see significant growth out in the Delaware. So while it didn't really grow too much relative to Q3, we do see continued growth going forward and there was a maintenance impact at Versado in the quarter.

And I think what I would add is that because of the cold weather, even with some freeze-offs, et cetera, what occurs is you get a lot more heater treaters being run to make sure that the oil is coming out of the ground. So you have a lot more consumption of natural gas at the wellhead that also takes gas away from what ultimately gets delivered into our gathering and processing facilities. So you see a combination of that, and weather not only affects in the freezing mechanism, but it also -- for heater treater purposes, et cetera. So we think volumes are growing, we see it. It is kind of a hiccup but it's not anything we haven't seen before or anything we're even remotely concerned about.

Okay, got it. And then on the '14 (sic) ['18] guidance, you split out the splitter contribution for '18. I was just -- are there any kind of onetime issues impacting that number? Is that a kind of a good rate -- run rate going forward?

I'm not sure I understood the question. Could you repeat it again?

Yes. So when I look at '18 guidance split, I think, normal spread of the project contribution is indicated as about $10 million for full year '18. I was kind of curious, are there any onetime items impacting that number? Or is that a good run rate going forward?

Well, the Noble splitter obviously comes online this year. And so we'll have OpEx associated with the splitter once it's online. And so I think if you think about the sort of $43 million payments that we have been receiving in October of every year, we sort of guided to kind of net op margin associated with that being sort of in the $30 million-ish range when you take into account OpEx.

Okay. And then just to clarify on the 5-year kind of guidance that you had given out for 2021. Seems like on the Slide 10 that, in the today's deck, you're still using the same projects that were used in July. I was wondering just to kind of benchmark our models, how should we be thinking about the CapEx in that base guidance that you gave back in July in terms of the CapEx from 2018 to 2020?

Well, to be clear, what appears on Page 10 of the deck is a repeat of what we showed in June, call it, on the first 2/3 of the page from the left side. And then a new column, which says recent additions to EBITDA growth outlook. It's not a new forecast. It wasn't really a forecast to begin with, it was an outlook. It's not a new outlook. It's showing that there have been changes made since the previous outlook and those changes are the new commercial agreements: GCX, the joint venture in the Bakken, the expanded joint venture in Centrahoma. So I don't want the chart to be misunderstood by anyone who hasn't seen it to think that we've got a new long-term guidance page out there. We don't. Our script comments did say -- they were mine, I kind of remember them. I did say that we believe that the outlook we gave in June is even better today and then we discussed the reasons. So I really can't help you with your modeling beyond that. And the sort of transcript of this will list those reasons, and some of those reasons are listed on Page 10 in that packet. Does that help?

And Our next question comes from Dennis Coleman of Bank of America.

Lots of good questions have been asked. I just have more of a -- I think, I have more of a detailed one. You mentioned in the agreement with ONEOK to move the liquids, that you could potentially just exchange the volumes, I guess, that take volumes that ONEOK has at Belvieu or some shape of that is what I'm imagining. Is there a basis negotiated into those kinds of agreements? Has that already been anticipated? Or do you just do that at market? How does that work?

Recognize that the agreement that we have, obviously, ONEOK has the pipe today -- OH LP pipe today, and then they've got through announcement of their Elk Creek Pipe. Practically speaking, it's my understanding that the current pipe is virtually full. So the additive of their Elk Creek Pipe provides the transportation leg to move the barrels to the various marketplaces. For us, we just view it as a transportation exchange. We're delivering barrels at the Bakken, and over time, an increasing amount of volumes will be redelivered back to us at our Mont Belvieu fractionator. We're not going to get into settlement prices or how that works, but needless to say, it is beneficial to Targa to have those volumes at our fractionator.

Thank you. And that concludes our question-and-answer session for today. I'd like to turn the conference back over to the company for any closing remarks.

Thanks, operator, and thanks to everybody on the call this morning. We hope that the additional color and 2018 guidance was helpful. Please feel free to contact Sanjay, Jen, or any of us to follow up. Have a good day.

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