Targa Resources Corp. (TRGP) Q3 2016 Earnings Report, Transcript and Summary

Good day ladies and gentlemen, and welcome to the Targa Resource Third Quarter 2016 Earnings Conference Call. 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]. I would like to introduce your host for today's conference, Jennifer Kneale. You may begin.

Thank you, Operator. I would like to welcome everyone to our third quarter 2016 investor call for Targa Resources Corp. Before we get started I would like to mention that Targa Resources Corp., Targa, TRC or the company has published its earnings release, which is available on our website at www.targaresources.com. An updated investor presentation will also be posted to our website later today. 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 statements. 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 for the year ended December 31, 2015 and quarterly reports on Form 10-Q. With that, I will turn the coal call over to Joe Bob Perkins.

Thanks, Jen. Welcome, good morning, and thanks to everyone for joining. This morning I am going to begin the call with some high level remarks, and then we’ll turnover it over to Matt to discuss our results for the third quarter in more detail. We will then hear from our business leaders, Scott Pryor, EVP of Logistics and Marketing, our downstream business; Pat McDonie, EVP of Southern Field Gathering and Processing; and Danny Middlebrooks, EVP of Northern Field Gathering and Processing, our North Dakota position. Scott, Pat, and Danny will discuss some of the trends and dynamics in their areas of operations. I will then finish with some closing remarks, and we’ll open up the call for questions. Well, 2016 has been a roller coaster year. Everyone on the call has been on that roller coaster, so I'll only ask you to recall a couple of things as we report this quarter, reflect on year-over-year results, and look forward. First, as we report third quarter results, we recognize that after a couple of quarters of commodity price improvements, Q3, 2016 natural gas and crude prices were both below the prices of third quarter of 2015, and NGL prices were about $0.03 higher relative to the third quarter of last year. Second, we look back at everything that Targa has accomplished, since the third quarter 2015, relative to our restructuring and the improvement of our balance sheet. And with that perspective in today's environment and looking forward, Targa is certainly well-positioned, and we are looking forward with cautious optimism, given the strength of our asset portfolio and the levels of activity we are seeing and expect to see around our assets. For Targa dividend coverage in the third quarter was 0.9 times, lower than previous quarters this year, largely as a result of reducing operating margin from our LPG export business and the recent exercise of approximately 95% of the warrants associated with the TRC preferred issued in March that Targa elected to net share settle. Adjusted EBITDA for the third quarter was approximately 5% less than the second quarter. However, for the fourth quarter, we expect adjusted EBITDA to be higher than the first, second, or third quarters of this year. We say that with the cautious confidence of our November 2 due and visibility because, we expect to load approximately six million barrels per month of LPGs from Galena Park in the fourth quarter. We have already benefited from some appreciation in commodity prices early in the quarter, and because of the known timing of a multi-year annual payment of approximately $40 million received in early October, associated with our long-term contract with Noble, related to the crude and condensate splitter. You will recall that we renegotiated the Noble crude and condensate splitter arrangement at the end of 2014, agreeing to explore other deal alternatives for them for a fee, and at the time set that our original deal economics from March 2014 would not be negatively impacted as a result of revised future contracts that would follow. Because we received the annual payment in early October, the cash will be included in dividend coverage in the fourth quarter. As a result of the previously mentioned factors, we expect dividend coverage to approach 1.2 times for the fourth quarter, and fully expect that we will meet our previously provided 2016 annual dividend coverage guidance of at least one times. For Targa looking forward beyond 2016 in gathering and processing, we expect our field volumes to grow, driven by increasing activity from producers in our most active areas. Areas that are positioned in some of the most economic basins in the world; the Permian, the Bakken, STACK and SCOOP. Current access capacity across much of the target systems will provide near-term margin expansion with minimal capital outlay. And in the heart of the active Midland Basin, we are today, I guess officially announcing another 200 million cubic feet per day plant in our WestTX system, which we expect to be online by year-end 2017. The WestTX system, of course, is our JV with Pioneer Natural Resources, and the new plant will serve their growing volume needs, as well as the growing volume needs of multiple other producers enjoying similar success. In the WestTX system, we are also restarting our 45 million cubic feet per day Benedum plant and 20 million cubic feet per day of capacity at our Midkiff plant. Both of these expansions are expected to be online in the first quarter of 2017. These capacity additions which are all very much needed by the end of year 2017 are excellent examples of our expectations for continued growth in this area of the Permian. We are also working on other attractive G&P projects across our footprint. On the M&A front, we are pleased to announce that on October 31 we executed an agreement with Chevron to acquire their 37% interest in the Versado joint venture, located primarily in southeastern New Mexico, partially in the Delaware Basin. Targa now owns 100% of the Versado system. Net of working capital, the acquisition cost of the 37% Versado interest is not very large, and is included in our current 2016 CapEx estimate of $525 million. The acquisition of the Versado interest is a very good deal, based on our outlook for the system and only 100% of Versado increases our ability to compete and expand further into the Delaware Basin to access new territory. We also will have increased flexibility to connect Versado with our other integrated Permian Basin systems in the future. Given our diversified asset footprint, increasing upstream gathering and processing activity will continue to drive growth for our downstream businesses, as we benefit from additional NGL volumes at our fractionation and export facilities. We will also benefit from greater expected ethane extraction as a result of the world class petrochemical facilities coming online in 2017 and 2018, with increased demand pulling additional volumes to Mont Belvieu. This increased ethane demand and the consequent lower natural gas supply should increase those commodity prices and benefit Targa on the G&P side related to our equity volumes. And our LPG export facility is well positioned, with a demonstrated track record of performance, and it will continue to help clear excess supply of propane and butanes, as domestic NGL production continues to grow without commensurate domestic demand growth, and as the US continues to take a larger market share of the growing global Waterborne NGL market. The combination of our well positioned asset footprint, plus expectations for continued activity and recovery, plus our strong balance sheet and liquidity position causes us to feel like Targa will be an early and continued beneficiary as the industry recovers. Looking forward, we expect to see continued positive catalyst to support our businesses, driving gathering and processing volumes, fractionation volumes, LPG export volumes, and attractive investment opportunities across the Targa platform. With that, I will now turn the call over to Matt to discuss our third quarter results in more detail.

Thanks, Joe Bob. Targa's reported adjusted EBITDA for the third quarter was 245 million and distributable cash flow was 168 million. Overall reported operating margin was approximately 12% lower, compared to the third quarter last year, and will be discussed in more detail in the segment results in a few moments. Reported net maintenance capital expenditures were 20 million in the third quarter of 2016 compared to 24 million in the third quarter of 2015. We expect 90 million or lower of net maintenance CapEx for 2016. Turning to our segment level results, I’ll go over our performance in the third quarter on a year-over-year basis. Beginning with the downstream segment, third quarter reported operating margin declined 23%, primarily due to the lower LPG export margin of volumes, lower [terminaling] and storage throughput, lower marketing gains, and the realization in 2015 of contract renegotiation fees related to our crude and condensate splitter project. Fractionation volumes this quarter were lower by approximately 9% compared to the third quarter of 2015, primarily as a result of some lower margin contracts rolling off as we have previously discussed. Downstream segment reported operating expenses increased a modest 2% in the third quarter of 2016 versus the same time period last year, as a result of the addition of Train 5. Turning to the Gathering and Processing segment, reported operating margin for the third quarter 2016 increased by 6% compared to last year, primarily due to higher NGL prices, higher inlet volumes in the Permian Basin, and lower operating expenses. NGL prices were 13% higher. Condensate prices were 6% lower, and natural gas prices were 1% lower compared to the third quarter of 2015. Third quarter reported 2016 natural gas plant inlet volumes for field gathering and processing were slightly under 2.6 billion cubic feet per day. Year-over-year, we saw an increase in volumes in WestTX, SAOU, SouthTX and Badlands offset by lower volumes in WestOK, North Texas, and Sandhills with volumes approximately flat in Versado and SouthOK. We also benefited from a 10% increase in NGL production in the third quarter of 2016, versus the third quarter of 2015. Crude oil gathered was 104,000 barrels per day in the third quarter, down approximately 5% versus the same time period last year and down approximately 1% compared to the second quarter of this year, primarily from producers shutting in production while completing and fracking new wells nearby. Third quarter 2016 Gathering and Processing segment OpEx was 1% lower than third quarter 2015, despite the addition of the Buffalo plant highlighting our continued focus on and continued success in managing costs. Let's now move to capital structure and liquidity. Recently, we took steps to further strengthen our balance sheet, improve liquidity and extend our debt maturity profile. In September, we priced an upsized offering of 1 billion of senior unsecured notes and two tranches, 500 million of 5 1/8 notes due 2025, and 500 million of 5 3/8 notes due in 2027. The proceeds from these offerings along with the TRP revolver borrowings were used to fund concurrent tender offers for three near-term maturities, and we announced in October the early acceptance of 483 million of 5% notes due 2018, 282 million of 6 5/8 notes due 2020 and 374 million of 6 7/8 notes due 2021. Subsequent to the closing of the tender offers we issued notices of full redemption to the trustees and note holders of TRPs 6 5/8 notes and 6 7/8 notes in addition to the 6 5/8 APL notes due October 2020. The aggregate $146 million principal amount outstanding of all three series of notes will be redeemed on November 15, and we expect to use funds drawn from the TRP revolver to redeem the notes, and we now have an enviable debt maturity profile with approximately 76% of our senior notes set to mature in 2022 and beyond. These transactions reflect our continued ability to access the high yield market at attractive terms and reflect investor appetite for Targa [Paper]. During the quarter, we also extended the maturity of our 1.6 billion TRP revolver by three years to October 2020 from October 2017 at substantially similar terms. As of September 30, we had no borrowings under TRPs 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 third quarter was 3.8 times versus a compliance covenant of 5.5 times. Also at quarter end, we had borrowings of 225 million under our accounts receivable securitization facility. As of September 30, 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. TRC availability at quarter end was approximately 395 million; including 141 million in cash; total Targa liquidity at quarter end was over 2.1 billion. On the equity side, we issued 150 million of equity through our ATM program during the third quarter to be used to fund growth CapEx. Given our third quarter TRC, consolidated debt-to-EBITDA is approximately 4.5 times. We continue to expect to fund growth CapEx looking forward, with a higher percentage of equity than our traditional 50% debt and 50% equity, and will likely use the ATM for any additional equity needs. As a reminder, there is no consolidated debt covenant at the TRC level. On September 16, the series A and series B warrants associated with $1 billion 9.5% series A preferred stock issuance we completed in March 2016 became exercisable. Upon notice of an investors desire to exercise, Targa had the option to either net share settle or net cash settle the differential between the market price and the warrant price. As mentioned by Joe Bob earlier, through the end of October approximately 95% of outstanding warrants have been exercised, resulting in the issuance of approximately 11 million shares. This increase in shares outstanding is the only dilution expected, as a result of the TRC preferred issuance and that dilution is essentially complete. Turning to hedges, for non-fee based operating margin relative to the partnership's current estimate of equity volumes, field gathering and processing, we estimate we have hedged approximately 60% of remaining 2016 natural gas, 55% of remaining 2016 condensate, and approximately 20% of remaining NGL volumes. For 2017 we estimate we have hedged approximately 55% of natural gas, 55% of condensate and approximately 20% of NGL volumes. During the third quarter, we added some calendar 2017 through 2019 natural gas, ethane, propane, crude, and natural gasoline hedges and also some additional ethane hedges in 2017, using a combination of swaps and cashless (inaudible). Our fee-based operating margin for the third quarter 2016 was approximately 79%. Moving on to capital spending, we estimate approximately 525 million for net growth capital expenditures in ‘16 and as mentioned earlier 90 million or less of net maintenance capital expenditures. We are currently working through our planning process and expect to be in a position to provide an improved 2017 growth CapEx estimate on our fourth quarter earnings call. Our current expectation is that we may see a similar level or likely higher of growth capital spending in 2017, as compared to 2016, which as we said earlier is about 525 million. We expect to provide other additional 2017 estimates, including commodity price sensitivities on or before our fourth quarter earnings call. That wraps up my comments, and I will hand it over to Scott to describe some of the trends and the logistics in the marketing business. Scott.

Thanks, Matt. Today I will provide some color around the current and forward looking dynamics of two of the key components of Targa's downstream business, LPG exports and fractionation. Overall for 2016, we expect to exceed our long ago stated guidance for monthly LPG volume exports from our Galena Park facility. Since stating it in early 2016, we have not changed our estimate to export at least 5 million barrels per month of LPGs for the year and supported by our visibility for the rest of this quarter, we can estimate with high confidence that we expect to average approximately 5.5 million barrels for the year, driven by strong volume performance in the first, second, and fourth quarters. Consistent with our stated expectations for the third quarter in both script and Q&A from our last earnings call in early August, the third quarter was the weakest of the year from both a volume and margin perspective for LPG exports. We had three lifting cancellations this year, one in June and two in July, and also worked with some our customers to defer scheduled lifting from third quarter to future quarters. We have not experienced further cancellations, and consistent with how he always operate our businesses, we continue to work to provide flexibility to our customers on a variety of fronts. We are currently seeing strength in LPG export demand, especially demand for butanes to stable markets in the Americas and other growing markets. We are able to simultaneously load propane and butane cargoes at our facility, either on the same vessel or on different vessels benefiting from the efficiencies of our facility infrastructure, which our customers seem to appreciate. Currently, we are seeing relatively strong demand for single year term deals, and we continue to experience success in extending long-standing annual contracts, while also addressing interest for multi-year contracts. Vessels leaving our facility continue to move to destinations consistent with previous quarters, with approximately 77% going to the Americas and 23% to areas such as Europe, Africa, and Asia in the third quarter of 2016. Looking forward, we believe the Americas will continue to show strong demand, and we are optimistic about increased demand from global petrochemical plants in Asia, and also from emerging markets like Africa, Indonesia, and India, all of which are demonstrating increased demand in the fourth quarter to date. Waterborne LPG transportation cost continue to reflect the growing global VLGC fleet, which is undergoing the largest single year increase in its history with 47 new builds expected to come online in 2016. The majority of these new ships were delivered in the first half of this year, which dramatically pushed shipping rates lower. Over the third quarter, we continue to see lower shipping rates. Using the Baltic shipping rate as an indicator, we began the quarter at just under $26 per metric ton. The rates continue to trend downward and hit a low around $18.50 in early September. Since then rates have increased slowly and steadily to around $29 per metric ton as of late October. During the latter half of the third quarter, we also saw vessels which were being used as floating storage inventory began moving to consuming markets. These were all positive indications that demand was beginning to creep back up. On the fractionation side of our business, we are benefiting from increased G&P filled activity, and looking year-over-year higher Targa equity volumes running through our fractionators, and we expect this trend to continue over the medium term; maybe not each quarter-to-quarter because of other factors, but on a yearly or LTM basis. As we look forward, the impact of more ethane being extracted domestically from upstream operations will be significant, driven by demand from ethane exports, and new large scale petrochemical crackers coming online in 2017 and beyond. Targa has available fractionation capacity and is positioned in the near and longer term to benefit. As many of you know, we brought Train 5 online during the second quarter, and also now have all the permits needed to proceed with 100,000 barrel per day Train 6 when needed, with a view that it is a matter of when and not if we will need to expand Mont Belvieu fractionation. On our second quarter call, we described that as a result of Train 5 coming online, we were no longer sending NGL volumes to Lake Charles to be fractionated. We also mentioned that we were considering other promising commercial uses for the Lake Charles fractionation facility, and now have finalized the terms for a new commercial deal during the third quarter. While it is an exciting project to us and demonstrates ingenuity on behalf of our employees, it is a relatively small project. We are utilizing an existing facility to generate additional margin without sacrificing our ability to use the operation in the future to fractionate overflow volumes from Mont Belvieu. Very simply described, we are spending a nominal amount of CapEx at attractive returns to fractionate ethane-propane mix at the facility to provide a nearby customer with purity ethane and propane. Shifting attention to our Petroleum Logistics business, all required permits have been received for our 35,000 barrel per day crude and condensates splitter at Channelview terminal and construction is well underway. We continue to expect the asset to be operational in the first quarter of 2018, and as previously discussed, we are already receiving an annual fee for it. At this point we are not announcing any other major downstream products; however, we are working on a number of attractive opportunities. So hopefully, that provides you with a little more color on what we are seeing downstream. And I will now pass the call over to Pat McDonie to discuss some of the trends that he is seeing in the Southern G&P side of our business.

Thanks Scott and good morning. Over the last six months or so we have seen a number of different things dominate our southern field G&P landscape. First, excitement over Permian producer results that just keep getting better, shorter drilling times, coupled with success from longer laterals, driving higher IPs, greater EURs, and lower breakeven costs. As rigs have been added in the Permian over the past few months, Targa has benefited particularly on the WestTX system. Second, Permian results and producer desire for additional acreage across the basin have driven a number of large and significant upstream M&A transactions. Targa has and will further benefit from some of these transactions, as some important customers are putting together large contiguous dedicated blocks of acreage around our existing systems. And third, increasing delineation of the STACK and SCOOP plays with the producers successfully improving EURs spacing, identification and completion efficiencies. For Targa, our areas of commercial focus in southern field G&P have been to continue to identify attractive opportunities to add acreage dedications and to grow volumes in margins across the Midland Basin, the Delaware Basin, the STACK, SCOOP and Eagle Ford. We believe that we have some inherited advantages given the position of many of our existing pipes and plans, and are focused on leveraging those advantages to grow our footprints across each of those areas. The 200 million cubic feet per day Buffalo Plant in WestTX came online in the second quarter and is rapidly filling, accelerating our need for additional infrastructure, and as discussed projects adding processing capacity in WestTX are now underway. The additional capacity needs being driven by increasing producer activity and results. If you had a chance to see Pioneer's earnings release of yesterday, their Q3 earnings release of yesterday. Pioneer being our partner and largest producer on the system, they stated that they will be increasing the company's horizontal rig count from 12 rigs to 17 rigs in the Northern Spraberry/Wolfcamp during the second half of 2016. Three rigs were added during September and October as planned, with two additional rigs expected in November. Their comments are consistent with those of the remaining large portfolio of customers that are dedicated to our system. Our new 200 million cubic feet per day Raptor Plant in SouthTX will be online in Q1, 2017, and will provide us with an Eagle Ford footprint that we think is very well positioned. In the third quarter, we gathered and processed lower volumes versus the second quarter, as producers are able to more readily move short term, low margin volumes at central delivery points. We believe that there will be continued asset rationalization in the Eagle Ford, and that our multi-plant, multi-location footprint will benefit Targa as we have flexibility related to outlets, delivery points, and reliability that are attractive to the producers. For Targa, we guided to higher average 2016 field G&P volumes versus average 2015, driven by higher Permian and SouthTX volumes, offset by lower NorthTX, WestOK and SouthOK volumes. We have 10 months [RD] under our belt and my expectations are unchanged. One month into the fourth quarter, we have seen continued volume growth in the Permian Basin, and continued activity around our WestOK and SouthOK systems. Overall, as we look into 2017 and beyond, we feel very good about the strength and position of our gathering and processing systems. Permian volumes will continue to grow, driven by our WestTX and SAOU systems. Our ability to continue to be successful in penetrating the STACK and SCOOP and the producers activity in our areas will determine the trajectory of volumes in areas like WestOK, SouthOK, and even North Texas. We have an Eagle Ford position that we really like and believe that the Sanchez advantaged Raptor plant coming online in early 2017 will provide us with additional advantages. I will turn it over to Danny now who will discuss some of the trends that he is seeing up in the Bakken.

Thank you, Pat and good morning. For our Badlands Systems (inaudible) gather both crude oil and natural gas, year-to-date 2016 has been highlighted by our mutually supported relationship with the MHA Nation or the three affiliated tribes, which has resulted in significant right away progress this year in building out our infrastructure, spending growth CapEx dollars to lay pipe to wells that in some cases have already been drilled in areas where we are experiencing additional drilling activity. On our second quarter earnings call, we mentioned a 13,000 barrel per day pipeline project to (inaudible) that is currently being trucked plus crude from new completions that are happening now. As of Tuesday, November 1, we are mechanically completing on 50% of the 30 miles of pipeline we are laying for this project, and as of today, we have initial production flowing of up to 2,500 barrels per day. We continue to expect this project to be fully completed during the fourth quarter of 2016, and for the full 13,000 barrels per day to be flowing by year-end. Our guidance for 2016 was that we expected average 2016 natural gas volumes to be higher than average 2015 volumes, and that we expected crude oil volumes to be approximately flat, and we’re on track to deliver on that guidance. We expect that we will not need to spend as much capital to collect future volumes on our dedicated acreage as we needed previously. Given that our infrastructure is largely built out and future volumes from new drilling activity and /or from the completions of [ducts], wells that been drilled but not yet completed will be located in closer proximity to what has been built out, as we enter into new contracts for new (inaudible) dedications and/or additional plain infrastructure that will obviously increase our capital spending trajectory. Feedback we are hearing from our producers is that at prices similar to the strip today, we're likely to see meaningful additional drilling in our area of the Bakken over the next several years. Given Targa's attractive per unit margins for both gas and crude oil in the Bakken and the available capacity of lower Missouri plants, we are poised to benefit with any (inaudible) in drilling activity. Joe Bob, I think that covers it for me. Thank you.

Thanks, Dan. Thanks everybody. We’ve covered a lot of ground today, with one of our longest scripted comments and certainly with the highest number of scripted speakers. Given the environment, we thought that it might be helpful to spend more time talking about our assets and positioning, and to let you hear about it from the folks that are leading those efforts every day. If not helpful, I'm sure you will give Jen or me feedback. We at Targa are focused and enthusiastic about the opportunities in front of us, and we are cautiously optimistic about the trends we are seeing. This has been a tough year, but I think we are starting to feel some tailwinds at our back. I believe that our execution over the last couple of years with some significant headwinds should provide even more comfort to investors about the quality of Targa assets and the capabilities of Targa people. I'm very proud of both. When I think of all of the steps that we have taken, significantly reducing costs, attractive recontracting, commercial execution, balance sheet management and others, it makes me even more enthusiastic for the future. Even if we see a temporary head (inaudible) in commodity prices or do not see the current strip materialize in the near term, I know that we are all well-positioned. Where there is activity we benefit, and in some other areas where there is consolidation we will benefit. As we see it, our positioning will provide opportunities for continued attractive performance across almost any expected environment. I want to wrap up by highlighting a few key points that I think are important as we sit here on November 2 with one month of Q4 already under our belt. Q4, 2016 EBITDA is expected to be higher than Q1, higher than Q2, and higher than Q3. We forecast fourth quarter of 2016 dividend coverage approaching 1.2 times, and reiterate that average coverage for the year will be slightly over 1.0 times. Looking forward we believe that our investors are exposed to an asset platform that cannot be replicated, and where Targa will clearly be a beneficiary in a recovering commodity price environment, benefiting from both improving prices and activity levels. So with that operator, please open up the line for questions.

[Operator Instructions] And our first question comes from the line of Brandon Blossman from TPH. Your line is open.

Let's see, let's start off with ‘17 CapEx. It sounds like around 500 million or maybe a little bit more for that, processing plant in there, anything else or any other color available as to what would fall into that line item?

Yeah, we’re working through that now. There are a lot of projects we are seeing on the gathering and processing side. There’re a lot of ones that are unlikely to even breakout into details, some $10 million and $20 million CapEx. So we're aggregating those and looking through our areas. We are still really formulating that, but we are seeing significant amount of activity, especially on the gathering and processing side. So we think that is going to be similar CapEx or it really is likely to be higher, just depending on what major projects that we want to announce or put into that bucket.

Okay, that's helpful. Just following on that gathering and processing, smaller CapEx, Joe Bob you mentioned the increased Versado flexibility with full ownership and maybe not mentioned, but are there some possibilities of that showing up in the CapEx line item? If so I assume those are high over term projects. Any color you can add to that and then maybe something similar in the Mid-Continent?

Sure, first if it wasn't clear, the capital expenditure associated with the acquisition of the Chevron interest is in the 2016 $525 million estimate. I know that number sounds familiar. You always have things move on the margin, but it includes the Chevron acquisition as well as the projects that we see between now and the end of year. Secondly, that additional flexibility, we’ve been spending money to support our horizontal San Andres play and to move into the Delaware primarily for Versado. That wasn’t where Chevron's EMP interests were at that time, and that provided the opportunity for us to acquire their interests. That continued effort at the scale of building existing capacity is in Matt's description of 2017 being at or more likely higher than 2016 levels. They are very attractive return opportunities. If we were to announce an even bigger project in that area, that would drive that 2017 directional sense even higher, and we do see opportunities around the system. And I like the fact that we're not constrained by Chevron worrying about whether they going to go consent or non-consent. It was a very amicable agreement, and I think that both parties are happy with it. I know that if you talk to Chevron, they would say we've always been a good partner. You said Mid-Continent, similarly, Pat; you want to address the Mid-Continent?

I think Matt touched on a lot of smaller projects that add up to a significant number on G&P spend, and I think it's just a result of some of the stuff that we have been talking to you in the past. It's getting acreage dedication that allows us to bolt onto our existing asset footprints and build out into new areas that have become active. And we’re going to see a lot of that. We're going to see volume adds as a result of that, and I think that's what we'll see in the Mid-Continent 2017.

And our next question comes from the line of Shneur Gershuni from UBS. Your line is open.

A couple of questions here, I was wondering you definitely gave a ton of detail and that’s appreciated. But I was wondering if you can sort of expand on your exposure to the Delaware. I believe you have talked about it in the past about connecting the two systems together there. Are there opportunities to build processing plants? When you look at a map, it looks like you have an opportunity there, but you are kind of on the sides. I was wondering if you could sort of expand on that a little bit for everyone.

I think you’re certainly looking at the right map, and that’s a very attractive area. We’ve been pushing to the South, Southwest of Versado, and have opportunities on broadly the western side of our Sandhills facility. We've looked at; it wasn't that long ago we announced without precision a plant in between those, we look forward to the opportunities, are working on those kinds of opportunities, but don't have any additional details to provide you right now, Shneur, other than that color and a hope the color was helpful.

And just a couple of quick follow-ups, in your prepared remarks you talked about extending LPG contracts. Can you talk about; are contracted levels for 2018-2019 going to look similar to where we are today? And then secondly, with respect to the Mid-Continent or specifically the SCOOP STACK have you secured any acreage dedications at all so that you could be able to move volumes to your (inaudible) plants?

Shneur this is Scott, I’ll try to take the first part of your question, and then I will take it over probably to Pat to address the second half. As far as LPG contracts and interest in extending contracts going forward, and what ‘17, ‘18 and forward look like. We're not prepared to give you any indication at this point, but what I would tell you is that the discussions are very robust with our existing and new potential customers on looking at long-term contracts going forward. We described in our prepared remarks that we are extending typical contracts that are negotiated on an annualized basis, and we're having success doing that, and we would like to get full understanding of what that looks like going forward as we mature throughout the balance of this year. But what I would tell you is that our belief is we’ll have success, we’ll be in the midst of all of the conversations, both in the Americas, as well as other parts of the world, that are continuing to develop. And with demand continuing to grow, we will have opportunities and I like our chances very, very well.

Okay and acreage dedication?

I don't speak to specific acreage dedications, but kind of consistent with the answer to the last question, we do have acreage dedications. We are building infrastructure. There is activity on that acreage, and we see a lot of additional activity through 2017. We continue to try to add acreage, and if you look at our Western Oklahoma system that you referred to the misaligned plans, we’re on the South, and the Southwest side of those facilities is where our incremental growth is occurring, and we expect it to continue.

And our next question comes from the line of Danilo Juvane from BMO Capital Markets. Your line is open.

I wanted to circle back to the LPG [explore] question, and perhaps I’m looking at it with a more near-term lens. So the 6 million barrels per month average for the fourth quarter, is that something that you had visibility to prior to getting to 4Q or were you able to get incremental contracts?

What I would tell you is that we had fairly good visibility, while we were in the third quarter, but a lot of it is shored up and we have got a lot more clarity as we move into the fourth quarter recognizing that we would always want to be cautious relative to providing levels of detail in the third quarter, relative to fourth quarter, given the fact that there was at that time the potential for cancellations with the shape of the market. We experienced cancellations in the third quarter. We referenced that in our script, we referenced that on our third earnings call, but we felt good about the fourth quarter. But certainly now that we are in November and we’ve already had one month that has past and obviously we know what those volumes look like, we feel very good about providing you all in this context where we are going to be for the fourth quarter.

And presumably to the extent that you got those incremental contracts, you also got contracted revenue spot rates on those volumes. Is that fair?

I would say that we have a mixture of contracts that shape up, that contribute to our fourth quarter volumes, both in a variety of contract structure, whether they’d be short or long term.

Moving on to G&P, what was the cost of the processing plants that you guys are sanctioning here? I may have missed that earlier in your comments.

We have not provided a breakout for the plant cost related infrastructure by line item. We're still working through our plan on that. So we will provide some more color about how much we think it is going to be in the Permian related to that plan. That’s one of the items we're still working through is what we think the cost is going to be for that. So we're still working on those pieces.

And what we publicly disclose on those pieces. I think it’d be fair to say that the costs of plants are lower today than they have been in the past.

And our next question comes from the line of Faisel Khan from Citigroup. Your line is open.

Just a couple of questions, can you just discuss a little bit on what’s going on with the trend in GPM in your West Texas system. It looks like those numbers are moving higher. Can you talk about, how much higher they can move and what’s going on in the system?

What you’re seeing out to there and you actually see a lot of that in SouthOK is a mix of the amount of ethane that we’re recovering. There are different contract structures at each plant, different transportation and other mechanisms that go into our decision of whether we recover or reject ethane. So typically when you see things moving around, I don't think we've seen a huge shift in the gas moving higher or lower GPM quality. It really has to do with more or less ethane being recovered.

Okay, so that's the big (inaudible) we're seeing. I think in one of your systems it looked like you went from 4/1 to 5/1. It was a pretty big move. So that’s just ethane coming out of the --

And the biggest move when you go through, it was on the SouthOK system, which is where you go in and out of recovery and rejection more than the others, but we do make those market decisions at those other plants as well.

Okay, got you. Going back to the uptick in the LPG volumes or export volumes in the fourth quarter, that's also more of a seasonal pattern that we are seeing globally, and generally speaking. Is this 4Q just a higher demand quarter for LPG demand overseas in general? Isn't it natural that 4Q would be higher than 3Q?

Faisel, to a certain degree that is correct? You are going to see some seasonality in certain market areas, for instance, in Europe and obviously due to the weather trends and things of that nature. Obviously South America would shift to a different direction as a result of that. But overall, it would say that you could have some seasonality affecting what fourth quarter looks like. But also at the same time, I recognize the fact that during the third quarter and as we alluded to in our comments today, there was a lot of shifts that were brought on the market during the first half of this year, and given expansions on the export side of the business, there was a lot of vessels that were loaded, and as a result of that - there was a lot of inventory that was sitting in areas like Singapore and others, that was waiting for a market uptick. Weather has something to do with that, global demand has a lot to do with that, petrochemical usage. So yes, weather contributes to it, but there are other factors that you have to consider on both demands as well as from an inventory perspective, as it impacted the third quarter of this year.

Speaking for Targa in particular, I think it would be better analysis to presume that the third quarter was driven down by the factors that Scott described, than the fourth quarter being driven up by strong seasonality.

Okay, got you. And then, one last question, in the Logistics and Marketing segment, it looks like OpEx picked up, looks about $5 million sequentially quarter-to-quarter. Can you just talk about what’s going on over there? Is that something related to either new capacity or new personnel coming online or what was driving that sort of higher number?

Primarily it was Train 5 being operational for the full quarter, and there’s also some fuel and power and other things which ticked up a little bit in Q3 relative to Q2.

When we look at non-fuel O&M, we are very pleased the cost reduction across the company holding onto that cost reduction across the company and continuing to improve it on the margin. We, in fact have brought up facilities on the gathering and processing side and the downstream side, covering a lot of those costs by cost reduction. That’s something we are proud of.

And our next question comes from the line of John Edwards from Credit Suisse.

I just have a couple of quick ones, on the South Texas G&P volumes it looked like they were down a bit sequentially, same with the frac volumes declined sequentially, and you acknowledging you got great process going forward. Just if you could fill us in on what drove those numbers?

I think as we said in our prepared remarks is that the producers in South Texas area have the ability to move volumes around on an interruptible basis, and generally those are low margin volumes, and some of the levels at which people are willing to do that in the quarter were levels that we didn't want to approach. So our volumes were down on an interruptible basis, but our underpinned higher level margin volumes remained in place. Honestly, we do expect when we bring the Raptor plant on for us to be able to do a number of different things because of our asset position and the flexibility it provides from east to west, and we think our opportunities forward are significant.

And John on the frac side, as we mentioned and we've mentioned it in previous quarters as well, we had some low margin contracts that rolled off from 2015 to 2016, added with that extraction economics for ethane, obviously have suffered some. But the positive side is we've seen some of that with the improvement of equity volumes from increased G&P production from our own plants has offset some of those types of negatives.

And our next question comes from the line of Craig Shere from Tuohy Brothers. Your line is open.

First question on the Sanchez JV; right now you are processing 100% of those volumes, right, but then when they transfer over to Raptor you'll only get credited 50%? So how does that work on an economic basis without becoming lumpy quarter-to-quarter?

You’re exactly right. We are processing those at our Silver Oak facilities where we own 100% of Silver Oak I and 90% of Silver Oak II. When the Raptor comes on, it will go into the 50/50 JV. So you are exactly right.

Okay, so just from an economic standpoint there’s a short term blip.

Yeah. It will be reduced all in net economics to us when we move those through the Raptor plant, all things equal.

Okay, fair enough. And Matt, when we think about, I don't know maybe 550 million to 600 million of 2017 spend and the disproportionate equity financing versus a normal 50/50 split, can you A, characterize anymore the disproportionality of equity, and B, give some longer term kind of signposts you’d be looking for, for when we might ease up on that equity pedal back to that 50/50 split?

Sure. A lot of it is really going to depend on the timing of the cash flows for when the projects come on, the amount of spend. We’ve lived in the three to four times debt-to-EBITDA target at the partnership level really since we've been public. Right now we're at 3.8 times. So it’s towards the higher end, but we are still within the range. So we’re going to keep a close eye on that as we move through 2017. So it's going to depend on the environment where the ultimate CapEx shakes out. What our ultimate EBITDA is, commodity price levels are, and we’ll just have to take a view as we go through into 2017. What we wanted to highlight is don't be surprised, depending on the environment, if we were to do more than 50% equity for that growth CapEx in 2017. But again that’s really dependent on the environment, what the all-in budget is and what the outlook is.

What we're doing in that 525 plus capital direction that we just described for 2017 are attractive return projects regardless of the mix of equity and debt.

Fair enough. So this is more kind of (inaudible) opportunistic, it’s not going to be mechanical where 75% is going to be kind of hit every quarter. It is more kind of nimble.

We take a longer term view of our all-in capital structure. So it’s certainly not quarter-to-quarter or even year-to-year. I think our long term target is with that 50% debt, 50% equity has worked for us over time. But in any given year or quarter it could be more heavily weighted towards debt or equity. So no, it’s not that we spend this much in Q1, so we are going to do that much equity. We're going to look at the balance of the year, look at the forecast, and then make the best decision from there.

Fair enough. And last one for me, any updates aground prospects for ethylene export opportunities?

Craig, this is Scott. We continue to be in that conversation. As you guys will recall, currently today we have the only facility in North America that exports ethylene on behalf of a very strategic customer that we have both in Belvieu as well as Galena Park. With that said, obviously the entire market as it relates to petrochemical expansion in ‘17 and ‘18 is trying to understand what the balance is going to look like for ethylene production, what the global demand is going to look like as it relates to that. Is it going to move out as ethylene or is it going to move out as derivatives. I think it’s likely going to be a mixture of both and we are involved in a variety of conversations that would be supportive of us looking just strategically at what it would take for us to enhance our abilities to load out ethylene. Given the fact that we’ve already got a facility that does it today, we’ve got infrastructure outside of the stated direct boundary lines of the asset at Galena Park, then obviously I think it makes strategic sense, economic sense and logistical sense for us to be involved in that conversation.

Would you say the conversations have the potential in the next year to manifest in anything that can be meaningful in terms of the overall economics of the facilities?

I would say we are not prepared to give any sort of lead into that sort of questioning. But there’s always that potential. But we would like to bake things a little bit more before we give any sort of indication.

And our next question comes from the line of Chris Sighinolfi from Jefferies. Your line is open.

Matt, I just wanted to clarify something. I think you had mentioned third quarter coverage being roughly 0.9 times. Just to clarify that's DCF over the TRGP common and the TRC preferred. Is that right?

Yes. It is over all outstanding, common and preferred dividend payment to TRC. That is right.

And that’s consistent with how we should interpret the fourth quarter guidance around the 1.2 level?

Correct, and if we start defining it differently, we’ll scream loud about a change in definition.

Okay. I just wanted to be clear. And then Joe Bob, can you remind me the Noble contract. I obviously remember when it happened. But with regard to the $40 million payment, can you remind me the tenants of that and for how long we should expect it, and then, are you guys planning when you talk about 4Q to include that in both the EBITDA and DCF numbers, or is that just a DCF number and exclusion from EBITDA?

It is a DCF number and it may very well be included in adjusted EBITDA. Going back from memory is probably more than you want to hear. The deal was originally done towards the end of 2014. Someone needs to step up.

March 2014.

March 2014. The recut of the deal was done midnight, December 31, 2014. That recut basically provided alternatives for our good customer Noble, as they looked at market opportunities and potential additional facilities to be combined with or without a condensate splitter. We said at the time, shortly after getting it done New Year's Eve, that that would not impact our forward economics of a project as if we had done it as originally negotiated, but instead, provided frankly an option payment for us. Over the next year, we did a lot of engineering work, worked with our customer to consider additional alternatives and then came back to essentially [doing] more flexible crude and condensates splitter project at the Channelview facility. We had not quantified the annual payment until this call, as I recall. On this call we described it as something over $40 million, payable in October and that will continue. We called it multi-year and we didn't say how long term of the contract was, but I think I would describe it as outside our forecast horizon. And that’s all good news. I think I started rambling with the history and may have forgotten the last points on your question.

No, that is effectively what I was looking for, Joe Bob. So it’s kind of a lumpy receipt in terms of when in the year it falls, but per your guidance it’s happening on a repeated basis.

It’s not lumpy on when it falls [larger receipt], we will have to then account for it properly for our DCF calculations in the future. By the way, we’ll have to account for it a little bit different when the plant starts because there will be some operating cost assisted with running the plant.

I just want to make sure we are clear on one thing. It will be lumpy in the sense that we'll receive that payment in October. So the cash payments received with the -- so that will go from October every year, sorry. And I was thinking of that as predictable or not. But it is lumpy.

Right.

Lumpy and predictable. I’m sorry, clear as mud. Thanks for cleaning that up, Matt. I’m sorry I miss-answered the lumpy question.

I guess what I'm trying to get after is, is this for current purposes when there is not a plant running, this is the fourth quarter impact physically and in the reported, but it will be obviously affected by the operations when the plant’s up and running in more of a smooth (inaudible) impact, is that right, Matt?

Well, I think the best way to think about this is, we're going to be receiving that $40 million plus payment in October. So as you think about modeling and planning that out, just have that as in there. We’ll include that, it will be in DCF. As Joe Bob mentioned, we’re still determining whether we are going to include that in EBITDA, and then when the plant is up and running, we will have some deduct for OpEx when the plant’s up and running.

Okay, perfect. My final question, you guys have done a lot to sort of winterize or fortify the balance sheet with obviously the preferred equity and common equity and the debt-free financing. I’m just curious, with the TRP leverage now down to 3.75, 3.8 times, at what point, I don't want to be presumptuous, but like at what point is perhaps a credit rating upgrade in the cards at the TRP level, and have you had any discussions with the agency's post all of the activities you have done in the third quarter?

Yes, we have continuous dialogue with the rating agencies. We have a good relationship with both that rate us. So we'll be meeting with them here on an annual basis relatively shortly, and we will lay out our forecast and ago over what our plans are. It’s tough to handicap when they would be comfortable in making a move on us. It’s pretty difficult to predict. I think where we are right now, don't really view it as impacting much our ability to access the markets as evidenced by our note offerings, the 5 5/8 and 5 3/8. So it would be nice to get an upgrade. I think if you look at our credit metrics, we grade out to a higher credit rating than where we are? But I don't know that if it’s really needed to get attractive terms for financing

And then a related question and a final one from me, do you have a long term target. I know we used to talk about at the TRP level, but in terms of the consolidated entity I know you mentioned we are sitting still around 4.5. Do you have a long term view of where you would like that to be? Obviously, respective to the opportunity set and the commodity price environment, but is there something that we should be thinking about longer term?

Yes. I think the three to four times at TRP, longer term I think we’d like to get TRC consolidated there. It would be nice to get our debt-to-EBITDA there at TRC by growing our EBITDA, would be to most economic way to get there. So as long as TRPs, we are in that three to four times and managing leverage there, we have time to manage the consolidated leverage to the long term profile that we’d like.

And our next question comes from the line of Jerry Tonet from JPMorgan. Your line is open.

This is Charlie for Jeremy. Just curious on how much third party volumes are running through the frac now. So looking at that at 313 figure, are you still in control of those barrels, and is that very competitive. And additionally real quick, is there any risk in customers electing to send those bonds elsewhere since Targa does not have complete control of the takeaway?

So first question, we don't give a break out of what our Targa equity volumes or controlled volumes through our fractionation relative to third parties. I’d say that we have a mix of both. I think what I would say is that you’ve seen in our numbers; we’ve had some third party contracts go to other fractionation facilities. So that’s impacted our numbers on a year-over-year basis. Those were relatively low margin business that moved elsewhere. But, yes there is some risk of that. On prior calls, we don't have in this script, but the amount of third party contracts coming up over the next several years is relatively low. I actually do not have that at my fingertips. It was in last quarter's script, if you want to go look at it. So it’s relatively small the amount of contracts that would be really available to move over the near term.

And without saying what percentage was third party control. You did hear us say and explicitly so, that we are increasing our equity volumes. We are always seeking to have control of the volumes that are going through our fractionator, and I would say that we’ve done a better job of that over the last couple of years than we did in the first couple of years of our history.

At this time I’m showing no further questions. I would like to turn the call back over to Joe Bob Perkins for closing remarks.

Thank you, operator, and thank you everyone on the call for your patience. We hope that the additional color and the additional speakers work for you. Please feel free to contact Jen, Matt, or any of us with your questions. Thanks again.

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