Western Midstream Partners LP (WES) 2019 Q2 法說會逐字稿

Good morning, and welcome to the Western Midstream Partners Second Quarter 2019 Earnings Conference Call. (Operator Instructions) Please note, this event is being recorded. I would now like to turn the conference over to Jack Spinks, Manager of Investor Relations. Please go ahead.

Thank you. I'm glad you could join us today for Western Midstream's Second Quarter 2019 Conference Call. I'd like to remind you that today's call, the accompanying slide deck and last night's earnings release contain important disclosures on forward-looking statements as well as the non-GAAP reconciliations. Please see the WES 10-K and other public filings for a description of factors that could cause actual results to differ materially from what we discussed today. Those materials are all posted on the Western Midstream website at www.westernmidstream.com.

Please remember that under GAAP accounting rules, our historical results of operations for periods prior to the closing of our Anadarko Midstream acquisition, have been recast to include the results from the acquired assets. Also we present our non-GAAP metrics and throughput, net of the 2% noncontrolling ownership interest that Anadarko holds in Western Midstream operating as well as the 25% noncontrolling interest in Chipeta.

I would now like to turn the call over to our CEO, Robin Fielder. Robin?

Thanks, Jack. Yesterday afternoon, we reported strong quarterly results with adjusted EBITDA and distributable cash flow of $433 million and $335 million, respectively, with a coverage ratio of 1.2.

Adjusted EBITDA does not include $12 million of cash received during the quarter due to the revenue recognition accounting standard. For the remainder of the year, we anticipate a similar run rate EBITDA impact from our cost of service contracts as it relates to revenue recognition, which we expect to total approximately $40 million for the year.

Operationally, gas throughput increased by more than 75 million cubic feet per day quarter-on-quarter. This increase was primarily driven by higher throughput from our equity interest assets in the Delaware Basin and from our Wyoming assets. Additionally, our total gas throughput grew more than 9% year-on-year, driven by our Delaware and DJ Basin assets.

Turning to liquids. Our DJ oil complex throughput increased by 9,000 barrels per day as our system achieved record volumes at our centralized oil stabilization facility. We also continue to benefit from solid performance across our portfolio of equity investments and growth from our long-haul crude pipelines. Our liquids gross margin of $1.85 per barrel was higher than expected due to the timing of distribution payments from equity investments. Once normalized, this margin would have been in line with the first quarter and with our expectations.

Construction at our Latham gas processing plant and the DJ Basin is progressing well, with train 1 expected to be online near the end of the third quarter, and train 2 around year-end. I also want to highlight our recent commercial success in the DJ Basin, where we re-contracted processing capacity at our second Latham train with a third-party, resulting in a higher value, longer-term contract, which retains a 100% of the valuable minimum volume commitments or MVCs. Both processing trains are fully subscribed and fully underwritten by MVCs.

Next, as we announced with our earnings last night, we have updated our 2019 guidance. Before I get into the drivers of the changes, I want to say that despite our lower guidance, we remain confident in the near and long-term potential of our best-in-class portfolio in the Delaware and DJ basins. As we've highlighted previously, a significant portion of our assets are underpinned by a long-term, fee-based contract portfolio, which includes significant MVC and cost of service protections. While these features do not insulate us from everything upstream or downstream of our systems, they safeguard our returns on capital invested in servicing these contracts, many of which have over a decade of life remaining.

The full year adjusted EBITDA decreased relative to our original guidance announced last November can be grouped into 3 categories. The largest driver is lower throughput, mainly associated with our Delaware Basin assets. Some of our customers have experienced a combination of issues, including higher than normal field downtime due to weather, power outages as well as shut-ins related to simultaneous operations. While our facilities continue to experience good run time, these impacts are reflected in our revised guidance. In addition, several producers provided revised forecasts, partially related to the timing of wells being delivered to our systems, which impacted forecast for the back half of the year.

Second, our legacy Wyoming assets continue to realize lower margins due to the significant decrease in NGL and natural gas pricing relative to when our budget was set in late 2018. In total, this represents $38 million of full year EBITDA. With the continued growth of our fee-based DJ and Delaware Basin assets. The EBITDA contribution from these and other assets that have direct commodity exposure will continue to decline over time.

For the first half of 2019, and excluding equity investments, only 7% of our gas volumes and none of our liquids volumes were directly exposed to commodity prices. Similarly, we continue to benefit from the diversification provided by our growing portfolio of fee-based equity interest investments.

And third, the revenue recognition impact related to revised cost of service contract assumptions has reduced annual EBITDA by approximately $30 million. However, this does not impact our distributable cash flow for 2019, as we expect to receive this amount in cash. Offsetting these lower EBITDA impacts, we are expected to benefit from favorable operating expenses at multiple assets, including at our West Texas and DJ Basin complexes as well as higher distributions from our equity investment portfolio.

Before we open the call to questions, I want to address a few additional items. In July, we completed an amendment to our term loan facility, which increased commitments by $1 billion to $3 billion in total, extended the maturity date through the end of next year and modified the mandatory prepayment provision. This amendment provides WES significant financial flexibility and increased liquidity. We appreciate that you may have questions related to the closing of the Anadarko and Oxy merger. At this time, integration and transition discussions are well underway, and we plan to share any relevant updates after the close of the merger, which is expected to occur shortly after the Anadarko shareholder vote on August 8. As always, we appreciate all of your continued support.

And with that, operator, I'd like to open the lines for questions.

(Operator Instructions) Today's first question comes from Gabe Moreen of Mizuho.

Just had a couple of quick questions. Maybe if you can talk about rate -- prospective rate redeterminations on some of your assets in light of, I guess, the lower-than-expected throughput volumes, particularly in the Delaware? Maybe, when you'll get visibility on that? And how those mechanisms may work going into 2020?

Gabe, it's Jaime Casas. As it relates to 2020 revised rates associated with our cost of service contracts, we won't have that information until the -- basically, the year-end, when we get new forecasts, and we go through each of the calculations associated with those contracts. So basically, when we come out with guidance, we currently expect to do that early next year, at that point in time, we would have the rates reset.

Okay. I appreciate that. And then maybe if I can ask a related question sort of on CapEx. Is there any flex, I guess, within the CapEx budget? Clearly, you've kept that the same for 2019? If you got producers with, I guess, revised drilling plans, was there any flex on the CapEx budget? Or should we see that maybe going into 2020 versus -- what original expectations were versus what you're expending in 2019?

Gabe, this is Robin. We're continuing to invest in our major projects. Primarily this year, it's been the construction of our Latham plant in the DJ Basin, so that remains underway as well as lots of continued gathering in both DJ and Delaware Basins. And we already have work underway on some expansion work at some of those larger facilities in West Texas, such as our regional oil-treating facilities to support continued growth as we see from our forecast. And with that, as we complete some of these large capital projects, you should expect capital decline year-on-year.

And our next question today comes from Jeremy Tonet of JPMorgan.

I was just hoping to dive into the lower throughput bucket a bit more here. Is this just the Delaware? Are there any other areas as well? Is this more -- within the Delaware, is this third-party? Is this APC? And just wondering anything else that you could provide as far as communications that you've gotten from your producer customers now versus 3 months ago when you guys reported last quarter?

Jeremy, thanks. I appreciate the question. While we are seeing some revisions from a number of customers, as I pointed out in my prepared remarks, a lot of it's been focused in West Texas across our product lines. The biggest piece and biggest component of that is on the gas gathering and processing side, where we've got a variety of customer base and largely third-party there. But I'll let Gennifer go into a little bit more detail on what's driving some of that for both the quarter and for our full year revision.

Jeremy, this is Gennifer Kelly. Just to provide a little bit more color on both the West Texas -- revisions related to West Texas and you asked if others were involved. There were some third-party DJ customers that have lower throughput, but we haven't seen major revisions in forecast that would make us think that that's anything more than temporal. But to really address the West Texas throughput changes in a little bit more detail, we've mentioned power and weather, and they're really fairly closely related. Most of the downtime that we've -- that the producers saw on their well sites was related to weather. And the weather is causing anything from wind causing lines to hit, to having fuses blown with lightning strikes, and there has been a lot of work underway, and we have insight into this because we cooperate the electrical system with our affiliate out in Delaware Basin to make sure that we're rightsizing transformers, to adding -- spacers have been added to all of our lines. We're looking to get on top of this as much as possible because we know weather is not going away. But we're hoping that we can reduce any weather effects that we see in the future.

Given that we did have quite a bit more downtime than we have seen before related to weather and weather-related power impacts in the first half of the year and we are anticipating that, that could continue while we continue to improve the system.

I also wanted to mention that we also saw downtime on the downstream side that wasn't related to our facilities, and we believe some of these downstream downtime incidents are related to new hookups. We have a lot of new takeaway coming on out of the basin. So some of our downstream partners were hooking up their new lines. And as a result, as valves are added and headers and manifolds are added, a lot of that resulted in spotty downtime, which are -- you'll see rolling through into third quarter and that we've incorporated into the guidance.

I also want to mention that well timing is one of the biggest components of this. And this is just shifts, not in -- we're not necessarily seeing customers that are pulling rigs out of the basin. I want to make that clear. What we're seeing is just the timing of well campaign. Some of that's probably, I'm speculating, related to takeaway constraints right now as people defer, as they're waiting for Gulf Coast Express and Cactus II to come online later this year. So we've seen impacts from all of these. And I want to be clear that we're forecasting in an abundance of caution that these can continue through the rest of the year, but we're very hopeful that we won't see all of these effects. We won't see all of these impacts and that takeaway constraints once relieved in Delaware Basin, will relieve a lot of this, the spotty nature of what we're seeing with timing shifts.

That's helpful. And just want to go to the outages that you're talking around -- about on the upstream side with the electrical issues. Is that in the past? Is that still ongoing? Or -- and if it is still ongoing, when do you expect that to be kind of fully resolved?

We did see downtime related to this in the first half of the year, Jeremy. We accounted for a lot of this in our forecast. We have a downtime -- we risk our forecast for downtime. What we have seen is we've eaten up most of our downtime for the year already because we had an outsized amount of weather-related downtime. For the first half of the year, we were able to meet our targets. But if we forecast that continuing in an abundance of caution, we're wanting to make sure we build that into guidance revisions. However, we have, as I mentioned, completed all of our addition of spacers on the lines and that's jointly between our affiliate and ourselves on our power system. And we are now underway with taking a look at all of our transformer sizing and our lightning protection program on our electrical system. So I anticipate that, that's underway now. I would anticipate that, that will largely be completed by the end of third quarter, maybe into the beginning of fourth quarter.

But we don't know for sure that, that will be the end of the problems that we see, but we hope it will go a very long way to eliminating lots -- what we have seen lots of shut-ins related to isolated incidents.

That's helpful. And one last one, if I could. Just as we look forward past these issues being resolved, and we look through '19 into '20, as far as the production growth that you expected, how would you characterize what would be loss versus deferred at this point?

Jeremy, I'll talk to that a little bit. We're -- as Gennifer highlighted, we're certainly addressing some of this and accounting for some continued downtime through the back half of the year. But also as she pointed out, we expect we'll have some of these long-haul pipes coming on for both residue and crude that should help ease some potential takeaway constraints and even netback pricing some of our operators may be subject to if they have exposure to WAHA and Midland basins. So we still feel like this is fairly temporal, and we've still point to the longevity of our customer base and our contracts as they sit within these key basins. And we still see that growth out there.

Maybe I could just follow-up is the 130-bucket. Is there any way to characterize that deferrals versus issues that you couldn't control like weather or electrical?

I would -- I guess, just spitballing here, I would say, probably at least half of it is deferred. And half is -- I'd say, production-wise, it's all deferred, and it's all still in the ground and will come out. But the -- especially, well timing that we're seeing, that is currently going to be probably incorporated into producer budgets as having shifted into 2020. So you will see positive changes, I'm sure, as those work their way through the system.

And your next question today comes from Spiro Dounis of Credit Suisse.

Maybe I just start off with the DJ Basin deal, which I believe was with DCP. It looks like that was done following a partial release of the contracted volumes, which I think you noted. I think those are underwriting some of the Latham plant. Could you just walk us through exactly what happened there? And how you were able to get a higher rate, I guess, even with a MVC backing this?

Spiro, this is Gennifer. I'll take that one. I want to be careful not to mischaracterize anything in this deal is that our affiliate was able to -- we are very grateful that our affiliate was able to release enough volume to allow us to do this new deal. Keep in mind, our affiliate volumes are dedicated to us. Their timing was just -- we were able to sync it to where we will be able to look at other alternatives, including our existing DJ complex for taking their gas and expansions as we need them for that affiliate volume. So -- don't believe there's anything negative to be gained from thinking that we released those volumes and then not coming back to us, they'll still be there. But this deal allowed us to add more value at an additional large customer. And I think it was really a highly strategic move for us and a good deal for all parties involved.

Okay. That's good color, actually, just given the sort of maybe growing relationship with someone like a DCP, let's say, and the desire to maybe be capital constrained in that basin, make sure you're not overbuilding. Obviously, they still retain the optionality to do something like Bighorn in the basin. Just curious if you would look to do maybe JVs going forward with them on something like that?

We haven't really considered anything like that. But I'd say anything is possible. It really is good to see the DJ competitors in the basin. We're all working, not together, but we're looking at the basin in aggregate and people are being careful about overbuilding.

Fair enough. And then just on Cheyenne Connector. It looks like that's still kind of being delayed a little bit here with some regulatory issues. Just curious what some of the trickle effects and impacts could be on the system there? And if that's already factored into your guidance?

On Cheyenne Connector, we feel like that's -- as far as the start-up of that, as long as that comes on sometime in 2020, we should be just fine. And on the timing, we've got an option there, but we don't need to make a decision until we get that FERC approval, and we'll address further questions on that to the operator.

Yes. Just to add, we don't expect any delays to our Latham II start-up, specifically. At the worst, we may see a little bit of gas price pressure in the basin in the spring shoulder season, but we don't expect any physical constraints in the basin, even if Cheyenne is delayed beyond 2019.

Got it. Last quick one, hopefully. In respect of the processes ongoing with your sponsor. Just in terms of their intentions in ownership and you over time, just curious if you're precluded at all from even shopping yourselves or doing anything proactive to just ensure that LP unitholders are protected. That's not a commentary on WES or anything, but I think the concern, broadly speaking, from a limited partner perspective, as they've seen in deals before, you sort of get a new sponsor, it's unclear what their intentions are. And I think ultimately that pressures the stock price. Just curious what the stance is on that?

Thanks, Spiro. I appreciate the question. As I mentioned in my prepared remarks, obviously we're working very closely with them through the integration and transition process, making sure we have a smooth transition of the MLP with the new sponsor. And as I've said publicly and with our own discussions, they see great value and opportunity based in the WES assets, and are committed to continued development, particularly with a lot of running room left in the early nature of the Permian Basin development.

Beyond that, I mean I think what we're really excited about is our existing contracts and customer base. As Gennifer just highlighted, we just signed up a new good piece of business in the DJ Basin, and we continue to actively seek those kinds of deals and ways we can further enhance our portfolio.

And our next question today comes from Shneur Gershuni of UBS.

Just want to go back and ask a few questions on some of the answers that you gave. Just with respect to -- first of all, on the negative guidance revision, I mean close to 10%. To sort of paraphrase some of your response, it sounds like about 25% of the negative revision is due to the revenue recognition issue, which will shore itself up, but it doesn't affect you on a cash basis.

You also talked about the other 3 quarters of the revision is basically, if I can paraphrase, due to down power line, downstream incidents and deferrals. Is it fair to conclude that there's a little bit of conservatism in kind of this number here, giving you some room if Oxy decides to take down numbers? I mean it just sort of seems like a 6% to 7% revision just due to power line overall seems kind of a bit much? Just wondering if you can sort of talk about that?

Sure. Thanks for the question, Shneur. As we kind of walk through and hopefully, you were able to see our slide deck, walking through the waterfall of our EBITDA revisions. We had a couple of things we pointed out. I mentioned commodity prices and some of the impacts related to revenue recognition and isolation. Those aren't hugely significant and basically are wiped out by the favorability we're experiencing with OpEx and some of our cash distribution timing. So really, we're looking at throughput revisions as they stand for the rest of the year. And a piece of that is a little bit of additional risking based on some of the power outages we've seen in the first half of the year, particularly this most recent quarter.

And as we mentioned, we are also taking into account the additional work taking place downstream ahead of some of these new major pipe projects start-ups, which, again, we think will not only enhance producer takeaway, but should incentivize continued development as -- for those who do have that price exposure within Midland as well for WAHA. So we're -- we are accounting for that in 2019, and further along that as we get into the budget process later this year, we'll have further insight. But again, we've got good line of sight with our affiliate and understand that continued development and have good support from Oxy on what they want to do in the Permian. And as I mentioned earlier, we've got the benefit of some protection with our various agreements, including cost of service contract structures.

Okay. And just to clarify, I mean there is the potential that when Cactus II comes on and GCX comes online that you may have over risked this. Is that a possibility as well? Or you kind of feel pretty comfortable with this?

I mean we always put together a risk profile on our production forecast or throughput forecast.

Okay. Fair enough. Just continuing on, can Oxy change the rates on any of your contracts once you take control of the general partner? Or are there some controls in place to prevent a negative NPV revision to contracts that you [proposed]?

Yes. This is Jaime Casas. As it relates to affiliate contracts, any proposed changes would have to be approved by our special committee. And so they can't just do it themselves in terms of forces to change contracts. It would have to be a negotiation and approved by our special committee.

Okay. Fair enough. And then just in response to questions on the DCP deal. Are the rates comparable to what you would have gotten to APC in year 1 of the deal, like kind of an apples-to-apples basis?

I get that you preserve the option to get more value. I'm just trying to understand if DCP is basically containing a comparable rate as to what APC would have been (inaudible)?

Yes. As it relates to the new DCP contract, the rates are very comparable. The main difference is that we're getting another 1.5 years of term on that contract. So that's going basically from a 5.5-year contract with Anadarko to a 7-year contract with DCP. And obviously, the MVCs are over that entire 7-year period.

Okay. Perfect. And then one final question. The story over the last 2 years was that how you oversized CapEx to accommodate your growth. And obviously you've taken time today and talked about deferrals and that showing up. And I guess you're saying it will show up. Given that backdrop, is it fair to assume that we can see something in the order of magnitude greater than a 50% reduction in CapEx for 2020 and just sort of likely to follow that type of a trend right now?

Yes. Based on what we know today, we are -- we continue to expect about a 40% decline year-over-year in terms of total capital from 2019 versus what we currently expect based on the projects we're aware of for 2020.

Do you mean that this guidance revision caused you to delay the in-service of some of those projects we're expecting for 2020?

Yes. No. The changes to our guidance does not impact any of our projects.

And our next question today comes from Harry Mateer of Barclays.

I guess first one, are you able to confirm your target leverage range of 3.5 to 4x? And if so when do you expect to get there, given the run rate of your new guidance implies something more like in the high 4s at the end of 2019?

Harry, this is Jaime again. Yes. There's -- obviously, with the revised guidance for 2019, we are expecting that leverage will be slightly higher than what we were initially guiding towards. And we think it will be more in the kind of mid-4 range as opposed to the 4.25 range previously. And as it relates to 2020, I really don't want to speculate on that until we come out with our budget for 2020. But what has not -- definitely, what has not changed is our strong preference to be under 4x and to be closer to 3.5x leverage long term. And obviously, we're focused on that and trying to -- we want to get there as quickly as we can.

Okay. And then I guess with respect to that, things change, your EBITDA guidance has changed, cash flow expectations changed. So is there any shift here in how you're thinking about funding things? I mean previously, there's been no equity capital required and just funding it with debt. As a result of that, your debt's going to continue to climb, presumably for the next couple of quarters. So do you adjust how you're thinking about financing your CapEx?

Not as it relates to equity needs or financing plans. We currently have no near-term plans or foreseeable plans to issue any equity to fund our capital needs. Although leverage, it will be slightly higher than what we were expecting when we came out with our initial guidance. We do expect it to continue to decline over the next few years.

And then as Robin mentioned in her comments, we obviously just amended our term loan facility, increasing not only the size of the facility, but also terming out the maturity date. So that provides us with significant liquidity. We'll have -- today, we have over $2 billion of liquidity as well as it gives us a lot of financial flexibility now as that term loan doesn't mature until end of next year.

Right. And I guess related to that, I mean end of 2020, does give you a little bit more breathing room, but it's -- obviously, it's not forever. I mean do you anticipate, maybe you can give us a sense, as you've been having transition discussions with the new sponsor? I mean do you anticipate being able to be in a position where you can actually make some longer-term financing decisions, post-closing of the Oxy-Anadarko deal?

Yes. Post close, we obviously will have very detailed conversations as it relates to our financing plans and addressing the term loan. I'll tell you that we obviously are actively monitoring the bond market, that is the plan to refinance the term loan, but I can't give you any specifics on the timing of when we might do that.

And your next question today comes from Colton Bean of Tudor, Pickering, Holt & Company.

So just to briefly round out the conversation there on the guidance revision. So I think the commodity portion is probably the only piece that wasn't touched on. I think the price swaps expired at the end of last year. Is that exposure is still mostly tied to DJ Basin and then Southwest Wyoming? And if so can you guys just provide a quick refresher on the nature of those contracts? Whether they will be POP or keep-whole?

Yes. This is Jaime, Colton. So it is a combination of POP contracts and keep-whole contracts. To your point, it is predominantly DJ and legacy Wyoming assets that is associated with. We do have -- and it is related to the exposure we now have given the fact that the swaps expired at the end of last year.

And the main driver on that is, when we set guidance late last year or the fall of last year, relative to where we expect NGL prices to be the -- where they were -- we have realized in the first half of the year, when we expect to be the second half of the year, NGL prices are off 40%. And so we're about 7%. -- and we have about 7% direct commodity exposure on the gas side. And

[Technical Difficulty]

Hello, everyone. This is the operator. I've rejoined the speakers.

Yes. Sorry. I think we got -- we briefly got disconnected. I'm not sure where we got disconnected. But all I was saying is, what's driving that is the fact that NGL prices are off 40%, what we were expecting. And the fact that we are -- given that the swaps expired, we do have some direct commodity exposure to gas prices and NGL prices.

Yes. And I guess just with Rocky gas prices actually being very strong in Q1, the implication here being that it's mostly weighted to POP versus keep-whole?

That's right. Yes.

And our next question today comes from Sharon Lui of Wells Fargo.

Just wondering if you can comment on your updated guidance on distribution growth and the rationale? Was it really to manage to a specific coverage ratio? Or is the thought that a lower growth rate may be appropriate going forward given market conditions?

Yes. Sharon, it's Jaime. I would say is that our revisions to our 2019 distribution growth guidance is a function of 2019 in terms of what we expect to achieve. We've obviously already have half the distribution growth baked in terms of the first half of this year. And so our guidance for the rest of the year is 6% on the high end and 5% on the low end. We will -- we've been -- management as well as our Board will continue to evaluate distribution policy every quarter. But given the fact that in this environment, we believe that the investors value coverage more than they value growth. We felt like we wanted to at least have 1.15x coverage, and that's basically how we came to the distribution growth of 5% to 6%.

Okay. Great. And then on the adjusted gross margin for your natural gas assets, can you maybe just talk about the sequential decrease? And also what the trend looks like going forward?

Sure. I think a lot of that just has to do with our Rocky's assets and what you're seeing from some of the legacy production flowing through those, particularly Wyoming.

Okay. So the thought is that perhaps they'll still trend -- continue to trend down a little bit more?

Yes. Slightly. But I think in the rest of this year, we're expecting our gross margin per Mcf to be flat relative to the second quarter.

Yes. And the biggest growing piece of our business will continue to be West Texas.

And our next question today comes from Dennis Coleman of BofA Merrill Lynch.

I guess if we could start. I know this is a little bit sensitive and the timing is short given that we're a little more than a week away from the likely close to the affiliate deal, I guess, without asking you what we might get, what kind of information do you expect you'll be able to share? And what kind of timing do you think you'll be able to give that to it once the deal is closed?

Dennis, it's Robin. I appreciate your question there and wanting to understand that. Obviously, nothing until we close the transaction expected sometime later next week and as soon as practical. But as we mentioned earlier, we will be going through our typical annual budgeting process. And as we get revised forecast from all of our customer base, we'll start working that through the fall and would expect versus last year when we announced somewhat earlier, in November, in conjunction with the announcement of our simplification and asset acquisition from Anadarko. We would expect to put out our full year 2020 guide probably early in the year after we've had the opportunity to revisit everything, including some of our cost of service contracts and potential rate determinations there.

Okay. So it's not like we're going to something in a couple of weeks. It's still under normal cadence of things to go?

As far as budgeting purposes, yes. That's what we're expecting.

Great. And I guess on this the third point of the revision, the revenue recognition, maybe I'm just not understanding this, but there's some assumptions in revenue. Is this not tied to volume? I guess I'm having a little trouble understanding how this is different than the lower throughput that you talked about as the primary driver of the revenue.

Yes. Dennis, this is Jaime. I appreciate the question. And it's definitely fair given the new revenue recognition standard. So at the end of each year, for all of our cost of service contracts, we basically, we get new forecasts from the various producers. Each of the contracts has a minimum rate of return that we need to -- we've provided based on OpEx, capital and the revenue based on the new rate that's redetermined every year. When we came out with our guidance in the fall of last year, we had not gone through that process. So we had not finalized 2019 new rates for those contracts. And we did that basically in the first quarter. We finalized all of the cost of service rate redeterminations in the first quarter of this year, and that's what's driving that $30 million impact relative to our original guidance, right.

As Robin mentioned, that is having an impact in terms of EBITDA, but it has no impact on our cash flow or DCF. And so that's providing a little color on cost of service. I don't know if you have any follow-up questions

I may need to take that off-line. Just to make sure I do have the details. And I guess my last one is just a little bit, maybe a detailed point. But on the volumes released by the affiliate, I mean can you give us the specific volume that was released?

Yes. Dennis, this is Gennifer. We're not going to release any contractual data. All we can say is that we're very happy to have an additional customer and MVC is covering all of Latham.

And ladies and gentlemen, this concludes our question-and-answer session. I'd like to turn the conference back over to the management team for any final remarks.

Thanks, Rocco, and thanks, everyone, for your questions. We appreciate your patience obviously as we go through this transition process and hope to have some more to share as appropriate once we close the acquisition with Anadarko and our new sponsor. And thank you for your continued support. Have a great day.

Thank you, ma'am. Today's conference has now concluded, and we thank you all for attending today's presentation. You may now disconnect your lines, and have a wonderful day.