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BP Midstream Partners LP (BPMP) Q3 2020 Earnings Call Transcript

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BPMP earnings call for the period ending September 30, 2020.

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BP Midstream Partners LP (BPMP)
Q3 2020 Earnings Call
Nov 6, 2020, 10:00 p.m. ET


  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Good morning everyone and welcome to the BP Midstream Partners 3Q '20 Results Conference Call and Webcast. [Operator Instructions] Please also note, today's event is being recorded.

At this time, I would like to turn the conference call over to Brian Sullivan, Vice President of Investor Relations. Sir, please go ahead.

Brian Sullivan -- Vice president, investor relations

Hello and welcome everyone to BP Midstream Partners third quarter 2020 results presentation. I am Brian Sullivan, Vice President of Investor Relations. And I am joined remotely today by Rip Zinsmeister, our Chief Executive Officer; and Craig Coburn, our Chief Financial Officer.

Before we begin, please take a moment to review our cautionary statement. During today's presentation, we will make forward-looking statements that refer to our estimates, plans and expectations. Actual results and outcomes could differ materially due to the factors we note on this slide and in our SEC filings.

We also refer to non-GAAP financial measures. Please refer to our SEC filings and supplemental information in this presentation for important disclosures related to these measures. These documents are also available on our website.

Now, over to Rip.

Robert P. Zinsmeister -- Chief Executive Officer

Thanks Brian. Good morning everyone and thank you for joining our call today.

We have navigated another challenging quarter, a quarter dominated by continuing COVID-19 concerns and an elevated number of storms in the Gulf of Mexico. In fact, the 2020 Atlantic hurricane season has been a historic season in terms of the number of named storms. This impacted our third quarter results and we expected to have some impact on our fourth quarter results as well.

That being said, absent these weather impacts our business continued to perform well demonstrating stability and resilience in a tough period. This performance underpinned our ability to declare an unchanged distribution for another quarter while continuing to maintain a robust distribution coverage ratio within our guided range.

Let me start today with a few business updates. First, our COVID-19 response. Second, some thoughts on the macro environment, specifically refined products demand. Third, the new minimum volume commitment or MVC arrangements we have agreed with our sponsor and fourth, some reflections on the strategy our sponsor laid out on August 4 and in more detail in September.

I'll then hand over to Craig to take you through our third quarter operational and financial results and our guidance for the remainder of the year and we will leave plenty of time for your questions.

The COVID-19 pandemic continues to challenge us all from our own personal lives to the broader impacts on the macro environment. Safe operations remain a core value. To-date we have not had any COVID-19 related issues impacting the availability of our pipelines. We continue to monitor local conditions and adapt our operating practices as appropriate. Additionally, we have not sustained hurricane-related damage to any of our offshore pipeline assets so far this year.

Looking at the macro environment and more specifically refined products demand across the US Midwest. Based on IHS Markit data, gasoline and distillate demand in North America has recovered levels around 10% lower than a year ago. Jet fuel demand remain subdued at levels around 50% below last year. And according to the US Energy Information Administration Pad 2 refining utilization has been recovering faster than other regions in the US. However it remains around 12% lower than this time last year.

We saw evidence of both of these broader trends across our own asset portfolio during the third quarter. Throughput on the River Rouge pipeline which transports refined products was around 75,000 barrels of oil equivalent per day in the third quarter, levels consistent with the third and fourth quarter of 2019 before the COVID-19 pandemic really started to impact demand.

Whiting Refinery utilization was solid in the third quarter although supply optimization at the refinery suppressed throughout on the BP2 pipeline during the quarter. We continue to monitor spikes in COVID-19 cases around the country particularly in parts of the Midwest evaluating any potential demand and supply dynamics that may impact us.

Turning to our MVC arrangements, three of the existing MVC arrangements relating to our onshore pipelines were set to expire at the end of this year. We have now agreed a new three-year MVC arrangement with BP. I will lay out these new arrangements and what they mean for BPMP in more detail in a moment.

And last, BP laid out its strategy during the third quarter in which it described both Whiting Refinery and offshore Gulf of Mexico hydrocarbon production as resilient and focused assets. We believe this reinforces their importance to BP's production and operations business group going forward. I'll reflect on this in more detail shortly and also the recent announcement of changes to several officer and director positions.

As I mentioned, we've agreed a new three-year MVC arrangement with BP in respect of each of our three onshore pipelines; BP2, Diamondback and River Rouge commencing January 1, 2020. These new arrangements considered forecast pipeline throughput, forecast performance and plant maintenance at Whiting Refinery, market conditions including prices and differentials for various crude grades, diluent and refined products. In addition, the parties considered broader midstream industry developments and dynamics such as Keystone XL, TMX and Enbridge Line 3 and Enbridge contract carriage as well as valuation of arranged of MVC options across different terms.

Let me comment on two aspects of the MVC arrangement, the term and the throughput levels. Regarding the term, as I mentioned, we evaluated a range of MVC options across different durations. Earlier this year, I indicated that we would open to one-year MVC arrangement with BP given the various demand and supply dynamics potentially impacting the outlook. However on balance, we felt unitholders would prefer an MVC arrangement that provides downside protection to the distribution over a longer three-year period rather than a shorter period.

Regarding the throughput levels, we believe we have negotiated the right balance between first securing protection for the partnership from significant disruptions and maintenance affecting the Whiting Refinery and the onshore pipeline network and second providing BP with the flexibility to optimize refinery supply and output. It is important to highlight that MVC has provide a floor not a ceiling on the revenues from the onshore pipelines and actual throughput may exceed MVC levels as has been the case on several of our pipelines during different periods since IPO.

Looking at the MVC arrangements for each pipeline in more detail. First BP2, the new minimum volume commitment will be 300,000 barrels per day in 2021; 290,000 barrels per day in 2022 and 280,000 barrels per day in 2023. These new levels reflect the importance of this pipeline and supplying heavy crude to Whiting Refinery from Canada while providing flexibility to BP to optimize supply.

We continue to expect BP2 to be a major source of advantaged heavy crude supplied to Whiting. Second, Diamondback there are two new minimum volume commitment arrangements on this pipeline. The first is with BP for 10,000 barrels per day with a term of three years. The second, also with BP is for 23,000 barrels per day and was renewed earlier this year in June for a one-year term. In addition, we have a dedication agreement with a third-party which was also renewed earlier this year in June for a one-year term. While this dedication agreement does not have MVCs, it offer potential volume upside on this pipeline. And although we're moving to a lower MVC level on this pipeline compared to the previous arrangement, Whiting is capable of lending diluent into the gasoline pool which may result in higher refined products volume. This could potentially provide volume upside for the refined products supply pipelines from Whiting including River Rouge.

Third, River Rouge the new minimum volume commitment will be 60,000 barrels per day for each year over the three-year term. This is unchanged from the MVC level in 2020. River Rouge is an important outlet for refined products produced by Whiting. We have consistently seen quarterly throughput on this pipeline at or above the MVC levels since IPO. With the exception of the second quarter 2020 due to COVID-19 impacts on demand. We expect high utilization of this pipeline to continue subject to broader market demand conditions being impacted by COVID-19.

In summary, the new multi-year MVC arrangements underpinned already stable reliable cash flows from a high quality portfolio of assets for the next three years assets that continue to perform well. Before handing over to Craig, let me finish by sharing some thoughts on the strategy that BP outlined in August 4 and in more detail in September. BP strategy includes creating a more resilient and focused hydrocarbon portfolio. It is a key contributor to BP's transition from international oil company to an integrated energy company. So what does this mean for the Whiting Refinery and production from offshore Gulf of Mexico in the context of resilient and focused hydrocarbon portfolio?

First, Whiting is considered an advantage refinery. It has access to and the capability to process an advantage feedstock namely Canadian heavy crude oil as well as a local advantage to Midwest demand centers. In addition, reliability at Whiting Refinery as measured by solemn unavailability has improved from 94% in 2014 to more than 96% for three consecutive years since 2017. This combination of feedstock advantage, location advantage and track record of high reliability as shown on the left side of this slide makes Whiting Refinery a good fit with BP strategy of having an advantaged refining portfolio.

Second, Gulf of Mexico production is a high margin region for BP. A region BP highlight is having absolute liquids volume growth in its portfolio over the period to 2025. It's a region with significant opportunities for infrastructure led growth with future tie back and infill drilling opportunities having a sort of fast payback, high return project economics that BP is prioritizing in its capital allocation.

The right-hand side of this slide contains an extract from the materials that BP presented during its strategy presentation. It shows the major projects that BP is already progressing in Gulf of Mexico as well as hopper of oil investment opportunities around BP's existing operated hubs that are within the catchment area of our offshore pipelines. And BP continues to explore around its existing hubs in Gulf of Mexico and has continued to participate in licensing rounds.

We also see other offshore producers in the Gulf of Mexico actively progressing major projects covering facilities, wells and pipelines and continuing to explore in the region. One example is the expansion of the Marsh pipeline that Shell Midstream partners is progressing. Gulf of Mexico offshore is a highly attractive region for many producers and while the timing of bringing some new major projects online has slowed as a result of COVID-19, they still represent opportunities that when developed fall within the catchment area of our offshore pipeline assets.

Before I hand over to Craig, a few comments on the recent announcement of changes to several officer and director positions of BPMP. BP previously announced that it would reinvent itself to become a more focused, integrated energy company to deliver its new ambition and strategy. As part of BP's reorganization, Brian Smith, Gerald Maret and Craig Coburn have decided to retire. I would like to personally thank Brian, Gerald and Craig for all they have done for the General Partner and BPMP.

Brian retired from the BPMP board on October 8, 2020 and was succeeded by Jack Collins. Gerald will be retiring on December 31, 2020 and will be handing over Chief Operating Officer responsibilities to David Kurt. Craig will be retiring at the end of February 2021 and Jack is expected to succeed Craig as Chief Financial Officer at such time. Both David and Jack will work with Gerald and Craig respectively between now and their retirement dates to ensure an orderly transition. We look forward to working with David and Jack. They both bring extensive experience and capabilities that will contribute to maintaining the governance, operating and financial stewardship of the partnership.

With that, I'll hand over to Craig.

Craig W. Coburn -- Chief Financial Officer

Thanks Rip. Good morning, everyone. Starting with operational results, total pipeline gross throughput was approximately 1.5 million barrels of oil equivalent per day in the third quarter around 5% lower compared to the second quarter of 2020. We had expected portfolio gross throughput to be higher this quarter compared to the second quarter. However, multiple weather events in the Gulf of Mexico during the third quarter negatively impacted throughput on our offshore pipeline.

Hurricanes Delta and Zeta in October are also expected to impact fourth quarter throughput on the offshore pipelines. Gross throughput on our offshore pipelines was around 8% lower compared to the second quarter reflecting the impacts of Hurricane Sally and Laura, which resulted in various offshore producers temporarily shutting it. We estimate quarterly gross impact on throughput within the range of 150,000 barrels to 200,000 barrels of oil equivalent per day.

This negative impact was partially offset by higher production from some offshore producers driven by the ramp up of production from new major projects and wells. Gross throughput on our onshore pipelines was around 2% higher compared to the second quarter, primarily driven by higher throughput on River Rouge. This reflected the recovery in refined products demand during the quarter with demand returning to levels lasting in the first quarter of 2020 before the full effects of the pandemic on product demand result. This was partially offset by lower volumes on BP2 due to refinery supply optimization by BP.

Net income attributable to the partnership for the third quarter was $45.3 million, 12% higher than the second quarter of 2020 reflecting higher throughput on River Rouge as previously mentioned, higher fixed loss allowance revenue in relation to BP2 due to a higher realized oil price in the quarter, lower pipeline maintenance expenses and higher income from equity method investments primarily due to the demand recovery in the quarter favorably impacting the contributions from KM Phoenix joint venture. These favorable impacts were partially offset by the absence of first quarter 2020 deficiency revenue recognized in the second quarter.

Adjusted EBITDA attributable to the partnership for the third quarter was $46.5 million. This was 2% lower compared with the second quarter of 2020, primarily due to lower distributions from offshore pipeline joint ventures. Cash available for distribution for the third quarter was $42.8 million, only slightly lower than the second quarter of 2020. The Board of Directors of our general partner declared a third quarter distribution of $0.3475 per unit consistent with the distribution level of the second quarter 2020.

Distribution coverage ratio for the third quarter was 1.14, in line with our target range of 1.1 to 1.2 times.

Turning now to guidance. Our full-year 2020 guidance is adjusted EBITDA of $190 million to $200 million and cash available for distribution of $180 million to $190 million. This guidance included an allowance for weather in the Gulf of Mexico during the hurricane season based on a statistical normal year. As Rip mentioned, it's been a historic year in terms of the number of named storms in a single season. Many of these storms requiring offshore producers to temporarily shut in production for safety reasons.

To give you a sense of how out of normal this year has been, hurricane impacts to cash available for distribution were around $2 million or less in each of 2017, 2018 and 2019.

During the third quarter the impact of hurricanes to our cash available for distribution was in the range of $4 million to $5 million. Notwithstanding this elevated impact, at the end of the third quarter we still expected to achieve the lower end of our guided ranges for the full year, adjusted EBITDA and cash available for distribution underpinned by otherwise resilient asset performance through the first nine months of the year.

In October, we experienced two additional hurricanes in the Gulf of Mexico. Hurricanes Delta and Zeta which again required offshore producers to temporarily shut in production. The Atlantic hurricane season hasn't quite finished yet either, officially runs until November 30. While we're hoping for normal weather through the Gulf for the remainder of the year, any future weather events have not been included in our guidance.

In addition, potential curtailment of production as a result of outages on the Cameron Highway Oil Pipeline System or CHOPS in the fourth quarter as well as any further delays to offshore project construction or drilling programs have not been included in our guidance.

We are holding to our previous full-year guidance for adjusted EBITDA and cash available for distribution. However we're still evaluating the impacts of these fourth quarter events, which may see actual full-year results being right at the low end margin or slightly below our guided ranges. We intend to hold our current distribution levels flat through remainder of 2020 though, which we would expect to deliver unitholders 5% distribution growth of the full-year 2019.

We expect our full-year 2020 distribution coverage ratio to be at the upper end of our target range of 1.1 to 1.2 times after factoring a weather impact through the end of the third quarter. We are building cash in 2020. We've grown cash on hand by around $25 million through the end of September 2020 compared to the cash balance at the end of 2019. This enables future organic growth projects to be funded once approved.

Looking ahead to the fourth quarter, we expect pipeline gross throughput to be higher than the third quarter largely reflecting higher throughput on offshore pipelines due to the absence of adverse weather in the Gulf of Mexico at levels we saw in the third quarter, higher throughput on BP2 due to expected higher refinery utilization and supply optimization benefiting from the widening of WTI, WTS differentials as Canadian production increases.

Adjusted EBITDA is forecasted to be broadly flat compared to the third quarter due to higher distributions from offshore pipeline joint ventures consistent with the expected recovery in offshore pipeline throughput. This is expected to be offset by increased maintenance spend associated with pipeline inspections and repairs forecasted for the onshore assets in the fourth quarter.

Cash available for distribution is expected to be higher than the third quarter reflecting the recognition of cash associated with the portion of River Rouge's volumes above the minimum volume commitment for the full-year in the fourth quarter. We expect to provide our 2021 guidance with our fourth quarter results.

With that, I'll hand back to Rip.

Robert P. Zinsmeister -- Chief Executive Officer

Thanks Craig. I'll wrap up with a few final messages. It's been another challenging quarter but we remained focused on what we can control. First, maintaining safe operations and second, the performance of our assets. Our focus on these areas ultimately begins in service of maintaining the financial strength of the partnership. We have a high quality asset portfolio that continues to perform well. This underpins our expectation and confidence to hold the current distribution level flat to the remainder of 2020, while maintaining a robust distribution coverage ratio, a great outcome in a challenging year and our balance sheet and liquidity remains strong.

Thanks for listening to our call today. Our Investor Relations team are available to speak with you further outside of this results call. And with that, we'll now take your questions.

Questions and Answers:


[Operator Instructions] Your first question today comes from Gabe Moreen from Mizuho. Please go ahead with your question.

Gabriel Moreen -- Mizuho -- Analyst

Good morning, everyone. Two part question on the Gulf first. Can you maybe talk about some of the fields on ramp ups there, whether it's Atlantis or Appomattox kind of where things are in the trajectory? And then I noticed some language in the release about the CHOPS pipeline being down and the impact is on potential shut-in? Is that something you're potentially thinking may happen or is it another work around is it -- that you don't think that's going to happen?

Robert P. Zinsmeister -- Chief Executive Officer

Good morning, Gabe. This is Rip. Can you hear me OK?

Gabriel Moreen -- Mizuho -- Analyst

I can.

Robert P. Zinsmeister -- Chief Executive Officer

Okay, so your question was two parts, first was kind of offshore activity set and second was offshore delivery, if I got it right. It's probably fair to say, offshore activity is lagging. It's kind of a confluence of COVID actually affecting both back office work, like the engineering, support to deliver major projects, as well as COVID impacts to drilling cruise. So we've seen both. So I'm expecting a delay in drilling wedges and projects slippage likely out of 2021 into 2022. BP announced the Atlantis start-up that's basically on schedule. Shell, I think is, let's just say notionally, one well behind on Appomattox. But honestly, those kind of questions should be directed to Shell, not me. Okay? We have a very good relationship with Shell and want to keep it that way. And I think BP has also talked about Mad Dog 2 notional slippage. These slippages feel like half years, not major slippage, but slippage is slippage. Okay?

And in terms of CHOPS, it had some upset circumstances related to one of the hurricanes. A workaround was put in effect at that point in time and there was no impact to the business. So it's fair to say that while we found a way to work around at once, lawyers always like want to put a cautionary statement out there when there are things outside our control that could affect our financials. So you should probably see it in that light.

Gabriel Moreen -- Mizuho -- Analyst

Understood. Thanks, Rip. And then second question is bit broader with your cash position, net debt being very strong, just wondering what organic and inorganic opportunities you may be looking at for '21 to deploy some of that cash and otherwise balance sheet capacity?

Robert P. Zinsmeister -- Chief Executive Officer

Okay. So we have a hopper of projects. For competitive, for proprietary reasons, we don't talk about bespoke projects that's kind of unwise in our business. The actual capex for the entire hopper as it stands right now is substantially less than our cash on hand in many respects. Double-edged sword, right? Good news is you've got plenty of cash on hand. We've probably like more projects, all else being equal. We've reviewed all of them and I can say that the IRRs on every project is higher than our yield. So while I don't like the yield at the moment, it would still bias as to invest in organic projects as oppose to doing something else with cash on hand as our first priority. Okay?

Gabriel Moreen -- Mizuho -- Analyst

Thanks, Rip. And then maybe if I could press you a little bit on inorganic. Is that something you're still evaluating and seeing any things come across your desk?

Robert P. Zinsmeister -- Chief Executive Officer

The investment universe out there is -- well, let's put it this way, it's easier for us to think about inorganic bolt-ons and organic capex as opposed to anything substantive and large. Okay? We're not in the M&A game to increase the size of the firm by 50%. It's a tough time in the energy world. Our performance is rock solid. I think we're in a generally enviable position as a firm and where we're at as BP Midstream. You have your own coverage universe, you can draw your own conclusions. I'll leave at that, Gabe.

Gabriel Moreen -- Mizuho -- Analyst

Thanks, Rip. Appreciate the insights.


And our next question comes from Theresa Chen from Barclays. Please go ahead with your question.

Theresa Chen -- Barclays -- Analyst

Good morning. Rip, I, first wanted to ask about the step down on MVCs overtime over the next three-year period in BP2. Is that reflective of your earlier comments about supply optimization for Whiting as in rerouting the WCS? Or do you think that it will consume less WCS somehow as time goes on although it would -- that the differential would likely widen from here? Any thoughts around that?

Robert P. Zinsmeister -- Chief Executive Officer

Good morning, Theresa. Thanks for the question. It's probably fair to say to be a bit cautious to read too much into the drivers of the MVC step down. And if I could start from the top and kind of do a deductive reasoning approach to the rationale, first, the machine itself can process more than 320 kbd heavy crude. Okay? Second, the optimization had that we experienced in 3Q had everything to do with doing some maintenance on the heavy-end of the refinery. So it was actually we had less heavy demand because we had units that we're working on as opposed to chasing sweet crude versus heavy. There were attractive sweet barrels available, and the supply organization, of course, access those, but it was really more about working on the heavy end of the kit.

And then the MVC has more to do with just accessing the crude. BP2 can transport substantially more than even refinery nameplate. So it's not a problem of our pipes being unable to get heavy to Whiting. It is not an issue of Whiting being unable to process more than the MVC, it's access. And even in the most recent month, we were seeing 20%-plus apportionment.

So the challenge that we found is when the differentials are attractive, too many players in the market all want access to the same crude and we've struggled to get it. And then you pivot into Enbridge Line 3 and contract carriage, we think we're comfortable playing at space with a certain fixed component and the trader is going to chase opportunistically. Topping above a fixed component, that has been decided as yet, but that's why the MVC steps down in the later years.

Theresa Chen -- Barclays -- Analyst

Understood. And longer term, when we think about the points and availability of egress out of Western Canada and if XL does not move forward but Trans Mountain expansion does and the marginal price setting point for that barrel is Asia, how does that affect the competitive dynamics of WCS being consumed in the Midcon and Whiting particular?

Robert P. Zinsmeister -- Chief Executive Officer

Okay. Needless to say that's probably a very complicated question. I would say we see more intensity over refineries chasing potentially fewer barrels. I think at least in terms of from an access standpoint, when you look at the Canadian landscape, there are periods when people think, if every pipe got built, we're going to be over-piped. If only two pipes got built and the Canadian producers continue on their trajectory, then rail is a natural solution and this will remain wide. The last I looked, it looks like Canadian production is pretty much going to be back to early 2019 -- excuse me, late 2019 levels by late 2020. Next year, we think there going to be more or less on trend. So I think we're going to see potential apportionment again. And I think the world will be competing for those barrels. TMX probably isn't that big of a problem in the round. But it has everything to do with Canadian supply, right?

Theresa Chen -- Barclays -- Analyst

Sure. Okay. That's very helpful. And lastly, if I can ask about the offshore outlook in light of many moving pieces on the legislative or political front. Is any impact -- what if any impact do you anticipate if there is a federal lease ban put in place, if the permitting process is slower? Can you offer any color or thoughts around that?

Robert P. Zinsmeister -- Chief Executive Officer

This probably falls more in the area of speculation and judgment and wouldn't want to be labeled as such. First, maybe offshore game is a long cycle game, right? So I think if you look at Appomattox as an example, the latest significantly large field put into production. I think it was discovered in circa 2009, so it was a 10-year cycle time from discovery to even the very front-end of first production. So if they stop leasing next year, it has a 10-year implication on our business, that far forward. So in the near term, no impact whatsoever. I think there is a federal lease sales scheduled in the next two weeks, BP is a registered bidder. Okay? Now, whether the leases are awarded are a different topic, right? And actually I'm not sure we know who's won the election yet.

But -- and then on the permitting front, kind of living the space of contract is a contract, so all of the industry players could pay good money, pay royalties and will prosecute their business accordingly. It's fair to say that BP like all large integrated international oil companies, we have constructive relationships with governments all around the world, and that will certainly include whatever administration comes in.

Theresa Chen -- Barclays -- Analyst

Thank you very much.


[Operator Instructions] Our next question comes from Derek Walker from Bank of America.

Derek Walker -- Bank of America Merrill Lynch -- Analyst

Hey, good morning, guys. Maybe if you can just...

Robert P. Zinsmeister -- Chief Executive Officer

By the way, Derek, I don't even know your question is, but I think I'm going to hand it to Craig to get him in the game. So I'll wake up my CFO with that warning.

Derek Walker -- Bank of America Merrill Lynch -- Analyst

Sure. Fair enough.

Craig W. Coburn -- Chief Financial Officer

Rip, you're doing a [Technical Issues] job. I don't know why you need to hand it off, but anyway, go ahead.

Derek Walker -- Bank of America Merrill Lynch -- Analyst

He's already retired, right. So there you go. Just a real quick one here. With BP2 volumes at [Indecipherable] for the quarter and you reset the MVC at 300 [Phonetic], just given the dynamics that you see, do you feel like you can get either at or above those levels going into next year? I'm just trying to understand sort of how you guys are thinking about the dynamics near term.

Robert P. Zinsmeister -- Chief Executive Officer


Craig W. Coburn -- Chief Financial Officer

Yeah. You got it, Rip. Go ahead.

Robert P. Zinsmeister -- Chief Executive Officer

Okay. Go ahead, Craig.

Craig W. Coburn -- Chief Financial Officer

I was going to say, we're going to be careful about giving 2021 guidance, Derek. But I would say, yeah, I think that we feel good about that 300 range. With the caveats that Rip talked about, in the world of dips, when the dips widen, people go after the Canadian crude and it kind of results in the apportionment game again, right? But we do expect that the Canadian production as Rip said is going to come back toward the end of this year and into 2021, there'll be more available. The dips we hope will widen and will be in the market to go after that.

So I think when we set these, I think, again coming back to sort of the text we had in the beginning of the call, you need to think about these as good downside protection to the partnership and not necessarily indicative over the forecast and things that we'll be talking about going forward. But that's -- it's going to [Indecipherable]. I mean we're very pleased with the fact that we've got this three-year deal now with BP and we have this underpinning our cash flows going forward.

Derek Walker -- Bank of America Merrill Lynch -- Analyst

Appreciate that. And maybe a little higher level, just on some of the -- was there a lot of back and forth between you and BP and sort of the legacy investor preference for the multi-year extension, but was there a lot of back and forth around how to think about either commodity prices, demand versus obviously a slower factors that went into it? But just trying to get a feel for how the discussions actually played out over the last couple of months?

Robert P. Zinsmeister -- Chief Executive Officer

I'll take the lead on that one. Actually I'll supplement what Craig had to say about the 2021. So the first point would be the machine can process more than 320 in terms of heavy and it is the most attractive crude that we want to process. The question is, can you get it? We have had historically weeks where we've processed more than 330, 340. The challenge, of course is, can you do that consistently month in, month out? The reality has been no. And opportunistically, what tends to happen as you nominate crude and then some other player has an upset condition at their refinery and then there is incremental crude available that you're buying from them that they have nominated. That's how you get surplus crude above, say, 310, 320 occasionally. But you can't run your business on a planning basis, that's going to happen month in, month out. So that's the color, Derek.

And then on the MVCs, we IPO the business in 2017. The landscape on what pipes were going to be built when has changed quite frequently, obviously, given Presidential permits, legal challenges, continual legal challenges, expressed statements by candidates about KXL, and here we sit, not quite sure what the election result is. It's fair to say the ambiguity about Line 3 and KXL has changed or shaped our views, quarter in, quarter out and we've talked about this back and forth. At one point, what I might characterize is kicking the can down the road of just doing a single year because there's too much uncertainty, was a possibility. But we as BP Midstream weren't comfortable with that, nor was our sponsor really advocating it as the desired outcome. So this is the compromise we've reached. And clearly by my testimony, we still see ample ambiguity in the future of what's really going to happen.

Derek Walker -- Bank of America Merrill Lynch -- Analyst

Understood. And then maybe I'll just ask one last one. [Indecipherable] to the gasoline supply, just how you kind of think about that dynamic over the near term?

Robert P. Zinsmeister -- Chief Executive Officer

Diluents, a bit of a surprising market, it's got too many moving points, right? So you've got Canadian condensate supply, which is local, the relative attractiveness is selling that condensate to someone else versus using it as diluent. And then the recycle game of shipping diluent from far south, which some people do, much further south than us. Our bias is to make gasoline out of it when we can. But when we're in such a challenging market as the one we're in and the Canadian producers actually want diluent, we see Q4 is being a bit of soft on diluent from a planning basis, but we must say we probably had a 100% increase in diluent demand in two weeks. It's just a volatile market at the moment. So our bias is to make gasoline quite frankly, which is why the MVC has been stepped down.

Derek Walker -- Bank of America Merrill Lynch -- Analyst

Got it. Appreciate that. Look forward to working with the new officers. Craig, congrats on your retirement and good luck on your next endeavors. It was a pleasure working with you. Thanks, guys.

Craig W. Coburn -- Chief Financial Officer

Thank you, Derek.

Robert P. Zinsmeister -- Chief Executive Officer

Thanks, Derek.


[Operator Closing Remarks]

Duration: 44 minutes

Call participants:

Brian Sullivan -- Vice president, investor relations

Robert P. Zinsmeister -- Chief Executive Officer

Craig W. Coburn -- Chief Financial Officer

Gabriel Moreen -- Mizuho -- Analyst

Theresa Chen -- Barclays -- Analyst

Derek Walker -- Bank of America Merrill Lynch -- Analyst

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