Good 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. If anyone should require assistance during the conference, please press star then zero on your touchtone telephone. I would now like to introduce your host for today's conference, Ms. Jennifer Kneale, Vice President, Finance. Ma'am, go ahead.
Thank you, Chris. I'd like to welcome everyone to the first quarter 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 in an updated investor presentation, which are available on our website, www.targaresources.com. Any statements made during this call that might include the company's expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Act of 1933 and Securities Exchange Act of 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 recent SEC filings, including the company's annual report on Form 10-K for the year ended December 31, 2016, and subsequently filed quarterly reports on Form 10-Q. Danny Middlebrooks, Executive Vice President of Northern Field Gathering and Processing, our North Dakota position, Pat McDonie, Executive Vice President of Southern Field Gathering and Processing, and Scott Pryor, Executive Vice President of Logistics and Marketing, our downstream business, will be joining Joe Bob Perkins, Chief Executive Officer, and Matt Meloy, Chief Financial Officer, with prepared remarks today. Joe Bob will begin the call, will then turn it over to Matt to discuss first quarter 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, Jen. 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 1st closing of the acquisition of additional Delaware and Midland Basin midstream assets in the Permian Basin. For the quarter, we benefited from one month of volume and margin from these assets.
We connected the acquired Delaware Basin assets to our Sand Hills system and were flowing natural gas volumes to Sand Hills very shortly after close. We are 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 WestTX system in the third quarter 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.
You will note the crude volumes from the acquired assets for both Delaware and Midland are included in a new line item called Crude Oil Gathered, Permian in the 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 Sandhills and southern Versado assets, we are officially announcing a new 250 million 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 million, and the plant is expected to be in service in the third quarter of next year. In addition to Wildcat, our 60 million cubic feet per day Oahu gas processing plant in the Delaware will begin service in the fourth quarter of this year. We are also adding associated pipeline infrastructure connecting our Versado and Sandhills systems to each other and to the new acquisition. These pipes, and the addition of Oahu 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 million cubic feet per day gas processing plant in WestTX in the Midland Basin. This will be named the Johnson Plant after Targa co-founder Roy Johnson. Targa would not exist if it were not for the vision of Roy Johnson. The Joyce Plant and Johnson Plant are well-placed Permian Basin reminders of the contributions of two of our retired founders and are a small gesture of thanks to Rene and Roy for all of their hard work getting Targa started. The Johnson Plant is estimated to cost approximately $90 million net to Targa's 72.8% interest and is expected to begin service by the third quarter of 2018. The Johnson Plant is expected online within two 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 WestTX system continues to increase significantly. We're also seeing increasing activity around SAOU. Both systems will benefit over time as producers continue to drill on existing dedicated acreage, on our newly acquired dedicated acreage, and on new dedications. Kind of amazes me. Pro forma for the plants announced today, Targa will have, in the middle of 2018, over 2.4 billion cubic feet per day of gross processing capacity in the Permian Basin, spanning across some of the most attractive acreage in the Delaware Basin and Midland Basin. From the second quarter 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 billion 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 field G&P areas outside of the Permian, there are attractive opportunities for additional investment in the Bakken. 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 LACT units, and pipelines. In South Texas, our 200 million cubic feet per day Raptor plant is mechanically complete. We're initiating startup.
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 million cubic feet per day before it was even complete. That expansion is expected to be completed mid-summer 2017. As a result of all the activity that we are seeing across our gathering and processing systems, we're increasing our estimated 2017 net G&P growth CapEx spending for announced projects to $800 million from our previous estimate of about $540 million. 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 G&P volume outlook, we expect additional volumes to flow to our available capacity at Mont Belvieu. 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 G&P 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 and condensate 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 million from the $700 million or more discussed last quarter. 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, we're working on potential new additional G&P and downstream projects. Turning to our first quarter results. Consistent with our previous expectations, the strength of our field G&P business drove adjusted EBITDA 5% higher versus the first quarter of 2016. There are always pluses and minuses to expectations as we enter a quarter. Some of the headwinds we saw in the first quarter were slightly lower than expected sequential field G&P volumes, lower LPG margins from our export business, and higher downstream OpEx. Despite those headwinds, our first quarter dividend coverage was approximately one times, inclusive of the issuance of more than 13 million 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 1st 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 second quarter EBITDA and dividend coverage may be lower than first quarter results. Over the third and fourth quarters, we expect increasing operating margin in both our G&P and downstream segments. With pretty good visibility that the fourth quarter will generate the highest operating margin of the year for both segments. While dividend coverage is likely to be lower in the second quarter, we expect it to be significantly higher by the fourth quarter and continue to estimate full year dividend coverage of one times or better.
With improving visibility as we look forward into 2018 and 2019 and benefit from full year contributions from our growth CapEx projects and increasing activity levels, we expect robust year-over-year operating margin growth both in G&P 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 and our asset footprints.
The activity, enthusiasm, and visibility of future successes 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 first quarter.
Thanks, Joe Bob. Targa's reported adjusted EBITDA for the first quarter was $277 million, a 5% increase compared to the same period in 2016, largely due to higher commodity prices, continued volume growth in Permian G&P, and the addition of one quarter's contribution of the Noble splitter payment, partially offset by lower volumes in our other G&P regions and lower margins from our downstream business. Reported net maintenance capital expenditures were $25 million in the first quarter of 2017, compared to $14 million in the first quarter of 2016. We continue to estimate approximately $110 million of net maintenance capital expenditures for 2017. Distributable cash flow for the first quarter was $194 million, resulting in dividend coverage of approximately one times. Generally, our second quarter financial results are the lowest of the four quarters, given some seasonality in our downstream businesses.
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 1.0 times or better remains unchanged. Let's now turn to our segment-level results. For the gathering and processing segment, reported operating margin for the first quarter 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&P inlet volumes. NGL prices were 79% higher, condensate prices were 75% higher, and natural gas prices were 63% higher than compared to the first quarter of 2016. First quarter reported 2017 field natural gas plant inlet volumes were approximately flat compared to the first quarter of 2016.
First quarter year-over-year volumes were higher in WestTX, SAOU, and Versado, offset by lower volumes in WestOK, SouthOK, South Texas, North Texas, Sand Hills, and Badlands. Compared to fourth quarter 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 first quarter results. Our outlook for South Texas also continues to improve as rigs move back into the Eagle Ford. In the Bakken, crude oil gather volumes were 114,000 barrels per day in the first quarter, up approximately 5% versus the same time period last year, and approximately 10% higher compared to the fourth quarter of 2016. Crude oil gather volumes for the Permian are currently about 26,000 barrels per day.
For our downstream segment, first 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 6.5 million 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 first quarter of 2017, using borrowings under the TRC revolver, we repaid the remaining $160 million in principal outstanding under the TRC term loan, which should generate approximately $5 million in annual interest savings. During the first quarter, we increased the size of our accounts receivable facility at TRP from $275 to $350 million.
As of March 31st, we had no amounts outstanding under TRP's $1.6 billion senior secured revolving credit facility due October 2020. On a debt compliance, TRP's leverage ratio at the end of the first quarter was 3.6 times versus a compliance covenant of 5.5 times. We also had borrowings of $285 million under our accounts receivable securitization facility at quarter end. TRP revolver availability at quarter end was $1.6 billion. As of March 31st, TRC had $435 million in borrowings outstanding under our $670 million senior secured credit facility, an increase of $160 million compared to year-end after paying off the TRC term loan. TRC revolver availability at quarter end was approximately $235 million. Including approximately $80 million in cash, total Targa liquidity at quarter end was approximately $1.9 billion.
For equity funding, we continued to utilize the ATM program to fund our growth CapEx projects. We have raised approximately $240 million of equity under the ATM program through April. We still have remaining capacity available on our current equity distribution agreement. We expect to file a second $750 million equity distribution agreement in the near future. Overlapping agreements are in place such that we always have access under an 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 1st.
In our financials, we recorded a $462 million 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 billion. In our corporate hedging program, we executed additional hedges during the first quarter. We added some balance of the year 2017 through 2019 natural gas, NGL, and crude swaps. Pro forma as of March 31st, 2017, for non-fee-based operating margin relative to the partnership's current estimate of equity volumes from field gathering and processing 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 million during the first quarter. Given our expectation that we will not be a cash taxpayer for at least five 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 million of income tax expense in the first quarter is expected to be offset by significant income tax benefits in the second through fourth quarters that we expect to result in a cumulative tax benefit for 2017 and continued effective cash tax rate of 0% for 2017. We also benefited from a cash tax add back to DCF of approximately $15 million for the quarter.
That includes an adjustment reflecting the benefit from a net operating loss carryback to 2014 and 2015 taxes and a Texas margin tax refund. I will now turn the call over to Danny Middlebrooks to lead our commercial efforts in North Dakota. Danny?
Thank you, Matt. Despite the impact in January and 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 fourth quarter as we benefit from warmer weather and volumes coming back online that were shut in during the first quarter while producers were fracking wells. With respect to the Badlands system, drilling activity is higher. Drilled, 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 2017 forecasted CapEx estimates for our Badlands system by $75 million.
Over the seasonal construction season, we will be expanding our infrastructure by adding compression at multiple locations, LACT 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 2018. Given our attractive per-unit margins for both gas and crude oil in the Bakken, we're excited about the potential growth opportunities that we're beginning to see return to the Bakken. I will now turn the call over to Pat, who leads our Southern Field G&P business. Pat?
Thanks, Danny, and good morning, everyone. Southern Field G&P results in the first quarter 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 experienced rapid increase in volume growth on our systems in both the Delaware and Midland Basins. In WestTX, the 200 million cubic feet per day Buffalo Plant came online in the second quarter of 2016. The 45 million cubic feet per day Bennington plant was restarted in the first quarter of 2017, and an additional 20 million cubic feet per day expansion at Midkiff will be completed in the second quarter of 2017.
In other words, we added 245 million cubic feet per day of organic processing capacity over the last year in the Midland Basin, and will add another 420 million cubic feet per day of organic capacity between now and the middle of 2018 with the added compression at Midkiff and the Joyce Plant and Johnson Plant announced earlier. Looking forward, we will likely need additional infrastructure in the Permian in 2019 and beyond to support the expected activity on acreage dedicated to our system. We only have one month's 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. 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 Sandhills, we are spending significant growth capital to continue to build out our gas and crude systems. The 60 million cubic feet per day Wahoo Plant will be online during the fourth quarter, and the newly announced 250 million cubic feet per day Wildcat Plant will be online in the third quarter of 2018. As Joe Bob mentioned, part of our spending in the Delaware will connect the Versado and Sandhills 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 first month as an operator of crude assets in the Permian successfully.
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. 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 SouthOK, we are pleased to announce that we are currently building a line that will result in higher volumes in the back half of 2017, 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 South Tex, as previously discussed, there was a decrease in inlet volumes in Q1 2017 relative to Q4 2016, associated with a short-term disruption as one of our key producers had production from multiple well pads shut in during the first quarter while fracking offset newly drilled wells.
As Joe Bob mentioned previously, our 200 million cubic feet per day Raptor plant is mechanically complete, and we are initiating startup. The 60 million cubic feet per day expansion is slated to be complete by mid-summer 2017 and will provide much needed support for growing Sanchez volumes. For 2017, we continue to expect 2017 average field G&P 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 fourth quarter. We exported 6.5 million barrels per month of propane and butanes from Galena Park, driven by continued global demand strength throughout the first quarter, despite periods of high domestic propane prices. 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 second quarter, 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 G&P 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 Mont Belvieu, 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 G&P business and the flow of NGLs to our asset position along the U.S. Gulf Coast. With that, I turn the call back over to Joe Bob.
Thank you, Scott. 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 first quarter of 2017 flew by. Thankfully, much more positive than the first quarter of 2016. Although the Targa 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 million from $700-plus million last quarter. We're likely to spend more if activity continues and some of the unannounced projects under development are successful.
Our strong available liquidity and demonstrated access to the capital markets positions us well to fund our current and future projects. Our 2017 field G&P volume guidance is unchanged versus our last earnings call, though I probably even feel better. Overall, we continue to expect field G&P inlet volumes to be about 10% higher for average 2017 versus average 2016, driven by volumes about 20% higher in the Permian Basin and higher Bakken volumes and higher South Texas volumes, partially offset by lower North Texas, WestOK, and SouthOK 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 G&P segment in 2018 and 2019.
Our field G&P 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. Our dividend coverage outlook remains unchanged. We continue to expect the dividend coverage of 1.0 times 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. Thank you all very much. With that, operator, please open the line up for questions.
Ladies and gentlemen, at this time, if you have 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. Once again, if you have a question at this time, please press star, then one on your touch-tone telephone. Our first question comes from Brandon Blossman from Tudor, Pickering. Your line is now open.
Good morning, Brandon. Yours was the first note I saw this morning. You get up early.
Way too early. All right. This may not be a fair question, Joe Bob, looking through your presentation on your asset overview slide, there's a new bullet there, integration of G&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 y'all have heard me bragging on how much better it's working over the last year or so with continued efforts. 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.
All right. We're not talking about any hard assets connecting those two 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. 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? 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 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 2013 and 2014 with our first level of contracting, we're not seeing those types of levels that we first had in that first initial contracts. 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.
Our next question comes from Kristina Kazarian from Deutsche Bank. Your line is now open.
Afternoon, guys.
Good morning.
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 a smaller, but the Eagle Ford declines, then more importantly on the Permian side. 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 two and a half 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.
Cadence within the year.
Cadence within the year. All of those up and to the right for the end of year. We would expect fourth quarter to be the best volume in all of them. You mentioned Eagle Ford. There were some unique situations about the Eagle Ford, 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. We handled an awful lot of that volume. Permian, I think we did give a lot of color. You have anything you want to add, Pat?
Yeah. I think in the Permian, what you see in the first quarter is always a lot of noise. You have heater treaters on dealing with winter weather, et cetera. Timing on fracs relative to offset production, et cetera. What we are producing today versus what we reported is an indication of what we expect throughout the year. 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 a depiction of and a reaction to the volume growth that we expect and we are seeing on a daily basis, a monthly basis across our system.
Great. 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 alluded to a willingness to participate in something here. Did I hear that right? 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 to processing assets. We are involved in discussions as an important customer or potential partner, 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, we've got attractive options.
Got it. That was it for me. Thank you, guys.
Okay, thanks.
Our next question comes from Darren Horowitz from Raymond James. Your line is now open.
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 contract 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 frack 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 we're working with a variety of customers on a variety of discussions relative to their volume needs, we will continue that effort and again, contract for what fits Targa well.
Okay. As a follow-up, Matt, if I could go back to the $462 million 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, 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 contract. 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, as the commercial effort ramps up, the accretion becomes higher. I'd like to know what's behind the fair value mark to market.
Yeah. What's on the books right now is the $462 million which you referenced. We base that off of forecast of discussion with our customers, drilling expectations over the next several years. 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 1st, as of the acquisition date. Those are all the things that we're going to have to take a look at on a quarterly basis going forward.
When we get into the first quarter of next year, we'll be making that first payment, and we'll continue to estimate through the life of the remaining earn-out. It'll get trued up in early 2019.
Thank you.
Okay, thanks.
Our next question comes from Shneur 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? 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 results in a lower payment that you'll make just because of the timing of it?
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, it does not appear to be the driving force to producer activity from our perspective today. They're drilling primarily for oil economics, it is impacting the expected gas net back, 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. What was the first part of the question?
The first part was fees.
Fees. 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, were done in a difficult time by the developers and to meet needs of producers who needed infrastructure in order to develop their own projects, that those contracts reflected the risk and greenfield nature new build at the time. You sort of answered your own question in the question. We continue to benefit from those higher than average Permian margins on the gas and oil side. Yes, that 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.
Other dedications we get.
dedications we already have.
You won't be able to see the moving pieces, but it is a positive for us.
Great. 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 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've 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. Y'all can see the number of rigs moving to the Bakken just as we can. I'm not comparing it to the Permian. 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 J.P. Morgan. Your line is now open.
Good morning.
Good morning.
Just wanted to follow up on Waha a little bit here, wondering if you guys have any plans for managing the basis risk there any differently that comes through in your POP exposure. Just wondering if you have any thoughts as far as how long the basis could be wide before maybe it tightens up again.
Yeah. I probably won't be the best expert on how long it's going to be wide before it tightens up again. We are not managing our Waha basis risk differently than we have in the past. We do hedge a portion of our 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 G&P operators such as ourselves to improve takeaway from the Permian.
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. 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 and Marketing segment. If you could provide a little bit more color there, that'd be helpful.
Yeah, Jeremy. As we went through the higher OpEx, it was multiple items. 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 first quarter. Sometimes these maintenance and repair items can be lumpy. Just a disproportionate amount kind of hit this first quarter. That's really what drove the higher OpEx on the downstream side. On the Gathering and Processing side, the higher OpEx was more related to the additional activity specifically in the Permian Basin. That was more expected and more normal course.
Got you. Great. 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? We charge a terminal fee to move the product across our dock.
Got it. 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?
Yeah, 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. 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 activity across our dock with the margin compression on that spot number impacts. 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. Again, it's all going to be dependent upon how the market dynamics play out over time.
Got you. Maybe just clarifying a little bit. 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. 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.
Our next question comes from T.J. Schultz from RBC Capital Markets. Your line is now open.
Great, thanks. Joe Bob, you mentioned the Johnson plant will be on just two quarters after the Joyce plant, if I got that right. You all mentioned a couple times this morning that there are likely needs for new infrastructure in 2019. Is that pace of a plant every six months, what is needed to meet your producer needs as you sit there today?
Yeah, 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 the second quarter of 2016. We put in Bennington, the Mid-Crest expansion happening in the first part of this year, and Joyce coming on in the first quarter-ish of 2018. That was a pretty extended period of time. May of 2016 was also 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 lookalikes 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 and 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. I'd just say stay tuned. We're able to be efficient with our capital. All of our plants can run a little bit more than the official nameplate, $200 million a day. 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 million-a-day plant. Periodicity from it. That's our first scale plant. We had to shove in the Wahoo 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 to $60 million 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. 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-$45 crude versus something range bound around, say, $55?
We prepared that one intentionally in our comments, and when you look back at my script, I think I say range bound at 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 a function of that. In the Permian Basin, it's pretty darn robust at that. In the Bakken, 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 y'all do. I hear the same stuff that you hear from, for example, Pioneer. I probably hear a little more that's not inconsistent with it. 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 a 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 the best operator in the basin and one of the few that is growing.
That's all positive. 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.
Our next question comes from Vikram Bagri from Citi. Your line is now open.
Good afternoon. First on G&P, the increase in gathering infrastructure spending in the Permian, is that driven more by crude or gas gathering? Also, if you can provide any color on expected increase in crude 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?
Yeah. In that other bucket for both Midland and the Delaware, there is a piece of that is crude related, the majority of that is related to our natural gas gathering and processing infrastructure. It's adding pipelines, compression, and the like. There is a piece of that is related to crude.
The existing capacity, 40,000 barrels a day each on Delaware and Midland side, how long do you think you can use that capacity, and when do you think you'll reach high utilization on that capacity when you need more?
Yeah, we're seeing a significant growth in the crude gathered volumes out there. If you look at it right now, that 27,000 barrels, we have still remaining capacity in both Delaware and the Midland. 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 to announce on this call we'll be discussing, as we work through plans with producers, there may be something large enough there that we would break out on subsequent calls.
Okay. 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 terminals fees are 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 to balance itself out. Here at Targa, we will continue to be focused in on the linkage that we have with our upstream G&P group in and through our assets for deliveries to end markets, whether those would be petrochemicals 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.
Our next question comes from Matthew Phillips from Guggenheim Partners. Your line is now open.
Thank you. Morning, guys.
Hey, good morning.
Follow-up on the downstream segment. Over the last couple quarters, fractionation volumes have been pretty flat. Export volumes have been at high levels. How should I think about the link between those two? Given the margins were compressed this quarter on marketing, 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? 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 in there. Do you want to add something first?
I guess I'll start maybe just generally, Scott, then maybe you can get more specific. I think of the linkage between those two over the long term rather than the short term.
Yeah.
Over the long term, as Y-grade increases at both our facilities and volumes going through our frac, there's going to be more available for export, both at our facilities and at other facilities. 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.
Perfect.
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. As ethane recovery comes on, that could have some minor impacts to us, but really the way we look at it is what's the overall growth in Y-grade production from upstream, and again, with our growth on the upstream side, that we are set to benefit from all of that.
Yeah. To that point, utilization's been in the high 60s for the past few quarters. Joe Bob has discussed a new frac at Mont Belvieu for the past couple quarters. Clearly, you're optimistic about volumes there. How should we think about when they should start to pick up, especially as ethane recovery increases?
Yeah. There you do have demand pull. Ethane pull from the new petchems will create demand, and there will be more ethane sampled as ethane instead of methane. That is a demand pull. The propane going into Y-grade is coming with the E&P production developments. Someone's line is beeping. Okay. I'm sorry about the noise if you all were hearing it.
Pull on ethane, E&P supply driven on propane, and we will build a frack 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 activity in the Permian, the Scoop Stack, and elsewhere driving into Mont Belvieu is going to be. We have pretty good visibility on it, and I would continue to say that Train 6 is a question of when, not if. 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 one year. Is that correct?
That's not a bad round number.
Okay. Thank you.
Okay, thanks.
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. 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 third-party producers or more opportunity for you to use it for equity volumes? 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 six months after the Joyce plant, is absolutely necessary to just handle our contracted volumes. Pioneer and others in the area. 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. 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. This is getting ahead of demand. Yeah, 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, above their name plate, that they start up day one, this isn't a perfect prediction, but something like 50% full. With current activity levels, it doesn't take long before we need another one. Six months in this case. Does that help?
That's very helpful. Yeah. Thank you.
Okay. Nice talking to you, Andrew.
My other question actually, your producer JV partner made some comments on the 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 and 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 a 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 Benedum in 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 provided a little bit more buffer. What also provides a little bit more buffer is we've done a really good job connecting the West Tex system to the rest of the Targa system, and it allows off loads and sometimes own loads 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. It's 60 million a day.
Great. Very helpful. Thank you.
Don't forget about that one.
Our next question comes from Timm Schneider from Evercore. Your line is now open.
Yeah, good morning, guys.
Hey, good morning.
First question is just follow up on that OpEx item. From a modeling perspective, how should we kind of model that going forward? I guess I understand it's lumpy, but it's going to decline from what we saw in Q1?
Yeah, I wouldn't expect you just to take Q1 and run rate. We should see some lower OpEx than that. 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.
The other question I had on the LPG side, as you guys are kind of going out there and looking at counter parties, where's 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 pretty price inelastic. Is it Asia? Is it Europe? Where's most of the incremental interest?
The story is predominantly centered around Asia.
Okay. Is that Chinese PDH facilities or large integrated crackers that are kind of being built? I think Formosa is building one. There's a couple 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.
Our next question comes from Jerren Holder from Goldman Sachs. Your line is now open.
Thanks. Morning. I know it's late. It was the decline in EBITDA from fourth quarter to first quarter. I recognize there some operating expenses are higher. It looks like fuel G&P operating income is higher, I guess that's why there have been some questions focusing on downstream and what's happening there. If I just look on either a year-over-year basis or quarter-over-quarter, we still have gross margin being down $50 million. It sounds like fractionation was slightly higher. Maybe exports was slightly lower with higher volumes being offset by the lower margins. 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 it's 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.
Yeah, because I guess on the gross margin side, it's still a material. Okay. Anyways, beyond that, from a financing perspective, it's good to see, I guess, additional growth CapEx. 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?
Yeah. I think we'll continue to use the ATM to fund the equity portion of our growth capital. I think we'll continue to over-equitize our growth CapEx who are historical 50% debt, 50% equity. I think we'll continue to run over that. We see one significant 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 3.6 times. We've had a three to four times range or target range really since the Targa partnership went public. We are comfortably within that zone. We're also, if you look at the reported leverage, it's about 4.4 times. I think over time, we're going to want to roll that down lower than that.
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.
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. Coastal NGL volumes dropped 20% from the fourth quarter. Is that natural declines, 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 E&P activity, has been on a decline with not a whole lot activity. It's nice that we get the benefit of some of the big deep water projects that continue, such as the Mars B type stuff. We've got the best catchers, man. I'll remind everyone to look more at the NGLs than the natural gas inlet. That's where we get our % of proceeds. I'd say it has more option value than immediate growth potential right now.
Also, there was an operational upset.
Oh, okay. Got it
of the tailgate of Sunoco during the first quarter. Going forward, I'd expect as inlet volumes to decline, the NGLs to decline. There was an operational upset which made that even larger this quarter.
Okay.
It was not our upset we were impacted by.
It was a third-party NGL line.
How much would that be just so we can get sort of the trajectory right on modeling that?
Yeah. I would expect the produced GPM to be similar going forward. You can just look at what the delta was in the inlet decline versus what was produced.
Okay. Then just, Joe Bob, one kind of big picture question. Are you done with M&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 working together. The communication across the businesses, this one has gone quickly and good. With respect to M&A, we look a lot. You can see our plate is pretty full on the organic growth opportunities in and around our assets. 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 onto the Midland and bolted onto the Delaware.
I think I said with a banker bringing a book around, say, "Just bring me another one of those.
Got it. That's very helpful. Thank you very much.
At this time, I am 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 day.