Day, ladies and gentlemen, and welcome to the Targa Resources First Quarter 2017 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 now like to introduce your host for today's conference, Ms. Jennifer Neal, VP, Finance.
Ma'am, go ahead.
Thank you, Chris. I'd like to welcome everyone to the Q1 2017 earnings call for Targa Resources Corp. I would also like to welcome Sanjay Lad to his first earnings call for Targa as our recently hired Director of Investor Relations. Before we get started, I would like to mention that Targa Resources Corp, Targa, TRC or the company has published its earnings release and an updated investor presentation, which are available on our website, www.targaresources.com. Any statements made during this call that might include the company's expectations or predictions should be considered forward looking statements and are covered by the Safe Harbor provision the Securities Acts 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 recent SEC filings, including the company's annual report on Form 10 ks for the year ended December 31, 2016, and subsequently filed quarterly reports on Form 10 Q. Danny Middlebrooks, EVP of Northern Field Gathering and Processing, our North Dakota position Pat McDonough, EVP of Southern Field Gathering and Processing and Scott Pryor, EVP of Logistics and Marketing, our Downstream business will be joining Joe Bob Perkins, CEO and Matt Molloy, CFO with prepared remarks today. Joe Bob will begin the call. We'll then turn it over to Matt to discuss Q1 2017 results, and then Danny, Pat and Scott will discuss their business areas in that order.
After closing remarks from Joe Bob, we will then open the call up for questions. With that, I'll turn the call over to Joe Bob.
Thanks, Jim. Good morning. It's a beautiful morning in Houston, and we appreciate you joining us today. I'm going to begin today's call with an update on the integration of our recent Permian acquisition. I will then discuss some exciting new growth CapEx projects that we are officially announcing today and then provide an updated estimate of 2017 growth CapEx for our announced projects.
I will finish my initial prepared remarks with some color on the outlook for Targa over the near and long term before turning it over to Matt to discuss first quarter results. One of our biggest first quarter highlights was the announcement and then later the March 1 closing of the acquisition of additional Delaware and Midland Basin Midstream assets in the Permian Basin. For the quarter, we benefited from 1 month of volume and margin from these assets. We connected the acquired Delaware Basin assets to our Sand Hills system and we're flowing natural gas volumes to Sand Hills very shortly after close. We're busy connecting wells and continuing to build out our Delaware Basin natural gas and crude footprints.
In the Midland Basin, we expect to connect the acquired assets to our Westech system in the Q3 of this year. When you look at the details of our earnings release in our Q1 results, the acquired Delaware natural gas inlet volumes are reported in Sand Hills and the acquired Midland asset volumes are reported in SAOU, reflective of the bolt on nature of the acquisition. You may also notice that Versado and Sand Hills volumes are being grouped and reported as Permian Delaware and West Texas and SAOU volumes as Permian Midland, which most accurately describes how we manage our combined Permian footprints and how we expect them to continue to develop. And you'll note, the crude volumes from the acquired press release and our 10 Q. Producer activity on the dedicated acreage underpinning the acquired assets is strong and increasing, and our long term outlook for the potential of the area around the acquired and expanding assets continues to strengthen.
As a result of our expectations for increasing activity around the Delaware acquisition and increasing Delaware activity around our Northern Sand Hills and Southern Versado assets, we are officially announcing a new 250,000,000 cubic feet per day gas processing plant serving that combined area of the Delaware Basin. It will be named the Wildcat plant. Total growth CapEx for the Wildcat plant is estimated to be about $130,000,000 and the plant is expected to be in service in the Q3 of next year. In addition to Wildcat, our 60,000,000 cubic feet per day Oahu gas processing plant in the Delaware will begin service in the Q4 of this year. We are also adding associated pipeline infrastructure, connecting our Rosado and Sand Hill systems to each other and to the new acquisition.
These pipes and the addition of Wahoo and the Wildcat plants will increase our flexibility to support volume growth from production of that combined portion of the Delaware. With these projects, all of our Permian systems will then be connected, multi plants, multi sites, multi systems all interconnected, continuing to increase our operational capabilities, reliability and efficiency of capital spend. In the Permian Midland, today we are announcing a new 200,000,000 cubic feet per day gas processing plant in Westex in the Midland Basin. This will be named the Johnson plant after Targa cofounder Roy Johnson. Targa would not exist if it were not for the vision of Roy Johnson.
The Joyce and Johnson plants are well placed Permian Basin reminders of the contributions of 2 of our retired founders. And our small gesture of thanks to Renee and Roy for all of their hard work getting Targa started. Johnson plants is estimated to cost approximately $90,000,000 net to Targa's 72.8 percent interest and is expected to begin service by the Q3 of 2018. The Johnson plant is expected online within 2 quarters of the Joyce plant, demonstrating the accelerating need for additional processing capacity in our portion of the Midland Basin. Activity in and around our Westtec system continues to increase significantly, and we're also seeing increasing activity around SAU.
Both systems will benefit over time as producers continue to drill on an existing dedicated acreage, on our newly acquired dedicated acreage and on new dedications. Kind of amazes me, pro form a for the plants announced today, Targa will have, in the middle of 2018, over 2,400,000,000 cubic feet per day of gross processing capacity in the Permian Basin, spanning across some of the most attractive acreage in the Delaware and Midland Basins. And from the Q2 of 2016, through the expected completion of the projects underway, as a result of organic growth and the recent acquisition, Targa will have added over 1,000,000,000 cubic feet per day of processing capacity in the Permian Basin. Even if we do not experience much commodity price recovery beyond today's strip levels over the foreseeable future, Targa's strong positioning in the Permian is likely to result in attractive volume and margin growth. Turning to some of our other fuel GMP areas outside of the Permian.
There are attractive opportunities for additional investment in the Bakken, and we are undertaking system expansions this year to support expected volume growth in late 2017, 2018 and beyond. This increased growth capital spending in the Bakken is primarily related to additional compression, additional lack units and pipelines. In South Texas, our 200,000,000 cubic feet per day Raptor plant is mechanically complete and we're initiating start up. Working closely with our partners, Sanchez Production Partners, expectations for volume growth on our system drove the decision to expand the Raptor plant to 260,000,000 cubic feet per day before it was even complete. And that expansion is expected to be completed midsummer 2017.
As a result of all the activity that we are seeing across our gathering and processing systems, we are increasing our estimated 2017 net GMP growth CapEx spending for announced projects to $800,000,000 from our previous estimate of about $540,000,000 dollars We continue to focus on maximizing our asset positions by coordinating our gathering and processing business activities with our downstream businesses to drive increasing NGL volumes downstream. Given our expectations for additional ethane extraction as the new petrochemical facilities come online and for overall NGL production growth, given our robust GMP volume outlook, we expect additional volumes to flow to our available capacity at Mont Belvieu. Also, there have been recent announcements and discussions of potential pipeline projects to handle crude, natural gas and natural gas liquid takeaway from the Permian Basin. Those announcements are a really good thing for Permian producers and Permian GMP operators, including Targa. As a result of our significant and growing gas processing positions I mentioned a little while ago, and the natural gas and NGLs under our control, coupled with our extensive geographic asset footprint, we are advantaged as a customer, partner or potential owner in assessing the best strategies for managing our volumes.
Shifting further downstream. Our 2017 estimated growth CapEx announced for downstream projects is primarily driven by the completion of our 35,000 barrel per day crude splitter at Channelview and for adding additional capabilities at and around Mont Belvieu as we continue to invest capital to increase our storage footprint and to enhance our downstream connectivity, for example, to petrochemical complexes in expansion mode. In aggregate, across all Targa businesses, we are raising our full year 2017 forecasted growth CapEx for announced projects to approximately $960,000,000 from the $700,000,000 or more discussed last quarter. And we are likely to spend more than that if activity continues and some of the unannounced projects under development are successful. Targa's development activity right now is robust with many attractive projects across our portfolio of assets.
Naturally, the size and scale of projects under development varies, and we're working on potential new additional GMP and downstream projects. So turning to our Q1 results. Consistent with our previous expectations, the strength of our field GMP business drove adjusted EBITDA 5% higher versus the Q1 of 2016. There are always pluses and minuses to expectations as we enter a quarter, and some of the headwinds we saw in the Q1 were slightly lower than expected sequential field GMP volumes, lower LPG margins from our export business and higher downstream OpEx. Despite those headwinds, our first quarter dividend coverage was approximately 1x, inclusive of the issuance of more than 13,000,000 shares during the quarter through a successful follow on offering in our ATM program.
These equity proceeds were used to fund the initial consideration for our March 1 Permian acquisition and for our growth capital spending. Given the so called seasonality observed over the last few years in some of our downstream businesses, we expect that 2nd quarter EBITDA and dividend coverage may be lower than 1st quarter results. However, over the 3rd and 4th quarters, we expect increasing operating margin in both our G and P and Downstream segments and with pretty good visibility that the 4th quarter will generate the highest operating margin of the year for both segments. So while dividend coverage is likely to be lower in the second quarter, we expect it to be significantly higher by the 4th quarter and continue to estimate full year dividend coverage of 1x or better. Then with improving visibility, as we look forward into 2018 2019 and benefit from full year contributions from our growth CapEx projects and increased and increasing activity levels, we expect robust year over year operating margin growth both in GMP and downstream, even in an environment where commodity prices remain range bound around today's levels.
The excitement at Targa from our commercial and operational teams is palpable and contagious. Everyone is very busy, perhaps the busiest we've ever been, working on attractive small, medium and larger deals and projects and experiencing day to day progress and successes across multiple fronts around our contractual positions in our asset footprints. The activity, enthusiasm and visibility of future successes on a long list of potential growth on a long list of potential growth projects in a plus
or minus $50
per barrel crude world compared to activity levels in that $80 per barrel world is amazing to me and a true testament to our well placed asset positions and the drilling results of our upstream customers as they continue to get better and better. With that perhaps too long introduction, I'll turn the call over to Matt to discuss Targa's results for the Q1.
Thanks, Joe Bob. Targa's reported adjusted EBITDA for the Q1 was 277,000,000 dollars a 5% increase compared to the same period in 2016, largely due to higher commodity prices, continued volume growth in Permian G and P and the addition of 1 quarter's contribution of the Noble Splitter payment, partially offset by lower volumes in our other G and P regions and lower margins from our downstream business. Reported net maintenance capital expenditures were $25,000,000 in the Q1 of 20 17 compared to $14,000,000 in the Q1 of 2016. We continue to estimate approximately $110,000,000 of net maintenance capital expenditures for 2017. Distributable cash flow for the Q1 was $194,000,000 resulting in dividend coverage of approximately 1x.
Generally, our 2nd quarter financial results are the lowest of the 4 quarters given some seasonality in our downstream businesses, and we expect our operating margin to ramp up in the second half of the year, largely due to increasing contributions from our Permian acquisition and cash flow from the completion of growth CapEx projects. As a result, our full year 2017 outlook for dividend coverage of 1.0x or better remains unchanged. Let's now turn to our segment level results. For the Gathering and Processing segment, reported operating margin for the Q1 of 2017 increased by 53% compared to last year, primarily due to higher commodity prices and higher inlet volumes in the Permian Basin, despite lower overall field G and P inlet volumes. NGL prices were 79% higher, condensate prices were 75% higher and natural gas prices were 63% higher than compared to the Q1 of 2016.
1st quarter reported 2017 field natural gas plant inlet volumes were approximately flat compared to the Q1 of 2016. 1st quarter year over year volumes were higher in West Texas, SAOU and Versado, offset by lower volumes in Westo, South of, South Texas, North Texas, Sand Hills and Badlands. Compared to Q4 2016 volumes, Permian volumes grew modestly, but our expectations for the rest of 2017 are unchanged and our expectations for 2018 are higher. Volumes in South Texas were sequentially lower, which impacted our Q1 results, but our outlook for South Texas also continues to improve as rigs move back into the Eagle Ford. In the Bakken, crude oil gathered volumes were 114,000 barrels per day in the Q1, up approximately 5% versus the same time period last year and approximately 10% higher compared to the Q4 of 2016.
Crude oil gathered volumes for the Permian are currently about 26,000 barrels per day. For our Downstream segment, 1st quarter reported operating margin declined 17%, primarily due to lower LPG export margin and lower wholesale and marketing margins and higher OpEx associated with maintenance and other items. Those variables were partially offset by higher fractionation margin. In our LPG export business, we exported approximately 6,500,000 barrels per month of propane and butane, but a strong volume quarter was partially offset by lower fees. Now let's discuss our capital structure and liquidity.
In the Q1 of 2017, using borrowings under the TRC revolver, we repaid the remaining 100 and $60,000,000 in principal outstanding under the TRC term loan, which should generate approximately $5,000,000 in annual interest save. During the Q1, we increased the size of our accounts receivable facility at TRP from $275,000,000 to $350,000,000 As of March 31, we had no amounts outstanding under TRP's $1,600,000,000 senior secured revolving credit facility due October 2020. On a debt compliance, TRP's leverage ratio at the end of the Q1 was 3.6x versus a compliance covenant of 5.5x. We also had borrowings of $285,000,000 under our accounts receivable securitization facility at quarter end. TRP revolver availability at quarter end was $1,600,000,000 As of March 31, TRC had $435,000,000 in borrowings outstanding under our $670,000,000 senior secured credit facility, an increase of $160,000,000 compared to year end after paying off the TRC term loan.
TRC revolver availability at quarter end was approximately 235,000,000 dollars Including approximately $80,000,000 in cash, total Targa liquidity at quarter end was approximately 1,900,000,000 dollars For equity funding, we continue to utilize the ATM program to fund our growth CapEx projects and we have raised approximately $240,000,000 of equity under the ATM program through April. While we still have remaining capacity available on our current equity distribution agreement, we expect to file a second $750,000,000 equity distribution agreement in the near future, so overlapping agreements are in place such that we always have access under and available EDA, so we can issue equity through the ATM if needed. We expect to continue to use our ATM program to fund the equity portion of our growth CapEx program and our first earn out payment related to the Permian acquisition payable in April 2018. I would like to briefly provide some color on our current expectations for the earn out payments related to our Permian acquisition that closed March 1. In our financials, we recorded a 462,000,000 dollars contingent consideration liability related to the current fair value estimate of the earn out.
We believe that this is a relatively reasonable reflection of our current view of the likely size of the earn out payments, which would mean total consideration to the sellers of just over 1,000,000,000 dollars In our corporate hedging program, we executed additional hedges during the Q1. We added some balance of the year 2017 through 2019 natural gas, NGL and crude swaps. Pro form a as of March 31, 2017 for non fee based operating margin relative to the partnership's current estimate of equity volumes from field gathering and processing For 2017 for 2017, we estimate we've hedged approximately 75% of natural gas, 70% of condensate and 60% of NGL volumes. For 2018, we estimate we've hedged approximately 50% of natural gas, 50% of condensate and 25% of NGL volumes. On to taxes for a minute.
Our first quarter financials include a line item for income tax expense of approximately $71,000,000 during the Q1. Given our expectation that we will not be a cash taxpayer for at least 5 years, this may cause some confusion. GAAP convention requires that estimates be made for the year based off book income, which may cause lumpiness from quarter to quarter. The $71,000,000 of income tax expense in the Q1 is expected to be offset by significant income tax benefits in the second through 4th quarters that we expect to result in a cumulative tax benefit for 20 17 and continued effective cash tax rate of 0% for 2017. We also benefited from a cash tax add back to DCF of approximately $15,000,000 for the quarter that includes an adjustment reflecting the benefit from a net operating loss carryback to 2014 2015 taxes and a Texas margin tax refund.
I will now turn the call over to Danny Middleton, who leads our commercial efforts in North Dakota. Danny? Thank you, Matt.
Despite the impact in January February of severe winter weather, our Badlands crude oil gathered volumes increased sequentially by approximately 10%. Our natural gas volumes decreased quarter over quarter due to the severe winter weather but are currently higher than the Q4 as we benefit from warmer weather and volumes coming back online that were shut in during the Q1 while producers were fracking wells. With respect to the Badlands system, drilling activity is higher, drilling uncompleted wells or DUCs are being completed and the general outlook for the commodity prices required for the producers to increase activity levels has improved. As a result, we are increasing our 20 17 forecasted CapEx estimates for our Badlands system by $75,000,000 Over the seasonal construction season, we will be expanding our infrastructure by adding compression at multiple locations, lacked units for well connections and pipelines and then looping of some additional pipelines. These expansions will support an expected drilling ramp in late 2017 continuing into 2018 and also contribute to our expectation that crude and natural gas volumes will be higher average 2017 versus average 2016.
Front loading our 2017 spending and some of our 2018 spend helps us avoid winter weather construction and positions us well for additional growth in 2019. Given our attractive per unit margins for both gas and crude oil in the Bakken, we're excited about growth opportunities that we're beginning to see return to the Bakken. I will now turn the call over to Pat, who leads our Southernfield GMP business. Pat?
Thanks, Danny, and good morning, everyone. Southernfield GMP results in the Q1 of 2017 were largely driven by continued growth in Permian Basin activity. The growth projects announced earlier on the call by Joe Bob will support the rapid increase in volume growth on our systems in both the Delaware and Midland Basins. In Westex, the 200,000,000 cubic feet per day Buffalo plant came online in the Q2 of 2016. The 45,000,000 cubic feet per day Benedum plant was restarted in the Q1 of 2017 and an additional 20,000,000 cubic feet per day expansion at Midkiff will be completed in the Q2 of 2017.
In other words, we added 245,000,000 cubic feet per day of organic processing capacity over the last year in the Midland Basin, and will add another 420,000,000 cubic feet per day of organic capacity between now and the middle of 2018 with the added compression at Midkiff and the Joyce and Johnson plants announced earlier. Looking forward, we will likely need additional infrastructure in the Permian in 2019 beyond to support the expected activity on acreage dedicated to our system. We only have 1 month worth of benefit from our recently acquired Midland assets, but the outlook for growth for both natural gas and crude from existing contracts was robust when we executed the acquisition agreements. And based on discussions with our dedicated producers, our expectations have only gotten better. Turning to the Delaware Basin.
Our recently acquired Delaware assets are integrated into Sand Hills, and we are spending significant growth capital to continue to build out our gas and crude systems. The 60,000,000 cubic feet per day plant will be online during the Q4 and the newly announced 250,000,000 cubic feet per day Wildcat plant will be online in the Q3 of 2018. As Joe Bob mentioned, part of our spending in the Delaware will connect the Versado and Sand Hills systems, meaning we will then have full interconnectivity across our Permian systems. This interconnectivity will benefit our customers with increased system flexibility and optionality, supporting our continued efforts to provide reliable services and grow our footprint across the Permian. We completed our 1st month as an operator of crude assets in the Permian successfully.
And while it is obviously early and starting small, we are excited about the outlook for building out our crude infrastructure and competing for volumes outside of acreage already dedicated to Targa. Moving to the STACK SCOOP. We continue to have commercial success in picking up additional acreage packages. So while we do not yet expect legacy basin declines to be fully offset by growing activity from these regions, our outlook continues to strengthen. We are very well positioned to benefit from the gradual Northwest movement of activity targeting the STACK and are focused on identifying attractive opportunities to put capital to work, growing our infrastructure further south in Woodward, Dewey, Blaine and Kingfisher Counties.
In South Oak, we are pleased to announce that we are currently building a line that will result in higher volumes in the back half of twenty seventeen, driven by the execution of an agreement that will bring additional SCOOP volumes to our system. This line will also be utilized to support projected growth in SCOOP volumes in the future. In Southtex, as previously discussed, there was a decrease in inlet volumes in Q1 2017 relative to Q4 2016 associated with the short term disruption as one of our key producers had production from multiple well pads shut in during the Q1, while fracking offset the newly drilled wells. As Joe Bob mentioned previously, our 200,000,000 cubic feet per day Raptor plant is mechanically complete, and we are initiating start up. The 60,000,000 cubic feet per day expansion is slated to be complete by midsummer 2017 and will provide much needed support for growing Sanchez volumes.
For 2017, we continue to expect 2017 average field GMP inlet volumes to be 10% higher than 2016, driven by year over year inlet volume growth of 20% in the Permian Basin. I will now turn the call over to Scott Pryor, who leads our downstream businesses. Scott?
Thanks, Pat. In our Downstream segment, our LPG export volumes, fractionation volumes and treating volumes were all higher in the first quarter versus the Q4. We exported 6,500,000 barrels per month of propane and butanes from Galena Park, driven by continued global demand strength throughout the Q1 despite periods of high domestic propane prices. However, the growth in volumes was not enough to offset the impact of margin compression on both term and spot deals as some of our older contracts roll off. Similar to previous years, we are likely to see some headwinds in the LPG export business in the Q2 given backwardation in market prices as we come off a period of higher demand.
We are aware of some cancellations at other facilities, but at this point, we have not experienced any at Galena Park. Looking forward, our outlook is unchanged given our substantial long term contract position and favorable global fundamentals for U. S. LPG exports. In our fractionation business, volumes were approximately 2% higher quarter over quarter as we benefited from higher volumes on our GMP systems in the Permian Basin and increasing domestic production.
We expect this positive volume trend to continue and given our available capacity at Mont Belvieu, fractionation margin is likely to increase over the course of 2017 and beyond, as we benefit from continued domestic volume growth and addition of more Gulf Coast based petrochemical cracker capacity, which creates more demand for ethane. As Joe Bob mentioned earlier, the increasing domestic volume growth outlook is also likely to accelerate the need for additional fractionation space at Mount Bellevue. And we could have growth CapEx spending for Train 6 in 2018 depending on expected volumes. Overall, the outlook for Targa's downstream business continues to strengthen, driven by continued integration with our growing GMP business and the flow of NGLs to our asset position along the U. S.
Gulf Coast. And with that, I turn the call back over to Joe Biden.
Thank you, Scott, and thanks to all the speakers. My concluding remarks now feel redundant to the well done remarks of the team, so I'll be brief. The Q1 of 2017 flew by, thankfully much more positive than the Q1 of 2016. And although the target employee attitude was still positive in 2016 relative to the circumstances, the energy and attitude at this time is much preferred. Hopefully, you can sense our excitement at Targa.
We've had a lot of very attractive growth projects announced and or underway and see a runway for continued attractive opportunities going forward. Today, we increased our full year 2017 forecasted growth CapEx for announced projects to approximately $960,000,000 from $700,000,000 plus last quarter. And we're likely to spend more if activity continues and some of the unannounced projects under development are successful. And our strong available liquidity and demonstrated access to the capital markets positions us well to fund our current and future projects. Our 2017 field GMP volume guidance is unchanged versus our last earnings call, though I probably even feel better.
Overall, we continue to expect field GMP inlet volumes to be about 10% higher for average higher Bakken volumes and higher South Texas volumes, partially offset by lower North Texas, West Oak and South Oak volumes. Importantly, our outlook beyond 2017 continues to strengthen as our visibility around activity and projects supports our expectations for the potential of significant margin expansion for our GMP segment in 2018 2019. Our field GMP business will continue to support our activities downstream, and the outlook for higher fractionation volumes and a substantially contracted LPG export business means we should see higher year over year margins for our downstream business over the foreseeable future. And our dividend coverage outlook remains unchanged. We continue to expect the dividend coverage of 1.0x or better, assuming a 2017 dividend of $3.64 per common share, and we expect coverage to improve beyond 2017 as we benefit from full year contributions from growth CapEx projects underway.
So thank you all very much. And with that, operator, please open the line up for questions.
And our first question comes from Brandon Blossman from Tudor Pickering. Your line is now open.
Good morning, Brandon.
This was the first note I saw this morning. You get up early.
Way too early. This may not be a fair question, Joe Bob, but looking through your presentation on your asset overview slide, there's a new bullet there, integration of G and P and downstream assets continued area of focus. Should I read anything into that?
It's continued. It's been a focus for some time. I hope you all heard me bragging on how much better it's working over the last year or so with continued efforts. But Scott's group, Pat's group, Danny's group couldn't be working better. That's not right.
They're going to keep working better and better, but I'm very happy with how they're working.
We're not talking about any hard assets connecting those 2 entities, are we?
I was just talking about how well the group was working together.
There's no foreshadowing that I should read into that.
I try not to do foreshadowing.
Sometimes you do. Sometimes you do.
All right. I'll leave that one. On the LPG export margin, Scott, any hints as to what we should see on a go forward basis? So obviously, a little margin compression Q over Q here. Any help on how we should think about that over the next few quarters?
I would just say that we are we continue to manage our contract portfolio very closely. We are working with existing customers both on their current contracts as well as potential contracts going forward. And we continue to work very closely with potential contracts. We'll evaluate each opportunity that's out there, whether it is a term related contract or it's a spot related contract that fits us well. Clearly, when we first initiated our projects in 20132014 with our first level of contracting, we're not seeing those types of levels that we first had in those in that first initial contracts.
But we are still we still have attractive contracts on the books in our portfolio and we believe that the market demand will continue to grow and we have a wonderful position on the U. S. Gulf Coast and we'll meet the demand as it continues to increase.
Okay. Thanks. That's helpful, Scott. I'll leave it there
for someone else.
Thank you. Okay. Thanks.
And our next question comes from Christina Kozhary from Deutsche Bank. Your line is now open.
Afternoon, guys.
Good morning. Good
morning. Can you guys provide a bit more color on volume trends in the quarter and just really relative to what you were expecting for the quarter and for the year, maybe start on I know smaller, but the Eagle Ford declines and then more importantly on the Permian side. Just could you touch on the cadence or what you guys are thinking of growth rate throughout the year to kind of get to your 20% growth outlook guidance?
I think I would start with and I may not have said it clearly, it was really pretty much on our expectations. Since the 2.5 months of our last quarterly earnings call, our feel and activity across the board has been positive. Cadence within the quarter, I'm not sure I'm good enough to do and Pat's kind of looking at me like cadence within the quarter is difficult.
Oh, cadence within the year.
Oh, cadence within the year. All of those up into the right for the end of year. We would expect Q4 to be the best volume in all of them. You mentioned the Eagle Ford. There were some unique situations about the Eagle Ford, but we feel very positive about the success of Sanchez.
They, by the way, will have their earnings call next week and are probably the best source for how they're doing, but we handle an awful lot of that volume. Permian, I think we did give a lot of color. You have anything you want to add, Pat? Yes. I mean, I
think in the Permian, what you see in the Q1 is always a lot of noise. You have heater treaters on dealing with winter weather, etcetera, timing on fracs relative to offset production, etcetera. But what we are producing today versus what we reported is an indication of what we expect throughout the year. And I can tell you that's up and volume growth is expected to continue. The activity level of our producers, the infrastructure that we've announced is absolutely
Great
Great. And then circling back to what I think Brandon may have been trying here. Joe, Bob, I thought I heard in your opening comments that with all the new projects in the Permian being announced by others, it sounded like you may have been may have alluded to a willingness to participate in something here. Did I hear that right? And if so, can you maybe talk about what the most attractive types of assets to participate in would be?
You heard part of it right with
the very attractive supply position we have in the Permian Basin across our gathering and processing assets. We are involved in discussions as an important customer or a potential partner, and we certainly look at work on our own. We want to be very thoughtful about what are the right decisions for Targa along those takeaway projects, in particular where we've got that large gas and NGL position. We want to do the right thing for our customers, the right thing for our shareholders, and we've got attractive options.
Got it. That was it for me. Thank you, guys.
Okay. Thanks.
And our next question comes from Darren Horowitz from Brendon James. Your line is now open.
Good morning, guys. Scott, I wanted to go back to some comments that you had mentioned around the downstream segment profitability over the course of this year and thinking about aggregate LPG margin compression. Can you give us a sense of the amount of term capacity that's rolling off over the course of this year? And as we think about the segment's profitability, do you think that the increase in frac margin magnitude that you alluded to over the course of this year could be enough to offset that LPG margin compression if it continues?
Well, what I would say is that first off, we gave some pretty detailed information in our last earnings call where we talked about how contracted we are for a long period of time. When you think about the availability of current space that we have over and above those term contracts, when we're selling spot volumes per se, those are not the same sort of levels we saw on spot values, say, again a few years back. Contracting levels for us, we feel very comfortable with. When you think about going forward, again, I'll go back to what I said earlier and that is, as we're working with a variety of customers on a variety of discussions relative to their volume needs. And we will continue that effort and again contract for what fits Targa well.
Okay. And then as a follow-up, Matt, if I could go back to the $462,000,000 of contingent consideration liability around the fair value of the earn out on those acquired assets. I know you've got some time before February next year, but can you give us a little bit more detail around those assumptions? Because if I'm not mistaken, they're based on a multiple of gross margin realized on the legacy contracts. So I'm wondering from a contractual perspective, possibly what is expiring?
How that's changed? I realize that you don't have any new contracts included. So as the commercial effort ramps up, the accretion becomes higher, but I'd like to know what's behind the fair value mark to market?
Yes.
So what's on the books right now is the $462,000,000 which you referenced. We base that off of forecast of discussion with our customers, drilling expectations over the next several years. And we put that on the books. We think that is not an unreasonable assessment of where we'd expect the actual payout to be. Of course, it's going to be dependent on volumes in both the Midland and the Delaware on crude and gas.
The operating margin for us could be significantly higher than that as we add contracts that weren't in place as of March 1 as of the acquisition date. So but those are all the things that we're going to have to take a look at on a quarterly basis going forward. And then it will be when we get into the Q1 of next year, we'll be making that first payment and we'll continue to estimate through the life of the remaining earn out. And then it will get trued up in early 2019.
Thank you.
Okay. Thanks.
And our next question comes from Sharath Gershuni from UBS. Your line is now open. Hi. Good morning, guys.
I was wondering if we can start off with Outrigger. Is it fair to assume that the tariffs for your new build capital will reflect build economics versus the typical tariffs that we would expect? And so overall, there would be kind of a margin improvement for your overall Permian position. And then in talking about that in respect to the payments and so forth that still need to be made, given that there are potential bottlenecks at Waha, is there a risk that it slows the outrigger ramp and perversely effectively result in a lower payment that you'll make just because of the timing of it?
Yes, there was a lot in there. Let's start with the last one I heard, which was WAHA. Waha has constraints. There are multiple projects announced to try to solve the Waha takeaway. And it does not appear to be the driving force to producer activity from our perspective today.
They're drilling primarily for oil economics, and it is impacting the expected gas netback, but I don't think it is the driving force. There's more to it than that, including their logistics and ability to get rigs and get equipment in a timely basis, that appears to be the bigger constraint to us. Taking a step in front of that relative to What was the first part of the question?
The
first part was fees. Okay. We've said publicly associated with the acquisition that the existing contracts at both the Midland and Delaware side with 15 sort of year average life We're done in a difficult time by the developers and to meet needs of producers who needed infrastructure in order to develop their own projects and that those contracts reflected the risk and greenfield nature newbuild at the time. So you sort of answered your own question in the question. And we continue to benefit from those higher than average Permian margins on the gas and oil side.
Yes, will have an impact on our overall profitability. Assets you see us building, I'll point to Wildcat as an example, will not necessarily just serve new contracts. They'll serve the newly acquired contracts. They'll serve those newly acquired contracts, other dedications we get and dedications we already have. So it's you won't be able to see the moving pieces, but it is a positive for us.
Great. And as a follow-up question, for the last year, there's been a hyper focus on the Permian from operators, the street and so forth. You talked about the Bakken in your prepared remarks, given how high returns on capital are there. Is this a potential source of material earnings expansion over the next few years? Are there are some interesting trends that you'd like to share with us with respect to your views on the Bakken?
I thought Danny's color was terrific, which is it has gotten more positive even at today's pricing that we got visibility with good communications with our producers, and we are spending capital in 2017 for the benefit of the end of 2017, 2018 and beyond. Now you all can see the number of rigs moving to the Bakken just as we can. I'm not comparing it to the Permian. But when you're in a good place for where those rigs are moving and where activity is occurring, I think we are indicating a positive.
All right. Cool. Thank you very much. Appreciate the
color, guys.
Okay. Thanks.
Our next question comes from Jeremy Tonet from JPMorgan. Your line is now open. Good morning.
Good morning.
Just wanted to follow-up on Waha a little bit here and just wondering if you guys have any plans for managing the basis risk there any differently that comes through in your POP exposure. And just wondering if you had any thoughts as far as how long the basis could be wide before maybe it tightens
up again? Yes. I probably won't be the best expert on how long it's going to be wide before it tightens up again. We risk risk differently than we have in the past. We do hedge a portion of our commodity, equity commodity risk, as you know, and Matt gave you the updates.
When the gas portion of that hedge is WAHA based, we hedge it as WAHA. We try to do so with discipline and without a view of when is the right time to hedge WAHA. When we think about more broadly managing that risk, it's trying to see the needs over time for interconnectivity for our assets. And in reality, our assets will mostly get market price. It's good for producers.
It's good for GMP operators such as ourselves to improve takeaway from the Permian. And the large basis that you're seeing now, and it probably gets larger before it gets smaller, will help eliminate that basis because it will incent capital investment for the takeaway. And you could say that broadly across all three commodities.
That makes sense. Just wanted to touch as well on some of the one off costs that you guys mentioned in the logistics marketing segment. If you could provide a little bit more color there, that would be helpful.
Yes, Jeremy. We had yes, as we went through the higher OpEx, it was multiple items. So we kind of lumped it into a maintenance category and other things. It was multiple business unit, multiple items that just kind of stacked up in the Q1. Sometimes these maintenance and repair items can be lumpy.
There's a disproportionate amount kind of hit this Q1. So that's really what drove the higher OpEx on the downstream side. And then on the gathering and processing side, the higher OpEx was more related to the additional activity specifically in the Permian Basin. So that was more of kind of more expected and more normal course.
Got you. Great. And then in logistics and marketing as well, could you provide any color as far as how much of Q1's export margin decline was driven by dock fees relative to kind of commodity margin? If dock margins stay stable from here, can commodity margins expand? Or any color there would be great.
Jeremy, I'm not sure I'm following exactly the question. I'll just say that when we export, it's a fee business, right? So we charge a terminal fee to move the product across our dock.
Okay. I guess is this just kind
of a steady run rate as far as the fee level that we would expect in the export
side? Yes, I would say somewhat steady, just recognizing that anything that we move across our dock in a given quarter is both a mixture of term contracts as well as spot activity. So as a result of that, when we're in a situation like we are today where the market is not as robust as it has been in previous years, spot Again with LPG export demand growing globally, we will be in a position to meet incremental opportunities across our dock and we should improve with that. But again, it's all going to be dependent upon how the market dynamics play out over time. Got you.
And then maybe just clarifying a little bit, if you guys you supply the product for the export as well, just wondering any commodity margin there. Is this kind of a steady rate or do you expect that to kind of alter a bit?
I think a steady rate. Again, recognizing that when you think about the connectivity we have with our upstream side of the business, Pat and his team are keeping our team on the downstream side very busy with all of their growth and that just enhances our downstream business overall. So leading with some of the, I guess, comments that Joe, Bob and team provided today, again, one of the reasons why we see second half of the year looking better as we move throughout the year.
Great. That's all helpful. Thank you very much.
Okay. Thanks, Jeremy.
And our next question comes from TJ Schultz from RBC Capital Markets. Your line is now open.
Great. Thanks. Joe Bob, you mentioned the Johnson plant will be on just 2 quarters after the Joyce plant, if I got that right. And you all mentioned a couple of times this morning that there are likely needs for new infrastructure in 2019. So is that pace of a plant every 6 months what is needed to meet your producer needs as you sit there today?
Yes. I was afraid someone might extrapolate it. I knew the question was coming. If you look at the previous two data points, you go back to Buffalo, which we put in, in the Q2 of 2016. We then put in Benedum, the Midcrest expansion happening in the 1st part of this year and Joyce coming on in the Q1 ish of 2018, that was a pretty extended period of time.
But May of 2016 was also the lowest rig rate in the lowest number of rigs in the Permian in quite some time. That's a pretty rapid ramp up. We're going to build them in time to take care of the needs of our important partner, Pioneer, where we get great information and the Pioneer look alikes who are doing as well as they are in the area. I don't have a prediction for you on how quick the next one will come, but you can be assured, we're looking with our high beams. We're comparing all of the producer forecast activity levels.
And I would say today, best information I've got is that each successive well continues to be a little bit better than the last one. So I'd just say stay tuned. We are going to be we're able to be efficient with our capital. All of our plants can run a little bit more than the official nameplate, dollars 200,000,000 a day And the interconnectivity of the systems, call it, the more toy plants that we have acquired and adopted and restarted all give us some flexibility on trying to manage the exact point in time that a plant has to be ready. If you look over on the western side of the Permian, the Wildcat plant, that's a $250,000,000 a day plant.
Periodicity from it, that's our 1st scale plant. But we had to shove in the Oahu plant to kind of take care of initial business. We owned it. It fit well there. It was a good bridge solution, but it doesn't take very long to fill up the $60,000,000 a day.
I know that's not as precise a formula as many of the people on the phone might like, but it really is the best answer I can give you right now.
Okay. No, that's helpful. And what kind of range on the oil price keeps your view of the activity ramp intact? Or how do you feel from your seat the producers are looking at it? Meaning does your view or expectations in the Permian change at $40 to $45 crude versus something range bound around, say, dollars 55
prepared that one intentionally in our comments. And when you look back at my script, I think I say range bound that today's forward script or range bound around today's levels. Our feeling and our view is by its very nature, the latest conversations we've had with our producers is at that, you were hearing the color we were giving you, which was positive. It's harder to say where do producers feel in, I think, you said $40 to $45 We're not in $40 to $45 now. But we kind of went through it with the activity increasing before we were in the $50 range.
I think we're positive here, positive around here, positive with the forward curve. I can't tell you what the downward piece looks like other than to say, certainly in the Permian Basin, I read the same stuff you all do. I hear the same stuff that you hear from, for example, Pioneer, and I probably hear a little more that's not inconsistent with it. So I'm not going to turn suddenly bearish at 40 to 45.
Okay. No, that's helpful. Just one last thing, switching gears a bit. As you look at more activity potentially in the Eagle Ford, you have Raptor ramping. What are your options for optimizing the remaining open capacity that you have in the basin?
And I guess, would you consider additional JVs on some of that capacity to drive more volumes?
In some ways, South Texas has been consolidating basin, and I think we've worked with that in mind. Our partnership with Sanchez is a very good one and has the benefit of working with 1 of the well, the best operator in the basin and one of the few that is growing. That's all positive. And we keep our eyes out for what's the best way to manage the available capacity in our hands and we're watching the consolidation that's going on around us.
Okay, fair enough. Thank you.
Okay, thanks.
And our next question comes from Vikram Bagri from Citi. Your line is now open.
Good afternoon. First on GMP, the increase in gathering infrastructure spending in the Permian, is that driven more by crude or gas gathering? And also if you can provide any color on expected increase in food gathering capacity post the spending in 2017 or any other way you can help us understand how big crude gathering opportunity can be for TRGP?
Yes. And so in that other bucket for both Midland and the Delaware, there is a piece of that that is crude related, but the majority of that is related to our natural gas gathering and processing infrastructure. It's adding pipelines, compression and
the like. But there is
a piece of that, that is related to crude.
So the existing capacity, 40,000 barrels a day each on Delaware and Midland side, How long can you how long do you think you can use that capacity? And when do you think you reach high utilization on that capacity when you need more? Yes, we're saying
right now, that 27,000 barrels versus we have still remaining capacity in both Delaware and the Midland. But with the activity around those systems, we're going to put in some additional infrastructure to handle that. We don't have any specifics or anything announced on this call we'll be discussing. But as we work through plans with producers, there may be something large enough there that we would break out on subsequent calls.
Okay. And then Scott, given propane inventories, can you comment on LPG supply demand dynamic in the U. S? And how is it affecting your ability to contract the uncontracted export capacity? Are you seeing any slowdown in discussions to contract additional capacity or the lower terminal fees offsetting some of that?
Propane inventories, obviously, people have a keen eye on the inventories. What I would suggest is that the global market along with the U. S. Market works pretty efficiently efficiently to balance itself out. And here at Targa, we will continue to be focused in on the linkage that we have with our upstream GMP group in and through our assets for deliveries to end markets, whether those would be petrochemical markets or other end user markets here domestically as well as what we are shipping across our dock.
Again, the market will balance itself out and we'll watch patiently as we move throughout the summer to see how the inventory fluctuates throughout the season.
Okay, great. Thank you.
And our next question comes from Matthew Phillips from Guggenheim Partners. Your line is now open.
Thank you. Good morning, guys. Hey, good morning. Follow-up on the downstream segment. So over the last couple of quarters, fractionation volumes have been pretty flat.
Export volumes have been at high levels. I mean, how should I think about the link between those 2? I mean, should given the margins were compressed this quarter on marketing, I mean, was there not the opportunity to run the fracs at a higher level to provide these barrels? Or were you all having to buy them in the open market? I mean, what is how should I think about the link between those two assets?
Scott, you want to
do it? Matt and I are trying to jump on and then you want to add some further.
I guess I'll start, maybe just generally, Scott, and maybe you can get more specific. I think of the linkage between those 2 over the long term rather than the short term. Over the long term as Y grade increases at both our facilities and volumes going through our frac, there is going to be more available for export, both at our facilities and at other facilities. So growing supply overall is good thing for the export business. On a quarter to quarter basis, what's going through our fractionation facilities is driven by production out in the field.
I wouldn't think of it as a demand pull from worldwide LPG what we run through our fractionators.
The only other thing I would add is that when you look at the volumes through the frac recognizing that we're still somewhat in a few areas of ethane rejection. So as ethane recovery comes on that could have some minor impacts to us. But really the way we look at it is, is what's the overall growth in wide grade production from upstream. And again, with our growth on the upstream side that we are set to benefit from all of that.
Past few quarters. I mean, Joe Bob has discussed a new frac at Mont Belvieu for the past couple of quarters. I mean, so clearly, you're optimistic about volumes there. I mean, how should we think about when they should start to pick up, especially as ethane recovery increases?
Yes, I mean, there you do have demand pull. Ethane pull from the new pet chems will create demand and there will be more ethane, so there's ethane instead of methane. That is a demand pull. The propane going into Y Grade is coming with the E and P production development. Someone's lying is beeping.
Okay. I'm sorry about the noise if you all were hearing it. So demand pull on ethane, E and P supply driven on propane, and we will build a frac at the right time to meet those volume needs. I'm not saying anything else about that. No one's crystal ball is perfect in terms of what we have pretty good visibility on it.
And I would continue to say that Train 6 is a question of when, not if. And if activity levels continue as they are currently, we've got the permit in hand, and we'll announce when
we start spending dollars on it.
I think before you had said from groundbreaking to in service would be about a year. Is that correct?
That's not a bad round number. Okay. Okay. Thank you. Okay.
Thanks.
And our next question comes from Andrew Weisel from Macquarie Research. Your line is now open.
Hey, Andrew.
Hey, everyone. Thanks for squeezing me in after the hour. You alluded to some of this, but I want to be a little more clear. The new processing plants you announced today, was that a function more of demand you're anticipating from 3rd party producers or more opportunity for you to use it for equity volumes? And on a related note, are you trying to get ahead of longer term demands in these projects?
Or is it where you expect demand to be a year or so from now when they come online?
Kind of a little of all of that. The Johnson plant in West Texas, which is coming on 6 months after the Joyce plant, is absolutely necessary to just handle our contracted volumes, Pioneer and others in the area. But we're still adding dedications, but we've got better visibility on the stuff already in hand than what we don't have. Similarly, we need the Wildcat plant, both for activity in the southern part of Versado and the northern part of Sand Hills, but also to meet the needs of the recently acquired Delaware position. So you were saying when you say equity volumes, recognizing that equity volumes are only a portion of the volumes that we're handling for our producer customers' needs, those plants are necessary for our producer customer needs and then some future producer customers as well.
But this is getting ahead of demand. Yes, I guess a little bit. I think we said on the last call that when you bring a new plant up in West Texas, because we've got the other ones up so full, okay, above their name plant that they start up day 1 something like this isn't a perfect prediction, but something like 50% fall. And with current activity levels, it doesn't take long before we need another one, 6 months in this case. Does that help?
That's very helpful. Yes. Thank you.
Nice talking to you.
My other question actually, your producer JV partner made some comments on their call this morning about you restarting or repurposing some previously mothballed plants in West Texas. I know you recently restarted the Benedum plant and added capacity at Midkiff. Could there be more to come or were they basically referring to prior stuff in these new greenfield plants will be instead of repurposing older things?
Unfortunately, preparing for this, I didn't hear it, and I'll read the transcript afterwards. We communicate on the IR to IR basis pretty darn well. I believe and I shouldn't be the spokesman for them, I believe they were referring to Midkiff and Benefitin and saying that they were glad that those were brought up because otherwise, the Johnson plant wouldn't be owned in time enough. It's helped us get to when the Joyce plant needed to be owned in time. It's just it provided a little bit more buffer.
Now what also provides a little bit more buffer is we've done a really good job connecting the Westech system to the rest of the Targa system, and it allows offloads and sometimes onloads that provides cushion, shock absorbers to the filling up around that area. I imagine that's what they were talking about. The only other non operating plant in the entire Targa system that I can think of is in SAOU and it's 60,000,000 a day.
Great. Very helpful. Thank you.
Don't forget about that one.
And our next question comes from Tim Schneider from Evercore. Your line is now open.
Yes. Good morning, guys.
Hey, good morning.
First question is just follow-up on that OpEx item. From a modeling decline from what we saw in Q1? Yes. I wouldn't decline from what we saw in Q1?
Yes. I wouldn't expect you to just to take Q1 and run rate. We should see some lower OpEx than that, although it is a little bit difficult to predict exactly what's going to show up in Q2 versus Q3 or Q4, but I think that's right.
And the other question I had on the LPG side,
as you guys are kind
of going out there and looking at counterparties, where is most of the incremental demand coming from? I know historically you ship a lot of stuff to Latin America, which I'm assuming is mostly commercial residential, so pre priced inelastic. But is it Asia? Is it Europe? Where is most of the incremental interest?
The story is predominantly centered around Asia.
Okay. And is that Chinese PDH facilities or large integrated crackers that are kind of being built? I think Formosus is building 1, there's a couple of others.
It's a combination of both domestic demand as well as PDHs and obviously petrochemical expansions.
Okay. All right. That's it for me. Thank you.
Okay. Thanks.
And our next question comes from Jared Holder from Goldman Sachs. Your line is now open.
Thanks. Good morning. I know it's late. Can you I mean, it was the decline in EBITDA from Q4 to Q1. I recognize there are some operating expenses are higher.
It looks like fuel G and P operating income is higher. And so I guess that's why there have been some questions focusing on downstream and what's happening there. And if I just look on either year over year basis or quarter over quarter, we still have gross margin being down $15,000,000 It sounds like fractionation was slightly higher, maybe exports was slightly lower with higher volumes being offset by the lower margins. And so is it just you guys had a bad quarter for like wholesale marketing distribution? Is that how we should think about it?
I mean, that's one of the factors, but it is lower exports. There was some lower margins on the wholesale side as well, but also higher OpEx. I mean, those are the kind of largest items that drove logistics and marketing lower, either year over year or if you look quarter to quarter.
Yes, because I guess on the gross margin side, it's still material, but okay. Anyways, beyond that, from a financing perspective, it's good to see, I guess, additional growth CapEx. And obviously, you guys are willing to use the ATM. How should we think about the leverage range, just given the incremental spending and of course, the earn out payments? How high of leverage are you guys willing to let that run before you sort of use ATM to keep things in check?
Yes. I think we'll continue to use the ATM to fund the equity portion of our growth capital. I think we will continue to over equitize our growth CapEx to our historical 50% debt, 50% equity. I think we'll continue to run over that. As we see one remaining CapEx to be spent this year, but also likely growing capital expenditures, we're going to want to stay ahead of that.
When you look at our leverage, our compliance at TRP was 3.6x. We've had a 3 to 4x range or target range for really since the Target partnership went public. So we are comfortably within that zone. But we're also if you look at the reported leverage, it's about 4.4x. I think over time, we're going to want to roll that down lower than that.
So I think that's going to keep us continuing to fund our growth CapEx likely over the 50% for the near term.
Okay. Thank
you. Okay. Thanks.
And our next question comes from Ethan Bellamy from Baird. Your line is now open.
Hi, Ethan. I think this will be our last call, last question.
What can we do for you?
Lucky, thank you for squeezing me in. I appreciate it. So coastal NGL volumes dropped 20% from the 4th quarter. Is that natural decline? And is that trajectory likely to continue?
Or is that somehow anomalous?
Coastal, which for the most part is catching offshore Gulf of Mexico and Southwest Louisiana, EMT activity has been on a decline with not a whole lot of activity. It's nice that we get the benefit of some of the big deepwater projects that continue such as the Mars B type stuff. And we've got the best catcher's other right now. And there
was also there was an operational offset of the tailgate of ESCO during the Q1. So going forward, I'd expect as inlet volumes to decline, the NGLs to decline, but there was an operational upset, which made that even larger this quarter.
Okay. It was not
our upset. We were impacted. It was a 3rd party NGL line.
And how much would that be just so we can get through the trajectory right on modeling that?
Yes, I would expect the produced GPM to be similar going forward. So you can just look at what the delta was in the inlet decline versus what was produced. Okay. And then done
with
M and A for the meantime done with M and A for the meantime, have your hands full on integration?
Well, first of all, I'm really, really proud of the integration. I would say that at this point in time, you wouldn't find anyone in the Targa side except perhaps a couple of abused accountants saying that they had their hands full with integration. I think it's working, okay? The operations folks are already Targa folks. It's been integrated into our operations.
People are working together. The communication across the businesses, this one has gone quickly and good. With respect to M and A, we look a lot. You can see our plate is pretty full on the organic growth opportunities in and around our assets, and that's our favorite work. If you put another deal like the recently closed Permian acquisition on the table right now though, I would hit that button.
At that price, at that value, bolted on to the Midland and Got it. That's very helpful.
Got it. That's very helpful. Thank you very much.
And at this time, I'm showing no further questions.
Thank you very much, operator. We appreciate your time. We know it ran long. If you have any other questions, please give Sanjay or Jen a call. Have a great day.
Ladies and gentlemen, thank you for your participation in today's conference and this does conclude the program. You may all disconnect. Everyone have a great