Targa Resources Corp (TRGP) 2016 Q4 法說會逐字稿

Good day ladies and gentlemen, and welcome to the Targa Resources fourth-quarter 2016 earnings webcast. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions). As a reminder, this conference call may be recorded.

I would now like to introduce your host for today's conference, Miss Jennifer Kneale, Vice President of Finance. Ma'am, you may begin.

Thank you Chanel. I would like to welcome everyone to our fourth-quarter 2016 investor call for Targa Resources Corp.

Before we get started, I would like to mention the Targa Resources Corp., Targa, TRC or the Company has published its earnings release and an updated investor presentation which are available on our website, www.TargaResources.com.

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 statement. For a discussion of factors that could cause actual results to differ please, refer to our SEC filings, including the Company's annual report on Form 10-K the year ended December 31, 2015, and quarterly reports on Form 10-Q.

Pat McDonie, EVP of Southern Field Gathering and Processing, Danny Middlebrooks, EVP of Northern Field Gathering and Processing, our North Dakota position, and Scott Pryor, EVP of Logistics and Marketing, our downstream business, will be joining Joe Bob Perkins, CEO, and Matt Meloy, CFO, in our scripted remarks. Joe Bob will begin the call and will then turn it over to Matt to discuss fourth-quarter and full-year 2016 results, and then Pat, Danny and Scott will discuss their business areas in that order. After closing remarks from Joe Bob, we will then open the call up for questions.

With that, I'll turn the call over to Joe Bob.

Thanks Jen. Good morning and thanks to everyone for joining.

As we wrap up 2016 reporting, we are also going to try to cover our current expectations for 2017, including a discussion of industry trends and activities that are driving those expectations.

We spent much of 2015 and 2016 taking some very important steps to position Targa for success across a range of commodity price environments. And now that we are feeling some commodity price stability at levels of support customer activity and volumes, we believe that Targa has a very positive outlook for 2017 and beyond. That positive outlook is highlighted by, first, a strong interconnected Targa Permian footprint with significant exposure to both Midland and Delaware activity, both of which are augmented by our recent acquisition announcement on January 23. Secondly, Targa assets in both the stack and scoop, where we are seeing activity levels increase, then positions in other E&P basins, where Targa volumes are likely to outperform overall Basin levels due to the strength of our asset position and due to the quality producers that we are serving, as evidenced by our Eagle Ford and Bakken activities, for example. And of course our Targa Downstream infrastructure poised to benefit from some of the changing domestic and global market dynamics, especially as world-class PetChem crackers come online on the Gulf Coast later this year and next year. And across all of our businesses where Targa commercial operations and future potential growth opportunities are supported by attractive partnerships, mutually beneficial customer relationships, a strong balance sheet, demonstrated access to capital markets, and a loyal and talented workforce.

2017 is off to an exciting start for us at Targa, highlighted by the announcement on January 23 that we were acquiring very nicely fitting additional assets in the Delaware and Midland Basins for $565 million, plus performance contingent future payments. And at the same time as the acquisition announcement, we did a concurrent oversubscribed equity offering that raised approximately $525 million of net proceeds after an immediate upsizing and exercise of the underwriters green shoot. Based on the success of the equity offering and the feedback that we've received from investors since January 23, the broad market seems to appreciate that, for Targa, this is an incredible strategic and operational fit, an accretive transaction derisked through the earnout structure where the ultimate consideration is driven by performance that also benefits Targa shareholders. We are essentially bolting these assets into our existing systems, benefiting from capital efficiencies and from operational and commercial synergies, and I would add benefiting from higher EBITDA margins than what some external audiences may perceive or extrapolate relative to historical averages on our existing assets in the Permian.

Assuming the acquisition closes in the near term, we plan to then quickly proceed with a 60 million cubic feet per day plant in Pecos County on the southern end of the acquired Delaware Basin assets. And as mentioned on our call announcing the acquisition, post-close, we would also anticipate quickly connecting the acquired Delaware Basin assets to our Sand Hills system and the acquired Midland Basin assets to our WestTX system. Subject to HSR approvals and other closing conditions, we expect a first-quarter close and hope and believe that it will be sooner rather than later.

So let's move to discussing our 2017 growth CapEx and operations guidance, what I'm going to take you through at a high level and then Pat, Danny and Scott will repeat some of those expectations and guidance and give you additional color later in the call. Matt will also provide some financial guidance and additional explanation during his prepared remarks.

For 2017, we currently expect net growth capital spending of at least $700 million. We recently posted an updated investor deck for this call. You can access it on our web, and on Page 11 of that presentation, we highlight growth capital spending for the year.

Let me first focus on four major projects spread across that table, the 200 million cubic feet per day Joyce plant in West Texas, the 60 million cubic feet per day plant in the Delaware Basin that we will move forward with after we close the acquisition, the Raptor plant in South Texas, which we recently decided with our JV partner Sanchez to expand before it is completed from 200 million cubic feet per day to 260 million cubic feet per day, and the 35,000 barrel per day crude and condensate splitter at Channelview. Although you won't see the subtotal on the table, those four major projects make up approximately $210 million of the quantified 2017 growth capital spending of at least $700 million.

Given the producer activity we are now seeing in many of our G&P areas, we currently also expect to spend at least another $400 million across our gathering and processing footprint related to identified projects that individually are each relatively small. Of course, this spending is somewhat dependent on activity levels, and it will occur primarily in the Targa systems where we are forecasting volume growth for the year.

Downstream, we have a similar group of smaller identified growth CapEx projects currently totaling approximately $90 million with attractive returns that are primarily associated with Mont Belvieu. As you probably anticipate, there are other attractive G&P and downstream projects currently under development, but not yet announced, that may lead to additional growth CapEx spending in 2017.

On our third-quarter call in early November, I said that our then current expectation was for a similar or likely higher level of growth CapEx spending in 2017 relative to what at the time was $525 million of growth CapEx guidance for 2016, but that we would wait until this call to provide better quantified guidance. I guess today's call confirms that the likely higher color previously provided is correct, driven by a combination of factors such as a portion of our growth CapEx spending expected in 2016 was pushed into 2017. And at this point in February, we have somewhat improved visibility on producer activity and expectations for the remainder of 2017 and the additional infrastructure needs and opportunities that that expectation provides.

We have had a chance to refine our initial view of integrated infrastructure spend around the acquired Delaware and Midland systems, and we have also improved our initial view of additional infrastructure to support the Targa Downstream business.

These highlighted capital expenditures are the result of and will support and benefit from the activity and resulting expected volumes we are currently experiencing around our systems. Of course, additional work and improving outlook could result in additional opportunities and/or additional announced projects.

Now let's shift our current outlook -- to our current outlook for Targa field G&P volumes. Sitting now in the middle of February 2017, we expect Targa's average 2017 Permian Basin natural gas inlet volumes to be approximately 20% higher than average 2016 volumes, driven by activity and expected volume increases for Targa assets in both the Midland and Delaware Basins. In both South Texas and the Badlands, we estimate 2017 average natural gas inlet volumes will be higher than average 2016 volumes. We also expect higher average crude volumes in the Badlands year-over-year. These falling increases that I just mentioned will be partially offset by lower volumes in WestOK, SouthOK, and North Texas in 2017 compared to 2016. However, with the overall Targa field G&P growth driven by the Permian, South Texas and the Badlands, we expect at least 10% growth in our overall field G&P inlet volumes in 2017 compared to 2016.

With respect to the Downstream, almost everyone on the call knows that we spent a lot of time in 2016 discussing LPG exports with investors, potential investors, and sell-side analysts, we believe providing helpful industry color, but not disclosing new information about our contract portfolio. This morning, after considerable internal deliberation, and still in the context of not wanting to disclose more than is competitively appropriate from a business competition viewpoint, we're going to provide you with another layer, snapshot, of our long-term LPG export contracts. We believe this snapshot is consistent with what we have been saying, and is consistent with the likely impressions among our customers, potential customers, and our competitors, and it is reflective of our commercial team's long time ongoing successful efforts around the globe ever since we became a significant exporter of LPGs.

So, currently, we have approximately two-thirds of our current estimated export capacity of 7 million barrels per month term contracted each year at attractive rates through 2022. Now, some years are slightly higher and some years are slightly lower than two-thirds, but two-thirds of 7 million barrels per month is representative of the volumes contracted in each year through 2022.

There has been and will continue to be an active ongoing contract portfolio management process, just as we've often repeated, adding and extending contracts as we go forward over time. This rare snapshot updates our continued success. However, today's updated snapshot should not imply any Targa willingness for a continuous or ongoing public update to such information. I'm looking across the table at Scott, and he is grinning at me. So that's about as much as you're going to get out of us even in extended Q&A.

With that, I'll now turn the call over to Matt.

Thanks Joe Bob. I will begin by discussing our fourth-quarter results and will provide some 2017 financial guidance as I move through my remarks.

Targa's reported adjusted EBITDA for the fourth quarter was about $298 million, which, as anticipated by remarks in our third-quarter call, was the highest quarter of 2016. Strong fourth-quarter results were due largely to continued growth in our Permian G&P assets and strong performance in our Downstream business, which included the partial recognition of the approximately $40 million payment received from Noble in October.

Let's pause briefly to discuss the payments associated with the Noble crude and condensate splitter in a little bit more detail. We received approximately $40 million from Noble in October 2016 and the entirety is included in distributable cash flow for the fourth quarter. The contribution to adjusted EBITDA will be amortized over four quarters beginning in the quarter received, so for the fourth quarter of 2016, approximately $10 million of adjusted EBITDA was recognized. A full explanation of our treatment of the splitter payment can be found on Slide 38 of the investor presentation that was recently posted to our website this morning.

Reported net maintenance capital expenditures were $28 million in the fourth quarter of 2016 compared to $24 million in the fourth quarter of 2015, and total net maintenance CapEx for 2016 was approximately $80 million. We currently expect approximately $110 million of net maintenance CapEx for 2017.

Turning now to our segment level results, I'll go over our performance for the fourth quarter on a year-over-year basis. For the Gathering and Processing segment, reported operating margin for the fourth quarter of 2016 increased by 21% compared to last year, primarily due to higher commodity prices and higher inlet volume in the Permian Basin with overall field G&P inlet volumes relatively flat compared to the fourth quarter of 2015. NGL prices were 45% higher, natural gas prices were 31% higher, and condensate prices were 20% higher compared to the fourth quarter of 2015.

Fourth-quarter reported 2016 natural gas inlet volumes of 2.5 billion cubic feet per day were approximately flat compared to the fourth quarter last year. For year-over-year quarters, we saw an increase in volumes in WestTX, SOU, SouthTX and Versado, offset by lower volumes in WestOK, SouthOK, North Texas, Sand Hills and Badlands. Note that the bright spot of the scoop and stack activity in Oklahoma did not fully offset other Oklahoma declines.

Crude oil gathered was 104,000 barrels per day in the fourth quarter, down approximately 5% versus the same time period last year and essentially flat when compared to the third quarter of 2016, primarily due to the timing of producer well completions and shut-ins to protect surrounding wells during fracing, and also impacted by very severe December weather. Whereas the East and West Coast were warmer relative to historic norms, North Dakota had the third coldest winter recorded in its history.

Moving to the Downstream business, fourth-quarter reported operating margin declined 8%, primarily due to lower LPG export margin, partially offset by higher marketing gains, higher fractionation margin, and higher trading volume. Fractionation margin increased primarily due to higher fees and favorable system product gains partially offset by lower volumes, which declined approximately 9% compared to the fourth quarter of 2015, primarily as a result of some lower margin contracts rolling off.

Now let's discuss our capital structure and liquidity. As we mentioned on our last earnings call, the Series A and Series B warrants associated with the $1 billion Series A preferred stock issuance completed in March 2016 became exercisable on September 16, 2016. At this point, almost all of the warrants have been exercised, which we elected to net share or settle, resulting in the issuance of approximately 11.3 million shares. Less than 1% of the warrants remain outstanding.

During the fourth quarter of 2016, we issued $1 billion of senior notes at attractive rates using the proceeds to successfully complete concurrent tender offers on some of our near-term senior notes. We also extended on our TRP revolver -- extended the maturity on our TRP revolver and Accounts Receivable facility. Looking forward, we have no significant near-term debt maturity concerns and have an attractive debt maturity profile that we will be continuing to manage over time.

As of December 31, we had only $150 million outstanding under TRP's $1.6 billion senior secured revolving credit facility due October 2020. On a debt compliance basis, TRP's leverage ratio at the end of the fourth quarter was 3.8 times versus a compliance covenant of 5.5 times. We also had borrowings of $275 million under our Accounts Receivable securitization facility at quarter end. TRP revolver availability at quarter end was over $1.4 billion.

As of December 31, TRC had $275 million in borrowings outstanding under our $670 million senior secured credit facility that matures in February 2020, and the balance on TRC's term loan facility that matures in February 2022 was $160 million, both flat to the September 30 balances. TRC revolver availability at quarter end was approximately $395 million. Including approximately $70 million in cash, total Targa liquidity at quarter end was approximately $1.9 billion.

On the equity side, we continued to utilize our ATM during 2016 and for the year issued approximately $575 million of equity through our ATM program. We expect to continue to utilize the ATM program to fund growth CapEx in 2017 and may fund growth CapEx with a higher percentage of equity than our traditional 50% debt and 50% equity ratio given our consolidated reported debt to EBITDA ratio is approximately 4.6 times. Ideally, our long-term Targa consolidated reported leverage ratio is also approximately 3 to 4 times. However, we are comfortable at our current leverage level, particularly given there's no consolidated debt covenant tests at the TRC level and because we expect EBITDA growth looking forward, which will reduce our leverage ratio.

As Joe Bob mentioned earlier, concurrent with the acquisition that we announced in January, we issued 9.2 million shares and raised approximately $525 million of net proceeds, which, along with cash on hand and revolver availability, will be used to fund the initial acquisition consideration of $565 million.

Turning now to hedges, given higher commodity prices in the fourth quarter of 2016, we entered into some additional swaps to hedge some of our gathering and processing equity volume commodity exposure. We added some calendar 2017 through 2019 natural gas, ethane, propane, butane, gasoline and crude swaps, and also added some additional calendar 2017 swaps. As a result, as of December 31, 2016, for non-fee-based operating margin relative to the Partnership's current estimate of equity volumes from field gathering and processing, we estimate that we have hedged approximately 75% of 2017 natural gas, 65% of 2017 condensate, and approximately 50% of 2017 NGL volumes.

Before handing the call over to Pat, I want to discuss a couple of items related to our Permian acquisition and also provide our estimated 2017 dividend coverage. Even given the increase in commodity prices incorporating the additional depreciation and amortization we expect from the acquired assets and our expected levels of future CapEx, we continue to not expect to be a cash taxpayer for at least five years. For full-year 2017, we are estimating dividend coverage in excess of 1.0 times assuming a $3.64 per common share 2017 dividend.

We are starting to get more questions related to dividend growth, so I wanted to provide some color around our current thinking. As we look forward, we see a very constructive industry environment for Targa in 2017 and beyond, and building excess coverage will further support our balance sheet as we continue to pursue growth in and around our asset base. Consistent with past practice, we would expect to build some excess coverage during more favorable parts of the commodity price cycle, which will provide additional cushion during downturns.

And with that, I will now hand the call off to Pat for some additional comments about the Southern Field G&P business that he leads. Pat?

Thanks Matt, and good morning everyone.

Looking back on 2016, I am extremely pleased with our performance in the Field G&P segment. And more importantly, looking forward, I am very excited about the opportunities that we see across our outstanding footprint of assets. We have a number of capital projects in progress, which obviously speaks to our expectations and the expectations of our producers for rising activity, which should support the Field G&P inlet volume growth that Joe Bob mentioned earlier.

In SouthTX, our Raptor plant will be ramping up during the first quarter and will be fully operational in early April. Our JV partner, Sanchez Production Partners, and Targa have jointly agreed to spend a limited amount of capital to add compression to increase total plant capacity to 260 million cubic feet a day from the originally planned 200 million cubic feet a day, a high impact, highly capital efficient expansion feature designed into the plant already under construction. The expansion decision highlights our continuing joint optimism for activity on our system in the Western part of the Eagle Ford.

In WestTX, the restart of our Benedum plant is slated for a first-quarter 2017 in-service date. The capacity expansion at Midkiff is planned for a second-quarter 2017 in-service date. And the new 200 million cubic feet per day Joyce plant is expected to be in service in the first quarter of 2018. These projects are on track and demonstrate continued optimism by Pioneer and Targa related to producer activity and the growth of volumes on our WestTX joint venture.

As also mentioned earlier, given our January acquisition announcement, we expect to connect the acquired assets in Martin County to our WestTX system at the Buffalo plant soon after transaction close. Given the activity levels that we are seeing in the Midland Basin, our broader footprint now deeper into Martin, Howard, and Borden Counties, we will likely need additional processing capacity in that area over the relative near term.

While we are not committing to another plant today, there is a strong likelihood that, later this year, we will be announcing another 200 million cubic feet per day Midland Basin plant starting up in the second half of 2018 that would require some capital to be spent in 2017.

In the Delaware Basin, assuming the close of the acquisition, as Joe Bob mentioned, we are initially going to add a 60 million cubic feet per day plant in Pecos County to support the activities of producers on the newly acquired Southern Delaware assets. Similar to the Midland Basin, and depending on activity levels on the soon-to-be acquired assets, we are already thinking about the optimal location and timing for the next Delaware plant.

Some of you will recall that we announced plans in October 2014 to build a 300 million cubic feet per day Delaware plant, plans that would have likely connected our Versado system and Sand Hills systems, but those plans were ultimately shelved during the downturn. Given success in the area, the acquisition, and our resulting increased Delaware footprint, we are considering whether the most efficient way to spend capital includes a plant and infrastructure that connects Versado to the rest of our Permian systems. Producer activity in the area is even higher than expected when we started looking at the acquired assets, which bodes well for continued expansion.

Turning to the Mid-Continent, where upstream activity targeting the stack and scoop continues and is increasing, we remain focused on reaching further into these highly economic resource plays. With resource delineation continuing to push stack activity further northwest as producers test the Merrimack and Osage formations, we are very well positioned to capture additional volumes with minimal incremental capital spend to utilize existing capacity on our WestOK system. While we have seen some producers with both stack and scoop assets focus more on the stack, the scoop continues to garner significant attention from producers in that area, and we are focused on continuing to reach further northwest into Grady County.

All of our efforts in G&P are supported by engineering and operations teamwork across all of our businesses to share lessons and best practices, and I am incredibly proud of the efforts of our people in 2016 and so far in 2017. I feel very confident in our forecasted increase in 2017 average Field G&P inlet volumes relative to 2016, and I'm extremely excited about the opportunities that we are currently seeing and the trajectory for beyond 2017 at these current commodity prices.

I will now turn the call over to Danny, who leads our commercial efforts in North Dakota, for an update on what is often a very cold place. Danny?

Thank you Pat, and good morning all.

The end of 2016 was characterized by historical snowfalls in North Dakota. I have heard it was the third worst snow event on record for the state. These events created delays with respect to construction activities and production, but will not have a long-term impact and only a minimal impact on fourth-quarter activity.

On the call -- on the last call, we updated you that we are mechanically complete on approximately 50% of the 30-mile pipeline project we were building on the Ft. Berthold Indian reservation, and had initial production of 2,500 barrels per day flowing at that time. Before stopping during the height of the winter storms, we had initial production of approximately 15,000 barrels per day flowing. We have since resumed construction and are over 97% complete with the expansion with only the tie-ins of about 10 well pads to finish.

Last February, we provided guidance we expected average 2016 natural gas volumes to be higher than average 2015 volumes and that we expected crude volumes to be essentially flat despite the slowdown in activity that was experienced across the Basin in 2015 and expected shut-ins to protect nearby wells during fracing.

For 2016, our Badlands natural gas volumes increased 6% versus 2015 and our crude volumes were down only slightly compared to 2015. During the fourth quarter, we tracked well shut-ins for fracture protection, and we estimate we had approximately 15,000 barrels per day shut in by our customers, which, coupled with the weather, created headwinds for us in the fourth quarter.

Looking forward to the rest of 2017, we continue to hear positive indications (technical difficulty) are likely to increase activity on our dedicated acreage, assuming crude prices stabilize around $55 per barrel. For the Badlands, in 2017, we expect average crude and gas volumes to be higher compared to 2016. Given Targa's attractive per unit margins for both gas and crude oil in the Bakken, and available capacity in our (technical difficulty) plants, we are poised to benefit with any uptick in drilling activity.

I'll now turn the call over to Scott Pryor, who leads our Downstream business unit. Scott?

Thanks Danny. As most of you know, my team and I lead the Downstream business.

Starting with LPG exports, 2016 was a really solid year for Targa as we outperformed our guidance for the year despite some volatile market dynamics. Fourth-quarter LPG export volumes were 6.3 million barrels per month, which exceeded the guidance provided on our third-quarter earnings call of at least 6 million barrels per month, and volumes would have been higher if not for unseasonable fog delays during the latter part of December.

Our fourth-quarter LPG export volume performance was a combination of term and spot contracts, which is typical, and what you should expect to be the case going forward. Globally, there was an increase in LPG demand during the quarter from places like Indonesia, India, China, Africa and Europe. Relative to those market trends, Targa is well-positioned to benefit from short-term opportunities and as a part of a longer-term contract portfolio management.

Vessels leaving our facility continued to move to destinations somewhat consistent with previous quarters with approximately 64% going to the Americas, and 36% to areas such as Europe, Africa and Asia in the fourth quarter of 2016. We did see more cargoes moving to Europe in the fourth quarter, due in large part to the weather. And our volumes to the Americas continued to grow even if the percentage of our overall volumes is slightly lower.

Our full-year 2016 average of 5.5 million barrels per month exceeded the guidance that we provided last February, when we said that we expected to export at least 5 million barrels per month of LPGs. We are particularly proud of our results given some of the global market disruptions in the summer. As previously discussed, those market disruptions had a minimal impact on our facility relative to others with only three cancellations during the period and none throughout the rest of 2016 for Targa. Our overall 2016 results are supportive of the growing presence of Gulf Coast LPG exports on the global waterborne market, and Targa's positioning as an important supplier to a diverse set of customers worldwide.

Given the increased competitiveness in the market as a result of additional capacity coming online over the last couple of years, we intentionally play our cards close to the vast, believing that there are commercial benefits to being less transparent around contracting.

Just as we did in February 2015, when we last provided you with a snapshot of the status of our contract portfolio looking out longer than the current year, today, we want to try to remove some of the investor concerns around the term of our contract portfolio. So I want to repeat what Joe Bob said earlier, because it is highly unlikely I will be convinced to provide any other data points for years.

Currently, we have approximately two-thirds of our current estimated LPG export capacity contracted each year through 2022 at attractive rates. That is about two-thirds of 7 million barrels per month for each year through 2022. There is some minor variation from the two-thirds figure in individual years, but it's never substantial, and it falls in that range year-in and year-out and doesn't trend lower over that same time frame.

As always, our marketing efforts in the global export market continue, and there has been and will continue to be an active ongoing contract portfolio management process whereby we continue to add and extend term contracts as we go forward over time while complementing the portfolio and the quarterly performance with spot contracts.

As we look forward to the rest of 2017 and beyond, the oil-driven US E&P activity is expected to increase domestic NGL production, which should solidify the US's position as one of the leading sources of low-cost LPG supply, which, given the support we have in accessing volumes from our G&P and fractionation assets, positions us well.

Globally, we are seeing the positive impact of OPEC production cuts through a tightening of LPG volumes available from the Middle East. This may further highlight the US as the fastest-growing provider of LPG supply to the global market, a distinction the US has held for several years and may hold for several years looking forward.

Turning now to our fractionation business, the expected growth in our industry and target GMP volumes with the increasing activity levels in a number of key basins that supply volumes to Mont Belvieu, means we are well-positioned, given we have fractionation capacity available at our CBF facility. In the fourth quarter of 2016, we had higher fractionation volumes sourced from our Upstream G&P facilities relative to the same period in 2015 and, looking forward, see supply and demand catalysts that will certainly benefit Targa. The outlook for increased ethane recovery in 2017 and beyond driven by growing petrochemical demand from the large-scale PetChem facilities scheduled to come online beginning later this year will drive fractionation volumes higher. Overall increased domestic exploration and production activities will also drive fractionation volumes higher.

We have available fractionation capacity today, but if you look at most of the NGL production forecasts that have been recently published, Mont Belvieu will need additional fractionation capacity. It's just a matter of when and not if. While we do not have immediate plans to proceed with Train 6 in Mont Belvieu, that permit is in hand and it is an example of a project that we will likely move forward with at some point.

Lastly, construction continues on our 35,000 barrel per day crude and condensate splitter at Channelview. We anticipate that the splitter will be online and fully operational in the first quarter of 2018.

Downstream, we are working on a number of other exciting project. We are constantly looking at how to best maximize our existing infrastructure and to provide solutions for customers here and around the world. We are not in a position to announce any additional downstream projects, but the positive tone around commodity prices and domestic activity levels is fostering discussions about additional infrastructure opportunities, which is a nice change relative to the market tone over the last couple of years.

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

Thanks Scott. We've covered a lot of ground this morning. Let me briefly summarize our new public expectations, or "guidance", provided today.

For 2017, we expect dividend coverage in excess of one times assuming a 2017 dividend of $3.64 per common share. We estimate at least $700 million of attractive growth capital spending based on the projects we highlighted, and expect $110 million of maintenance capital spending. We expect average 2017 Permian Basin volume growth of approximately 20% over average 2016.

In the Badlands, we estimate higher crude and gas volumes year-over-year. In South Texas, we estimate higher average inlet volumes year-over-year. And for our overall Field G&P inlet volumes, we expect at least 10% growth in 2017 compared to average 2016. Downstream, we have export services of approximately two-thirds of 7 million barrels per month contracted for multiple years, in each of multiple years.

With that summary and our comments today, I hope you have also heard we are optimistic about the current environment, thanks in large part to our team's successful navigation of 2015 and 2016, and the activity levels of customers who also successfully navigated such waters. I am so proud of the work of our employees over the last couple of years, and a lot of my excitement is driven by the enthusiasm that I am hearing from them across the Company relative to the opportunities that they are seeing in the market.

In conclusion, looking forward to the rest of 2017 and beyond, we have a number of attractive capital project identified or underway and expect to see continued opportunities to build out infrastructure around our assets at compelling returns. We are hopefully soon closing an acquisition that knits together very well with our existing assets and provides us additional runway for growth in the most active G&P areas in the country. And we are well-positioned with our existing asset footprint to benefit from domestic market themes such as ethane recovery, increased G&P activity in the best basins, and increased domestic NGL production. These themes, combined with Targa positioning and Targa execution, should create upside for our investors.

So, with that, operator, please open up the line for questions. Thank you very much.

(Operator Instructions). Brandon Blossman, Tudor, Pickering, Holt.

Good morning. I hesitate to ask, but I'm going to do it. LPG recontracting, Joe Bob, I think the term you used was attractive rate. What's the point of comparison for attractive? Is that spot rates, current spot rates, historical contracted rates, something in between, or something else?

Brandon, you win. We did predict that was the first question. And we also predicted that Joe Bob wouldn't answer it, which is why Scott is going to.

Thanks for the question. We did anticipate it to a certain degree. What I would say is this, that when we first started our Phase I and Phase II export projects and contracting for those, those were at very, very attractive rates. And these attractive rates that we have out there and we are constantly contracting going forward and we're working our contract portfolio on a term basis regularly. So we are very happy with the rates that we have. You hear a lot of times in the marketplace customers that may be trying to mitigate some of their take-or-pay requirements, and you hear what I would refer to as re-trade spot values that are at relatively low rates, in my opinion. So these are attractive compared to those types of rates.

Okay, that's actually more than I expected. Thank you Scott.

Because it was Scott instead of Joe Bob, right?

How about -- this is hopefully fairly easy. Frac Train 6, what do you need to see to sanction that project and what's the timeline between sanction and online date?

Sanction is an interesting word. We have said for some time, and we realize that, that it's not a question of if, just a question of when on Train 6. We are not completely full in the target portfolio of Mont Belvieu based fractionation, but we don't have a whole lot of room, and we are filling up that room primarily based on Targa's increasing equity barrels flowing through our fractionation. We also want to be able to meet the needs of our customers, and if we stay at current price levels, there's going to be a need for additional fractionation. From the time we actually break ground on that, you've seen, based on our past track record, that that can be done in about a year. Can we do it a little faster? Sure. If we were, and I don't expect this to be the case, kind of pushing the end of the contract without renewal process, we might get started and move a little bit slower. But on average, from the time we break ground, and people would notice it really quickly when we broke ground, we would probably tell the markets at the same time, you could count on roughly a year.

Absolutely no risk that it gets too tight at Mont Belvieu? You guys will meet demand as needed?

I think there is risk it gets too tight at Mont Belvieu in some point, because it does take time to build these. At the same time, Targa in particular has a portfolio that allows us a little bit of tightness release valve by pushing NGLs to Lake Charles to fractionate on a temporary basis.

Understood. Thank you Joe Bob. I'll leave it there.

Jeremy Tonet, JPMorgan.

Good morning. I just want to dig in on the Permian a bit more here. And I was wondering if you might be able to provide us what type of -- as that ramps, what type of exit rate -- kind of if you look at 4Q 2017 versus 4Q 2016, how that might look, and if there's any color you could provide kind of on same-store sales without Outrigger? Just trying to calibrate our models here. Thanks.

Understood. Same-store sales is a really interesting question. If you take that all the way down to the well, all of the new horizontal wells start up at higher rates, have a fairly rapid first year decline and then that decline slows down. We aren't about one well at a time. In fact, we hook up entire drilling pads and tank batteries behind -- pads behind existing tank batteries. So, it's a multi-store equation even at the most disaggregated of our connections. And that also makes it capital efficient for our connections.

Exit rate for 2016 compared to 2017 compared to exit rate 2016, is not granularity we are providing for you right now. And we have multiple forecasts. I hope it helps you calibrate your models to look at about 20%. This isn't going to be precisely 20%. Frankly, I would take the over on 20% of Targa's Permian in 2017 relative to 2016.

Just to add to that, I'd say when we look at our growth out in the Permian, we see growth really pretty steady across 2017. I don't know that we forecasted a big step change one quarter versus the others. There is very building with when some of our customers connect the wells, so it won't be smooth, but our estimate is for a pretty steady ramp across the year. It's going to be wrong in any given quarter, but we see continued growth just throughout the year.

Okay. Matt, I just want to pick up on some of your comments as far as growing coverage, and just wondering if you could tie any numbers in there, kind of how you think about it philosophically as far as what type of coverage or range of coverage would make sense and leverage employees before you thought about dividend growth.

Yes, we talked about it some. We intentionally left out any kind of number to put in there. But I guess what I would say is, coming out of the environment we were in and looking ahead at the growth opportunities we have, we have $700 million of growth CapEx here, which we anticipate to grow significantly, just with all the opportunities that we have, we want to take care of the balance sheet first. So that's going to be our first priority. The 3 to 4 times targeted ratio for the partnership, we don't really plan to change that. We think, over time, we will get our consolidated into that range, but don't necessarily have to solve for that right up front. So I think it's really just priorities for us, and our priority is going to be taking care of the balance sheet.

Okay, great. That's helpful. That's it for me, thank you.

Chris Sighinolfi, Jefferies.

Good morning, Joe Bob, how are you? I just had a question. I was looking at the slide presentation, and noticed, on the Joyce plant in West Texas, $90 million of spend for the $200 million of gas processing capacity seems very attractive relative to the typical costs we've seen from you and others in the past. So I'm just wondering if there's something unique about that facility or something about that region in general that maybe affords it more economic investment on these types of things going forward.

You picked up on it. First, I'd say I'm very, very proud of our engineering group working on a different way of approaching these costs. And they were able to -- you can see it relative to our last press events -- figure out ways for this to be less costly relative to other $200 million a day plants built in a different time and at different cost in a slightly different way. More importantly, we like to think that we've learn things along the way, are very experienced at building those plants in West Texas and can (technical difficulty) capture some of those costs going forward. It would not be fair to not count the fact that, because it's pretty close to another plant, we've gained some infrastructure advantages by being close to that plant. And every plant comes with associated infrastructure spending, and we might have had less on this one.

Just to add to that too, Joe, when you look at the all-in cost for the plant and related infrastructure, it is cheaper than our historical spend for a plant. But that $90 million, it is also it's net, so it's a 73% interest, so that is our share of the plant, so the gross is a bit higher than that.

Okay. That's helpful, Matt. But I guess, in relation to Jeremy's question, I think about some of the returns, we should -- opportunities like this where you have something located close to an existing asset, you can extract the costing improvement. When you bid that plant out or sell that capacity, we should think -- is it incorrect to think that's a better return project, therefore you basically get to capture that cost improvement?

Yes, at a return.

Yes, as we are able to reduce the costs in the plant and as we are adding more plants, we are going to continue to do everything we can to continue to drive those costs down.

I would extrapolate that to any plant being added to a multi-plant interconnected multisystem set of infrastructure has advantages, cost advantages, asset flexibility advantages, reliability advantages. You're sort of touching on that.

I would add one more thing too, and that is we are doing it at a lower cost with the same efficiencies and capabilities to process our gas.

Okay. I guess switching gears a little bit, I have two other remaining questions if I could. Matt, first, I guess, on that NGL sensitivity for 2017, it looked like it's escalated a touch from what we were sort of seeing for 2016. I'm just wondering what's driving that. It looks like you're more hedged now, so I'm just wondering. Is that net to the sensitivities on hedges or is there a mix shift in the contracts? Any dynamic around maybe what's shaping that would be helpful.

Yes, I think that's likely the volume outlook because we see growth, but not only inlet, we're going to see increased NGL production growth too. So we do have some more hedges in place but then we do have more equity volumes from the growth in our business. So, it's just a trade-off of those two.

Okay. And then that's helpful. And then, finally, I guess I remember from the 10-K from last year that you had I think it was the Velma agreement with OneOK in the SouthOK system that was set to expire at the end of the year and you were planning to move that volume on to your own downstream network. I don't think the volumes were ever quantified, but I'm wondering, now that that agreement presumably has expired, if you offer any color on that, maybe what the uplift might be on your own downstream position from that contract expiration.

We've got a number of different arrangements at different plants. We are always looking to try and get as many volumes as we can through our downstream assets. I don't recall the term of that exact one that you are referring to, but --

But across the portfolio.

Yes.

Okay, I figured it might've been larger (multiple speakers) it was called out.

Across the portfolio -- Scott is kicking me under a wide table here. Across the portfolio, we are always trying to control more liquids instead of less liquids. You should assume that we are working on that. And you should also presume that we are probably not going to dissect individual agreements and continue to describe them publicly. There was greater visibility on some of those agreements (technical difficulty)

Okay. I didn't know if those were because they were legacy Atlas or because they were significant in size, but they were denoted, and that's the only reason I brought that one up.

Okay, I understand.

Thanks a lot guys.

Darren Horowitz, Raymond James.

Good morning guys. Regarding the comments that have been made around equity NGL volume exposure, pro forma the Permian acquisition being integrated by the end of the year, you're going to have obviously gathering capacity over 2 Bcf a day, so more rich gas coming across the system through that, and also acres dedications. How much equity barrel or commodity sensitive marketing exposure do you want to have pro forma the assets being integrated? And could it be a situation where the incremental fee-based EBITDA from the organic growth projects grows consistent with that equity NGL exposure such that the amount of margin that's actually exposed still stays around 30%?

Yes, it's a good question, Darren. We have a mix, so it really does depend on what growth we see from those assets relative to our legacy assets --

And price.

-- and price. The Outrigger acquisition, it's essentially all fee-based, as you will recall, so it's 98%. We are going to see significant growth. That's going to be pushing dollar fees higher, so then it's just really a matter of what happens to commodity prices and our volumes that are on our WestTX and other areas where it's primarily percentage of proceeds.

Okay. And then just one quick follow-up question on the Permian Basin G&P natural gas inlet volume growth, recognizing that it's really going to start picking up pro forma the asset integration, but I'm just wondering. From a timing and magnitude perspective, how pronounced do you expect the back half of your step change to be? And can you give us at least your preliminary thoughts of where you think, exit 2017, Permian Basin G&P natural gas inlet volumes could be versus day one when those assets are integrated?

It sounds a lot like a question we got earlier on the kind of volume ramp. I think as we think about Permian growth across 2017, I think we're going to see a steady ramp in volumes. At times, there are periods where a bunch of compressor stations do come on and we do get some kind of intermediate step changes, but we don't have really good visibility on when those occur at this 10 seconds. So our forecast is for a steady ramp of Permian volumes really from kind of now through the end of the year and then continuing into 2018.

And then the individual producer, like shut-in wells to protect while they're fracing have pad drilling and pad completion, maybe more in drilling mode than completion mode at a particular point in time, but those things tend to even out with each other. I don't think -- even though we analyze it hard and run lots of forecasts, I don't really believe we can give you much more color other than to say it is steadily increasing, which was (multiple speakers) that's our expectation. It's going to be what it's going to be, but it's going to be up and to the right. 20% average to average is pretty nice growth, and we are not trying to imply that we've got 1% precision on that (multiple speakers)

I appreciate that, Joe Bob. And then if I could, just one bigger picture follow-up. And I appreciate the color on this. But when you've outlined the opportunities for example to connect the Delaware system and the Sand Hills and what you're going to do in the Midland with the legacy West Texas assets and also talked about what's going on in Howard and Martin and Borden Counties, where do you see the biggest area of incremental opportunity for you, just from a system leveraging perspective?

I think we really -- we had a phenomenal position in the Midland with our existing assets and we were kind of pushing into the Delaware, but this acquisition with the Outrigger assets gives us a really good footprint in the Delaware to grow. I think we feel really good about both the Delaware and the Midland Basin.

They are both in the very good category. Differentiating among that I don't think is particularly helpful. It will be (multiple speakers). We know what the future looks like in the Midland. We've been there. We see it. We've got a partner who is highly communicative with us. And we are certainly getting closer to closing. And with closing, we can have even better communication with the producers on the Delaware side. The new producers on the Delaware side.

Thank you very much.

Danilo Juvane, BMO Capital.

Good morning. Most of my questions have been hit. I did have one quick follow-up. So in the Downstream segment, OpEx picked up I think 10% year-over-year. I think you mentioned the compensation was largely due to that increase. But if you exclude that for 2017, how should we think about OpEx for the Downstream segment?

We had a couple of factors hitting OpEx for Downstream. You had the Train 5 coming on, and then you also had commodity prices, gas prices, move up on a year-over-year. A lot of that OpEx is pass-through where the OpEx increases and that's a variable component to the fee that is passed back to the fractionation customer. So part of it is just going to depend on essentially where commodity prices are a bit on OpEx. Then with Train 5 coming on, that was the other increase that you saw.

But you should not expect, particularly years to years, a radical step function other than that increase in Train 5 nonfuel-based operating costs. There was also an increase in Train 5 fuel-based operating costs.

That's it for me. Thank you.

I'm showing no further questions at this time. I would now like to turn the call over to management for closing remarks.

Thank you very much operator. And thanks to everyone on the call for the patience with the large amount of ground we covered, and with our admittedly typical reticence on Q&A. We look forward to 2017 and performing for our investors in 2017 and look forward to the next call or the next time we'll be talking to you. In the meantime, feel free to contact Luke, Jen, Matt or any of the rest of us. Thank you very much.

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