Good morning, welcome to the Western Midstream Partners' second quarter 2019 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on your touch-tone phone. To withdraw your question, please press star, then two. 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 discuss 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% non-controlling ownership interest that Anadarko holds in Western Midstream Operating, as well as a 25% non-controlling 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 continued 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 in the DJ Basin is progressing well, with Train One expected to be online near the end of the third quarter and Train Two around year-end.
I also want to highlight our recent commercial success in the DJ Basin, where we recontracted processing capacity at our second Latham train with a third party, resulting in a higher value, longer-term contract, which retains 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 decrease relative to our original guidance announced last November can be grouped into three 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 runtime, 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 forecasts for the back half of the year.
Second, our legacy Wyoming assets continued 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 continued to benefit from the diversification provided by our growing portfolio of fee-based equity interest investments. Third, the revenue recognition impact related to revised cost of service contract assumptions has reduced annual EBITDA by approximately $30 million.
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 WES 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 8th. As always, we appreciate all of your continued support. With that, operator, I'd like to open the lines for questions.
Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your touch-tone phone. If you're using a speakerphone, we ask that you please pick up your handset before pressing the keys. To withdraw your question, please press star then two. Today's first question comes from Gabe Moreen of Mizuho. Please go ahead.
Hey, good morning, everyone. Just had a couple quick questions. Maybe if you can talk about 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.
Hey, Gabe, it's Jaime Casas. Good morning. As it relates to 2020 revised rates associated with our cost of service contracts, we won't have that information until basically at year-end when we get new forecasts and we go through each of the calculations associated with those contracts. 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. Appreciate that. 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've got producers with, I guess, revised drilling plans, was there any flex in the CapEx budget, or should we see that maybe going into 2020 versus what original expectations were versus what you're expecting in 2019?
Hi, 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, that remains underway, as well as lots of continued gathering in both DJ and Delaware basins. We already have work underway on some expansion work at some of the larger facilities in WES Texas, such as our regional oil treating facilities to support continued growth as we see from our forecast. With that, as we complete some of these large capital projects, you should expect capital to decline year on year.
Okay, great. Thanks, Robin.
Our next question today comes from Jeremy Tonet of JPMorgan. Please go ahead.
Hi. Good morning. 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? Within the Delaware, is this third party? Is this APC? 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.
Hi, Jeremy. Thanks. We appreciate the question. While we've seen some revisions from a number of customers, as I pointed out in my prepared remarks, a lot of it's been focused in WES 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. 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.
Hi, Jeremy. This is Gennifer Kelly. Just to provide a little bit more color on both the revisions related to WES Texas, and you asked if others were involved. There were some third-party DJ customers that had lower throughput, but we haven't seen major revisions in forecasts that would make us think that that's anything more than temporal. To really address the WES Texas throughput changes in a little bit more detail, we mentioned power and weather, and they're really fairly closely related. Most of the downtime that the producers saw on their well sites was related to weather and the weather causing anything from wind causing lines to hit, to having fuses blown with lightning strikes.
There has been a lot of work underway, and we have insight into this because we co-operate the electrical system with our affiliate out in Delaware Basin to make sure that we're right-sizing transformers. 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's not going away. 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 had 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.
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. 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 you'll see rolling through into third quarter and that we've incorporated into guidance. Want to mention that well timing is one of the biggest components of this, and this is just shifts. 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 campaigns.
Some of that's probably, if 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. 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. We're very hopeful that we won't see all of these effects, we won't see all of these impacts, and that the takeaway constraints, once relieved in Delaware Basin, will relieve a lot of this, the spotty nature of what we're seeing with timing shifts.
Thanks for the color there. That's helpful. Just want to go to the outages that you were talking about on the upstream side with the electrical issues. Is that in the past? Is that still ongoing? 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 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. If we forecast that continuing, in an abundance of caution, we wanted to make sure we built 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. We are now underway with taking a look at all of our transformer sizing and our lightning protection program on our electrical system.
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. We don't know for sure that that'll be the end of the problems that we see, but we hope it'll go a very long way to eliminating what we have seen, lots of shut-ins related to isolated incidents.
That's helpful. Thanks. One last one, if I could. Just as we look forward past these issues being resolved, and we look through 2019 into 2020, as far as the production growth that you expected, how would you characterize what would be lost versus deferred at this point?
Jeremy, I'll talk to that a little bit. As Gennifer highlighted, we're certainly addressing some of this and accounting for some continued downtime through the back half of the year. 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 net back pricing some of our operators may be subject to if they have exposure to Waha Midland basis. We still feel like this is fairly temporal, and we 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.
Sorry. Maybe I could just follow up. The 130 bucket, is there any way to characterize that deferrals versus issues that you couldn't control, like weather or electrical?
I guess, just spitballing here, I would say probably at least half of it is deferred. I'd say production-wise, it's all deferred, and it's all still in the ground and will come out. Especially the well timing that we're seeing, that is currently going to be probably incorporated into producer budgets as having shifted into 2020. You will see positive changes, I'm sure, as those work their way through the system.
That's helpful. That's it for me. Thanks.
Our next question today comes from Spiro Dounis of Credit Suisse. Please go ahead.
Hey, good morning, everyone. Maybe just start off with the DJ Basin, excuse me, deal, which I believe was with DCP. Looks like that was done following a partial release of the contracted volumes, which I think you noted. I think those were 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 an MVC backing this?
Hi, Spiro. This is Gennifer. I'll take that one. Want to be careful not to mischaracterize anything in this deal as bad. We're 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. The 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. Don't believe there's anything negative to be gained from thinking that we released those volumes and then they're not coming back to us. They'll still be there.
This deal allowed us to add more value, add 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 this 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's 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. Then just on Cheyenne Connector, 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 startup of that, as long as that comes on sometime in 2020, we should be just fine. 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 startup, 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. Respective, the process is ongoing with your sponsor. Just in terms of their intentions and ownership in you over time, just curious if you're precluded at all from even shopping yourselves or doing anything proactive to just ensure that LP unit holders are protected. That's not a commentary on WES or anything, but I think the concern, broadly speaking, from the 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. As they've said publicly and with our own discussions, they see great value and opportunity base 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 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.
Got it. Really appreciate all that color. Thanks, everyone.
You bet.
Our next question today comes from Shneur Gershuni of UBS. Please go ahead.
Good morning, everyone. Busy call today. 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, close to 10%. To sort of paraphrase some of your responses, it sounds like about 25% of the negative revision is due to the revenue recognition issue, which will short itself up, but it doesn't affect you on a cash basis. You also talked about the other three-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?
It just sort of seems like a 6%-7% revision just due to power lines and deferrals 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 walked 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. In 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. Really, we're looking at throughput revisions as they stand for the rest of the year. 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.
As we mentioned, we also taking into account the additional work taking place downstream ahead of some of these new major pipe project startups, 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 itself or Waha. We are accounting for that in 2019. Further along that, as we get into the budget process later this year, we'll have further insight. 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. As I mentioned earlier, we've got the benefit of some protection with our various agreements, including cost of service contract structures.
Okay. Just to clarify, 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 also, or you kind of feel pretty comfortable with it?
We always put together a risk profile on our production forecast or throughput forecast.
Okay. No, fair enough. Just continuing on. Can Oxy change the rates on any of your contracts once they take control of the general partner, or are there some controls in place to prevent a negative MVC revision to contracts without your approval?
This is Jaime Casas. As it relates to affiliate contracts, any proposed changes would have to be approved by our special committee. They can't just do it themselves in terms of force us to change contracts. It would have to be a negotiation and approved by our special committee.
Okay, fair enough. Just in response to questions on the DCP deal. Are the rates comparable to what you would have gotten to APC in year one of the deal, like kind of on 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 paying a comparable rate as to what APC would have been paying.
Yeah. As it relates to the new DCP contract, the rates are very comparable. The main difference is that we're getting another year and a half of term on that contract. That's going basically from a five-and-a-half-year contract with Anadarko to a seven-year contract with DCP. Obviously, the MVCs are over that entire seven-year period.
Okay, perfect. One final question. The story of the last two years was about how you've oversized CapEx to accommodate growth. Obviously you've taken out guidance today, and talked about deferrals in 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? I'm just sort of like if we follow that type of a trend right now.
Based on what we know today, 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.
Does this guidance revision cause you to delay the in-service of some of those projects that you were expecting for 2020?
Yeah, no. The changes to our guidance does not impact any of our projects.
All right, perfect. Thank you very much, guys. Really appreciate the call today.
Thanks.
Our next question today comes from Harry Mateer of Barclays. Please go ahead.
Hi, good morning. I guess first one, are you able to confirm your target leverage range of three and a half to four times? If so, when do you expect to get there, given the run rate of your new guidance implies something more like in the high fours at the end of 2019?
Good morning, Harry. This is Jaime again. 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'll be more in the kind of mid-four range as opposed to the four-and-a-quarter range previously. As it relates to 2020, I really don't want to speculate on that until we come out with our budget for 2020. Definitely what has not changed is our strong preference to be under four times and to be closer to three and a half times leverage long-term. Obviously we're focused on that and we want to get there as quickly as we can.
Okay. I guess with respect to that, things change. Guidance has changed, cash flow expectations change. Is there any shift here in how you're thinking about funding things? Previously there had 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. 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 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.
Okay.
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. That provides us with significant liquidity. Today we have over $2 billion of liquidity, as well as it gives us a lot of financial flexibility now that that term loan doesn't mature until end of next year.
Right. I guess related to that, end of 2020 does give you a little bit more breathing room, but obviously it's not forever. Do you anticipate, maybe you can give us a sense as you've been having transition discussions with the new sponsor, being able to be in a position where you can actually make some longer-term financing decisions post-closing of the Oxy and Anadarko deal?
Yeah. 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. I can't give you any specifics on the timing of when we might do that.
Okay. Thank you.
Our next question today comes from Colton Bean of Tudor, Pickering, Holt & Co. Please go ahead.
Morning. Just to briefly round out the conversation there on the guidance revision, 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 still mostly tied to DJ Basin and then Southwest Wyoming? If so, can you guys just provide a quick refresher on the nature of those contracts, whether they be POP, keep whole?
Yeah. This is Jaime, Colton. Good morning. It is a combination of POP contracts and keep whole contracts. To your point, it is predominantly DJ and legacy Wyoming assets that it's associated with. It is related to the exposure we now have given the fact that the swaps expired at the end of last year. The main driver on that is, when we set guidance late last year, the fall of last year, relative to where we expect NGL prices to be, where we have realized in the first half of the year and where we expect to be the second half of the year, NGL prices are off 40%. We have about 7% direct commodity exposure on the gas side.
Hello, everyone.
Hi.
This is the operator. I've rejoined the speakers.
Yeah. Sorry. I think we briefly got disconnected. I'm not sure where we got disconnected. 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 given that the swaps expired, we do have some direct commodity exposure to gas prices and NGL prices.
Got it. I guess just with Rockies gas price actually being very strong in Q1, the implication here being that it's mostly weighted to POP versus keep whole?
That's right. Yep.
Appreciate that.
Our next question today comes from Sharon Liu of Wells Fargo. Please go ahead.
Hi. Good morning, everyone. 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?
Good morning, 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 obviously already have half the distribution growth baked in terms of the first half of this year. Our guidance for the rest of the year is 6% on the high end and 5% on the low end. We, being management as well as our board, will continue to evaluate distribution policy every quarter. Given the fact that in this environment, we believe that investors value coverage more than they value growth, we felt like we wanted to at least have 1.15 times coverage, and that's basically how we came to the distribution growth of 5%-6%.
Okay, great. On the adjusted gross margins 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 Rockies assets and what you're seeing from some of the legacy productions flowing through those, particularly Wyoming.
Okay. The thought is that perhaps they'll still continue to trend down a little bit more?
Yeah, slightly. I think the rest of this year, we're expecting our gross margin per MCF to be flat relative to the second quarter.
Yeah. The biggest growing piece of our business will continue to be WES Texas.
Okay, great. Thank you.
Our next question today comes from Dennis Coleman of BofA Merrill Lynch. Please go ahead.
Thank you. Thanks for taking my questions. I guess if we could start, I know this is a little bit sensitive, and the timing is short given we're a little more than a week away from the likely close of 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 us once the deal is closed?
Hey, 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. As we mentioned earlier, we will be going through our typical annual budgeting process, and as we get revised forecasts 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 for 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, and including some of our cost of service contracts and potential rate determinations there.
Okay. It's not like we're going to get something in a couple weeks. It's still on the normal cadence of things.
As far as budgeting purposes, yes. That's what we're expecting.
Great. I guess, on 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 talk about as the primary driver of the revision.
Dennis, this is Jaime. Appreciate the question. It's definitely fair given the new revenue recognition standard. At the end of each year, for all of our cost service contracts, we basically get new forecasts from the various producers. Each of the contracts has a minimum rate of return that we need to be 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. We did that basically in the first quarter. We finalized all 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.
Okay.
That's providing you a little more color on cost of service. I don't know if you have any follow-up questions on our part.
No, I may need to take that offline just to make sure I do have the details. I guess my last one is just a little bit, maybe a detailed point, but on the volumes released by the affiliate, can you give us the specific volume that was released?
We'll let Gennifer take that.
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 MVCs covering all of Latham.
Okay. All right. That's it for me. Thank you.
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. 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.