Good day, ladies and gentlemen, and welcome to the Targa Resources 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. If anyone should require assistance during the conference, please press star then zero on your touch-tone telephone. I would like to introduce your host for today's conference. Jen 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 provisions of the Securities Acts of 1933 and 1934. Please note that actual results could differ materially from those projected in any forward-looking statements.
For a discussion of factors that could cause actual results to differ, please refer to our SEC filings, including the company's annual report on Form 10-K for the year ended December 31st, 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 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, 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 of 2015 relative to our restructuring and the improvement of our balance sheet. With that perspective, in today's environment and looking forward, Targa is certainly well-positioned.
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 2nd view 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 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 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 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 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 CapEx outlay.
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. 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 Bennington plant and adding 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 GMP projects across our footprint. On the M&A front, we are pleased to announce that on October 31st, 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 owning 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 GMP side related to our equity volumes. 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.
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 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 terminalling 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 Five. Turning to the Gathering and Processing segment, reported operating margin for the third quarter 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 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 West TX, SAOU, South TX, 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. In September, we priced an upsized offering of $1 billion of senior unsecured notes in two tranches, $500 million of 5 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. 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 TRP's 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 15th. We expect to use funds drawn from the TRP revolver to redeem the notes.
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 30th, we had no borrowings under TRP's $1.6 billion senior secured revolving credit facility due October 2020. On a debt compliance basis, TRP's leverage ratio at the end of the 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 30th, TRC had $275 million in borrowings outstanding under our $670 million senior secured credit facility that matures in February 2020. The balance on TRC's term loan facility that matures in February 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. 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 16th, the Series A and Series B warrants associated with the billion-dollar, 9.5% Series A preferred stock issuance we completed in March 2016 became exercisable. Upon notice of an investor's 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. 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 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 collars. Our fee-based operating margin for the third quarter of 2016 was approximately 79%. Moving on to capital spending, we estimate approximately $525 million for net growth CapEx in 2016, and as mentioned earlier, $90 million or less of net maintenance CapEx.
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 sensitivity, on or before our fourth quarter 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. 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. 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 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 third quarter to future quarters. We have not experienced further cancellations. 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. 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. 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 costs 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 continued 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 continued 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 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 Targa equity volumes running through our fractionators. 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 Five online during the second quarter and also now have all the permits needed to proceed with 100,000 barrel per day Train Six 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 Five 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 condensate 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 projects. We are working on a number of attractive opportunities.
Hopefully, that provides you with a little more color on what we are seeing downstream. I will now pass the call over to Pat McDonie to discuss some of the trends that he is seeing on 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 break-even 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. 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&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 position 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 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. As discussed, projects adding capacity, 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 GMP volumes versus average 2015, driven by higher Permian and SouthTX volumes, offset by lower NorthTX, WestOK, and SouthOK volumes. We have 10 months already under our belt. 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 has seen up in the Bakken.
Thank you, Pat, and good morning. For our Badlands systems, where we gather both crude oil and natural gas, year-to-date 2016 has been highlighted by our mutually supportive relationship with the MHA Nation or the Three 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 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 connect crude that is currently being trucked, plus crude from new completions that are happening now. As of Tuesday, November 1st, we are mechanically complete on 50% of the 30 miles of pipeline we are laying for this project.
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. We are on track to deliver on that guidance.
We expect that we will not need to spend as much capital to collect future volumes in 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. The feedback we are hearing from our producers is that at prices similar to the strip today, we are 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 at our Little Missouri plants, we are poised to benefit with any uptick 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'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 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. With that, operator, please open up the line for questions.
Thank you. Ladies and gentlemen, at this time, if you would like to ask a question, please press star then one on your touch tone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. Our first question comes from the line of Brandon Golsan from TPH. 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 million, maybe a little bit north of that. Processing plant in there, anything else or any other color available as to what will fall into that line item?
Yeah. 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 into detail, some $10 million and $20 million CapEx. We're aggregating those and looking through our.
We're still really formulating that, but we're seeing significant amount of activity, especially on the gathering and processing side. 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. I guess 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 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? 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. We always have things move 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&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. 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&P spend. 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 mold on to our existing asset footprints and build out into new areas that have become active. We're going to see a lot of that. We're going to see volume adds as a result of that. I think that's what we'll see in the Mid-Continent over 2017.
Thanks, Brandon.
Thank you guys.
Thank you. Our next question comes from the line of Sunil Bushani from UBS. Your line is open.
Hi, good morning, guys.
Sunil.
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've talked about 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're kind of on the side. 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 south, southwest of Versado and have opportunities on the broadly the western side of our Sandhills facility. We've looked at, it wasn't that long ago, we announced without precision a plan in between those. We've afforded opportunities, are working on those kinds of opportunities, but don't have any additional details to provide you right now, Sunil, other than that color, and I hope the color was helpful.
Okay. 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? Secondly, with respect to the Mid-Continent, or I guess specifically the SCOOP STACK, have you secured any acreage dedications at all so that you could be able to move volumes to your Mistletoe plants?
Sunil, this is Scott. I'll try to take the first part of your question, 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. 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. We would like to get full understanding of what that looks like going forward as we mature throughout the balance of this year.
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. With demand continuing to grow, we will have opportunities, and I like our chances very well.
Okay. Acreage dedication?
I don't speak to specific acreage dedications, 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. If you look at our Western Oklahoma system, you referred to the Mistletoe 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, Sunil.
Okay, thanks.
Thank you. Our next question comes from the line of Danilo Juvane from BMO Capital Markets. Your line is open.
Thanks, Renee. Good morning. I wanted to circle back to the LPG export question, perhaps I'm looking at it with a more near-term lens. The 6 million barrels per month average for the fourth quarter, is that something that you had visibility to prior to getting to four Q, 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. A lot of it has shored up, and we've 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 3rd earnings call. We felt good about the fourth quarter. Certainly now that we are in November, and we've already had one month that has surpassed, 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.
Thanks for that. 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 contribute to our fourth quarter volumes, both in a variety of contract structure, whether they be short or long-term.
Got it. I guess 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.
Yeah. We have not provided a breakout for the plant cost related infrastructure by line item. We're still working through our plan on that. 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. We're still working on those pieces.
Great.
What we publicly disclose on those prices. 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. Our next question comes from the line of Faisel Khan from Citigroup. Your line is open.
Hi. Thanks, guys. 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 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 there, and you actually see a lot of it in SouthOK, 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. 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. 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. That's just ethane coming out of the.
Yeah. The biggest move when you go through, I think it was on the SouthOK system, which is where you see where we go in and out of recovery and rejection more than the others. We do make those marginal decisions at those other plants as well.
Okay. Gotcha. Just going back to the uptick in the LPG volumes, the export volumes in the fourth quarter. Isn't this also more of a seasonal sort of pattern that we're seeing globally and generally speaking? Isn't 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 weather trends and things of that nature. South America would shift to a different direction as a result of that. Overall, it would say that you could have some seasonality affecting what fourth quarter looks like. Also, at the same time, recognize the fact that during the third quarter, 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.
Given expansions on the export side of the business, there was a lot of vessels that were loaded. 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. 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 the third quarter of this year.
Okay.
Speaking for Targa in particular.
Yep.
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. One last question. In the Logistics and Marketing segment, it looked like OpEx ticked up, looks like 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?
Yeah. Primarily, it was Train Five being operational for the full quarter. 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're very pleased with the trends.
Right.
Cost reduction across the company, holding on to that cost reduction across the company, 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.
Right.
That's something we're proud of.
Okay. Got it. Thanks for the time, guys.
All right. Thank you.
Thank you. Our next question comes from the line of John Edwards from Credit Suisse. Your line is open.
Good morning, everybody. I just have a couple quick ones. Just on the South Texas G&P volumes, looked like they were down a bit sequentially, same with the frac volumes declining sequentially. Acknowledging you 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. Generally, those are low-margin volumes. Some of the levels at which people were willing to do that in the quarter were levels that we didn't want to approach. 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. We think our opportunities forward are significant.
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. 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.
Okay. Thank you for that. Yeah, thanks for clarifying that. Appreciate that. That's it for me. Thank you.
Thanks, John.
Okay, thanks.
Thank you. Our next question comes from the line of Craig Shere from Tuohy Brothers. Your line is open.
Hey, Craig.
Thanks for the incredibly detailed outlook. That was terrific.
Craig, can you speak up a bit?
I'm sorry. Is this better?
Yes.
Yes.
Yep. Thank you.
No problem. First question on the Sanchez JV. Right now you're processing 100% of those volumes, right? When they transfer over to Raptor, you'll only get credited 50%? How does that work on an economic basis without becoming lumpy quarter-over-quarter?
No, you're exactly right. We're processing those at our Silver Oak facilities, where we own 100% of Silver Oak 1 and 90% of Silver Oak 2. When the Raptor comes on, it'll go into the 50/50 JV. You're exactly right.
Okay. Just from an economic standpoint, there's a short-term blip.
Right. Yeah, it'll be a reduced all-in net economics to us when we move those through the Raptor plant, all things equal.
Okay. Fair enough. Matt, when we think about the, I don't know, maybe $550 million-$600 million of 2017 spend, and the disproportionate equity financing versus a normal 50/50 split, can you, A, characterize any more the disproportionality of equity, and B, give some longer-term kind of signposts you'd be looking for?
Sure
For when we might ease up on that equity pedal back to that 50/50 split?
Sure. A lot of it is really gonna depend on the timing of the cash flows for when the projects come on, the amount of the 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're still within the range. We're going to keep a close eye on that as we move through 2017. It's going to depend on the environment, where the ultimate CapEx shakes out, what our ultimate EBITDA is, commodity price levels are. We'll just have to take a view as we go through into 2017. 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. Again, that's really dependent on the environment, what the all-in budget is, and what the outlook is.
I would also-
Go ahead.
Which 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.
Right.
Fair enough. This is more kind of carpe diem, opportunistic. It's not going to be mechanical where 75% is going to be hit every quarter. It's more nimble.
We take a longer term view of our all-in capital structure. It's certainly not quarter to quarter or even year to year. I think our long-term target is the 50% debt, 50% equity has worked for us over time. In any given year or quarter, it could be more heavily weighted towards debt or equity. 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, make the best decision from there.
Fair enough. Last one for me. Any updates around the 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 expansions in 2017 and 2018, is trying to understand what the balance is going to look like for ethylene production and what the global demand's 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. 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, say, the direct boundary lines of the asset at Galena Park, 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 could be meaningful in terms of the overall economics of the facilities?
I would say we're not prepared to give any sort of lead into that sort of questioning. There's always that potential. 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. Our next question comes from the line of Chris from Jefferies, your line is open.
Hey, good morning, guys.
Hey, good morning.
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.
Okay.
It is over all outstanding common and preferred dividend payments at TRC. That's right.
Okay. That's consistent with how we should interpret the fourth quarter guidance around the 1.20 level?
Correct.
Okay.
If we start defining it differently, we'll scream loud about a change in definition.
Okay. I just wanted to be clear. Joe Bob, can you remind me, the Noble contract, I obviously remember when it happened. With regard to the $40 million payment, can you remind me the tenets of that and for how long we should expect it? 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. It may very well be included in adjusted EBITDA. Going back from memory is probably more than you want to hear. 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 31st of 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 a lot of engineering work, worked with our customer to consider additional alternatives. Then came back to essentially, though 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 million payable in October. That will continue. We called it multi-year. We didn't say how long the term of the contract was, but I think I would describe it as outside our forecast horizon. 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 Bob. It's kind of a lumpy receipt in terms of when in the year it falls.
No
per your guidance, it's happening on a repeated basis.
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 plant starts, because there will be some operating costs associated with running the plant.
Right. Okay.
Okay. I just want to make sure we're clear on one thing. It'll be lumpy in the sense that we'll receive that payment in October.
Yes.
The cash payment received would be. Right. Okay.
Right.
October every year. Sorry, I was thinking of that as predictable and not.
Okay.
It is lumpy. It's lumpily predictable.
Right.
Lumpily predictable, yeah.
I'm sorry.
Clear the mud. Yeah.
Thanks for cleaning that up, Matt. I'm sorry I misanswered the lumpy question.
I guess what I'm trying to just get after is, I guess for current purposes, when there's not a plant running, this is a 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 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-plus million payment in October. As you're thinking about modeling and planning that out, just have that as in there. We'll include that. It'll be in DCF. As Joe Bob mentioned, we're still determining whether we're going to include that in EBITDA. When the plant is up and running, we will have some deduct for OpEx when the plant's up and running.
Got it. Okay, perfect. 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, 3.8 times, at what point, I don't want to be presumptuous, but at what point is perhaps a credit rating upgrade in the cards at the TRP level? Have you had any discussions, I guess, with the agencies post all the activities you've done in the third quarter?
Yeah. We have continuous dialogue with the rating agencies. We have a good relationship with both that rate us. We'll be meeting with them here on an annual basis relatively shortly, and we'll lay out our forecasts 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, we don't really view it as impacting much our ability to access the markets, as evidenced by our note offerings, the five and an eighth and five and three-eighths. 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.
I don't know that it's necessarily needed to get attractive terms for financing.
Okay. 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 TRP level, but in terms of the consolidated entity, I know you've mentioned we're sitting still around four and a half. Do you have a long-term view of where you'd like that to be? Obviously, respective to the opportunity set and the commodity price environment. Is there something we should be thinking about longer term?
Yeah. I think the three to four times at TRP. Longer term, I think we'd like to get TRC consolidated there. It'd be nice to get our debt EBITDA there at TRC by growing our EBITDA would be.
Yes
most economic way to get there. As long as TRP, we're in that 3-4 times and managing leverage there, we have time to manage the consolidated leverage to the long-term profile that we'd like.
Okay, perfect. Thanks again for the time this morning, guys.
Okay, thank you.
Thank you. Our next question comes from the line of Jeremy Tonet, J.P. Morgan. Your line is open.
Hey, Jerry.
Hey, Jeremy.
Oh, I'm sorry. I thought I heard Jerry. Sorry, Jeremy.
I'm sorry. This is Charlie for Jeremy.
Well, you're both wrong.
Yeah. What was it?
You get the benefit of being the last question. We're conscious of the time. You can tell Jeremy that Charlie got the last question.
All right. Thanks, guys. Yeah, just curious how much third-party volumes are running through the frac now. Just looking at that 313 figure. Are you still in control of those barrels, and is that rate competitive? Additionally, sorry, real quick. Is there any risk in customers electing to send those volumes elsewhere since Targa doesn't have complete control of the takeaway?
First question, we don't give a breakout of what our Targa equity volumes or control volumes through our fractionation relative to third party. I'd say we have a mix of both. I think what I'd say is you've seen in our numbers, we've had some third-party contracts go to other fractionation facilities. That's impacted our numbers on a year-over-year basis. Those were relatively low margin business that moved elsewhere. Yes, there is some risk of that. On prior calls, we don't have it in this script, but the amount of third-party contracts coming up over the next several years is relatively low. I actually don't have that at my fingertips.
What we publicly disclosed
It was in last quarter's script if you want to go look at it. It's relatively small, the amount of contracts that would be really available to move over the near term.
Without saying what percentage was third-party control, you did hear us say, and explicitly so, that we're increasing our equity volumes, we're always seeking to have control of the volumes that are going through our fractionator. I'd 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.
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. 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. You may now disconnect. Everyone, have a great day.