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. I would like to introduce your host for today's conference, Jennifer Neal. You may begin.
Thank you, operator. I would like to welcome everyone to our Q3 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 193319 34.
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 ks for the year ended December 31, 2015 and quarterly reports on Form 10 Q. With that, I'll turn the call over to Joe Bob Perkins.
Thanks, Jen. Welcome, good morning and thanks to everyone for joining. This morning, I'm going to begin the call with some high level remarks and then we'll turn it over to Matt to discuss our results for the Q3 in more detail. We will then hear from our business leaders Scott Pryor, EVP of Logistics and Marketing, our Downstream business Pat McDonough, 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. 1st, as we report 3rd 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 Q3 of 2015 and NGL prices were about $0.03 higher relative to the Q3 of last year.
2nd, we look back at everything that Targa has accomplished since the Q3 of 2015 relative to our restructuring and the improvement of our balance sheet. And with that perspective, in today's environment and looking forward, Target 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 Q3 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 3rd quarter was approximately 5% less than the 2nd quarter.
However, for the 4th 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 2nd view and visibility because we expect to load approximately 6,000,000 barrels per month of LPGs from Galena Park in the 4th 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 $40,000,000 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 said 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 Q4. As a result of the previously mentioned factors, we expect dividend coverage to approach 1.2 times for the 4th quarter and fully expect that we will meet our previously provided 2016 annual dividend coverage guidance of at least 1 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 excess capacity across much of the Targa 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 200,000,000 a day cubic feet per day plant in our Westech system, which we expect to be online by year end 2017.
The Westech 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 leather producers enjoying similar success. In the Westech system, we're also restarting our 45,000,000 cubic feet per day Benedum plant and adding 20,000,000 cubic feet per day of capacity at our Midkiff plant. Both of these expansions are expected to be online in the Q1 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 GMP projects across our footprint.
On the M and A front, we're 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 $525,000,000 The acquisition of the Versado interest is a very good deal based on our outlook for the system and owning 100 percent 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 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 GMP 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 U. S. 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 catalysts 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 Q3 results in more detail.
Thanks, Joe Bob. Targa's reported adjusted EBITDA for the Q3 was 245,000,000 dollars and distributable cash flow was $168,000,000 Overall reported operating margin was approximately 12% lower compared to the Q3 last year and will be discussed in more detail in the segment results in a few moments. Reported net maintenance capital expenditures were 20,000,000 dollars in the Q3 of 2016 compared to $24,000,000 in the Q3 of 2015. We expect $90,000,000 or lower of net maintenance CapEx for 2016. Turning to our segment level results, I'll go over our performance in the 3rd quarter on a year over year basis.
Beginning with the Downstream segment, 3rd 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 Q3 of 2015, primarily as a result of some lower margin contracts rolling off as we have previously discussed. Downstream segment reported operating expenses Turning to the Gathering and Processing segment. Reported operating margin for the Q3 of 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 Q3 of 2015.
3rd quarter reported 2016 natural gas plant inlet volumes for field gathering and processing were slightly under 2.6 1,000,000,000 cubic feet per day. Year over year, we saw an increase in volumes in West Tex, SAOU, South Tex and Badlands, offset by lower volumes in West Oak, North Texas and Sand Hills with volumes approximately flat in Versado and South Oak. We also benefited from a 10% increase in NGL production in the Q3 of 2016 versus the Q3 of 2015. Crude oil gathered was 104,000 barrels per day in the 3rd quarter, down approximately 5% versus the same time period last year and down approximately 1% compared to the Q2 of this year, primarily from producers shutting in production while completing and fracking new wells nearby. 3rd quarter 2016 Gathering and Processing segment OpEx was 1% lower than Q3 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 $1,000,000,000 of senior unsecured notes in 2 tranches, dollars 500,000,000 of 5.8th notes due 2025 $500,000,000 of 5.3eight notes due in 2027. The proceeds from these offerings along with the TRP revolver borrowings were used to fund concurrent tender offers for 3 near term maturities and we announced in October the early acceptance of $483,000,000 of 5 percent notes due 2018, $282,000,000 of 6 5.8 percent notes due 2020 and $374,000,000 of 6 7.8 percent notes due 2021. Subsequent to the closing of the tender offers, we issued notices of full redemption to the trustees and noteholders of TRP's 6 5eight notes and 6seveneight notes in addition to the 6fiveeight APL notes due October 2020.
The aggregate $146,000,000 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 Target Paper. During the quarter, we also extended the maturity of our $1,600,000,000 TRP revolver by 3 years from October 2020 from to October 2020 from October 2017 at substantially similar terms. As of September 30, we had no borrowings under TRP's $1,600,000,000 senior secured revolving credit facility due October 2020.
On a debt compliance basis, TRP's leverage ratio at the end of the 3rd quarter was 3.8 times versus a compliance covenant of 5.5 times. Also at quarter end, we had borrowings of 225,000,000 under our accounts receivable securitization facility. As of September 30, TRC had $275,000,000 of borrowings outstanding under our $670,000,000 senior secured credit facility that matures in February 2020 and the balance on TRC's term loan facility that matures in February was 160,000,000 dollars TRC availability at quarter end was approximately $395,000,000 including $141,000,000 in cash, total target liquidity at quarter end was over $2,100,000,000 On the equity side, we issued $150,000,000 of equity through our ATM program during the Q3 to be used to fund growth CapEx. Given our Q3 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 we'll 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 the $1,000,000,000 9.5 Percent Series A preferred stock issuance we completed in March 2016 became exercisable. Upon notice of an investor desired 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 11,000,000 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 from 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 Q3, 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 collars. Our fee based operating margin for the Q3 of 2016 was approximately 79%. Moving on to capital spending, we estimate approximately $525,000,000 for net growth capital expenditures in 2016 and as mentioned earlier $90,000,000 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 Q4 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 $525,000,000 We expect to provide other additional 2017 estimates including commodity price sensitivity on or before our Q4 earnings call. That wraps up my comments and I'll hand it over to Scott to describe some of the trends in the Logistics and Marketing business. Scott?
Thanks, Matt. Today, I will provide some color around the current and forward looking 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 5,000,000 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 5,500,000 barrels for the year, driven by strong volume performance in the 1st, 2nd and 4th quarters. Consistent with our stated expectations for the 3rd quarter in both script and Q and A from our last earnings call in early August, the Q3 was the weakest of the year from both a volume and margin perspective for LPG exports. We had 3 lifting cancellations this year, 1 in June and 2 in July and also worked with some of our customers to defer scheduled liftings from the Q3 to future quarters.
We have not experienced further cancellations and consistent with how we 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 Q3 of 20 16. 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 Q4 to date. Waterborne LPG transportation costs continue to reflect the growing global VLGC fleet, which is undergoing the largest single gear 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 Q3, 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 18.5 $0 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 begin 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 GMP field activity and looking year over year higher target 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 Q2 and also now have all the permits needed to proceed with 100,000 barrels per day Train 6 when needed, with a view that it is a matter of when and not if we will need to expand Mount Bellevue fractionation. On our Q2 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 Q3. 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 Mount 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 condensate sliver at Channelview Terminal and construction is well underway. We continue to expect the asset to be operational in the Q1 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 projects.
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 McDonough to discuss some of the trends that he is seeing on the Southern GMP side of our business. Thanks Scott and good morning. Over the last 6 months or so, we have seen a number of different themes dominate our Southern field G and P landscape.
1st, excitement over Permian production 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 Westex system. 2nd, Permian results and producer desire for additional acreage across the basin have driven a number of large and significant upstream M and A transactions. Target Hazen 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 producers successfully improving EUR spacing, identification and completion efficiencies. For Targa, our areas of commercial focus in Southern Field G and P have been to continue to identify attractive opportunities to add acreage dedications and to grow volumes and margins across the Midland Basin, the Delaware Basin, the STACK, SCOOP and Eagle Ford. We believe that we have some inherent advantages given the positioning of many of our existing pipes and plants and are focused on leveraging those advantages to grow our footprints across each of those areas. The 200,000,000 cubic feet per day Buffalo plant in Westex came online in the 2nd quarter and is rapidly filling, accelerating our need for additional infrastructure. And as discussed, projects adding capacity processing capacity and Westex 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 larger 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 twenty sixteen. Three rigs were added during September October as planned with 2 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 200,000,000 cubic feet per day Raptor plant in South Texas will be online in Q1 2017 and will provide us with an Eagle Ford footprint that we think is very well positioned.
In the 3rd quarter, we gathered and processed lower volumes versus the 2nd quarter as producers are able to move readily 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 and P volumes versus average 2015, driven by higher Permian and South Tex volumes, offset by lower North Tex, West Oak and South Oak volumes. We have 10 months already under our belt and my expectations are unchanged. 1 month into the Q4, we have seen continued volume growth in the Permian Basin and continued activity around our West Oak and South Oak 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 West Tex 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 Weston, South Oak 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 has seen up in the Bakken.
Thank you, Pat, and good morning. For our Badlands Systems,
where we've gathered both crude oil
and natural gas, year to date 2016 has been highlighted by our mutually supportive relationship with the MHA nation or the 3 affiliated tribes, which has resulted in significant right of way 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 and in areas where we are experiencing additional drilling activity. On our Q2 earnings call, we mentioned a 13,000 barrel to date pipeline project to include that is currently being trucked, plus crude from new completions that are happening now. As of Tuesday, November 1, we are mechanically complete on 50% of the 30 miles of pipeline we're 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 Q4 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 twenty 15 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 completion of DUCs, wells that have 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 acreage dedications and or additional plant infrastructure that will obviously increase our capital spending trajectory.
Feedback we're 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 our Little Missouri plants, we are poised to benefit with any uptick in drilling activity. Joe Baum, 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'll 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're 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 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 fake 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's 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 2nd with 1 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 Q4 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.
Thank And our first question comes from the line of Brandon Balson from TTH. Your line is open.
Good morning, everyone.
Hey, good morning.
Let's see. Let's start off with 2017 CapEx. It sounds like around $500,000,000 maybe a little bit more of that processing plant in there. Anything else or any other color available as to what will fall into that line item?
Yes. We're working through that now. There are a lot of projects we're seeing on the gathering and processing side. There's a lot of ones that are unlikely to even break out in the detail some $10,000,000 $20,000,000 CapEx. So we're aggregating those and looking through our areas.
So we're still really formulating that, but we're just we're seeing significant amount of activity, especially on the gathering and processing side. So we think that's 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. And I guess just following on that gathering and processing smaller CapEx. Joe Bob you mentioned the increased Persado flexibility with full ownership And maybe not mentioned, but is there some possibilities of that showing up in the CapEx line item? If so, I assume those are high return 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 $525,000,000 estimate. I know that number sounds familiar. You always have things moving on the margin, but it includes the Chevron acquisition as well as the projects that we see between now and end of the year. Secondly, that additional flexibility, we've been spending money to support a horizontal San Andres play and to move into the Delaware primarily for Versado.
That wasn't where Chevron's E and P interests were at that time and that provided the opportunity for us to acquire their interest. 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.
I like the fact that we're not constrained by Chevron worrying about whether they are 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 and P spend. And I think it's just a result of some of the stuff that we've been talking to you in the past. It's getting acreage dedications that allows us to bolt on to 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 over 2017. Thanks, Brandon.
Thank you, guys.
Thank you. And our next question comes from the line of Shneur Roshani from UBS. Your line is open.
Hi, good morning guys.
Hi, Shneur.
A 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've talked about in the past about connecting the two systems together there. Are there opportunities to build processing plants?
When you look at the map, you look it looks like you have an opportunity there, but you're kind of on the side. So I was wondering if you can 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 Southwest of Versado and have opportunities on the broadly the western side of our Sand Hills facility.
We've looked at
it wasn't that long ago we announced without precision a plan in between us. We look forward to opportunities are working on those kinds of opportunities, but don't have any additional details to provide you right now, Cheniere, other than that color. And I hope the color was helpful.
Okay. 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 I guess specifically the SCOOPSTACK, have you secured any acreage dedications at all so that you could be able to move volumes to your misaligned plants?
Shneur, this is Scott. I'll try to take the first part of your question and then I'll kick it over probably to Pat to address the second half. As far as LPG contracts and interest in extending contracts going forward and what 2017 2018 and forward look like. We're not prepared to give you any indication at this point. But what I will 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 the demand is 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, you referred to the misaligned plants. 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.
Great. Thank you
very much guys. Really appreciate the color.
Thanks, Shneur. Okay. Thanks.
Thank you. And our next question comes from the line of Danilo Juvan from BMO Capital Markets. Your line is open.
Thanks and good morning. I wanted to circle back to the LPG export question and then perhaps I'm looking at it with a more near term lens. So the 6,000,000 barrels per month average for the Q4, is that something that you had visibility to prior to get into 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 Q3, but a lot of it is short up and we've got a lot more clarity as we move into the Q4 recognizing that we would always want to be cautious relative to providing levels of detail in the Q3 relative to Q4 given the fact that there was at that time the potential for cancellations with the shape of the market. We experienced cancellations in the Q3. We referenced that in our script. We referenced that on our 3rd earnings call. And but we felt good about the Q4.
But certainly now that we are in November and we've already had 1 month that has surpassed, 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 Q4.
Thanks for that. And presumably to
the extent that you got those incremental contracts you also got contracted rather than 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 Q4 volumes both in a variety of contract structure whether they be short or long term.
Got it. I guess moving on to G and P. What was the cause of the processing plants that you guys are sanctioning here? I may have missed that earlier in your comments.
Yes. We didn't 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'll provide some more color about how much we think is going to be in the Permian related to that plant. 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.
All right. Great. And what we publicly disclosed on those pieces. I think it'd be fair to say that the cost of plants are lower today than they have been in the past. Right.
Okay, great. That's it for me. Thank you. All right. Thank you.
Thank you. And our next question comes from the line of Faisal Khan from Citigroup. Your line is open. Hi,
Faisal. Hi, Faisal. Good morning. 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 that number those numbers are moving higher. Can you talk about how much higher they can move and what's going on in the system?
Yes. I mean what you're seeing out there and you actually see a lot of it in South Oak is a mix of the amount of ethane that we're recovering. There's different contract structures at each plant, different transportation and other mechanisms that go into our decision of whether we recover or reject ethane. So that's 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 movements 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
Yes.
And the biggest move when you go through I think it was on the South Oak system, which is where you go in and out of recovery and rejection more than the others. But we do make those marginal decisions at those
And then just going back to the uptick in the LPG volumes, the export volumes in the 4th quarter, I mean, is this also more of a seasonal sort of pattern that we're seeing globally? And generally speaking, is this 4Q just a higher demand quarter for LPG demand overseas in general? So isn't it natural that 4Q would be higher than 3Q?
Basil 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 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 4th quarter looks like.
But also at the same time recognize the fact that during the Q3 and as we alluded to in our comments today, there was a lot of ships 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, much 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 demand as well as from an inventory perspective as it impacted Q3 of this year.
Okay.
Speaking for Targa in particular, I think it would be better analysis to presume that the Q3 was driven down by the factors that Scott described than the Q4 being driven by strong seasonality.
Okay. Got you. And then one last question. In the Logistics and Marketing segment, it looked like OpEx ticked up, looks like about $5,000,000 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?
Yes. It was 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 and M, we're very pleased with the cost reduction across the company holding on to 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're proud of.
Okay. Got
it. Thanks for the time guys.
All right. Thank you.
Thank you. And our next question comes from the line of John Edwards from Credit Suisse. Your line is open.
Yeah. Good morning, everybody. Thanks for taking I just have a couple of quick ones. Just on the South Texas G and P volumes, it looked like they were down a bit sequentially same with the frac volumes declining sequentially and acknowledging you've got great prospects 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 the 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 were 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. And 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 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, as we've seen some of that with the improvement of equity volumes from increased GMP production from our own plants has offset some of those types of negatives.
Okay. Thank you for that. Yeah, thanks for clarifying that. Appreciate that. That's it for me.
Thank you.
Thanks, Chuck. Okay. Thanks.
Thank you. And our next question comes from the line of Craig Shere from Cowen Brothers. Your line is open.
Craig, thanks for the incredibly detailed outlook.
Craig, can you speak up a bit?
I'm sorry. Is this better?
Yes. Thank you.
No problem. First question on the Sanchez JV. Right now you're processing 100% of those volumes, right? But then when they transfer over to Raptor, you'll get credited 50%. So how does that work on an economic basis without becoming lumpy quarter to quarter?
No. You're exactly right. So we're processing those at our Silver Oak facilities where we own 100% of Silver Oak 1 and 90% of Silver Oak 2. And then when the Raptor comes on, it will go into the fifty-fifty JV. So you're exactly right.
Okay. So just from an economic standpoint, there's a short term
pull up?
Right. Yes. It will be reduced all in net economics to when we move those through the Raptor plant all things equal.
Okay. Fair enough. And Matt, when we think about the I don't know maybe $550,000,000 to $600,000,000 of 2017 spend and the disproportionate equity financing versus a normal fifty-fifty split. Can you A, characterize any more the for when we might ease up on that equity pedal back to that fifty-fifty split?
Sure. Yes, 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 the spend. We've lived in the 3 to 4 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're 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 kind of as we go through into 2017. But I just what we wanted to highlight is just 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.
I would also Go ahead. The things we're doing in that $525,000,000 plus capital direction that we just described for 2017 are attractive return projects regardless of the mix of equity and debt. Right.
Fair enough. So this is more kind of carpe diem opportunistic. It's not going to be mechanical where 75 percent is going to be kind of hit every quarter. It's more kind of nimble.
Yes. It's 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 the 50 percent 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 a we spend this much in Q1, so we're 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 around the prospects for ethylene export opportunities?
John or 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 Bellevue as well as Galena Park. With that said, obviously, the entire market as it relates to petrochemical expansion in 2017 2018 is trying to understand what the balance is going to look like for ethylene production and 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 today, we've got infrastructure outside of say the 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.
But would you say the conversations have the potential in the next year to manifest in anything that could be meaningful in terms of the overall economics of the facilities?
I would say we're not prepared to kind of give any sort of lead in to 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. Understood. Thank you.
Okay. Thank you.
Thank you. And our next question comes from the line of Chris Steinle, from Jefferies. Your line is open.
Hey, good morning guys.
Hey, good morning.
Matt, I just wanted to clarify something. When you I think you had mentioned 3rd quarter coverage being roughly 0.9 times. So 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 payments at TRC. That's right.
Okay. And that's consistent with how we should interpret the Q4 guidance around the 1.2% level?
Correct. Okay.
If we
start defining it differently, we'll scream loud about a change in definition.
Okay. I just want to be clear. And then, Joppa, can you remind me that the Noble contract, I obviously remember when it happened, But with regard to the $40,000,000 payment, that's just can you remind me that 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 we are 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 establish. 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 this 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 some a lot of engineering work, worked with our customer to consider additional alternatives and then came back to essentially go a more flexible crude and condensate 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 $40,000,000 payable in October and that will continue. We called it multi year and we didn't say how long the 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 forgot the last fine points on your question.
No. That's effectively what I was looking for, Joe. 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. So it's
lumpy on when it falls or is received. 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 a little bit different when the plant starts because there will be some operating costs associated with running the plant.
Right. Okay.
Okay. But I just want
to make just make sure we're clear
on one thing. It will be lumpy in the sense that we'll receive that payment in October. Of so the cash payment received would be right?
Right, right. So the physical
October every year sorry and I was thinking of that as predictable or not. Okay. But it is lumpy. Right,
right. Lumpy predictable. I'm sorry. Thanks
for tuning that up, Matt. I'm sorry, I missed answers the lumpy question.
No. I guess what I'm trying
to just get after is, is this I guess for current purposes when there's not a plant running, this is a 4th 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 smoothed out impact. Is that right Matt?
Well, I think the best way
to think about this is we're going to be receiving that 40 dollars plus 1,000,000 payment in October. So as you're thinking 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're going to include that in EBITDA.
And then when the plant is up and running, we will have some deducts for OpEx when the plant is up and running. That's it.
Got it. Okay, perfect. And then I guess 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 refinancing. I'm just curious with the TRP leverage now down to 3.75 times, 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 I guess with the agencies post all the activities you've done in the Q3?
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'll lay out our forecast and go 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, it's don't really view it as impacting much our ability to access the markets as evidenced by our note offerings the 5.8th and 5.38th. So it would be nice to get an upgrade. I think if you look at our credit metrics because we grade out to a higher credit rating than where we are. But I don't know that it's necessarily needed to get attractive terms for financing.
Okay. And then I guess a related question and final one for me is just do you have sort of a long term target? I know we used to talk about it at the PRP level, but in terms of the consolidated entity, I know you've mentioned we're sitting still around 4.5. Do you have a long term view of where you'd like that to be? I mean, obviously, respective to the opportunity set in the commodity price environment, but is there something we should be thinking about longer term?
Yes. I think the 3 to 4 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 the most economic way to get there. So as long as TRP we're in that 3 to 4 times of managing leverage there. We have time to manage the consolidated leverage to the kind of long term profile that we'd like.
Okay. Perfect. Thanks again for the time
this morning guys.
Okay. Thank you.
Thank you. And our next question comes from the line of Jerry Konik with JPMorgan. Your line is open.
Hey, Jerry. Hey, Jeremy. I'm sorry. I thought I heard Jeremy.
I'm sorry. This is Charlie for Jeremy.
We're both rock. Yes. You get the benefit of being the last question. We're conscious of the time. So you can tell Jeremy that Charlie got the last question.
All right. Thanks guys. Just curious how much third party volumes are running through the frac now? I'm just looking at that $3.13 figure. Are you still in control of those barrels?
And kind of is that rate competitive? And then just additionally sorry real quick. Is there any risk in customers electing to send those bonds elsewhere since Target doesn't have complete control of the takeaway?
Okay. So first question, we don't give a breakout of what our Targa equity volumes or control volumes through our fractionation relative to 3rd party. I'd say we have a mix above. And I think what I'd say is you've seen in our numbers, we've had some third party contracts go to other fractionation facility. 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 it in this script, but the amount of 3rd party contracts coming up over the next several years is relatively low. I actually don't have that at my fingertips. But public 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 3rd party control, You did hear us say and explicitly so that we're increasing our equity volumes and we're always seeking to have control of the volumes that are going through our fractionator. And I'd say that we've done a better job of that over the last couple of years than we did in the 1st couple of years of our history.
Great. Thank you.
Okay. Thank you.
Thank you. 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 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