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Greetings and welcome to the Magellan Midstream Partners’ First Quarter 2020 Earnings Conference Call. During the presentation, all participants will be in listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions].
I would now like to turn the conference over to Mike Mears, President and Chief Executive Officer. Please go ahead, sir.
Thank you. Hello and thank you for joining us today to discuss Magellan's First Quarter financial results as well as our latest outlook for 2020, including an update on the refined product demand trends on our pipeline systems. 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. I'd like to before by recognizing the tremendous response from our employees to the challenges they have faced over the past two months. Their dedication to operating safely to ensure the continuity of fuel supply to the communities we serve is admirable.
During this period of significant disruption to normal work processes, all of our facilities have remained fully operational and our internal environmental and safety targets were exceeded in almost every category. In addition, we were also able to effectively execute on our strategic objectives such as closing on a marine terminal sale in mid-March.
Turning now to our first quarter earnings. The year started off well as we generated solid financial results and exceeded our previous guidance by $0.20 per unit. This was primarily driven by lower operating expenses and higher gas liquid blending margins. In addition, about $0.06 per unit was a result of the gaining the sale of a 10% interest in Saddlehorn in February.
Our CFO, Jeff Holman will now review Magellan's first quarter financial results versus the year ago period, and I'll be back to discuss our latest outlook for 2020, before opening the call for your questions.
Thank you, Mike. As usual, I'll be making references to certain non-GAAP financial metrics including operating margin and distributable cash flow or DCF. We have included exhibits to our earnings release that reconcile these metrics to their nearest GAAP measures. Earlier this morning, we reported first quarter net income of $287.6 or $1.26 per unit on a diluted basis, compared to $207.7 million or $0.91 per diluted unit reported for the first quarter of 2019.
Excluding the impact of mark-to-market activity in the current quarter, adjusted diluted earnings per unit was $1.28, which exceeded our guides for the quarter of $1.08. Distributable cash flow for the quarter was $306.5 million, $11.5 million lower than the $318 million reported in first quarter of '19, primarily due to lower operating margin from our crude oil segment.
Before I discuss the performance of our segment in more detail, let me take the opportunity to remind everyone that, as we discussed in our Analyst Day presentation or late March, we now report our businesses in just two segments; Refined Products and Crude Oil, following the sales for of marine terminal. Our Galena Park marine terminal, and our interest in our Pasadena marine terminal joint venture are now included in our Refined Product segments while our Corpus Christi Terminal is included in our crude oil segment.
So, turning to our Refined Product segment first. Refined Product generated $305.8 million of operating margin in first quarter of 2020, an increase of about $98 million the 2019 period, with most of that increase resulting from more positive mark-to-market adjustments on our commodity hedges during the current period. Transportation and terminals revenue for the segment increased $4.7 million, driven primarily by higher average tariff rates, which were favorably impacted by the July, 2019 tariff increase of 4.3%, partially offset by the impact of higher short-haul investments, on which we earned a lower rate.
Volumes also increased, primarily as a result of incremental barrels on our East Houston-to-Hearne pipeline, which began service and second half 2019, partially offset by the impacts on our refined product volumes of both virus-related restrictions and reduced drilling activity in the later part of the first quarter. Operating expenses for the refined product segment increased $3.2 million between period, due primarily to higher property taxes in the current quarter, while other operating income decreased to $3.5 million, as the 2019 period benefited from the hurricane Harvey related insurance settlement.
Product margin increased $84.8 million compared to first quarter 2019, primarily due to the timing of mark-to-market and inventory valuation adjustments, which were approximately $75 million favorable in the current quarter versus the prior year period. Of course, for DCF purposes, we adjust out the impact of those mark-to-market and inventory valuation adjustments until the period, in which the related barrels are sold. On a DCF basis, the current period product margin was approximately $9.6 million favorable to first quarter '19 mostly due to favorable fractionated margins and favorable sales and profit overages.
Refined product equity earnings increased approximately $15.3 million versus first quarter of 2019, primarily due to favorable mark-to-market adjustments on hedge position at our Powder Springs joint venture as well as higher contributions from Pasadena marine terminal joint venture as Phase 2 of that project begun coming online in the first quarter of this year.
Moving now to crude oil segment. First quarter operating margin of $119.9 million was $23 million lower than first quarter 2019. Crude oil transportation and terminals revenue decreased $6.5 million, primarily as a result of lower spot volumes on Longhorn in the current quarter. While overall Longhorn throughput including barrel shipped by our marketing affiliates actually increased slightly to 276,000 per day from 274,000 barrels per day, the average rate per barrel we earned decreased between periods, as the current period did not include any third-party movements at our posted spot barrel of rate.
Consistent with our previous forecast, we do not currently anticipate receiving third-party spot nominations on Longhorn in 2020 just given the forward price curves. Similarly, we are not forecasting any meaningful marketing from our own uncommitted marketing activities for the rest of the year. Instead, our crude oil transportation volume and revenue expectation assumes that our customers ship at their commitment levels, while our marketing affiliate continues to ship barrels pursuant to its committed buy or sell agreement.
Recall that, our committed volumes on Longhorn including our marketing affiliates committed by sell volumes averaged about 240,000 barrels per day in 2020. The large majority of our committed revenues continue to be backed by creditworthy counterparties and our forecast assumes those counterparties continue to perform on their commitments to us.
Given the current commodity price environment, it is conceivable that some of our customers could choose to face deficiencies in lieu of transporting the committed volumes, which could affect the timing of when we recognize the related revenues. Although the timing of when you receive the cash payments for those commitments would remain unchanged. Any such sufficiency activity is impossible for us to predict however. And so, we have not assumed any significant impact of 2020 earnings from deficiency payments at this time.
Turning now to our Houston distribution system. Volumes decreased slightly year-over-year, although the average rate on those volumes increased in the current period as a result of the origin destination mix of movement from on that system. Crude oil segment operating expenses increased about $1 million, during the period, primarily due to lower product gains. Other operating expenses payment was $4 million unfavorable in first quarter of 2020 as the Permian to Houston differential resulted in less favorable settlements on our basis derivative agreement as well as unfavorable mark-to-market valuation of that adjustment of that agreement.
Crude oil equity earnings decreased $2.9 million between periods. The largest driver of that result was lower Saddlehorn earnings, with a favorable impact of higher average volumes of approximately 180,000 barrels per day, versus 100,000 barrels per day in the 2019 period, that's more than offset by the combined impact of lower average tariffs and the lower ownership percentage, following our sales of the 10% interest early in the quarter.
BridgeTex equity earnings increased slightly, primarily due to lower overall expenses, which sets volumes at 407,000 barrel per day or slightly lower than the 490,000 barrels per day shift in the 2019 period, while the average rate for barrel shift also decreased between periods, as more barrel used under joint tariffs in the first quarter 2020 as opposed to spot tariff movement we saw in the first quarter of '19.
Consistent with our remarks regarding spot barrels on Longhorn, we do not anticipate spot barrels or any other uncommitted on either BridgeTex or Saddlehorn for the remainder of the year, just given current differentials and the production outlook for the rest of the year, and our forecast assumes that volumes track customer commitments.
Finally, product margin for the Crude oil segment was about $9 million unfavorable to 2019, primarily as a result of non-cash adjustments to our Crude oil inventories, which more than offset the cash margin earned by our affiliate marketing activities on Longhorn during the quarter.
Moving out to other variances to last year's quarter. Depreciation, amortization and impairment expense increased $1.7 million, compared to first quarter of '19, largely due to the commencement of depreciation on assets recently placed into service. G&A expense decreased $9.1 million versus the same period in 2019, primarily due to lower incentive comparables.
Net interest expense was $4.5 million lower in the current quarter, primarily due to make all payments made in the prior year period to retire our notes due 2019 early. Otherwise, higher debt outstanding was partially offset by a lower average rate.
Our weighted-average interest rate was approximately 4.6% during the first quarter, and our average outstanding debt was $4.8 billion. At March 31st, total long-term debt was $4.75 billion, including zero commercial paper over volatile bonds outstanding.
Gain on disposition of assets was $8.9 million lower in first quarter of 2020, as the gain we realized in the current period on the sale of a 10% interest in Saddlehorn was less than the gains we realized in the prior year on the sale of a portion of our BridgeTex and our interest in BridgeTex and the sale of the discontinued Delaware basin crude oil pipeline project.
Moving briefly to capital allocation, balance sheet metrics and liquidity, we began opportunistically repurchasing unit shortly after our fourth quarter Investor Call. We repurchased a little over $3.6 million units in the quarter at an average price of $55.62 per unit for a total spend of $202 million.
As previously disclosed, the vast majority of those repurchases were conducted prior to the gas and oil prices and the implementation of lockdown measures. As we have consistently noted in the discussions of our repurchase program, the time, price and volume of unit repurchases will depend on a number of factors, including but not limited to our expected expansion of capital spending needs, alternatives investment opportunities, excess cash available, balance sheet consideration, legal and regulatory requirements as well as market conditions and the trading price of our units.
Given the events of the last two months, we have prioritized balance sheet strength and financial flexibility over additional unit repurchases for the time being. Our leverage ratio for compliance purposes was approximately 2.7 times at the end of the quarter, as the impact on leverage from our unit repurchases is basically offset by the proceeds we received during the quarter from our marine terminal sale and our sale of a 10% interest in Saddlehorn. In terms of liquidity, we continue to maintain our multi-year credit facility, with a capacity of $1 billion and had approximately $139 million of cash on hand at the end of first quarter.
I will now I'll turn the call back over to Mike to discuss our updated guidance for the year.
Thanks, Jeff. I would now like to walk you through our updated outlook for the year. This morning we provided a revised DCF range of $1 billion to $1.075 billion for 2020. We believe a range estimates is appropriate at this time due to the continued uncertainty regarding the pace of refined product demand recovery and the continued volatility in commodity prices.
While a number of states within our operating footprint are beginning the process to reopen their economies, the trajectory of the recovery and the length of time until these markets returned to more historical levels of refined product demand are not easily predictable.
For those of you joined us for our virtual investor update on March 26th, you may have noticed that the current DCF estimates are roughly $20 million to $30 million lower than what we discussed at that time. The decline is primarily related to an even lower commodity price environment than was projected a month ago as well as expectations for a larger reduction in aviation fuel demand for the remainder of the year.
I would like to review the key assumptions related to our new 2020 DCF range, so that you can understand how we're thinking about the current environment, compared to how the world looks and when entered 2020 with our original $1.2 billion guidance. In our press release this morning, we included a table that shows a range of original guidance adjustments that we now are going to discuss and this table is consistent with the table we presented in our Analysts Day on March 26th, just so that you can compare easily between the two of them.
So, starting with the first item, which is lower blending profits and tenders, the range of reductions for that line item is $110 million to $140 million for the year. On the low-end of that range, we are assuming which is consistent with what we were assuming back in March that we have zero blending profits in the second half of the year, and then the remainder of that of the reduction has to do with the low commodity price applied to our fractionation business and our tender.
Most of the change, as you can see was related to the price impact on our tenders and frac business, since we had already been assuming zero blending profit. On the higher-end of that range, it just assumed that $10 increase in the price of crude oil, which we're not necessarily predicting. It's just showing a range of what's possible over the course of the year, and that would be, that shows the variance between those two numbers of $30 million.
If I go to the refined product demand impact, that range is now $60 million to $70 million. The assumptions in that range are listed in the table. It's 25% reduction for gasoline in the second quarter, 5% reduction in distillate and 70% reduction in aviation, and then in July, we would have half of those amounts before we return to normal levels for gasoline and diesel, but we're keeping aviation declines at 25% through the remainder of 2020.
Just to give you a benchmark on actual data, that's behind those assumptions, our actual -- and this is for April, so this is a year-over-year comparison for April. Our gasoline loadings were down 33% for the month of April. Our distillate loadings were down 9% and our jet deliveries, which is a much smaller portion of our movements was down 72%. If I look at just the last 7 days of April, those numbers have improved substantially. Gasoline for the last seven days of April is down 24% year-over-year, distillate is down 4% and jet is down 76%.
I would highlight on the distillate numbers, if those are total reductions and throughput on our system, and in our assumptions, we have a separate line item for a reduction in diesel demand associated with drilling reductions in the basis that we serve. All of that's included in the reductions that I just gave you. So, that's a comprehensive number I just gave you. So for instance, we're assuming 5% decline for the quarter on diesel. What we saw in April was 9% in total, including reductions in and the drilling basins.
I know there's been some discussion regarding other data points with regards to total refined product demand reductions, both year-to-date and forecast going forward for the quarter. Just to give you a sense of what our experience has been, so you can compare against those reference points, our total refined product reduction was 26% for April and our total refined product reduction for the last 7 days of April was 20%. So clearly, the markets that we serve have not seen as dramatic reduction as other parts of the country, and the data would suggest that, we've seen the bottom and we're starting at trajectory upwards.
Moving onto the other assumptions in the forecast, again, I mentioned briefly that, we have a separate line item for reduced distillate volumes entirely associated with drilling reductions. We've changed our assumption for the Permian Basin in these assumptions from a 30% rate reduction declines or a 50% rate reduction decline. And that generates a on the low end of reduction of $30 million for the year. And then to the extent that, that softened somewhat later in the year, we've got on the high end a $20 million reduction.
The assumption on reduced volumes on the crude oil, our cruel systems has not changed. In March, we were projecting that we would have no spot volumes and that's consistent with what we're still projecting. So, that decline has remained at $10 million for the remainder of the year. And then the other item is a range from $50 million to $75 million. That has improved, from the March forecast for two reasons. One is additional storage revenue that we've been able to capture and also additional expense savings has led to that increase. All of that total through our, our forecast range of 1 billion to 1.075 billion for the year.
So based on this latest DCF sensitivity analysis as well as investor feedback, we intend to maintain our quarter cast distribution at the current level for the remainder of 2020. We have heard clearly from long-term investors that the stability of the distribution and healthy distribution coverage remain of utmost importance to them, especially during this period of unprecedented economic uncertainty.
With our current distribution amount of $4.11 per unit on an annualized basis, we expect distribution coverage in the range of about 1.1 to 1.15 times based on our latest DCF sensitivity, which generates excess cash is $75 million to $150 million for 2020. We do not intend to provide financial guidance beyond 2020 at this time, but continue to target distribution coverage above 1.2 times once refined products demand returns to more historical levels and the commodity price environment stabilize.
Regarding expansion capital spending, we still expect to spend $400 million during 2020 to complete the projects already underway with about 40% of that spending occurring during the first quarter. We do not expect to defer any projects at this time, as most of our expansion projects are nearing completion and are supported by long-term agreements. Our largest project relates to the expansion of our West Texas refined products pipeline, which is in its final stages and expected to begin operation or way third quarter.
So as discussed today, we clearly expect near-term financial impacts from the current significantly lower commodity prices and significant reductions in refined products demand. However, Magellan's proven this good approach resilient business model and financial strength position as well to respond not only to the short term industry challenges, but to successfully manage our company for the long term.
And that concludes our prepared remarks. So operator, we're now ready to turn the line over for questions.
Thank you. [Operator Instructions] The first question comes from Theresa Chen of Barclays. Please go ahead.
Mike, I wanted to ask you about the guidance that you laid out in detail. First, just so we understand correctly, the last seven days of April, the numbers you give being comprehensive. So, if that is the pace for the rest of the quarter, then the reduced drilling impact on distillate volumes that negative $20 million to $30 million impact like would not necessarily even be there. Is that the way to interpret your comments?
I'm not sure I understood the question. If it continues at the current pace, then on the distillate assumption will be our distillate assumption.
Right.
For the second quarter, is that your question?
Right.
Then that's the answer.
Okay. The other question I had about, why your refined product demand deterioration has not or had been better than some of the other public data points? Can you talk about -- does this have to do with the markets that you serve or the different types of end user population density, any color around why that's happening?
Yes, I can tell you what our thoughts are. I mean, obviously we don't have any empirical data to go support our assumptions, but I think there's a number of things to take into consideration. First of all and maybe one of the most important is that, the lockdown restrictions I think generally were less severe in the Central Midwest than they were in other places, that's one item. The second item is, there is significant rural areas where the distances that people need to travel to get their basic supplies is further than in other locations. There's no mass transit really of any significant consequence in these markets.
So, I think that, those are kinds of the things we think about from gasoline demand standpoint that is probably softened to the mitigation than you may have seen on the coast for instance. From diesel demand, clearly, we're impacted by a lot of the same drivers as national demand with regards to phrase and economic activity. But one thing we do have in our area that is not true elsewhere is just significant agricultural demand, which has been less impacted by the current environment.
And when you are assuming a recovery in these numbers, is there any sense of permanent demand destruction built into the guidance or do you assume that everything's bounces back to pre-COVID levels?
These assumptions with the exception of jet fuel assumed the demand drop the returns to pre-COVID levels sometime in mid-third quarter.
Except for around the drilling side which is separate.
Yes, yes. Jeff brought up a good point except with regards to distillate demand in the drilling basis.
And then lastly from me, just 50 to 75 benefits from cost reductions and storage revenue. Can you just talk about how much is in each bucket? Are those costs reductions sustainable?
Well, I would say, on the low end of that range, the cost reductions and storage are about evenly split there. A large portion of those costs reductions, we believe are sustainable. And in fact, we have process programs in place to increase those costs reductions over a multiyear period. So, yes, we do think that number's sustainable.
Our next question comes from Tristan Richardson of SunTrust. Please go ahead.
Just to follow up on the last question and again, really appreciate all the detail, particularly around even just the last seven days. As you look at that sensitivity, thinking about the recovery again, should we think of an assumed recovery back towards the actual 2019 levels in terms volumes. Is that kind of conceptually what you're thinking about as you laid out these sensitivities? Or is it more -- when you say normalized, is it kind of a three year, five year average type of type of number?
Well, this assumption as soon as we go back to essentially a 2019 level, sometime the third quarter. In fact, there's a chance that we're even higher than that because we've got a number of growth projects that are, that have come online or coming online to increase that volume. But from a base standpoint, that's the assumption that's built into the forecast.
And it's probably worth mentioning if aviation stays down 25%, which that's, we don't know exactly what that number is going to be. We tried to model something with the exact number on that is not as pivotal as the other products given the small amount of jet we move. But there's, there's potential upside on gas is people try to drive on vacations rather than twice. We have not built any of that in. We're not assuming that by any stretch, but it's hard to know exactly how things are going to look when we come out of this. But I don't think we believe all the outcomes are necessarily negatives.
And then just one quick follow up more of a clarifying item just as we're reconciling things on our side, maybe just the op margin contribution and refined products this quarter from the Pasadena terminals or just generally the assets that were formerly in earnings to bridge?
I don't have that total ready to hand of the amount from the Marine terminals. We did have some contributions from Pasadena as we mentioned the phase two started up this quarter. So, there was some -- it wasn't a full quarter, but it started up this quarter. So, there was some contribution from that. I'd say right now, first, we don't really have an intention of continuing to separately report the marine terminals moved into refined products.
Thank you. Our next question comes from Keith Stanley of Wolfe Research. Please go ahead.
I wanted to maybe could start somewhere a little different. So, the Form 6 filings have largely been made, I believe at this point. And so, thinking you guys have seen the cost data for 2019 that now goes into the next index calculation. So putting aside, I guess, how FERC deals with the income tax issue, do you have any preliminary views on how costs are shaping out both for yourselves and the industry in the 2019 data, just because that's a key input obviously for the next five years?
Well, we surely know how that shook out for us because we made our filing, but I mean, what's relevant is the industry data and most of the pipelines did file on time. There are still some large pipelines that have not asked for an extension. I don't have a preliminary answer for you on that. We have a consultant that is representing the industry through AOPL that is in the midst of collating and processing and analyzing all of that data as we speak. And I don't have a report on that yet. The filing date was the 20th, so we're less than two weeks from actually having the data filed. So, I don't have a preliminary number for you on that yet.
Okay. And then, sorry, just some more clarifications on the very transparent assumptions here. Did you say Mike, the $110 million to $140 million impact from commodities was, $140 million based on current forward terms and $110 million was if oil would arise another $10? Did I hear that correctly?
Yes, I think that's directionally accurate, correct.
Okay. And then on the, sorry, on the prior question, when you say assuming similar gasoline and distillate volumes for August to December holding aside drilling, is that even with the West Texas expansion project that you're assuming volumes flat year-over-year August, December? Or is that before the incremental volume you might see on West Texas expansion?
It's just the base. Once the West Texas expansion is in place then we have commitments that kick in that would layer on top of that. So, that's just a reduction in the base volume.
Thank you. Our next question comes from Gabe Moreen from Mizuho Securities. Please go ahead.
Hey, good afternoon. I just had a little bit of a multi-pronged question on butane blending. I guess my question is, is there something that you have to do to serve customers, so regardless of where the pricing relationship goes or is it really just all discretionary? And then given I guess the outlook for LPG supply. Can you talk, I know Magellan has invested a great deal historically and I think logistics around beauty and supply. Can you talk about confidence and access to butane supply? And I guess getting butane that's priced in a way that you could make a margin going forward, if that makes sense?
Well, on your first question, we have no obligation to blend whatsoever. If the margin is not available, we won't do it. We don't have any supply contracts associated with gasoline from blending activities that would require us to blend. So, no, we're not obligated to do it if there's not money to be made in doing it.
With regards to your second part of your question, we are not concerned with access to butane supply, that's not a concern for us. And I should mention, I don't want to highlight this in a forecast because, I really don't want to necessarily emphasize the up sides, but since you asked the question, I'll bring it up.
This forecast as I said, assumes no blending profits. There may be opportunities for us to buy butane at depressed prices and recognize margins, maybe not in every single market we operate in, but in some markets in the fall and we're continually evaluating and planning for those opportunities. And we're actively doing that as we speak. Again, we have not forecast that we'll find any, but there's certainly upside associated with that.
Thank you. Our next question comes from Shneur Gershuni from UBS. Please go ahead.
Hi. Good afternoon everyone. Just to follow up on some of the guidance sensitivity questions, I'm actually more focused on the quote unquote other section, the change versus what you outlined at the virtual Analyst Day. I was wondering if you could give us a little bit of color about the change. You said storage and cost. Is it more one than the other? Is it a lot of incremental OpEx savings? Is it specifically about the fact that the crew containment got bigger or smaller? I just call it input that's driving that big positive change.
Yes, the increase is about half and half expense savings and storage revenues. We've continued to find additional opportunities for storage revenue. Most of what we're doing that's the vast majority of what we're doing is through leases rather than taking a contango position ourselves. So we've found opportunities to do that. We also, we're continuing to look for other opportunities.
We're looking at storage right now at Galena Park that we could potentially convert to crude oil. As we continue to try to optimize available storage opportunities. We also, um, have an ice contract, at East Houston that has a compound of it that, where we auction lease storage space monthly. And so there's some benefit from that also in the improved number.
On the expense side, its continued focus on cost reduction and the success we've had around that. That's also increased that number. I would note that we initiated a multi-year cost reduction program late last year, long before this happened. And we're seeing the fruits of that work now and it's been accelerated. So we weren't, we didn't start flat-footed with, with the cost reduction program. We had been developing the framework for that, well in advance of this crisis.
Okay. I appreciate the color on that and then maybe as a follow-up. Just going back to the discussion about the FERC tariffs and so forth, you had talked about at the virtual Analyst Day about theoretical being able to actually increase tariffs, if there's a structural decline in demand and so forth. And I imagine that you could do that with your market based rates pretty quickly. Is it too late to put something like that into the filings for the upcoming FERC review? Or would we have to wait five years to see something like that happen?
Well, there's a lot of elements to what you just said, and I'll break it down as best I can. First of all, with our market based rates, it's not related at all to the index proceedings. I mean, our market based rates generally where we have the freedom to raise or lower those rates when and if we see fit, it's not tied to a specific date. It's not tied to anything other than what the market, the competitive forces in the market will allow. So, the short answer is, yes. We could increase those rates from a regulatory standpoint. We need to evaluate that on a case-by-case basis because the fact that, they are market-based rates means that they're competitive in market. And so, we need to be cautious as to what we do in those markets, just related to competitive pressures.
With regards to the index market, the process for determining the index is going to be based on 2019 actual data, so none of the indicators or results from 2020 will be factored into the actual index calculation. Again, that index that they're calculating now won't go into effect until 2021. So, anything that we might want to do to recover lost income due to the pandemic will likely need to be done outside of the index process, and we don't necessarily have that figured out yet or evaluating it and thinking about it and we'll take action, if we think it's appropriate in the right time. But it's likely to be completely separate from the index process.
And maybe just to follow-up on your first comment, just specifically to the market based rates. I mean, do you currently have plans to push through a rate increase now or evaluating it now?
Well, I'll say this. I mean in our planning for this year, we had assumed a certain rate increase in those markets and we're evaluating whether or not we should adjust that, but we haven't made any decisions on that yet. And so, that's probably all I can say at this point.
Okay, great. One last accounting clarification question, you were talking in the prepared remarks about Chinese oil deficiencies. And I just want to clarify that I understood your statement correctly that, if you receive a deficiency payment is effectively use of the cash on the cash flow statements today, but the timing of the revenue recognition could be later on. So, it's a scenario where you can see cash and permanent in near term, but not see a corresponding increase in economic side, is that a right way to think about it?
Yes. That's possible. And we've had that in some amounts before. And then the question becomes a little bit which contract are we talking about? How much should a period do they have to use deficiency credit and how many other people are also trying to get you that same door at the same time and what are the physical possibilities for them to realize that credit? And so, we just have to evaluate that when it happens, if it happens.
Yes. And to Jeff's point, we've had this. This has happened really every year since we've had contracts in place, and the numbers had not really been material enough for us to talk about. We don't include. We don't adjust our DCF for that. So, historically we haven't. So, for instance, if in a particular year we received $2 million of cash, but we have to defer recognition of that for some time period. We wouldn't adjust our DCF to reflect that. If those numbers become material, we likely won't adjust our DCF, but we will disclose what that number is, so that the market will be aware of the fact that we've received the cash. We just haven't earned the been able to recognize it yet.
Next question comes from Jeremy Tonet of JP Morgan. Please go ahead.
Good afternoon. Just wanted to follow up on the storage situation a little bit more. Didn't know if you were able to provide any more color with regards to kind of specifically what type of a, what level of rate increases might be happening in the market place today given the contango structure out there and just exactly how full you guys are on shore to this point.
Well, I wish, I mean, the rates are higher. There's no doubt, it's hard to give you a single data point because not every tank is the same, depending on where it's at for instance. And in some, it really depends too as to whether you're willing to do a six month contract or you want to try to secure a two year contract a while the market's hot. So it's kind of hard to say. Undoubtedly if you're willing to do short term contracts, the rates can be very high. I mentioned the ice contract, the ice auction we have through the ice platform, which is relatively short term contracts.
We were able to get some very, very attractive rates there. We tend to err on the side of longer terms. So we would prefer to get longer term contracts for lower rates than short term contracts for higher rates typically, which is what we're trying to do. I'm sure some of our peers may be doing something different. So, it's hard to say, exactly what everyone's experience is going to be as far as incremental revenues from what incremental revenue in 2020 will be for the current storage market.
Got you, that makes sense. And just wants to take to a higher level question. I know that Magellan continuously reviews the portfolio and sees, if other market participants assign more value recently having sold assets, not too long ago here. And even just looking at where Magellan trades right now, we saw Buckeye taken out not too long ago, if I look at where you guys trade versus your 2021 street estimates. It seems like there's a discount there. So just at a higher level, if you could share any thoughts about how you think about that dynamic, where do you guys trade what private equity is willing to do in this current environment?
Well that's a loaded question. I don't really have an answer for you on that. I mean, I clearly, I would state that I think our company has more long-term value than we're trading right now. So, I don't know if that's necessarily the right benchmark to compare against what private equity is slowing to pay. So, I probably don't have much more color on that. We're not actually talking to private equity firms about acquiring Magellan in the end. Honestly, that wouldn't be at the top of our list. So we haven't spent a lot of time evaluating that.
Our next question comes from Michael Lapides of Goldman Sachs. Please go ahead.
Hi guys. Thank you for taking my questions. Can you, I know it's probably a little bit early, but when you're thinking about growth capital spend for 21 and maybe 22 kind of directionally, do you think given what went on in the world, that you kind of go down to a level of capital spend that's closer to just pure maintenance for a year or two? And so, you get a significant move either in normalization of gasoline demand in jet fuel at the same time or just simply higher WTI pricing?
Well, I think that's certainly within the range of the possible. I think, it's more likely that we're going to find some opportunities, and those opportunities may be more skewed towards Refined Product opportunities than crude oil in the short-term. As we sit here today, we've very little commitments beyond 2020, but we're still actively working with counterparties on potential projects. And some of those projects, we think have a significant prospect of happening. Obviously, we haven't built any of those into our forecast.
And given the market, the way it is now, we would not proceed with any project of significance without strong creditworthy contracts to underwrite it. But those opportunities are still available. I think it's not likely that, we're going to be in a capital environment similar to what we've seen in the last 3 or 4 years that, it will be significantly reduced from that. But we're still approaching this as we're interested in growth. We think the capital markets are open to us. We've got a strong balance sheet. And when I say the capital markets, I'm primarily talking about debt. We're not looking at issuing equity anytime in the foreseeable future.
So, many of these projects are on hold, not because we're not interested in them, but the counter parties obviously are frozen, so to speak with regards to their interest in committing than anything right now. But once that starts to free up, I think we've got some opportunities in front of us. And again, I think refined product is going to be strong or stronger I should say than crude oil opportunities at least in the short-term.
And I just want try and see if I can understand, when we think about both your refined product in your crude storage, how much is that is a percentage wise roughly? How much of that is contracted or leased long-term to customers versus kind of what percentage is the open and available for your marketing team to utilize?
You've asked great question. I don't have that percentage in front of me. I mean, we have a significant amount of storage in the crude oil. And in the crude oil, I mean, both of the businesses are different. In the crude oil business, the majority of our storage is available for lease. Crushing storage is available for lease, almost all it from our perspective is available for lease.
In Houston, the percentage is very high of the storage that we own that's available for lease. The refined product business is different. The majority of our refined product storage is operational in nature to maintain the flow of the products throughout the Midwest, and it's a smaller percentage of that that's available for lease, but I don't have those precise numbers.
But in my view what point that even in that refined product setting, it's operational, it's not really marketing. It's not as if we've had marketing activities going on in that storage typically. There are some opportunities for us to use to use storage in some cases. But generally speaking, our model is everything that's available. So, we don't need for operational. We try to lease it, and we don't keep very much of it for ourselves for marketing purposes.
Our next question comes from Derek Walker of Bank of America. Please go ahead.
A lot of my question has been answered, but maybe just kind of update on how you guys are thinking about the special distribution. I know you've talking about it in the past and to do -- your thought process around the CapEx and buybacks, but just kind of thinking about that special distribution avenue?
Well, as we've said, we've guided towards a flat distribution for this year, keeping it at this level for this year. And in our view, that's really out of the abundance of caution, given the uncertainty in the market. I can tell you, I mean, we had long discussion about whether we were going to maintain our 3% growth or keep it flat this year. And, I think it's clear the market's really not paying for growth right now maintaining a focus on a solid balance sheet, strong distribution coverage. Even though many of the events we're seeing right now, especially on the product side, are transient nature. And when we think about 21 and 22 and beyond that, there should be little lingering impact from that.
We still out of the abundance of caution, decided to keep the distribution flat this year as far as what we would do next year. We haven't made decisions on that. We'll make that decision at a later point when we see -- when we have a view on what 21 and 22 will look like. But nothing's really changed with regards to our thoughts on capital allocation. We are still interested in stock buy backs at the right time and at the right price, and that'll still be in the mix, when the time is right, the time slot right at the moment. And we'll be balancing all of those decisions going forward.
Okay, great. Well, maybe just a follow-up on my question the growth CapEx. As you talked about more skewed growth opportunities on the refined products and crude at the moment, and given kind of how you're thinking about the guidance, cadence and trajectory. Obviously, there's a lot of unknowns there. But do you feel like the -- to get into the second half of the year that some of these projects that I guess are, could be -- I don't want to say pull forward, I really kind of move forward on the getting past the FID page? Or do you really think it's to be kind of the rest of this year needs to happen and then kind of see how 2021 plays out before we really capture some of those opportunities. Just trying to get sense for some of the discussions you're having with your counter parties, if they think that they're ready to move forward maybe this year things kind of improve in second half or if it really just going to be a functionary kind of environment in 20, and that's really probably one where you think things will problems before?
Well, it's really going to depend on the pace of the recovery. If we get into the third quarter and fourth quarter and refine products demand and the refining industry is back to normal, then I think that's going to make counterparties more receptive to push forward some of the things we're talking about. If we have lingering issues into the third and fourth quarter then it's probably going to delay. So, it's really hard to predict that. We think we have projects that are very attractive and interesting to both us and the counterparties in a normalized environment. And so, when we get to a normalized environment, whenever that is, I think we've got potentially actionable projects.
Thank you. And our next question comes from Spiro Dounis of Credit Suisse. Please go ahead.
Hey, good afternoon everyone. Sorry, if it is covered already. Just wants to get back to the discussion around some of the deficiency payments, and I'm thinking about crude volume specifically. One of your peers is out last week saying that, they have not seen a major supply response yet on their assets. And, I think the refined product demand response has been pretty well documented at this point. Just curious, if you've seen any meaningful pullback in volumes on the crude side beyond the uncommitted spot movements?
We have not. We have had strong movements on our Crude Oil pipelines to-date. We have strong nominations for May. And again, at this point, we're talking about contracted volumes. So, we're not surprised by that because we have contracting commitments to shift those volume levels. So, no, we haven't seen a reduction in volume, any material reduction other than the uncommitted volumes to-date.
Great. That's good to hear. My second question, just want to touch on the $500 million of feature projects that understandably is not a focus right now, but just curious if you could talk to maybe how this downturn has changed the profile of this project, if at all? It's basically the same project off late as it was before. If I believe this all happened, and how would you characterize the timing of when you think those projects could come to market now versus before COVID?
Well, I think I touched on this a little bit earlier. But I think, the most likely project, the most actual projects at our view over the next year or so are refined product projects. Crude oil projects are going to be much more challenging in our view for the time being. And the actionality of those is really driven by how quickly we get back to a normal refined product demand environment, so…
In my view just worth overlaying our approach to projects, which really hasn't changed, we always would be for a large refined product project. We're looking for strong counterparty to be on the other side of that, that's not changed. It's not as if we were going to take a lot of risk before and now we're not going to. We were always going to be looking for the right risk and work balance and that hasn't really changed. And so, to my point, a lot of it depends on credit worthy account and parties being willing to make investments and that would probably require some clarity. But again, most of the disruptions we think are short lived, and if that clear up, we'll be applying basically the same methodical risk reward balanced approach that we've always used going forward.
Thank you. That was our final question. Mr. Mears, I'll turn the call back over to you for any closing remarks.
Well, thank you all for taking time on a Friday afternoon to listen to what we have to say, and we want to thank you all for your continued interest in Magellan. Hope everyone has a great weekend.