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Greetings, everyone, and welcome to the Fourth Quarter 2020 Earnings Call. During the presentation, all participants will be in listen-only mode. Afterwards, we will have a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded today, Tuesday, February 2, 2021.
I would now 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. Such 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 should review the risk factors and other information discussed in our filings with the SEC and form your own opinions about Magellan's future performance.
Magellan closed out 2020 with solid financial results, especially considering the continued negative impact the pandemic is having on petroleum products 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 for our refined products pipeline system.
While 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. Then 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, let me mention that, as usual, I'll be making references to some non-GAAP financial metrics, including operating margin and distributable cash flow, or DCF, and we've included exhibits to our earnings release that reconcile these metrics to their nearest GAAP measures.
So as we reported earlier this morning, our net income for fourth quarter 2020 is $184 million, compared to $286 million in fourth quarter 2019. Adjusted earnings per unit for the quarter, which excludes the impact of commodity-related mark-to-market adjustments, was $0.94, which, as Mike pointed out, was higher than $0.80 guidance we provided last fall. With stronger-than-expected performance of the southern portion of our refined product system being the largest single driver of the outperformance versus our expectations, as a result of both higher volumes and higher average rates.
DCF for the quarter was about $270 million, 25% lower than fourth quarter 2019, as consistent with our commentary since the outbreak of the pandemic, the lower commodity price environment and other pandemic-related factors continue to negatively impact our results.
Full year 2020 DCF was $1.04 billion, resulting in a distribution coverage ratio for the year of 1.13 times. While this is, of course, below both our original 2020 guidance of about 1.25 times and our long-stated target of 0.2 times, nevertheless we believe this result underscores the resilience of our business model and the financial strength of our company.
Even in the year to present of this with what was a simply unprecedented decline in refined products demand, at the same time that we saw a severe decline in commodity prices, we were able to generate more than $120 million in excess cash.
You can find a detailed description of the quarter-over-quarter variances in the earnings release we issued this morning. So I plan to just touch on a few highlights and overall themes of our quarterly performance.
Refined products generated $250 million of 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 2020, gasoline and 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 product volumes across all of our system were about 5% lower than the 2019 period. That figure includes the impact of the more volatile South Texas portion of our system, which, as we frequently noted in previous calls, move at significantly lower rates than our average tariff and are somewhat more volatile, both in volumes and product mix than the rest of our system.
Excluding the impact of South Texas, volumes are down 6% for the quarter versus 2019 levels. And, more specifically, gasoline volumes were down 9% distillate was actually up by 4% and aviation fuel was down 33%.
Please note that while we have previously broken out product variances 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 were backed by new customer commitments to drive volumes to our system. In the current environment, in which gasoline demand remains significantly impacted by the impacts of the pandemic and distillate demand is still recovering from reduced rig counts, the effect of those contracts in some cases is that a portion of the base demand served by the expanded assets has been satisfied by customers meeting those new commitments, such that growth volumes are generally tracking our expectations, while what we would characterize as our base volumes have underperformed more than market conditions would otherwise been as to expect.
Of course, as demand continues to recover, we expect total volumes on these expanded assets to meet the expectations we had when we initially undertook the expansions. And we saw positive signs of that recovery in fourth quarter 2020. Especially in distillate volumes, but the timing and pace of that recovery remain uncertain and will depend on both general economic conditions and promising drilling activity.
In addition, a portion of the commitments to our East Houston-to-Hearne expansion only take effect once the committed customer completes the connection to their own asset.
And that customer's construction of that connection has been delayed by COVID-related issues. We currently forecast that construction to be complete by mid-2021. So having to discuss the overall volume picture all note that higher average transportation rates partially offset the volume declines we experienced due primarily to our 3.5% 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 in our gas liquids blending business declined from about $0.57 in 2019 to $0.28 in fourth quarter 2020, with the volumes on that business also being negatively affected by fewer economic buying opportunities. Finally, the sale of three marine terminals in early 2020 also reduced the contribution from the refined segment. So lower operating expenses partially offset the decline.
With regards to our crude oil business fourth quarter operating margin was approximately $110 million that's down 28% from the fourth quarter 2019. During the quarter, the crude oil business was mainly impacted by lower average tariff rates as well as by decrease in volume shipped. Volumes on a long-haul averaged about 250,000 barrels per day compared to 275,000 a day in the fourth quarter of 2019.
While our customers continue to shift at or near the commitment levels, you may recall that 75,000 barrels per day of long-haul commitments expired at the end of the third quarter. While the resulting decrease in third-party shipments was largely offset by volume to show you to our affiliate marketing activities. The margin we realized in those activities is more reflective of the prevailing differential between the Permian Basin and Houston, which is currently well below the tariffs we had been earning 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 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 our Seabrook 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 didn’t offset by higher terminaling revenue from 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 than longer haul Longhorn shipments, which means that they were impacts on our reported volumes and average rate is much greater than their impacts on our actual revenues.
Crude oil segment results also declined between periods as a result of lower contributions from our BridgeTex and Saddlehorn joint ventures. BridgeTex volumes averaged approximately 350,000 barrels per day in the fourth quarter of 2020 compared to approximately 425,000 a day in 2019 driven by decreased uncommitted shipments, which again were a function under currently low Permian to Houston differential.
Saddlehorn volumes also declined somewhat from approximately 180,000 barrels per day in the fourth quarter 2019 to approximately 165,000 a day this quarter. However, the largest driver of the lower contributions from Saddlehorn was our sale of the 10% interest in first quarter 2020.
On a corporate level, you may have noticed that G&A expense increased in fourth quarter 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 and liquidity. First, we repurchased nearly 600,000 units during fourth quarter 2020 spending $25 million. This brings the total number of units repurchased at 5.6 million at a total cost of $277 million. This results in a total return of capital to unitholders including both distribution 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 have consistently noted in the past the timing, price and volume of any unit repurchases will depend on number of factors; including our expected expansion capital spending, excess cash available, balance sheet metrics, legal and regulatory requirement as well as market conditions and the trading price of our equity.
At year end the face value of our long-term debt outstanding was $5 billion with a weighted average interest rate on debt of about 4.4%. We had no outstanding commercial paper borrowings with $13 million of cash on hand and no drawings on our $1 billion credit facility and our next bond maturity isn't until 2025, with the average life to maturity of our bond portfolio at year end at about 20 years.
Our leverage ratio remains strong at 3.5 times for compliance purposes as of the end of 2020 well below our long-stated limit of 4 times. I will point out however that of course our leverage ratio is calculated on a trailing four-quarter basis.
So as stronger pre-pandemic quarters the last of which was really first quarter of 2020 have been rolling out of 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'll continue to do so until those lower EBITDA quarters themselves roll off as the economy recovers and result in increasing EBITDA results in our leverage ratio coming back down again.
With that I'll turn the call back over to Mike to discuss our guidance for 2021 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. This morning we announced DCF guidance of $1.02 billion for 2021. We recognized this number is a bit lower than the Street was expecting. And as usual I'll walk you through the key assumptions we have used to build our 2021 projections and it may shed some light on where the differences may be 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 as 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 additional volume growth from our recent expansion projects within the state of Texas.
Factoring all of this in 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 against pre-COVID demand levels as well. Compared to 2019 results, we expect our 2021 refined product shipments to increase 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 our Refined Products pipeline system is an important component to model this segment.
You are probably aware that FERC has now finalized the new index methodology to be used for the next five years beginning July 1, 2021. The new FERC index is based on the change in the producer price index plus 0.78%. As you may know the preliminary change in PPI for 2020 is a negative 1.3% which results in an index rate adjustment of negative 0.5% for the 40% of our markets that follow the index.
However the remaining 60% of our refined 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 our actual 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 2021 similar to our historical approach. Even though we expect to raise Refined Products tariffs an 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 to the 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 21 blending sales volume.
Considering these hedges and a mid-January forward curve for the unhedged volume we currently expect an average blending margin of $0.25 per gallon for 2021 which would be a historical low. Butane prices have been strong of late and RIN costs have also been trending higher both of which put pressure on our blending margins.
For comparison blending margins averaged $0.45 per gallon during 2020 which is consistent with the 5-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 $0.60 per gallon. Based on hedges put in place in late 2019, whereas the fall 2020 pricing was closer to levels we are seeing now.
Moving to our crude oil segment. We expect volumes on our Longhorn pipeline to average 230,000 barrels per day versus the 270,000 barrels per day we averaged in 2020. As Jeff mentioned a portion of the Longhorn contracts expired last fall, but we still have commitments for approximately 70% 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 spaces 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 in fourth quarter financial results we expect the average Longhorn tariff to be lower going forward, again, as a result of the contract expirations with 2021 representing the first full year impact.
Concerning our joint venture pipes, we expect shipments on BridgeTex to average around 310,000 barrels per day during 2021, which is lower than the 360,000 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 uneconomical for customers even with incentive rates in place. As a reminder, BridgeTex has commitments with an average remaining life of four years for approximately 80% of the pipeline's capacity.
For Saddlehorn, we expect to move about 200,000 barrels per day during 2021, which is higher than the 170,000 barrels per day to transport in 2020. The expansion of the Saddlehorn pipeline was complete at the end of 2020 as expected adding 100,000 barrels per day for new capacity of 290,000 barrels per day. We have commitments for roughly three quarters of the full capacity with an average remaining life of six years, but expect some shippers to utilize bank's credits in the near term for extra volumes shipped in previous periods.
On the expense side, we've discussed in the past the Magellan kicked off an 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, business 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, this line item shows reduction between periods, it's more of a classification issue between capital and expense. Magellan 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 in 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 our 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 1.1 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 1.2 times once Refined Products demand and blending margins return to more historical levels.
Magellan remains focused on delivering long-term value for investors through a disciplined combination of cash distributions, equity repurchases and capital investments. Although, the current environment for 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 to benefit Magellan's future.
During 2020, we spent $355 million on expansion capital projects 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 expansion capital spending to be in the range of $100 range million. As mentioned last quarter, current opportunities are smaller in scale, but generate very attractive returns that meet or exceed our six times to eight times EBITDA multiple thresholds.
For example, recently approved new projects including expansion of our truck loading capabilities in our Cheyenne, Wyoming refined products terminal and improved butane supply transportation for Houston area gas liquids blending activities, which are both high returning low-risk opportunities. We expect to find more of these type of bolt-on projects in part due to opportunities to address changes in logistical patterns to satisfy demand for petroleum products in 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 in the markets we serve and we'll not typically invest in speculative projects based on potential future market needs. With regards to energy transition topics, Magellan has been an active participant in expanding renewable fuel access by providing ethanol blending capabilities for E10, E15 and E85 at all of our gasoline terminals and handling biodiesel at a number of locations. We are assessing additional 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 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 included that -- every time we have concluded that remaining of partnership is the best alternative for long-term value creation for investors. And we have now shared our analysis to help investors understand our approach and assist them and forming their own opinions on this subject.
We understand the view that being structured as a corporation could attract additional investor interest. Assuming potential inclusion in some broader stock market indices but the magnitude of any resulting potential value increase is not known. And while the sustainability of any potential uplift in equity price is even more and clear. In any case, we believe the potential increase in 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 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 for 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. Bottom-line is our priority remains focused on long-term investor value.
That now concludes our prepared remarks and so we can open the line up for questions.
Thank you very much. [Operator Instructions] And our first question comes from the line of Jeremy Tonet JPMorgan. Please go ahead.
Hi good afternoon.
Hi Jeremy.
I just want to pick up on the guidance and thanks for providing the color there. I was just wondering if you might be able to kind of unpack a little bit more the cadence of Refined Product recovery over the course of 2021. Just want to get a sense if this is kind of back-end of the year weighted, or if you see a kind of more linear progression over the course of the year? Just want 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 the course of the year. I don't have actual graph of the chart in front of me. But it's -- I mean it's a pretty ratable increase. I think the first quarter has by far the biggest impact. And then in the second third quarters it ramps up fairly quickly to get closer back to normal levels at least for gasoline and distillate by the fourth quarter.
Got it. That's helpful. Thanks. And maybe just also turning to the guidance and how you think about it? And the butane blending is inherently difficult to make assumptions on as it can kind of move around that margin there. But just curious I guess the $0.25 that you're seeing right now and it looks like that's baked into your guidance. Is that what you think is kind of a new paradigm for butane blending with RINs 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, I think that it's more likely than not that these numbers will gravitate back towards kind of the 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 really going into the spring has been the relative strength of butane prices versus gasoline prices which one would expect 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, you've started to see some refinery rationalizations already with expectations of future lower demand on gasoline that that will widen the margin for 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 -- two things it's 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 are blended into the fuel stream.
Got it. That's helpful. I’ll stop there. Thanks.
Our next question is from Shneur Gershuni, UBS. Please go ahead.
Hi. Good morning or rather good afternoon, everyone. I was wondering, if you can pivot to the discussion around, you were talking about adding potential growth projects. And 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 needed to be spend obviously at the return profile that you described, or is there operating leverage within your existing systems 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's a significant amount of operating leverage in our system. I mean, our pipes in general are not operating at 100% capacity into many, many markets. And so there's operating leverage there. It's impossible to say though, how much capital, if any we 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 of our terminal, but that's simply so we can get more trucks across the truck rack, but the pipeline capacity can accommodate the gap that's left in the market. And so it's really – it's hard to answer your question. I think in many cases the capital we would need to invest, if they're refineries that are kind of embedded in our system or at the ends of our system then the amount of capital would be very, very modest. But again, we haven't done a lot of work on modeling that. We're planning for that because, we don't have any inside knowledge as to what refineries are planning to reduce capacity or expand. I mean, we'll know, when you know, and so we don't spend a lot of time planning for what we don't know yet, but we can react pretty quickly if that happens.
And that makes perfect sense. Thank you for that. And maybe just pivoting back to your 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 can also provide to us you sort of went quickly through the prepared remarks. But if you can provide to us volumetrically, where you see 2021 versus 2019 on an apples-to-apples basis sort of excluding the growth projects. Just kind of curious, how you're thinking about that.
Well, to answer your first question and what we're seeing year-to-date in January is consistent with our expectations, which is not surprising since we're giving the guidance here at the end of January. But we're pleased with the trajectory that the Refined Product demand is in the markets we serve. On the second part of your question, I don't have that handy. I think the number is 3% overall. But I don't have the breakdown in front of me on – and maybe Jeff does.
Yeah. No. Well, one of the reasons we don't have a number handy is because as I tried to explain a little bit the nature of that analysis is pretty complicate, because the majority of our growth projects were those Texas projects that came with good contracts behind them. The assets that were being expanded have been on allocation for years. Some of the existing business was committed and some of it wasn't. But with the pandemic and the drop in drilling what you saw was – and so those things happened just as those projects started to ramp up. And some people started meeting their commitments and you saw some volume shifting from base to growth.
So, if we look at it that way, we get kind of a skewed answer where our growth projects look really strong. And our base business looks really weaker than what would otherwise you would expect based on what's happened to overall demand. So it's – it kind of just becomes a bucketing exercise when we do that. It's I think obscures more than reveals. And so that's why the reason we've stopped providing that separate look.
Obviously, we know that has implications clearly for the short-term sort of multiple on those projects. Those projects did not anticipate starting in the middle of the pandemic or a price war. We fully expect and are starting to see that demand ramping back up. And so we expect that eventually the demand we originally did those projects to serve will be there. But right now, it's kind of a bucket excise in growth and base 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 after distributions this year will be directed towards buybacks, or are we pivoting more to the growth side now?
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 the units whether or not we think that they're 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 million of free cash flow above the distributions and we're also projecting $100 million of expansion capital spending. So, it's fairly well balanced. So to the extent that we outperform our guidance then perhaps we'll have excess cash to pay to equity.
We're not planning at this point to increase leverage further in 2021 just to buy back 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.
All right, perfect. Really appreciate the color today. Thank you very much.
Thank you.
And our next question is from Tristan Richardson with Truist. Please go ahead.
Hey, guys. Good afternoon. Appreciate all the comments on the crude side. Just one quick one on Saddlehorn, as it relates to being contracted at 75%. Can you talk about when credits expire and/or you expect them to be exhausted such that you start to see customer volumes ex the affiliate and reach that contracted level?
I don't have those numbers right in front of me on the credit. It's not a very huge number. It's really not that -- not a very big driver. There's a little bit of that going on there. But this should be complete by the first half of the year. We should be fully ramped up in the second half of the year.
Helpful, thanks Jeff. And then, just going back to the question around on the distillate side, kind of curious what we should be looking for in terms of either rig count or production recovery to hit the assumptions that you guys have kind of laid out?
Well, I don't have a specific rig count. And to be totally candid, there's still a little bit of discovery on that, because we are moving barrels to Albuquerque were moving barrels and 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 demand in that system.
The best I can really tell you is directionally as rig count goes up as activity goes up, up there you will see our volumes go up and those are long-haul barrels. So they're typically very attractive barrels for us to move. And that's really best I can tell you. Demand in Dallas is also part in that picture because of the ECs earned expansion sort of Dallas market. So, there's a number of different factors.
Fair enough. Thank you, guys. Appreciate very much.
Our next question is from Spiro Dounis, Credit Suisse. Please go ahead.
Good afternoon, everybody. I'd like to go back to guidance quickly if we could. Mike, all 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 EBITDA guidance, year-over-year being down. And it would seem like the $355 million spent on expansion last year recovering refined products market, should have been enough to offset Longhorn and butane. But I guess that's not right. So I'm just curious, you just elaborate a bit more on -- maybe on a gross margin basis what some of the big puts and takes are in the year.
Well, give me a moment. I think let me just kind of hit some high-level buckets. If we look at crude transportation and blending profits year-over-year, what we have in the model. I can tell you for crude transportation year-over-year. It's about $60 million less 2020 versus 2021. And that's just a combination of volume and rate.
And then the blending profits, I think where things maybe a little skewed is that our blending profits 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 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 Product recovery, which is bringing us back to where we are. Those are the biggest buckets. There's some other smaller things in here. I think for instance, in the second half of the year we 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 in 2021. So there's a handful of things in there. But those are the biggest buckets.
Okay. That's actually really helpful. So thanks for helping bridge that for us, Mike. Second question you and Enterprise recently announced plans to develop a futures contract market with physical delivery into Houston. Can you talk about the decision to do this now? And how you expect that to impact volumes on the system longer term? And if there's any other areas for you and EPD to work together like this?
Well as you know both, we and Enterprise initiated programs on different exchanges a couple of years ago to try to build a pricing market and a futures market in the Houston area. And quite frankly it hasn't carried a lot of traction. The pricing market at our Houston facility or the pricing mechanism has become well adopted. But the futures offering really hasn't gained traction. And there's what we believe a couple of reasons for that that we've heard from the market is that there's just a great deal of confusion and friction on how we and Enterprise work together with delivering 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 hasn't taken off.
At the same time, there was another effort being developed with the AGS contract that was -- had a lot of interest in the market. We 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 and clarity around how we and Enterprise would work together to make that happen. So it became apparent to us and I believe Enterprise also is 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 agree on access to the facilities. We are going to agree on identifiable transfer rates between the terminals for physical delivery. We're going to do all those things to make it easy for the customers in the market to trade futures contract in Houston between our two respective systems. We think that that has great value to the market. We think that there's a lot of people interested in that. We're still working on the details of that behind the scenes, working on an exchange to work with to put this into place. There's 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 and really all of the export facilities in the area.
So we think we've got a comprehensive offering. The real value here we think is just a long-term value to make Houston the destination of choice. And increased 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 to keep our respective pipelines, which go from the Permian to Houston as full as we can as customers want to get to a market where they have a liquid futures contract similar to what you see in Cushing.
Thanks for the color. Mike.
Thanks.
And our next question is from Gabe Moreen with Mizuho. Please go ahead.
Good afternoon. Just quick two-pronged question from me here on the corporate conversion potential. To what extent was the income tax allowance issued with the FERC considered or not considered I think in the analysis? I guess that's one. And then maybe sort of as a related follow-on or maybe not related. Just either your returns at your regulated pipelines in 2020 and latest thoughts on following the rate case sometime in the future?
I didn’t understand the second part?
Could you repeat the second part of the question?
Sure. Just latest thoughts on filing a rate case 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 of the commission. This was just clearly looking at what's our tax liability is a partnership today and what's our tax liability, if we convert to the C-Corp. Now there's a nuance there. Obviously, if we convert it to C-Corp and there was a tax liability on our regulated assets. Then that clearly is a factor that would impact the cost of -- potential cost of service filing, which presumably increase our rates in order to capture that cost of that tax liability.
I'd point out though again that, that only applies to 40% of our regulated markets, which is also just a subset of our entire business. So 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, I think it might lower the -- if we were successful in that regard to get the tariffs increase to recover that that, it'd be a small portion of what we've projected to be our total tax liability.
On your second question, whether or not we intend to file rate case, we haven't made any decisions on that. We will -- we are evaluating it. We -- if you look at our historical page 700s it reflects that we're under earning in total on our pipeline system. And we do not believe in our view that the current index is representative of what our future cost increases per burn mile are going to be, especially if you believe that refined products demands are going to slowly decline over time. And so we evaluate it.
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 been in 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 cost of service rate case is pretty dated. So we are aggressively going internally through the process of getting ourselves up to speed and prepared in case we decide to do that.
Understood. Thanks, Mike.
Our next question is from Praneeth Satish with Wells Fargo. Please go ahead.
Thanks. Good afternoon. We're seeing some new strains of COVID and I guess a relatively slow rollout of vaccine. So I'm just wondering just from a high level, how you approach this in the 2021 guidance? And does it include any kind of cushion there for these variables?
Well you're 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, and I mean we don't have a much 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 have a handful of consultants big name consultants who know who do refine product demand projections. We take 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 some of the third-party models we looked at then, yes. But we didn't look at our trends and say, we think there's going to be a material change in these trends based on the new variants and based on the slowness of the vaccine rollout. Because I think it's still too early to tell. I mean, the vaccine rollout is picking up steam. Hopefully, it will keep progressing and gaining momentum. And -- but in short, your answer is no. We haven't specifically put those variables in there.
Yeah. I'd just add, we were very much in the problem -- situation. I think we could all point of different data points that you could extrapolate one way or the other. That's why we try to continue to tell people look rule of thumb, if you want to make your assumption to present demand it's about $10 million on an annualized basis. So if you think you need a little bit of Cushing, you can build it, but we have not built Cushings per se into our forecast.
I think just on the positive side, I mean, the other thing we haven't built into our forecast is a pop in demand. But based on all this pent-up or perceived pent-up desire for people to get out and travel. I mean, there's a number of people that are projecting that. I personally 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 there's probably pent-up demand that wants to drive a car rather than flying an airplane. We haven't built any of that into our models either.
Okay. That's helpful. And then this is I guess a 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 a scenario where energy transition occurs over the next few decades, do you think it makes sense to just keep chipping away the leverage ratio and get to an even lower run rate leverage, or are you comfortable with where it is based on the current business mix?
Well, we have a lot of flexibility right now I think is what I would say. We do not have any debt due until 2025. We've got the luxury to watch things develop. I think the kinds of things you're talking about that are almost generational typically they're not going to happen overnight. So we've got time to address. But we're not on -- we're not currently on a path to lower leverage. We have not decided that 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'll continue to watch that and manage as some of the things you're discussing start to get more or less firm.
Got it. Thanks.
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. I was at a conference last month where a prominent CEO one of the producers made a comment about 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. And if I think out past three or four years, maybe four or five contracts roll for pretty much everyone all included. How do you -- if that CEO scenario plays out, how do you think about what the long long-term, kind of, post year three, what that does to the earnings trajectory not to you all specifically, but also the industry as a whole the, kind of, the big Permian pipe.
There's a lot to that question. I mean, I think 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 a very liquid futures contract with access to the water. So that's one thing we're doing.
I also think it's likely if we get into that scenario that participants in the market will start evaluating conversions of their pipes to other services. I can't promise that will be done. I can tell you we think about it 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 environment where the margins are so low, all the contracts are gone you have excess capacity. So everyone's fighting per barrel with extremely low tariffs then there's going to be a huge incentive for people to look for economic conversions and take capacity out of the market.
So there's a lot of what ifs there. I mean, first what if is, is he right? I mean it's -- which I think once 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 -- again if you go through a normal cycle, we could 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 now. And we wouldn't plan for it now since we have contracts today. But as we get closer to the end of our contracts as other pipelines get closer into their contracts then I think those are the things people will be looking at.
Right. No, that makes sense. And then another question shifting to the refined products pipeline side of the biz. You talked about on the 60% that negotiated rate that you normally try to get a 3% to 4% increase around the same time the indexation rates kick in, just curious how have your customers responded to you, given just kind of all the pain that your customers have gone through this year? And in 2020, obviously, like are they willing to absorb a 3% to 4% price hike?
Well, if you're 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 in certain years raised our rates in our competitive markets more than we have in our index markets. And 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 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, the 2014, 2015, 2016 time frame and try to think about were you able to pass-through a 3% to 4% increase back then and just compare it to what we're all going through and watching now?
Well, I can't recall exactly what we did back during that time. But there have been a number of times where there's been a deviation between the index and our competitive markets. And that's caused a little disruption.
And our next question is from Derek Walker, Bank of America. Please go ahead.
Hi, good afternoon everyone. Mike, I think in your formal remarks, you mentioned there are some smaller projects that were canceled. Can you just discuss some of the dynamics there? And I just want to see what types of projects were canceled?
Well, I mean the kinds of projects you would expect would be canceled in the kind of environment we're in. I mean, they were based on expectations for continued volume growth that we've dealt in certain markets and 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 were looking at building in some southeast terminals to accommodate incremental volumes into those terminals. It 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 helped lending biodiesel renewable diesel beyond what you might be doing today I guess, what's one of those do you see as the largest opportunity set? And what type of CapEx or return profile do you expect for those projects?
Well, there's quite a bit of potential legislation in our markets, 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 transport it by pipe. We can certainly blend renewable diesel into diesel and transport it by pipe. There's no market for that today in our market areas, but if states enact low carbon fuel standards and there may be a market for that. And actually -- and this is probably a little more in the development stage. But we feel like, we've reached a level of comfort where we could ship 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. Appreciate the time.
Thanks.
And 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 just any high-level thoughts?
Is your question one of capacity, or is it one of what our projections are for increased volumes?
Not necessarily capacity in the sense that your pipelines 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, how much more volume would that be relative to what you've laid out for 2021? Is it -- is there income of 5%, 10%, 20%? I guess. I'm just trying to get a sense for how much of normal ROE in 2021? And then theoretically how much room would that be beyond 2021 in that?
One way to maybe answer that question -- one way to maybe answer that question would be when we came into 2020, I believe our initial thoughts were with growth projects we were expecting an increase in volumes of 10% over 2019. So now we're telling you 2021 all-in, we expect to be 3% over 2019. So there's probably at least 7% higher growth you can imagine if we got back to full levels. And that's probably understating things a little bit because it doesn't include any additional ramp on our gross projects that we would have expected. And we gave that 10% number. So 7% is probably a floor.
Okay. 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 310,000 barrels a day of throughput. I think that number is fairly significantly lower than the 80% number. Am I doing the math right there?
Yes.
Any color on what's going on there? Are you still going to be receiving deficiency payments, or maybe any color about how that's going to work.
Well it's a little complicated. We have a contract with an affiliate of the pipeline. And the way that contract works is there's an associated basis derivative agreement. And when the margin gets particularly low, the differential gets particularly low. There's -- it reaches a point where even if they shift we don't make anything off of it. And so we've just assumed 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. It would increase our income in the current basis differential environment.
Okay. So it's not related really to deficiencies as much as it is just the basis.
Yes. Right.
And then if I could fit one more and I apologize. But can you maybe talk a little bit about sensitivity to butane blending margins if we get an extra $0.10 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 commodity sensitivity through I think pipeline loss allowances and things of that nature. So any color on what commodity deck your guidance was based on?
Well, on the first question I think you asked about 10. Maybe if I could tell you I'm not cheap and say $0.15 a gallon…
Okay.
We see an issue. And this year we say about $35 million of upside. And it be more the following years because this – a significant portion of this year of course is already fixed already hedged.
Got you.
Especially the number that I had handy. And then I think you asked about what commodities that we're using. And that's just...
I think his question was what would be the impact on our over and shorts. If there was an improvement in price. I don't know if we have that number.
I don't have that handy.
Yes. We don't have that number handy.
Well actually the number I quoted you the $0.15 and the $0.25 is inclusive of it's both tenders and lending.
Okay. Okay. I think last year you had talked about like a $10 price in crude oil was maybe $30 million of DCF. And so I was just wondering if we had a similar – if we had a running crude if maybe that relationship still held?
That relationship is – it's not – it's more just experience-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 apply as 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 a normal kind of environment it will. But right now it doesn't.
Okay. Understand. Thanks for the color.
Our next question is from Michael Cusimano with Heikkinen Energy Advisors. Please go ahead.
Hey, good afternoon. Thanks for all the details you’ve provided. Going back to butane blending. Can you talk a little bit more about the enhanced connectivity all 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 truck it.
Okay. Got you. Yes. And then also do you all see any – is there any floor pressure on the butane margins from the continued growth in LPG exports that we've seen?
Well I think that's certainly what we're seeing right now is that the export demand has strengthened the price of butane relative to gasoline. And so that's one of the 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 affecting those margins?
It is affecting the margins.
Certainly through recently.
Yes.
Over the last year I'm not sure, I'd say if we went back and looked at say what margins are doing in April. Not sure that was the case but there hasn't been the case more recently that the dramatic move has been in the butane side.
Got it All right. That’s all I had. Thank you.
Thanks.
Our next question is from Jim Murchie Energy Income Partners. Please go ahead.
Hey, guys. Thanks. It's Jim Murchie and Louis Lazzara at EIP. I wanted to go to the corporate conversion analysis we tried to kind of back into your $2.3 billion present value number. It all 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 just kind of ramp – you kind of ramp up the tax liability consistent with the depreciation graph you have.
The present value over the first 10 years is only like $500 million. It's like $2 a share. 5% of 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 tax is something like $4 billion. It's 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's question was an -- a offset maybe on the regulatory side. But there's an offset on the shareholder side too, the shareholder tax rate goes down and you didn't account for that.
Just back of the envelope it looks like the shareholder savings is at least $1 billion in present value using the same kind of 8% discount rate that you guys have had? Because really it's the incremental tax for the -- both the company and the shareholders, that matters. And again the present value captures these years way onto the future of that.
I'm not sure how many shareholders look at that. I mean, your graph alone showed that two-thirds of your shareholders have owned the stock for five years or less. So anyway I just want to make sure that, we understand the sort of the character of that present value. A, how much of it is in the -- beyond 2040. And B, that is not decremented by the savings to the limited partners?
Yeah. So, I think you're overstating, how much of its back -- in the backend in the 2040, although, you're -- I think you're directionally correct. I haven't calculated the first 10-year number, but directionally obviously.
Yeah. I'm using your, -- I'm using your numbers. I mean, I'm just kind of assuming a smooth progression from the $75 million in 2027, $187 million in 2030, discounted in percent, its $500 million.
I think you maybe overstated the 24 piece of it. But clearly, it is a long-term look, no question about that. As for the question around individual unit holders we did -- we have run in the appendix when we gave just a brief little bit of color. It depends on the trade group. It depends on when the person in question plans on selling.
And it's a very -- it's sort of idiosyncratic answer for each unit holder, well what happened on an after-tax basis. If we're paying taxes and if we don't pay taxes, because it depends on what changes law happen, when they sell, what their basis which trade group they're in. So the more recent trade groups, actually are -- would be less likely to benefit from a conversion, in the older trade groups by our map.
No, question, but when you're going out to effectively 2090, effectively all of those years have turned over, right?
Again, 100% depends on holding periods. I mean, those questions are all again idiosyncratic to that person. So there is a one answer that, in this trade group's case, the answer is ex. It depends on how long I hold. And so if you hold -- the longer you hold, the more favorable the partnership is.
See Jim, I might suggest that we just schedule a call with you separate, because we can get into the details on this a lot, to your liking and discuss it. But, if that's okay with you, maybe we can just schedule a call. And go through it in more detail.
Sure. Louis, did you have something else?
Yeah. Just on slide six, when you guys looked at valuation there's vast majority of the S&P 500 companies, do not use DCF, as a metric, right? PE is much more commonly used. And if you look at the C-Corp comp that you guys presented here, the average forward P/E ratio is around 18.8 times, whereas Magellan is at 10.8%.
So that's a 75% difference, just on Bloomberg consensus estimates. Did you guys consider that sort of valuation gap, in this analysis? And when you came to your decision here, or did you only arrive at DCF.
No. We focus on the details. Although, we look at valuation, we didn't put it on here but we looked at valuation all kinds of ways, as we try to think about this -- and we have over the years. And we simply don't think that the gap is there in the way that some people might perceive. We think that this while -- we take your point clearly DCF is not something that's super calm as pretty -- on for midstream companies. And we're pretty in line. And actually look pretty good. So, we struggle, I need to see that there's some arbitrage there that was obviously missing.
But on a P/E basis you guys clearly traded a discount relative to those concrete that are midstream companies, right? Is there a reason in your business -- like is there something I'm missing in terms of why your P/E would be depressed relative to the other -- the volumes and grades, some of those other guys?
I don't think I'm prepared to go into a lot of that on P/E, because we don't -- and frankly none of our investors ever bring up P/E with this either. So, it's hard for us to suddenly think about it, maybe in this terms.
Well, that's kind of the issue, right? That's the issue. The investors that hold you are through funds that are getting liquidated every day and the people that can't buy you, because you issue a K1 and 1099, who buy and sell things on PE and growth rates and earnings stability are the people that would change your valuation.
The people that own you that you're talking to can't possibly change the valuation, they already own you. It's only the new people that can change the way the stock is priced and they can't buy you, so long as you issue a K-1. So that's why we make that point. You get into the world of the S&P 500, it's -- DCF is not the metric.
Just in the essence of time, I think, it would be better for us just to have this conversation one-on-one. And we want to have this conversation. So I'm not trying to push up. I just think that we need to move on and let's schedule a call, so we can talk about this in more detail, if that's okay with you.
Sure. Yes.
All right.
Yes. Thanks.
Thanks.
And those are all the questions we have at this time. Mr. Mears, I'll turn it back to you.
All right. Well, I want to thank everyone for their time today and I want to thank you for your interest in Magellan and we will talk to you soon.
Ladies and gentlemen, that concludes our conference today. We thank you all for your participation. Have a great rest of your day and you may disconnect your line.