Targa Resources Corp (TRGP) 2017 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Targa Resources First Quarter 2017 Earnings Conference Call. (Operator Instructions) I would now like to introduce your host for today's conference, Ms. Jennifer Kneale, VP of 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 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 of the securities acts of 1933 and 1934. Please note that actual results could differ materially from those projected in any forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our 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, EVP of Northern Field Gathering and Processing, our North Dakota position; Pat McDonie, 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 Meloy, CFO, with prepared remarks today.

Joe Bob will begin the call. We'll 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 the 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. And 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 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 WestTX 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 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, we're 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 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 in the fourth quarter of this year. We are also adding associated pipeline infrastructure connecting our Versado and Sand Hills systems to each other into 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 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 René and Roy for all of their hard work getting Targa started.

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 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 WestTX system continues to increase significantly, and 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 and Midland Basins. And 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, 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 LACT units and pipelines.

In South Texas, our 200 million 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 million cubic feet per day before it was even complete. And 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.

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 really a 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. 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 G&P and downstream projects.

So 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. It's always pluses and minuses to expectations as we enter a quarter, and 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 1x, inclusive of 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 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 second quarter EBITDA and dividend coverage may be lower than first quarter results. However, over the third and fourth quarters, we expect increasing operating margin in both our G&P and downstream segments and with pretty good visibility that the fourth 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 fourth quarter and continue to estimate full year dividend coverage of 1x or better. Then 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. And 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 the $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 1 quarter's contribution of the Noble splitter payment, partially offset by lower volumes on 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 1x. Generally, our second 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 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 when 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, 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 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 gathered 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 million to $350 million. As of March 31, 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 3.6x versus a compliance covenant of 5.5x. We also had borrowings of $285 million under our accounts receivables securitization facility at quarter-end. TRP revolver availability at quarter-end was $1.6 billion. As of March 31, 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, and we have raised approximately $240 million 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 million equity distribution agreement in the near future, so 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 on 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 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 -- so balance of the year 2017 through 2019, natural gas, NGL and crude swaps. Pro forma, 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 '17 -- 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 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 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 '15 taxes and a Texas margin tax refund.

I will now turn the call over to Danny Middlebrooks, who leads our commercial efforts in North Dakota. Danny?

Thank you, Matt. Despite the impact of 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 up 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 spending 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 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 Benedum 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 we'll 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 and Johnson plants announced earlier.

Looking forward, we would 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 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 million cubic feet per day Oahu 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 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 first 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 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 SouthTX, 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 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. 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 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.

And with that, I turn the call back over to Joe Bob.

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 first quarter of 2017 flew by, thankfully much more positive than the first quarter of 2016. And 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. 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 G&P volume guidance is unchanged versus our last earnings call, so 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 project supports our expectations for the potential of significant market -- margin expansion for our G&P segment in 2018 and '19. 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. And our dividend coverage outlook remains unchanged. We continue to expect the dividend coverage of 1.0x or better, assuming the 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.

(Operator Instructions) And our first question comes from Brandon Blossman from Tudor Pickering.

Yours 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&P and downstream assets' continued area of focus. Should I read anything into that?

It's continued. It has been a focus for some time. I hope you've 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.

All right. We're not talking about any hard assets connecting those 2 [at the knees], 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.

Okay.

I'll leave that one. On the LPG export margins, 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 2013 and 2014 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're 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.

And our next question comes from Kristina Kazarian from Deutsche Bank.

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 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 -- 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.

Cadence within the year.

Oh, cadence within the year. All of those up and to the right for the end of the 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, 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 got anything you want to add, Pat?

Yes. I mean, I think, in the Permian, what you see in the first quarter is always a lot of noise. You have the heater treaters on dealing with the winter weather, et cetera, timing on fracks relative to offset production, et cetera. 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 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. 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 -- you 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?

I'd -- 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 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.

And our next question comes from Darren Horowitz from Raymond James.

Scott, I wanted to go back to some comments that you had mentioned around the downstream segment profitability over the course of this year. I'm thinking about aggregate LPG margin compression. Can you give us a sense of the amount of term contracting 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 when 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, is 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 million of contingent consideration liability around the fair value of the earn-out on those acquired assets. I know you got some time before February next year. But can you give us a little bit more detail around those assumptions? Because I -- 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 million, which you referenced. We base that off of forecasts 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'll be -- 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, and then it will get trued up in early 2019.

And our next question comes from Shneur Gershuni from UBS.

I was wondering if we can start off with the 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 results in 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. And 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?

First part was fees.

Okay, fees. We've said publicly, associated with the acquisition, that the existing contracts at both the Midland and Delaware site 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 risks and greenfield nature, new build of the time. 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, that will have an impact on our overall profitability. Assets you see us building -- I'll point the Wildcat as an example, will not necessarily just serve new contracts. They'll serve the newly acquired contracts. So 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 hyperfocus 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 '17, '18 and beyond. Now you all can see the number of rigs moving to the Bakken just this weekend. 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 it's -- I think we're indicating a positive.

And our next question comes from Jeremy Tonet from JPMorgan.

I just want to follow up on Waha a little bit here, and I'm 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 have any thoughts as far how long the basis could be wide before it maybe 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 are not managing our Waha basis 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 G&P 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 can say that broadly across all 3 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 -- 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 first quarter. Sometimes these maintenance repair items can be lumpy. Just a disproportionate amount kind of hit this first quarter. 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 kind of more expected and more normal course.

Got you. Great. And then in logistics 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 margins? If dock margin 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 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, it's 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 activity across our dock is -- 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. 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 a leading -- with some of the -- I guess, comment 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.

And our next session comes from TJ Schultz from RBC Capital Markets.

Great. 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 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 and I knew the question was coming. If you look at the previous 2 data points, you go back to Buffalo, which we put in in the second quarter of 2016, we then put in Benedum, the Midkiff expansion happened 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. But May of 2016 was also the lowest rig rate -- 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 are looking with our high beams comparing all of the producer forecasts 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. So I'd just say stay tuned. We're 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 200 million a day. And the interconnectivity of the systems, the -- 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, now that's 250 million a day plant. (inaudible) That's our first 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 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. 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, $35?

Yes. You -- we prepared that one intentionally in our comments. When you look back at my script, I think I say range-bound 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. And 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 field?" I think you said $40 to $45. We're not in $40 to $45 now. But we kind of went through it with 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 volume?

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 one of the -- 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.

And our next question comes from Vikram Bagri from Citi.

First on [G&P bearing fees] and 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 [and freezing] 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?

Yes, and -- so in that other bucket for both Midland and the Delaware, there's a piece of that that is crude-related. But majority of that is related or natural gas gathering and processing infrastructure. It's adding pipelines, compression and the like. But there's a piece of that that is related to crude.

So the existing capacity, 40,000 barrels a day, each in Delaware and Midland side, how long can you -- how long do you think you can use that capacity? And when you think you reach the high utilization on that capacity when you need more?

Yes, we're seeing significant growth in the crude gathered volumes out there. If you look at it right now, that's 27,000 barrels versus -- we still have remaining capacity in both Delaware and the Midland, but with 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 kind of work through plans with producers, there may be something large enough there that we would break out in a subsequent call.

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 terminals fees are offsetting some of that?

Propane inventory is, obviously, people have a keen eye on the inventories. What I would suggest is, is that the global market, along with the U.S. market, works pretty 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 G&P 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.

And our next question comes from Matthew Phelps from Guggenheim Partners.

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 two? I mean, should -- given the margins were compressed this quarter on marketing, I mean, was there not the opportunity to run the fracs at 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 2 assets?

Scott, you want me to do it?

Matt and I are trying to jump...

I guess I'll start maybe just generally, Scott, and then 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 wide rate 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. 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.

Yes, the only other thing I would add is, 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 rate production from upstream. And again, with our growth on the upstream side, that -- we are set to benefit from all of that.

Yes. I mean, to that point, I mean, utilization has been in the high 60s for the 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 petchems will create demand, and there will be more ethane instead of methane. That is a demand pull. The propane going into wide grade is coming with (inaudible) E&P production -- someone's light is beeping. I'm sorry about the noise, if you all were hearing it. So demand pull in ethane. E&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 activity in the Permian, the SCOOP, STACK and elsewhere driving at the Mont Belvieu is going to be. But 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 -- we've got the permit in hand, and we'll announce when we start spending dollars on it.

Yes, I think before, you'd said from groundbreaking to in-service would be about a year. Is that correct?

That's not a bad round number.

And our next question comes from Andrew Weisel from Macquarie Research.

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 third-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 demand by announcing 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 positions. 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% full. 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. 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?

I -- unfortunately, preparing for this, I didn't hear it, and I'll read the transcript afterwards. We communicate on an IR-to-IR basis pretty 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 on 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 WestTX 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'd imagine that's what they were talking about. The only other nonoperating plant in the entire Targa system that I can think of is in SAOU, and it's 60 million a day.

Don't let them forget about that one.

And our next question comes from Timm Schneider from Evercore.

First question is just a follow-up on that OpEx item. From a modeling perspective, how should we kind of model that going forward, I guess? It's going to be -- I understand it's lumpy, but is it going to decline from what we saw in Q1?

Yes, I wouldn't expect it 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 counter-parties, where is most of the incremental coming from? I know historically you ship a lot of stuff to Latin America, which I can -- assuming is mostly commercial-residential, so [pre-price inelastic]. But is it Asia? Is it Europe? Where is most of the incremental interest?

[The store 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 of others.

It's a combination of both domestic demand as well as PDH's and obviously petrochemical expansions.

And our next question comes from Jerren Holder from Goldman Sachs.

I know it's late. Can you -- I mean, it was a -- the decline in EBITDA from fourth quarter to first quarter, I recognize there's some operating expenses are higher. It looks like fuel G&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 a either year-over-year basis or quarter-over-quarter, we still have gross margin being down $15 million. It sounds like fractionation was slightly higher, maybe exports or 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. Anyway, 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 equity portion of our growth capital. I think we'll 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 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 3.6x. We've had a 3x to 4x range, or target range for -- really, since the Targa 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.

And our next question is from Ethan Bellamy from Baird.

I think this will be our last call -- last question. What can we do for you?

Lucky me. So coastal NGL volumes dropped 20% from the fourth quarter. Is that natural declines? 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 E&P 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 catchers mitt. I'll remind everyone to look more at NGLs than the natural gas inlet. That's where we get our percent of proceeds. And let's say it has more option value than immediate growth potential right now.

And there was an -- and also, there was an operational upset.

(inaudible) tailgate (inaudible) during the first quarter. So going forward, I'd expect, as inlet volumes decline, the NGLs to decline. But there was an operational upset which made that either even larger this quarter. That's not...

(inaudible) was not our upset we were impacted by.

It was a third-party NGL line.

And how much would that be? Just so we could get sort of the trajectory right on modeling that.

Yes. I would expect the produced GPM to be similar going forward. So if you look at what the delta was and the inlet decline versus what was produced.

Okay. And then just, Joe Bob, just one kind of big-picture question. Are you done with M&A for the meantime, having your hands full with integration?

Well, first of all, I'm really, really proud of 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 well 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. 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, bolt it onto the Midland and bolt it onto the Delaware. I think I said -- with the bank or [bringing a book around], say "Just bring me another one of those."

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 Jenn a call. And 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.