Q4 2020 Magellan Midstream Partners LP Earnings Call
Okay.
Okay.
Greetings, everyone and welcome to the fourth quarter of 2020 earnings call. During the presentation. All participants will be in listen only mode. Afterwards, we will have a question and answer session at that time. If you have a question. Please press the one followed by the four on your telephone.
Any time, you need to reach an operator, please press star zero.
As a reminder, this conference is being recorded today Tuesday February strike into 2021.
Now I'd like to turn the call over to Mike Mears Chief Executive Officer. Please go ahead.
Hello, and thank you for joining us today for our fourth quarter earnings call.
Before we get started I must remind you that management will be making forward looking statements as defined by the SEC.
These statements are based on our current judgments regarding the factors that could impact the future performance of Magellan, but actual outcomes could be materially different you share.
To review the risk factors and other information discussed in our filings with the SEC and form your own opinions about magellan's future performance.
<unk> closed on 2020 with solid financial results, especially considering the continued negative impact of the pandemic is having on petroleum product demand and commodity prices, our fourth quarter results exceeded our expectations, primarily due to the incremental benefit from higher than expected shipments and average tariff rates.
Our refined products pipeline system, while we.
We are not yet back to pre pandemic levels of demand progress continues to be made.
Our CFO, Jeff Holman will now review, our fourth quarter financial results versus the year ago period.
I'll be back to discuss our outlook for 2021, and the corporate conversion analysis posted to our website. This morning before answering your questions.
Thanks, Mike first on you mentioned that as usual well be making references to some non-GAAP financial metrics, including operating margin and distributable cash flow or DCF.
We've included exhibits to our earnings release that reconcile these metrics to their nearest GAAP measures.
As we reported earlier this morning on net income from first quarter 2020 was $184 million.
Compared to $286 million fourth COVID-19.
Adjusted earnings per unit for the quarter, which excludes the impact of commodity related mark to market adjustments.
With 94, which as Mike pointed out was higher than based on guidance. We provided last fall with stronger than expected performance on the southern portion of our refined product system being the largest single driver on the outperformance versus our expectations as a result of both higher volumes and higher average rates.
<unk> DCF for the quarter was about $270 million, 25% lower than the fourth quarter and 19.
Consistent with our commentary since the outbreak independent on.
The lower commodity price environment, and other pandemic related factors continue to negatively impact our results.
Full year 2020, DCF was $1 <unk> 4 billion.
<unk> distribution coverage ratio for the year of one from one three times.
Paul This is of course below our original 2020 guidance of about two five times and our long stated target of one two times. Nevertheless, we believe this result underscores the resilience of our business model and the financial strength from our company.
Even in a year that presented us with a simply unprecedented decline in refined products demand at the same time that we saw a severe decline in commodity prices, we are able to generate more than $120 million from excess cash.
You can find a detailed description of the quarter over quarter variances from the earnings release, we issued this morning. So I plan to just touch on a few highlights on overall feeds of our quarterly performance.
<unk> generated $250 million from operating margin in fourth quarter, 2020 down approximately 16% versus the 2019 period.
While volumes continue to grind higher from the lows we saw during the second quarter from 20 Gasolines aviation remained impacted by the effects of the pandemic, particularly in some of the metropolitan areas. We serve while lower drilling activity continues to negatively impact distillate volumes on our system.
Total refined products volumes across all of our system, we're about 5% lower than the 2019 period.
The figure includes the impact of the more volatile South Texas portion of our system, which as we've frequently noted on previous calls moving significantly lower rates on our average tariff and are somewhat more volatile growth in volumes and product mix than the rest of our system.
Excluding the impact of South, Texas volumes around 6% per the quarter versus 2019 levels and more specifically gasoline volumes were down 9%. This was actually up by 4% in aviation fuel was down 33%.
Please note that while we had previously broken on a product greenhouses versus 2019 between base and growth volumes. These figures by product that I just mentioned combined both our base business and the impact of our recently completed growth projects.
As you'll recall those projects flow backs by new customer commitments to drive volume to our system in.
In the current environment in which gasoline demand remained significantly impacted by the impacts of the pandemic and distillate demand is still recovering from reduced rig counts the effect that those contracts in some cases is that a portion of the base demand served by the expanded assets has been satisfied by customers, meaning those new amendments such that growth volumes.
Generally tracking our expectations well, what we would characterize as our base volumes have underperformed more than market conditions would otherwise lead us to expect.
Of course as demand continues to recover we expect total volumes on a standard assets to meet the expectations. We had when we initially undertook the expansion.
And we saw positive signs of that recovery in fourth quarter of 2020, especially in distillate volumes, but the timing and pace of that recovery remain uncertain and will depend on both general economic conditions and Permian drilling activity.
In addition, a portion of the amendments to our east Houston to Hearne expansion only take effect once a committed customer a complete the connection to their own assets and that customers construction of that connection has been delayed by COVID-19 related issues. We currently forecast that construction to be complete by mid 2021.
Having discussed the overall volume picture I'll note that higher average transportation rates, partially offset the volume declines we experience due primarily to our 55% average tariff increase in mid 2020.
Beyond transportation revenue, our fourth quarter refined products financial results also declined versus 2019 due to lower profitability from our commodity related activities as margins on our gas liquids blending business declined from about 57.
In 2019 to 28 in fourth quarter 2020 with.
But the volumes on that business also being negatively affected by fewer economic blending opportunities.
Finally, the sale of three marine terminals in early 2020 also reduced the contribution from the refining segment, while lower operating expenses, partially offset the decline.
With regards to our crude oil business fourth quarter operating margin was approximately $110 million.
Around 28% from the fourth quarter of 2019.
During the quarter the crude oil per month was mainly impacted by lower average tariff rates as well as by a decrease in volume shipped vol.
Volumes on longhorn averaged about 250000 barrels per day compared to 275, a day in the fourth quarter of 2019.
While our customers continue to ship at or near their commitment levels. You may recall that 75000 barrels per day of loans and commitments expired at the end of the third quarter, while the resulting decrease from third party shipments was largely offset by volume shortly to our affiliate marketing activities.
Margin, we realized on those activities is more reflective of the prevailing differential between the Permian basin on the Houston.
Which is currently well below the tariffs we had an early on the recently expired contracts.
As a result, our average realized rate per barrel declined during the period consistent with the expectations. We had when we provided both our full year and fourth quarter of 2020 guidance.
Volumes on our Houston distribution system also declined during the quarter, partly due just to a change in the way customers contract for access to receive joint venture terminal as we've discussed on previous calls as a reminder, this change results in lower reported transportation volumes on our distribution system, but that reduction is offset by higher <unk>.
Permanently revenue on the related new terminal transfer fee.
Although we sometimes see volatility in our HD volume for two quarters keep in mind that those volumes move at significantly lower rates to low longer haul long haul shipments, which means that there are impacts on our reported volumes and average rate is much greater and theyre impasse impact on the actual revenue.
Crude oil segment results also declined between periods as a result of lower contributions from our bridge Sino foreign joint ventures.
<unk> volume averaged approximately 350000 barrels per day in the fourth quarter 2020, compared to approximately 425, a day in 2019, driven by decreased uncommitted shipments, which again were a function of the currently low Permian to Houston differential.
Saddle Horn volumes also declined somewhat from approximately 180000 barrels per day in the fourth quarter 2019 to approximately 165 per day. This quarter. However, the largest driver on the lower contribution from settlement was our sale of a 10% interest in first quarter 2020.
On a corporate level you may have noticed that G&A expense increased in the fourth quarter of 2020 that was primarily due to severance payments associated with an early retirement program as well as higher incentive comp accruals.
For the full year G&A was down about 12%, primarily due to lower overall incentive comp expense for the year as a result of the impact of the pandemic and commodity prices on our full year 2020 results.
Now I have just a few brief comments on capital allocation balance sheet metrics on liquidity first we repurchased nearly 600000 units during fourth quarter 2020 spending $25 million.
This brings the total number of units repurchase of five 6 million at a total cost of $277 million.
This results in a total return on capital to unitholders, including both distributions and share repurchases of nearly $1 $2 billion in 2020.
I'll note that while we clearly see buybacks as a viable use of capital in the current environment ultimately as we've consistently noted in the past the timing price and volume of any unit repurchases will depend on a number of factors, including on our expected expansion capital spending excess cash available balance sheet metrics legal on.
Regulatory requirements as well as market conditions, and the trading price of our equity.
At year end on the face value of our long term debt outstanding was $5 billion.
The weighted average interest rate on net debt of about 4% we.
We had no outstanding commercial paper borrowings with $30 million of cash on hand, and no drawings on our $1 billion credit facility and our next bond maturity isn't until 2025, but the average life to maturity of our bond portfolio at year end at about 20 years.
Our leverage ratio remained strong at three five times for compliance purposes at the end of 2020, while below our long stated limit of four times.
I will point out however that of course, our leverage ratio as calculated on a trailing four quarter basis, so as stronger pre pandemic quarters. The last of which was really first quarter 2020 have been rolling out that the trailing four quarters calculation and have been replaced by quarters that were impacted by the pandemic our leverage ratio has crept up.
And we will continue to do so until those lower EBITDA quarters themselves roll off as the economy recovers and the result of an increase in EBITDA results on our leverage ratio coming back down again.
With that I'll turn the call back over to Mike to discuss our guidance for 'twenty, one as well as a few highlights of the corporate conversion analysis, we published this morning.
Thanks, Jeff.
Turning to our outlook for the new year. If this morning, we announced DCF guidance of 1.02 billion for 2021.
We recognize this number is a bit lower than the street was expecting and as usual I'll walk through the key assumptions, we have used to build our 'twenty, one projections and it may shed some light on where the differences maybe in the key assumptions.
Starting with our refined products segment, our guidance assumes that refined products demand will continue to increase during 2021, especially during the first half of the year, it's vaccines become more readily available and travel economic activity and drilling rebound as the nation continues to open up we further expect to benefit from it.
Additional volume growth from our recent expansion projects within the state of Texas.
Background on all of this and we expect refined product shipments to increase about 13% compared to 2020 results driven by 16% higher gasoline, 8% higher distillate and 20% higher aviation fuel demand.
To be clear. These volume projections include a partial recovery of demand lost during the pandemic as well as a material contribution from the continued ramp up in volumes associated with our new pipelines that were put into service in 2019 and 2020.
We also thought it might be helpful to compare our forecast it gets pre COVID-19 demand levels as well compared to 2019 results. We expect our 2021 refined product shipments increased about 3% overall driven by improved volumes from our Texas expansion projects, partially offset by continued lower aviation.
Fuel demand.
For sensitivity around our assumptions.
We ballpark estimate that on average every 1% difference in total refined products transportation volumes is about $10 million in revenue on an annual basis.
In addition to volume the average tariff rate for five products pipeline system is an important component to model this segment.
You are probably aware the FERC has now finalized the new index methodology to be used for the next five years beginning July one 2021.
The new FERC index is based on the change in the producer price index, plus 0.7% to 8%.
As you May know the preliminary change in PPI for 2020 is a negative one 3%.
Which resulted in index rate adjustment of negative <unk>, 5% for the 40% of our markets that follow the index.
However, the remaining 60% of our refining markets are either intrastate movements or deemed to be competitive by the FERC and are therefore, not subject to the index methodology.
We adjust rates in these markets each year closer to what we believe are actual per barrel per barrel mile cost increases are and as competitive forces allow we generally intend to increase rates in these competitive markets by 3% to 4% in mid 'twenty, one 'twenty one similar to our historical <unk>.
Growth.
Even though we expect to raise for final products tariffs on average around 2% in mid 2021, our overall rate per barrel is projected to remain relatively flat between periods.
This is because a few of our expansion projects are adding incremental volumes at rates lower than our overall average due to the shorter haul nature of the movements.
For our refined products segment, the commodity price environment is also important as it directly impacts our gas liquids blending profits.
We have almost all of our spring blending margin hedged at this point, which equates to roughly 40% of our total expected 'twenty one blending sales volume.
Considering these hedges and a mid January forward curve for the unhedged volume. We currently expect an average blending margin of 25 per gallon for 2021, which would be a historical low.
<unk> prices have been strong of late and RIN costs have also been trending higher both of which put pressure on our book blending margins.
For comparison blending margins averaged <unk> 45 per gallon during 2020, which is consistent with the five year average however, I'd like to point out there was a notable difference between margins before and after Covid.
Specifically, our spring 2020 margins were closer to <unk> 60 per gallon based on hedges put in place in late 2019, whereas the fall 2020 pricing was closer to the levels. We are seeing now.
Moving to our crude oil segment, we expect volumes on our longhorn pipeline to average 230000 barrels per day versus the 270000 barrels per day, we average in 2020 as Jeff mentioned, a portion of the long haul contracted contracts expired last fall, but we still have commitments for approximately 70.
Percentage of the pipe capacity with an average remaining life of six years.
Although we prefer third parties to move product on our pipes whenever possible. Our marketing affiliate has been stepping in to fill some of that space as market conditions allow.
As Jeff described the profitability of these marketing activities closely reflects the prevailing Permian to Houston differential and so is currently relatively low.
And as we already saw on our fourth quarter financial results. We expect the average longhorn per to be lower going forward again as a result of the contract explorations with 2021, representing the first full year impact.
Concerning our joint venture pipes, we expect shipments on Bridgetex to average around 310000 barrels per day during 2021, which is lower than the 360000 barrels a day moved in 2020 as mentioned earlier the price differential between the Permian and Houston continues to be quite low with no expected.
Improvement anytime soon making spot shipments on economic corporate customers, even with incentive rates in place.
As a reminder, bridgetex has commitments with an average remaining life of four years per approximately 80% of the pipelines capacity.
For saddle Horn, we expect to move about 200000 barrels per day during 2021, which is higher than the 170000 barrels per day transported in 2020 <unk>.
The expansion of the saddle Horn pipeline was complete at the end of 2020 as expected, adding 100000 barrels per day per new capacity of 290000 barrels per day we.
We have commitments for roughly three quarters of the full capacity with an average remaining life of six years I would expect some shippers to utilize bank credits in the near term for extra volume shipped in previous periods.
On the expense side, we've discussed in the past the Magellan kicked off that initiative over a year ago to identify cost savings and efficiency opportunities throughout the organization.
We have made significant progress to date with our 2021 guidance, including $50 million of cost savings already identified through this effort.
These savings are primarily being realized through pipeline power and drag reducing agent optimization.
<unk> process improvements across the organization and modest workforce reductions, including an early retirement program offered in late 2020.
Concerning maintenance capital, we spent nearly $100 million during 2020 and expect to spend closer to $85 million in 2021.
Although although this line item shows reduction between periods, it's more of a classification issue between capital and expense.
<unk> spent significant time and effort each year to ensure the safety and reliability of our assets and considering both capital and expense, we expect to spend approximately $225 million in total on maintenance and integrity work from 2021.
Which is very similar to our 2020 spend as you recall, both maintenance capital and expense are considered in determining distributable cash flow.
As previously indicated Magellan intends to maintain a quarterly cash distribution at the current level during 2021.
Based on our DCF guidance of 1.02 billion, we expect to generate excess cash of approximately $100 million. This year, resulting in distribution coverage of one one times for the year.
At this time, we do not intend to provide financial guidance beyond 2021.
However, we do expect annual DCF to increase over the next few years as the economy continues to improve and as the ramp on our Texas expansion projects are fully realized.
Further we are still targeting distribution coverage of at least one two times once refined products' demand and blending margins returned to more historical levels.
Magellan remains focused on delivering long term value for our investors through a disciplined combination of cash distributions equity repurchases and capital investments.
Although the incurred current environment from large scale capital investments is challenging and we generally expect a lower capital environment for the foreseeable future. We continue to look for opportunities to invest in attractive low risk project benefit magellan's future.
During 2020, we spent $355 million on expansion capital project, and we plan to spend $75 million in 2021.
On projects that are currently under construction.
Previously we had expected 2021 spending of $40 million, which has now increased slightly due to a combination of carryover spending from 2020, some projects coming in under budget and a few smaller projects being canceled as well as the addition of new projects.
We likely will add additional growth projects throughout the year, including these potential projects. We expect our actual 2021 expect expansion capital spending to be in the range of $100 million.
As mentioned last quarter current opportunities are smaller in scale, but generate very attractive returns that meet or exceed our six to eight times EBITDA multiple thresholds. For example, recently approved new projects include an expansion of our truck loading capabilities at our Cheyenne, Wyoming refined products terminal and <unk>.
<unk> butane supply transportation from our Houston area gas liquids blending activities, which are both high returning low risk opportunity.
We expect to find more of these type of bolt on projects in part due to opportunities, but dress changes and logistical patterns to satisfy demand for petroleum products and our markets consistent with our previous approach we remain a disciplined service provider and make investment decisions to meet the needs of our customers and demand.
And in the markets, we serve and we will not typically invest in speculative projects based on potential future market needs.
With regards to energy transition topics Magellan has has been an active participant in expanding renewable fuel access by providing ethanol blending capability capabilities for E. N E <unk> and E 85 at all of our gasoline terminals and handling biodiesel at a number of locations.
We are assessing additional emergency emerging renewable fuel opportunities that are associated with the expected growth in the ethanol biodiesel and renewable diesel markets and the potential adoption of biofuel mandates or low carbon fuel standards in the states, where we operate.
As always we will continue to maintain our disciplined investment approach.
Before we open the line for questions I'd like to briefly hit on the corporate conversion analysis, we've posted to our website. This morning.
The topic of C Corp, conversions continues to come up in Investor and analyst conversations and we periodically assess the potential impact of converting from a publicly traded partnership to a corporation.
Every time, we have concluded that every time, we have concluded the remaining a partnership is the best alternative for long term value creation for our investors.
And we have now shared our analysis to help investors understand our approach in that system and forming their own opinions on the subject.
We understand the view that being structured as a corporation could attract additional investor interest assuming potential inclusion in some broader startup stock market indices, but the magnitude of any resulting potential value increases not known and while the sustainability of any potential uplift in equity prices, even more and clear.
In any case, we believe the potential increase in the equity value over the long term is not sufficient to overcome the burden of future cash taxes, which are expected to be quite material over time.
We have not provided any new long term guidance in this analysis, while we have used for modeling purpose purposes is a simplistic forecast using basic assumptions for illustrative purposes.
Investors can manipulate these assumptions to their own analysis.
Based on this material, we still conclude that the corporate conversion is not warranted from Magellan at this time, but we will continue to monitor the issue, including relative valuations against other midstream companies potential developments and tax policy and investor feedback bottomed.
Bottom line is our priority remains focused on long term investor value.
That now concludes our prepared remarks, and so we can open the lineup for questions.
Thank you very much ladies and gentlemen, if you'd like to register a question. Please press. The one followed by the four on your telephone you won't hit rates III, Tom prompt to non would your request. If your question has been answered you like to withdraw. Please press. The one three once again for a questions. Please press. The one followed by the four one moment. Please for the first question.
And our first question comes from line of Jeremy Tonet from Jpmorgan. Please go ahead.
Hi, good afternoon.
Hi, Jeremy.
I just wanted to pick up on the guidance and thanks for providing the color there.
Just wondering if you might be able to kind of unpack a little bit more of the cadence of growth.
<unk> product.
Hovering over the course of 2021, just wanted to get a sense. If this is kind of back end of the year weighted or if you see it kind of more linear progression over the course of the year just wanted to see what's baked into your assumptions there.
Well, it's kind of a combination of those two it is back end weighted certainly and it is a gradual progression through through the course of the year.
I don't have actually craft book.
The chart in front of me, but it's.
I mean, it's a pretty ratable increase I think the first quarter.
By far the biggest impact and then in the second and third quarters. It ramps up fairly quickly to get closer back to normal levels at least for gasoline and distillate by the fourth quarter.
Okay.
Got it that's helpful. Thanks.
Maybe just also turning to the guidance on how you think about it in the <unk>.
<unk> blending is inherently difficult to make assumptions on as it can kind of move around that margin there.
But just curious I guess, the 25 that youre seeing right now and it looks like that's baked in to your guidance is.
Is that what you think is kind of a new paradigm for butane blending with rates, where they are or do you view. This as kind of a short term disruption in the market and there could be room for recovery in blending margins in the future.
Well you guys think that it's more likely than not that these numbers will gravitate back towards kind of a long term averages we don't really see anything in the market in a post pandemic world.
That would dramatically change that.
What's hurt the margins.
In the fourth quarter, and and really going into the spring has been the relative strength of butane prices versus gasoline prices, which one would expect too.
To widen again once gasoline demand starts to catch up.
And then the other element has been the increase in RIN prices now one could argue that RIN prices may stay elevated for some time, but I think again as gasoline demand grows again.
This is some refinery rep rationalizations already with expectations of future lower demand on gasoline.
It will widen the margin per gasoline, even further to capture some of that RIN value.
There's a number of efforts underway to increase the amount of renewables being blended into fuel and that also should put some pressure back on RIN prices to bring them down so.
Our view is that this is us.
Two things.
Related to the pandemic and the reduction in gasoline demand and it's also related to the emergence of increased RIN pricing, which I think will moderate over time as more renewable fuels, our blended into the fuel stream.
Yes.
Yes.
Got it that's helpful I'll stop there thanks.
Our next question is from Shneur <unk> UBS. Please go ahead.
Hi, good morning, or rather good afternoon, everyone.
I was wondering if you can pivot.
Pivot to the discussion around you were talking about adding potential growth projects you talked about in the last conference call about how some of the refinery shutdowns could create opportunities should we expect that for you to capitalize on those opportunities that it will always involve capital that will need to be spend.
Obviously at that point.
While that you described.
<unk> operating leverage within your existing system that will allow you to take advantage of that as well too and so we can just sort of see a natural progression upwards without having to spend capital in some instances.
Well I'd start by saying that there is a significant amount of operating leverage in our system our pipes.
In general are not operating at 100% capacity into many many markets and so.
There is operating leverage there, it's impossible to say, though.
How much capital if any would have to spend because it's very specific to which refineries reduce capacity or set out so for instance.
In Cheyenne with the refinery closure.
We're making some modest capital investments to expand the capacity.
Our terminal.
But.
That's simply so we can get more trucks across the truck rack, but the pipeline capacity can accommodate.
The GAAP that's left in the market.
No.
It's really.
Hard to answer your question I think in many cases, the capital we would need to invest if they're if they're refineries that are kind of embedded in our system or at the end of our system then.
The amount of capital will be very very modest.
But again.
We haven't done a lot of work on.
Modeling that are planning for that because.
We don't have any inside knowledge as to what refineries, you're planning to reduce capacity or expand I mean, we'll know and you know and.
And so we don't spend a lot of time planning for all we don't know yet, but we can react pretty quickly if that happens.
That makes perfect sense. Thank you for that.
Maybe just pivoting back to guidance expectations for this year.
I was wondering if you can say I know it's early in the year at this point right now, but sort of how you're tracking versus your first quarter forecast.
And then if you could also provide to US you sort of went quickly to the prepared remarks, but if you can provide to us volumetric we were.
Where you see 21 versus 2019 on an apples to apples basis sort of excluding the growth projects.
Kind of curious on how youre thinking about that.
Well to answer your first question I mean, what we're seeing year to date in January is is consistent with our expectations.
Which is not surprising since we're giving the guidance here at the end of January but.
But we're pleased with the trajectory that the refined product demand is in.
In the markets we serve on the second part of your question I don't have that handy.
I think the <unk>.
Number is 3%.
Overall, but I don't have the breakdown in front of me on.
And maybe Jeff.
Well one.
One of the reasons, we don't have the number handy because as I tried to explain a little bit the.
The nature of that analysis is pretty complicated.
The majority of our growth projects, where those Texas projects that came with good contracts behind us.
On the assets that were being expanded had been on allocation per years.
Some of the existing business was committed and some of it wasn't.
With the pandemic and the drop in drilling which you saw was in those those things happened just as those projects started to ramp up and some people trying to meet their commitments. So you saw some volume shifting from base to growth. So if we if we look at it that way, we get kind of a skew to answer where our growth projects look really strong.
And our base business looks really weaker than otherwise.
Otherwise you would expect based on what's happened to overall.
Demand so.
Kind of just becomes a bucket exercise when we do that.
I think on obscures more than reveals.
And so thats why the reason we've stopped providing that separate book.
Obviously, we know that that has implications clearly for the short term.
Sort of multiple on those projects those projects did not anticipate starting from the middle of the pandemic on oil price War.
We fully expect on restarting to see that.
Net demand ramping back up and so we expect that eventually.
The demand we originally did those projects to serve will be there right now which kind of.
Bucket <unk> growth.
On the basis, we don't find that productive.
No I appreciate the difficulty there maybe if I can slip one last one in.
Given the sizable capacity remaining on your buyback authorization is it fair to assume that any excess cash flow or free cash flow. After distributions that you will be directed towards buybacks or are we pivoting more to the growth side, though.
Well.
I think it's fair to say that free cash flow above our distributions and above our capital spending.
Is going to be considered for equity buybacks, it's going to be a timing issue, it's going to be a valuation issue on on the on the units whether or not we think that they are attractive.
At the point in time that we have that free cash flow.
We think the price is very attractive right now, but if you look at our forecast for the year.
We're projecting $100 billion of free cash flow above the distributions that we're also projecting $100 million of expansion capital spending so it's fairly well balanced so.
So.
To the extent that we outperformed our guidance then perhaps we'll have excess cash to pay to equity we're not planning at this point.
Increased leverage further in 2021, just to buyback equity we did some of that in 2020.
As it stands right now we don't plan to do that in 2021.
Of course, all of that is subject to change as we have new information as the year goes on but that's where we stand right now.
Alright, perfect really appreciate the color today, thank you very much.
Thank you.
And our next question is from Tristan Richardson with Suntrust. Please go ahead.
Hey, guys good afternoon.
I appreciate all the comments on the crude side just one quick one on saddle horn as it relates to being contracted at 75% can you talk about when.
Credits expire end or you expect them.
Be exhausted so you start to see customer volumes ex the affiliate reached that contracted level.
I don't have those numbers right in front of me on the credits its not a huge number.
It's really not that that's not a very big driver there is a little bit of that going on there.
But there should be complete by the first half of the year, we should be fully ramped up second half of the year.
Helpful. Thanks, Jeff and then just going back to the net.
Question around on the distillate side kind of curious what we should be looking for in terms of either rig count or <unk>.
Production recovery.
To hit the assumptions that you guys have kind of laid out.
Well I don't have a specific rig count to be totally can there is still a little bit of discovery from that because we.
We are moving barrels to Africa.
Albuquerque won't moving barrels in the Kinder Morgan going West, we're moving barrels into Mexico. So it's not just the rig count that matters for our volumes out west.
It's a very big part of it but we're working on other things as well to draw on demand in our system.
The best I can really tell you is directionally as rig count goes up as activity goes up there you will see.
Our volumes go up and those are on long haul barrels so they're typically very attractive for us for us to move.
And that's really the best I can tell you demand in Dallas is also apart on that picture because he sees to earn expansion sort of the Dallas market. So there's a number of different factors.
Fair enough. Thank you guys I appreciate very much.
Our next question is from Spiro <unk> with credit Suisse. Please go ahead.
Hey, good afternoon everybody.
Want to go back to guidance quickly if we could Mike all of those inputs make a ton of sense on in isolation, but I guess, what I'm still struggling with a bit is just big picture EBIT guidance year over year being down.
And it would seem like the 355 million spent on expansion last year recovering refined products market share.
Have been enough to offset longhorn and butane, but I guess, that's not right. So I'm. Just curious can you just elaborate a bit more on maybe on a gross margin basis, what some of the big puts and takes on the year.
Yeah.
Well.
Give me a moment.
Thank you.
Let me just kind of hit some high level buckets, if we if we look at.
Crude transportation.
And.
Blending profit year over year.
What we have in our model I can tell you for crude transportation year over year, it's about $60 million less.
<unk>.
2020 versus 2021, and Thats, just a combination of volume and rate and then the blending profits I think.
Things may be a little skewed is that our blood and the profit in 2020 in the first quarter were very strong.
And so if we compare our forecast for 2021 versus the full year of 2020, that's almost a 50 million dollar decline there. So between those two is $110 million.
Year over year decline in earnings between those two items.
Offsetting that is mostly the refined products recovery, which which is bringing us back to where we are.
Those are the biggest bucket there are some other smaller things in here.
<unk>.
I think for instance.
In the second half of the year.
Had increased storage revenue because of the contango in the market that we locked in for the second half of the year, that's not repeating.
2021, so theres some theres a handful of things in there, but those are the biggest buckets.
Okay.
Really helpful. So thanks for helping bridge that for Us Mike.
Second question you in Enterprise recently announced plans to develop a few futures.
Contract market with physical delivery into Houston can you talk about the decision to do this now and how you expect that impact volumes on the system longer term and if there's any other areas for you any PD to work together like that.
Well as you know both.
We and enterprise.
Initiated programs on different exchanges, a couple of years ago to try to build.
Pricing market.
On the futures market.
In the Houston area.
Quite frankly, it hasn't carried a lot of traction the pricing market.
Our east Houston facility or the pricing mechanism.
Has become.
<unk> adopted but the futures price the futures offering really hasnt gained traction in there.
What we believe a couple of reasons for that that we've heard from the market is that there is just a great deal of confusion and friction on how we in enterprise work together.
With <unk>.
Deliberate product crude oil to each other how a customer can transfer from one terminal to another what's the price discovery on the tariffs.
And quite frankly, it is confusing and so we think that's one of the big reasons why.
This hasnt taken off.
At the same time, there was another effort being developed with the Ags.
Contract.
Net.
Was had a lot of interest in the market.
He had been in discussions with.
The sponsors of that program.
And the market was really looking at that as maybe a solution, but the biggest impediment.
Is the lack of transparency transparency and clarity around.
We and enterprise would work together to make that happen.
So.
It became apparent to us and I believe enterprise also that if we really wanted to make something work in the Houston area. We had to work together. So that's what we've done.
We are going to agree on.
Mutual delivery points, we are going to inquiry on access to the facilities, we are going to agree on on.
On identifiable transfer rates between the terminals for physical delivery.
We're going to do all of those things to make it easy for the customers and the market to trade a futures contract in Houston between our two respective systems.
We think that that has great value to the market. We think that there is a lot of people interested in that.
We're still working on the details of that behind the scenes.
Working on an exchange to to work with to put this into place.
Theres really no capital involved for us at least to do this we've got the storage we've got the piping.
Both of our pipeline systems are connected to.
The refining complex in really all of the.
Export facilities in the area. So we think we've got a comprehensive offering.
The real value here, we think it's just long term value to make Houston the destination of choice.
And increase liquidity, which we think will in time increase the value of the storage and the utilization of the storage in the Houston market and also.
If it works the way we expect it to work is too.
Keep our respective pipelines, which go from the Permian to Houston.
As far as we can.
As as customers want to get to a market, where they have a liquid futures contract.
Similar to what you're seeing Cushing.
Thanks for the color Mike you all everybody.
Thanks.
Yes.
And our next question is from Gabe Moreen with Mizuho. Please go ahead.
Good afternoon, everyone. Just a quick two part question from me here on.
The corporate conversion potential to what extent was the income tax allowance to share with the FERC considered or not considered I think in the analysis.
I guess, that's one and then maybe it's sort of as a related follow on or maybe not related just.
These are your returns at your regulated pipelines in 2020 and latest thoughts on filing a rate case sometime in the future.
Understood.
Could you repeat the second part of the question.
Sure just latest thoughts on filing a rate case at the on the pipeline on the regulated pipelines.
Okay I got it.
Well I mean in our analysis, we really didn't take into consideration the income tax policy at the commission.
This was just clearly looking at.
What's our tax liability as a partnership today and what's our tax liability. If we converted to a C Corp. Now there is a nuance there obviously, if we converted to a seat growth.
And there was.
A tax liability on our regulated assets.
And that clearly is a factor that would impact the cost of a potential cost of service filing and which are presumably increase our rates in order to capture that causes that tax liability.
I would point out, though again that that only applies to 40% of our regs.
Regulated markets.
Which is also just a subset of our entire business. So there is there is a small benefit presumably or I should say there is a small opportunity I shouldn't say small there's a partial opportunity to recover some of that tax.
In tariffs, we didn't factor that into our equation I don't think it would change the answer because.
In the context of our entire company.
It might be lower if we were successful on that regard to get the tariffs increase to recover that.
Net be a small portion of what we projected to be our total tax liability.
On your second question.
<unk>.
Whether or not we intend to file a rate case.
We haven't made any decisions on that we will.
<unk>.
We are evaluating it.
We if you look.
<unk> looked at our historical page seven hundreds it reflects that were under earning in.
In total on our pipeline system.
And we do not believe.
In our view the current index.
Is representative of what our future cost increases per barrel mile are going to be especially if you're if you believe that refined products' demands are going to slowly decline over time.
And so we evaluated and.
And if we think that the gap between what we're earning and what we could earn or should be able to earn to recover our costs. We'll proceed with the cost of service filing, but that's the best I can say now.
It's not something that we've made a decision to do but it is something that.
We are evaluating and I can tell you. It's also something that we're preparing ourselves for we haven't we haven't been at a cost of service rate for over 20 years back when we were part of our predecessor Williams and so.
Our experience and knowledge on the details of actually executing on.
Cost of service.
Rate case is pretty dated so were we are.
Graessle. They go on internally through the process of getting ourselves up to speed and prepared.
Case, we decided to do that.
Understood. Thanks, Mike.
Next question is from Preneed soft tissue with Wells Fargo. Please go ahead.
Thanks, Good afternoon.
Seeing some new strains of Covid and I guess, the relatively slow rollout of vaccine. So I'm just I'm just wondering just from a high level. How you approach. This in the 'twenty one guidance.
And does it include any kind of cushion there for these variables.
Well youre, probably getting a little more precise into our guidance than what we actually did I mean, when we look at our when we developed our refined product guidance.
I mean, we don't have.
Better Crystal ball on the future than other people do certainly we know what our trends are we know what we're seeing within our market areas, but we also rely heavily on third party analysis. We haven't we have a handful of consultants big named consultants to know who do refined product demand projections, we have.
Government statistics on refined product demand projections, we kind of take all of those things and homogenize. It into what we think is the best guess.
So.
To the extent that those factors were built into the third party models. We've looked at then yes, but we didnt look at our at our trends and say.
We think theres going to be a material change.
In.
And these trends based on the new variance and based on the slowness of the vaccine rollout.
Because I think it's still too early to tell on the vaccine rollouts picking up steam hopefully it'll it'll.
Keep progressing and gaining momentum.
And but.
The short answer is no we haven't specifically put those variables in there yes, I'd just add we're very much on the fog of the situation I think we could all point to a different data points that you could extrapolate one way or the other that's why we've tried to continue to tell people book rule of thumb do you want to make your own assumptions a percent.
Demand.
It's about $10 million on.
On an annualized basis. So if you take it needs a little bit of cushion.
Can build that we have not built cushion per se into our into our forecast I think just on the positive side on the other thing we haven't built into our forecast as a pop in demand.
On all this pent up.
Perceived pent up desire.
Desire for people to get out and travel.
There's a number of.
People are projecting that I personally I think that that's likely going to happen that once we get to a level of stability, whether it's late spring or summer that there is a lot of pent up demand and it's probably pent up demand that wants to drive a car rather than flat on an airplane, we haven't built any of that into our models.
Okay.
Helpful. And then this is I guess.
Very high level question, but as you look at your leverage obviously, one of the better balance sheets in the space, but if we're in this scenario where energy transition occurs over the next few.
Decades, do you think it makes sense to just keep chipping away at the leverage ratio and get to an even lower.
Our run rate leverage are you comfortable with where it is in loans.
Just on the card business day.
Well, we have a lot of flexibility right now I think is what I would say it would not have any debt due till 'twenty five we've got the luxury to sort of watch things develop I think.
Kinds of things you are talking about almost generational typically they are not going to happen overnight. So.
We've got time to pivot as necessary, but we're not on a we're.
We're not currently on our path to lower leverage.
We have not sort of decided thats, our our intended course, we like where we're at.
It's consistent with what we've talked about for a long long time, but we will continue to watch that and manage as some of the.
The things that youre discussing start to get more or less firm.
Got it thanks.
And our next question is from Michael Lapides Goldman Sachs. Please go ahead.
Hey, guys. Thank you for taking my question I know this is pretty far out thinking.
Is that a conference last month, where a prominent CEO of one of the producers made a comment on oil pipeline takeaway capacity in the Permian that we're probably going to have a massive excess of supply not just for the next couple of years, but for like eight to 10 years.
Think out past three or four years maybe.
Four five contracts roll from pretty much everyone.
All included how are you.
If that Ceos scenario plays out.
Do you think about what the long long term kind of post year, three what that does to the earnings trajectory.
T. All specifically, but also kind of the industry as a whole book kind of the big Permian pipes.
So there's a lot to that question.
<unk>.
The first thing I'd say is.
One thing we're trying to do to prepare for that if it happens is to make Houston, the most desirable location for physical barrels by advancing.
Liquid futures contract with access to the water. So that's one thing we're doing.
I also.
I think it's likely if we get into that scenario.
Participants in the market will start evaluating convergence of their pipes to other services.
Can't promise that it will be done I can tell you we think about it if if the need is there to do that with our pipes.
Nowhere near making any kind of decisions on that but I think if you get into an environment where.
The margins are so low all the contracts are gone.
You have <unk>.
Excess capacity, so everyone's fighting for a barrel with extremely low tariffs, then theres going to be huge incentive for people to look for economical conversions that take capacity out of the market. So.
There's a lot of what ifs there.
I mean, the first what is the right.
I mean, it's it's.
Which I think what you get out five or six years from now I don't think anyone knows what the crude oil market might look like.
I mean at peak.
Again, if you go through a normal cycle, we can have very high prices and drilling picking back up but.
I'm, not making that as a prediction I'm, just saying that there's so many variables related to that that you really can't plan for it now and we wouldn't place where it now since we have contracts today, but as we get closer to the end of our contracts as other pipelines get closer to the end of their contract that I think those are the sorts of things people will be looking.
Yeah.
Right no that makes sense.
And then another question shifting of the refined products pipeline side. It does.
You talk about on the 60% that are negotiated rates that you know when we tried to get a 3% to 4% increase.
Around the same time, the indexation rates or kick in just curious.
Your customers responded to you given just kind of all the pain that customers have gone through this year.
And in 2020, all basically like are they willing to absorb about 3% to 4% price hike.
Well.
If youre asking about this year.
We haven't done it yet so we haven't had those discussions with our shippers, but we have over history.
Certain years raised our rates in our competitive markets.
More than we have on our index markets.
And.
Sure.
When we have discussions with our customers.
We really try to focus back on what our actual cost structure is and.
I'm not going to I'm not going to argue that they like it when we raise rates, but we've got a good basis for it.
It's an easier discussion.
Got it Okay. I was just thinking back to maybe the last really big oil downturn kind of a 2014 15 16 timeframe and trying to think about.
Were you able to pass through.
Got it to 4% increase back then and just kind of compare it to what we're all kind of go into and watching now.
Well I can't recall exactly what we did back during that.
At that time, but.
There have been there had been a number of times, where there's been a deviation between the index and our competitive markets and.
Okay.
That's caused a little disruption.
And our next question is from Derek Walker of Bank of America on please go ahead.
Good afternoon, everyone.
Hey, Michael I think in your follow on Mark you mentioned there are some smaller projects that were canceled.
Can you just discuss some of the dynamics there.
Just wanted to see what type of project for Campbell.
Well I mean, the kinds of projects you would expect would be cancelled in the kind of environment. We're in I mean, they were they were based on.
Expectations.
Patients for continued volume growth that we have down in certain markets that we now think is either longer dated.
And so well.
So that we don't need to make those investments right now I mean for example, there were some tanks that we're looking at building it from southeast terminals to accommodate incremental volume to those terminals that really isn't necessary right now.
It may not be necessary for a number of years and so it's those kinds of things.
Got it and then maybe just a quick follow up.
As far as the energy transition opportunities you mentioned, that's all blending biodiesel renewable diesel.
What you might be doing today I guess, what was one of those do you see as the largest opportunity set in.
Type of Capex or return profile do you expect from those projects.
Well, there is quite a bit of a potential legislation.
In our market areas, Minnesota, Colorado, Iowa, Missouri that are considering either.
Increasing their ethanol mandates or.
Instituting.
Biodiesel mandates.
Those create opportunities for us either by investing in blending infrastructure at the terminals, particularly for biodiesel because we don't have blending infrastructure at all of our terminals for biodiesel.
Or.
For blending for pipeline transportation.
We can blend.
A certain level of biodiesel into diesel and transported by pipe we can certainly.
Blend renewable diesel into diesel and transported by pipe.
Market for that today in our market areas, but.
States enact low carbon fuel standards and there may be a market for that.
And.
And actually and this is this is probably a little more in the development stage, but we feel like we've reached a level of comfort, where we could shift blended gasoline and ethanol in the pipe. So we're looking at some opportunities for that also.
That's helpful. That's it from me guys I appreciate the time.
Thanks, Andrew.
Our next question is from James Carreker U S capital Advisors. Please go ahead.
Hi, Thanks.
Just going back to kind of.
Views of normal refined product demand.
Any thoughts about.
You talked about DCF increases over the next several years.
How much more volume could you put on your system, if we kind of get back to that.
2019 level of demand.
I know, it's a tough question, but.
Any high level thoughts.
As your question on one of capacity or is it one of what our projections are for.
Increased volumes.
Not necessarily capacity in the sense that your pipeline is run below 100%, but just in terms of if we did get back to a scenario that was very 2019 like in terms of demand.
Much more volume would that day relative to what you've laid out for 2021.
Is it is there is there an income of 5%, 10%, 20% I guess I'm, just trying to get a sense for how much.
Of normal are we in 2021.
And then theoretically how much.
Room would there be beyond 2021.
One way to maybe answer that question one way to maybe answer that question would say when we came into 2020 I believe.
Initial possible with growth projects, we are expecting an increase in volume 10% over 19.
So now we're telling you 21, all in we expect to be 3% of our 19th so theres, probably at least 7% higher growth that you can imagine if we got back to full levels.
That is probably understanding things a little bit because it doesn't include any additional ramp on a gross projects on that.
We would have expected.
Given that 10% number so seven seven.
7% is probably a floor.
Okay. That's that's very helpful.
And then I just wanted to maybe ask about Bridgetex I think you guys talked about.
The capacity is 80% contracted but you're expecting I think 310.
<unk> thousand barrels a day of throughput I think that numbers.
Significantly lower than the 80% number am I doing the math right there.
Yes.
[laughter].
Any color on what's going on there or are you still going to be receiving.
Deficiency payments or maybe any color about how that how that's going to work.
Well, it's a little complicated we have a contract with an affiliate.
Pipeline.
And the way that contract works.
Is there is an associated basis derivative derivative agreement and when the margin gets particularly low differential gets particularly low.
On.
It reaches a point, where even if they shift we don't make anything off of it.
So.
So we just assume that it's not shipped.
If they did ship it wouldn't increase our income so.
I think that's the way to look at it.
Wouldn't increase our income in the current.
Basin basis differential environment.
Okay. So it's not related really to deficiencies as much as it is just the basis step.
Right.
And then if I could slip one more on I apologize.
But can you maybe talk a little bit about sensitivity to butane blending margins, if we get an extra.
Ken.
In the back half of the year.
What that could do to cash flow and then broadly speaking I think you've also talked about you do have some growth.
On commodity sensitivity through.
I think pipeline loss allowances and things of that nature. So.
Any color on what commodity deck.
The guidance was based on.
Well on the.
First question I think you asked about 10, let me if I could tell you.
Cheap, let's say 15 cents per gallon, we see Okay initiative. This year, we say about $35 million.
Outside.
And it would be more default in following years because this happened at a significant portion initiative of course is already fixed or hedged.
Gotcha.
Especially at the number of AD, Andy and then I think you asked about what what commodity and equity using.
Yes.
So I think his question was what would be the impact on our over in shorts. Yes. If there was an improvement in price I don't know if we have that number.
Yes.
Yes, we don't have that number handy.
Actually the number I quoted you the 15 and.
75% inclusive of.
The book tenders and blending.
Okay. Okay.
Last year, you had talked about like a $10 price in crude oil was what's maybe $30 million of DCF from so I was just wondering if we had a similar.
If we had a running crude maybe that relationship still held.
That relationship is.
It's not as.
It's more just experienced driven it's not perfect.
And if you look at what's happening right now with the elevated butane prices and the elevated RIN prices that correlation really doesn't.
Fly is well right now we don't have a new correlation for you but.
I wouldn't use that correlation at this point in time, and maybe when we get back to.
Normal kind of environment.
But right now it doesn't.
Yeah.
Okay understood thanks for that color.
Yeah.
Our next question is from Michael Cusimano, Cusimano with Heikkinen Energy Advisors. Please go ahead.
Hey, good afternoon. Thanks for all the details you all provided going.
Going back to butane blending can you talk a little bit more about the enhanced.
Activity on announced.
Previously and is that more expanding your butane access or does it have like direct margin expansion for that business.
It's pretty simple, it's direct margin expansion, because we're going to be able to pipe all the butane into the facility rather than trucking.
Okay Gotcha.
Yeah, Okay, and then also.
Do you all see any is there any.
More pressure on the butane margins from the continued growth in LPG exports that we've seen.
Well I think Thats certainly what were seeing right now is that the export demand has strengthened the price of butane.
Relative to gasoline and so that's that's one of the kantar.
Contributors to the compressed margin, we're seeing right now.
Okay. So I mean do you see that.
I guess is it the butane price coming up more than the weakness in gasoline over the last year.
<unk> margins.
It is affecting the margin certainly true recently over the last year I'm not sure I would say if we.
We went back and looked at it and say what margins are doing in April I'm not sure that was the case, but it has been the case more recently that the dramatic movement has been the butane side.
Got it alright, that's all I had thank you.
Thanks.
Yes.
On the next question is from Jim Murchie Energy income partners. Please go ahead.
Hey, guys. Thanks, it's Jim marching in Lazaro.
I wanted to go to the corporate.
Version.
Assets.
Tried to kind of.
Back into your $2 3 billion.
Present value number.
It looks like a lot of that is in the out years, you gave us those data points.
In a few of the years between now and 2040.
And if you could just kind of a ramp.
You kind of ramp up the tax liability consistent with the depreciation graph you have the <unk>.
Doesn't value over the first 10 years is only like $500 million, it's like $2 a share.
5% on market cap.
So to get to the $2 3 billion when we model this out through 2040, it looks like the terminal value of the cash.
It's something like $4 billion is like 40% of the $2 3 billion is happening more than 20 years from now that's the first question.
The second question is this is just what the corporation pays.
As Gabe gave his question was there was an offset maybe on the regulatory side, but there's an offset on the shareholder side to the shareholder tax rate goes down.
And you didn't account for that.
<unk>.
Just back of the envelope it looks like the shareholder savings is at least $1 billion on the present value using the same kind of 8% discount rate that you guys have had because really it's the <unk>.
Incremental tax for the both the company and the shareholders.
Matters.
And.
And again the present value captures these years way out in the future its assets.
I'm not sure how many shareholders look at that I mean, you are.
Your graph, allowing showed that two thirds of your shareholders suffer on the stock for five years or less.
So anyway, I just want to make sure that we understand.
Sort of the character of that present value.
Hey, how much of it is in the beyond 2040, and B that its not decremental by the savings to the limited partners.
Yes, so I think youre overstating, how much of it back in the back end of 2014, although.
Directionally correct.
Calculated on the first 10 year number, but directionally, obviously I'm using your on using your numbers I mean, I'm, just kind of assuming a smooth progression.
On the $75 million in 2027.
$187 million in 2030.
Discounted.
500 million Bucks.
Thank you maybe overstating the 24 piece of it that clearly.
It is a long term look.
No question about that as for the question on individually unit holders.
We did we have run.
<unk> when we gave just a brief little bit of color it depends on the trade it.
It depends on when the person in question planned on selling and it's a very.
Just sort of idiosyncratic answer for each unit holder, what will happen on an after tax basis.
We're paying taxes, and if we don't pay taxes, because it depends on what changes happen when they sell what they are basis, which trade group there and so the more recent trade groups.
Actually our would be less likely to benefit from a conversion from the older trade groups and by our math.
No question, but when youre going out to effectively 2090.
No.
Effectively the same vendors have turned over.
Again, 100% depends on holding periods. Those questions are all again idiosyncratic to that person. So there is no one answer that.
This trade groups case, the answer is X it depends on how long they hold.
And so it's the whole toward the longer you hold the more favorable on the partnership for us.
Say, Jim I might suggest that we need to schedule a call with you separate because we can get into the details on this a lot.
To your liking.
Discuss it but.
If that's okay with you maybe we can just schedule a call and go through it in more detail.
Sure.
Did you have something else.
Yes.
Yes, just on slide six when you guys looked at valuation.
The vast majority of S&P 500 companies do not use DCF metric right.
<unk> is much more common coming to us.
And if you look at the C Corp concrete that you guys presented here the average forward p/e ratios around 18 times, whereas the Magellan pinpointing.
So that's on that's a 75% difference just on book.
On the consensus estimates.
Did you guys consider.
Consider that sort of valuation GAAP.
On this analysis.
And when you came to your decision here.
Okay.
What did you don't know.
We focus on DCF, although we look at our valuation we didnt put it on here, but we look to valuation all kinds of ways.
As we've tried to think about this.
Over the years.
And we simply don't think that the GAAP is there and the way.
There's some people might perceive.
We think that while we take your point clearly DCF is not something that's super comments pretty complementary companies and we're pretty in line.
Actually look pretty good so we struggle to see that there is some arbitrage share that were obviously missing.
But on a p/e basis, you guys are.
Clearly traded a discount relative to those that's concrete.
Midstream companies is there a reason.
Like is there something I'm missing in terms of why your p/e would be depressed relative to the other.
The Williams engage with others.
Yes.
I don't think I'm prepared to go into a lot of that is lumpy because we don't know.
Frankly, none of our investors that were bring a pea with this either so it's hard for us to suddenly think about it maybe on his times well that's kind of on the issue right. That's the issue of the investors that hold you are through funds that are getting liquidated every day on the people that can't Bayou because you issue a K one on a 10 99, who buy and sell things on pay and growth rates.
On earnings stability.
The people that would change your valuation that people, but on you that you are talking to can't possibly change the valuation there already on you.
It's only the new people that can change the way the stock is price.
They can't buy your songs you issue a K one.
So thats low Thats why can we make this point you get into the world of the S&P 500.
DCF is not the metric.
Just just in the essence of time I think it would be better for US just to have this conversation.
One on one and we wanted to have this conversation so I'm not trying to push up I just think that.
We need to move on and add let's schedule a call. So we can talk about this in more detail.
If that's okay with you.
Alright. Thanks.
And those are all the questions. We have at this time on Mr. Mears I'll turn it back to you.
Alright, well I want to thank everyone for their time today and I want to thank you for your interest in Magellan and we'll talk to you soon.
Ladies and gentlemen that concludes our call for today, we thank you all for your participation and have a great rest of your day and you may disconnect Your line.
Yes.
[music].