Please ensure Javascript is enabled for purposes of website accessibility

Magellan Midstream Partners LP (MMP) Q1 2021 Earnings Call Transcript

By Motley Fool Transcribers - Apr 30, 2021 at 2:31AM

You’re reading a free article with opinions that may differ from The Motley Fool’s Premium Investing Services. Become a Motley Fool member today to get instant access to our top analyst recommendations, in-depth research, investing resources, and more. Learn More

MMP earnings call for the period ending March 31, 2021.

Logo of jester cap with thought bubble.

Image source: The Motley Fool.

Magellan Midstream Partners LP (MMP 0.88%)
Q1 2021 Earnings Call
Apr 29, 2021, 1:30 p.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Greetings, and good afternoon, everyone. Welcome to the First Quarter 2021 Earnings Call. [Operator Instructions]

It is now my pleasure to turn the call over to Mike Mears, Chief Executive Officer. Please go ahead, sir.

Mike Mears -- Chairman, President and Chief Executive Officer

All right. Well, hello, and thank you for joining us today for our first quarter earnings call. Before we get started, I'll remind you that management will be making forward-looking statements as defined by the Securities and Exchange Commission. 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 inform your own opinions about Magellan's future performance. With that, I am pleased to announce that Magellan started the year with stronger-than-expected results, exceeding our previous EPU guidance by a considerable amount.

The effects on the midstream industry from the unusually cold weather in February has been an industry theme for the first quarter of 2021, and Magellan's results were affected as well. Although some of our assets were inoperable because of the freezing conditions and power issues for about a week during mid-February. Overall, we recognized a net positive financial impact related to the weather events during the quarter. These positives included additional refined product throughput on our system due to short-term refinery outages, improved basis differentials on the sales from our butane blending activities and gains from our power hedging activity. These positives were offset by lower crude oil volumes, but in total, we estimate about a $25 million favorable impact on a combined basis as a result of these weather events.

Further, our outperformance for the quarter was also driven by a number of other positive items, some of which relate to timing of expenses that are expected to occur later in the year. I also would like to touch on our continued portfolio management activity. Last week, we announced the sale of nearly half of our interest in our Pasadena marine terminal joint venture. As Magellan has demonstrated in the past, we regularly review both potential investments and our own asset portfolio for opportunities to unlock incremental value for our investors.

With this transaction, we were able to monetize a portion of our ownership position at an attractive price while retaining a meaningful position and operatorship of this strategic refined products export facility. We intend to use the $270 million of proceeds from this transaction, consistent with our stated capital allocation priorities, including potential unit repurchases and we will continue to have an opportunity to participate in future expansions of this facility. Our CFO, Jeff Holman, will now review our financial results in more detail versus the 2020 period then I'll be back to discuss our latest outlook for the year before answering your questions.

Jeff Holman -- Senior Vice President, Chief Financial Officer and Treasurer

Thanks, Mike. First, let me mention that, as usual, I'll be making references to certain non-GAAP financial metrics, including operating margin and distributable cash flow or DCF, and free cash flow, and we've included exhibits to our earnings release that reconcile these metrics to their nearest GAAP measure. Earlier this morning, we reported first quarter net income of $221 million compared to $288 million in first quarter of 2020. Adjusted earnings per unit for the quarter, which excludes the impact of commodity-related mark-to-market adjustments, was $1.09, which, as Mike pointed out, significantly exceeded our guidance for the quarter of $0.75.

DCF for the quarter of about $277 million is approximately 10% lower than first quarter 2020, primarily due to lower commodity-related profits in the current quarter as well as lower crude oil revenue following the expiration of a portion of our Longhorn commitments in September of last year. You can find a detailed description of our quarter-over-quarter variances in the earnings release we issued this morning so I'm going to just touch on a few highlights and overall themes of our quarterly performance. Refined products operating margin of $274 million in the quarter was approximately 10% lower than the 2020 period. Refined segment transportation revenue was actually up between periods, partially offsetting the impact from the sales through marine terminals in early 2020.

While refined products volumes continue to improve from the pandemic lows, first quarter volumes did reflect the lingering impacts of COVID-19 and still recovering drilling activity, which were not yet significant factors in the 2020 period. These year-over-year volume declines were partially offset by contributions from our West Texas pipeline expansion, which began operations in third quarter 2020. In addition, refinery outages caused by enter storms during the quarter resulted in supply disruptions that our pipeline network was well positioned to accommodate, resulting in incremental throughput on our systems. Taking these various factors altogether, total refined transportation volumes, excluding the impact of the more volatile South Texas portion of our system, were up 1% for the quarter versus first quarter 2020. Is 9% higher distillate volumes more than offset 4% lower gasoline and 21% lower aviation fuel.

Please note that these figures by product that I just mentioned are inclusive of both our base business and our recently completed growth projects. And finally, I'll note that including volumes on the South Texas portion of our system, which move at a much lower average rate, total volumes were down by 1%. Higher average refined transportation rates more than offset this slight overall volume decline. Due in part to the 3.5% average tariff increase implemented in July 2020. Additionally, the supply disruptions I mentioned just a moment ago, also resulted in incremental longer haul movements on our system, further contributing to the higher average rate per barrel.

Beyond transportation and terminals revenue, our first quarter refined products financial results declined versus 2020 due to lower profitability from our commodity-related activities. Margins in our gas liquids blending business declined from about $0.55 per gallon in 2020 to closer to $0.30 a gallon in first quarter 2021. With the total blended volumes also being negatively affected by fewer economic blending opportunities in the current quarter. As a reminder, our first quarter 2020 blending results benefited from hedges put in place in late 2019, and prior to the commodity price decline last year. While most of the margin we captured in the current period was locked in prior to the recent improvement in commodity prices. Turning to our crude oil business. First quarter operating margin was approximately $109 million, which was down 9% from the first quarter of 2020.

Our crude oil segment was mainly impacted by lower average tariff rates as well as by lower volume shipped. Volumes on Longhorn averaged about 235,000 barrels per day compared to 275,000 barrels per day in the first quarter of 2020. This decrease is partly a result of the impact of recent storms and the operations of our customers. In addition, you may recall that some Longhorn commitments expired in the fall of 2020. While the resulting decrease in third-party shipments was largely offset by volumes related to our affiliate marketing activities. The margin we realize on those activities is more reflective of the prevailing differential between the Permian Basin and Houston, which is currently well below the tariff we have been earning on the previous contracts.

As a result, our average realized rate per barrel declined during the period, consistent with the expectations we had when we provided our guidance. Volumes on our Houston distribution system also declined versus the prior year period, again, in part due to disruptions caused by the recent winter storms as well as to a change in the way customers contract for access to Seabrook, as we've discussed on previous calls. Although we sometimes see volatility in our HDS volumes between quarters, those volumes move at significantly lower rates than longer haul Longhorn shipments, which means that they're impact in our reported volumes and average rate is much greater than their impact on our actual revenues. Moving on to our joint ventures. BridgeTex volumes were approximately 300,000 barrels per day in the first quarter of '21 compared to approximately 405,000 barrels per day in 2020.

Driven by a decrease in uncommitted shipments. Saddlehorn volumes of approximately 180,000 barrels per day were essentially flat between periods. Operating expenses were favorable across both business segments during the first quarter of 2021, primarily due to lower power costs. As you may recall, as early as late 2019, we've begun focusing on opportunities to realize efficiencies across our business, and we formed a team dedicated to those optimization efforts. One of the most significant impacts of that team has been in the area of power costs, where we are seeing significant year-over-year savings as a direct result of the optimization team's efforts.

In addition to those efficiency gains, we've had a long-standing practice of hedging a portion of our long-haul power expense. During the recent volatility in power costs, that hedging activity resulted in gains that were reflected in our quarterly results as lower power expense. Just a couple of other quick notes on our year-over-year results, G&A expense increased between periods, primarily as a result of higher incentive compensation expense just as a result of our relative outperformance during the quarter as compared to the prior year period. And lastly, net interest expense was higher during the current quarter, primarily due to lower capitalized interest, which reflects the decrease in ongoing construction activity we are seeing in this lower capital environment. As of March 31, the face value of our long-term debt outstanding was $5.02 billion, with a weighted average interest rate on net debt of about 4.4%. Moving on to capital allocation. Balance sheet metrics and liquidity.

First, in terms of liquidity, we continue to have our $1 billion credit facility available to us through mid 2024, with $17 million outstanding on our commercial paper program in March 31. And our next bond maturity isn't until 2025. Next, I'd like to quickly make a few remarks regarding free cash flow. As you may have noticed, we have added a free cash flow calculation this quarter in the financial schedules accompanying our earnings release, just based on continued investor interest in the concept and in capital allocation in general. We've calculated free cash flow as DCF, less expansion capital and including any proceeds from divestitures. For the first quarter of 2021 free cash flow was approximately $267 million, with free cash flow after distributions amounting to $37 million.

Finally, I'll note that we remain focused on delivering long-term value for our investors through a disciplined combination of quarterly cash distributions, capital investments and equity repurchases. An important part of that disciplined approach has been our long-standing financial policy with its 4 times leverage limit, which we believe has played an important role and are delivering strong, predictable returns to our unitholders over many years. We came into the first quarter of 2021, anticipating their leverage ratio would likely approach that 4 times limit this quarter. Just as a result of the impact of the pandemic and lower commodity price environment on the full trailing 12-month period EBITDA as of the end of the first quarter. And as a result of this expectation of relatively elevated leverage, we did not repurchase any units during the quarter.

However, the outperformance of the business resulted in our leverage coming in lower than anticipated. At around 3.85 times or about 3.75 times as calculated for our credit agreement, which still incorporates the pro forma impact of our recently completed West Texas pipeline expansion project. As reflected in our updated guidance, we expect trailing 12-month EBITDA to improve over the course of the year. And with the proceeds from the recent sale of a partial interest in our Pasadena marine terminal joint venture, we should be in a position to opportunistically repurchase units in the coming periods.

We continue to view unit repurchases as an important tool in our efforts to maximize value for our unitholders. And have nearly $475 million of authorization remaining under our existing $750 million repurchase program. Of course, as we have consistently noted in the past, the timing, price and volume within the unit repurchases will depend on a number of factors, including our expected expansion capital spending, excess cash available, balance sheet metrics, legal and regulatory requirements, as well as market conditions and the trading price of our equity. With that, I'll turn the call back over to Mike to discuss our updated guidance for the year.

Mike Mears -- Chairman, President and Chief Executive Officer

Thanks, Jeff. We announced this morning that we have increased our 2021 DCF guidance by $50 million to $1.07 billion. This higher guidance is a result of our strong performance during the first quarter as well as a more favorable commodity pricing environment for our gas liquids blending activities. Our updated guidance also takes into account lower distributions due to the recent sale of nearly half our interest in the Pasadena terminal joint venture. Many of you have been tracking the forward curve for butane blending margins. And so you are aware that margins have improved since we provided guidance in early February.

As is typical for this time of the year, we have started locking in our fall blending margins with about 30% of expected fall activity hedged so far. Based on the improved commodity price environment, we now forecast average blending margins of $0.40 per gallon for the year versus the $0.25 expectation as we enter the year. As a reminder, the 5-year average blending margin is about $0.45 per gallon. So we are trending back toward a more normal blending margin. Magellan is a net buyer of RINs as a result of our butane blending activities. As you may know, RIN prices have increased dramatically this year, and we have factored these higher prices into our current estimates.

We have purchased most of our RIN obligation related to 2021 blending activity at an all-in average price of around $0.10 per gallon. We currently expect to spend about $30 million for RINs this year, which is more than double our annual cost over the last few years. Turning to refined products demand. We expect our refined product shipments to be in line with our previous estimates for the year, with total volume still forecasted to be 13% higher than last year. Based on general trends to date, a projected continued recovery in travel and economic activities and further volume increases on our recent Texas expansion projects in the coming months, we expect total gasoline shipments to be 13% higher, distillate 10% higher and aviation fuel 25% higher than our 2020 volumes.

Our overall 2021 refined product shipments are still expected to be about 3% above the more normal demand year we saw in 2019. As previously discussed, we intend to maintain our current quarterly cash distribution through 2021. Assuming the current number of units outstanding, we expect our $1.07 billion DCF guidance to result in distribution coverage of 1.17 times for the full year, which is approaching our long-term annual target of at least 1.2 times once refined product demand returns to historical levels. As Jeff mentioned, we remain focused on delivering long-term value for our investors through a disciplined combination of cash distributions, equity repurchases and capital investments.

While we continue to assess potential low-risk projects to expand our service offering and generate additional value for our investors, our projected expansion capital spending currently totals less than $100 million, with $75 million of expected spending in 2021 and $15 million in 2022. These estimates now include a more than 5,000 barrel per day expansion of our New Mexico refined products pipeline system following our recent successful open season. The additional capacity is expected to be available in mid-2022, and is supported by long-term committed volumes.

While the New Mexico expansion is forecasted to cost less than $20 million, we expect to generate a return at the lower end of the six to 8 times EBITDA multiple we are generally targeting. We remain committed to Magellan's long-standing capital discipline and balance sheet strength. We expect to generate free cash flow after planned distributions of $350 million for the year that will be available for additional investment opportunities and unit repurchases. That now concludes our prepared remarks. So operator, you can open the lines for questions.

Questions and Answers:

Operator

[Operator Instructions] Our first question comes from Theresa Chen with Barclays.

Theresa Chen -- Barclays -- Analyst

Mike, within your refined product pipeline system. The demand recovery seems to be progressing nicely. And I wanted to ask about the changes within the guidance with individual clean products themselves. Slightly lower gasoline expectations versus previous guidance, higher growth rates in distillate and jet throughput. Can you talk about what's driving that? And then separately, but related, we hear a lot of anecdotal data about potential pent-up demand as it relates to gasoline, as we are on the cusp of summer driving season and people are eager to get out of the house after being locked down for a year. Have you seen any evidence of this in your system yet?

Mike Mears -- Chairman, President and Chief Executive Officer

Well, first of all, the primary adjustments to our guidance really are informed by what we saw in the first quarter and by what we're seeing so far in the second quarter. And there's really no more magic to it than that. We just kind of extrapolated the trends we're seeing through the rest of the year in relation to our previous forecast. As far as seeing any pent-up demand. I mean, it's really hard for us to parse through the data and determine how much of it is base demand and how much is pent-up demand. So I can't really speak to whether we're actually seeing that or not. I think our expectations are consistent with what other are predicting is that we are going to see improved gasoline demand as we go through the summer. But it's hard for us to point a finger at direct evidence of that right at this point.

Theresa Chen -- Barclays -- Analyst

Got it. And then maybe switching gears and just on the topic of Pasadena. Can you provide some more color about how the sale came about, given that Magellan is typically not a seller of assets. And I'm just curious what prompted you to part with half your interest in this one. And to the extent that it impacts any future phases and additional build-out of the facility, what does that look like? And what is your view on even just the base case for future build-outs in light of refining rationalization domestically?

Mike Mears -- Chairman, President and Chief Executive Officer

Well, thanks for the question. I'd rather not get into the specifics of the negotiations that led to this happening. As you know, Valero also sold a portion of their interest. And so all of that was happening simultaneously. What I will say is that we believe we've got a very good price for our transaction. And that we routinely look at our entire portfolio and assess whether or not there are assets that we can sell at what we view to be a premium valuation. And this asset falls into that category of assets we would look at routinely to do that. So I don't -- I think we have historically said that we evaluate our portfolio to determine what -- there's value to be add by selling assets.

We did that a few years ago with BridgeTex. We did that last year with our marine terminals in the Northeast. We've now done that with a portion of MDP and we will continue to look at optimizing our portfolio going forward. So I think you should view that as more as just part of our routine process to evaluate strategic options with our assets and monetize them if we think we can get a premium price.

Theresa Chen -- Barclays -- Analyst

Okay. And at this point, are there other assets in your portfolio or partial interest in assets that you may likely prune further?

Mike Mears -- Chairman, President and Chief Executive Officer

Well, all I'll say is that we regularly look at our assets and evaluate whether or not the market will pay a premium price for them versus what against a couple of benchmarks. What we think the ongoing value is versus the price being paid and also in consideration of what the alternative use of the funds, which most likely in this environment is to buy back equity and whether that's a good value arbitrage as we're evaluating it. So I'm not going to mention whether or not we've got specific assets that we're looking at now or will in the future. I will just say that it's a regular part of our process.

Operator

Our next question is from Jeremy Tonet at JPMorgan.

Jeremy Tonet -- JPMorgan -- Analyst

Just wanted to kind of follow-up, I guess, with the buyback question more directly, I guess. With the capacity here with asset sales, I mean you see current levels as something that makes sense to push on the buybacks in the near term? Just trying to get a sense for how you think about pace.

Mike Mears -- Chairman, President and Chief Executive Officer

Well, again, you're asking a question that's probably more specific than I can answer directly. What I can tell you is that unit buybacks are part of our going-forward plan. I'm not going to comment on the timing or the pace of those. But they are a core part of our capital allocation strategy going forward. I can't. I'm not going to address whether this specific price is a good price or not because I don't think that would be appropriate. But I can't tell you equity buybacks are, as I've just said, to reiterate, core part of our capital allocation strategy.

Jeremy Tonet -- JPMorgan -- Analyst

Got it. That makes sense. Pivoting here, last quarter, you discussed assessing additional renewable fuel opportunities. And do you have any updates here? Is there currently any legislation being considered that would increase MMP's opportunities on this front?

Mike Mears -- Chairman, President and Chief Executive Officer

We are -- we're continuing to evaluate renewable opportunities on our systems. And with the primary focus on transporting renewable fuels by pipe. As you know, all of the ethanol that's consumed in our market area is blended at the terminals. All of the biodiesel in our market areas is blended at the terminals or downstream in the market post our terminals. And the efforts we're evaluating are to transport those products in the pipe, either in an e-form or blended into the fuel, which will do two things. I mean, one, it will create transportation opportunities for us; and two, it's a more efficient way to transport the fuel in the market than trucking.

So we're evaluating that. I don't have an update on that yet. We do think we've got some very promising opportunities with regards to that. If you look at pending legislation in our markets, there's a number of states that are -- that have particularly increased biodiesel blending mandates under consideration. And I think those fit favorably with what our strategic goals are with regards to transporting the fuels on the pipeline.

Operator

Our next question is from Praneeth Satish, Wells Fargo.

Praneeth Satish -- Wells Fargo -- Analyst

When you look at supply versus pipeline takeaway in the Permian, when do you think there'll be enough of a tightening that you might be able to contract some of your spot capacity on Longhorn? And I guess tied to this, do you think emerging pipelines in the Permian makes sense and something that could speed up this process?

Mike Mears -- Chairman, President and Chief Executive Officer

Well, I think that -- see the first question, I think the trajectory before pipeline capacity, crude oil pipeline capacity gets tight in the Permian in a status quo environment is a number of years out. And when I say a number of years, I mean, at least three to five years out before you get to any -- in our view, based on reasonable growth projections in the basin. That's kind of the time frame we would see. In this environment, it's tough and probably for a number of years to -- into the future, even if the market were to improve, there's still a challenge to get shippers to contract because until there's a clear line of sight that there's not going to be enough capacity.

There's really low incentive for shippers to commit to long-term contracts. You may be able to get short-term contracts secure to lock in short term pricing. But it's a challenging environment, as I said, for probably the next three to five years to get long-term contracts on crude oil pipes. Unless something changes, and the things that can change, obviously, are pipeline conversions or mergers that would optimize the use of the assets. And -- So whether or not that's going to happen, I'm not going to sit here and predict, I mean there's a number of challenges currently to get that done.

One of those is many pipelines have existing contracts. And it's difficult to harmonize multiple pipeline systems that all have different contracts with different tariff rates and different conditions into, say, one pipe. There's challenges there to get that done. But I'm not saying it's impossible. And that certainly is one way to reduce the oversupply in the basin. I'm probably going to stop at that.

Praneeth Satish -- Wells Fargo -- Analyst

Great. And then just maybe switching gears slightly. I'm wondering if there's been any thought of increasing your long-term coverage target above 1.2%. I think this level is below some of your peers. So I'm wondering if there's thought of increasing that over time? Or do you think it's appropriate just based on the capex backlog that you see?

Jeff Holman -- Senior Vice President, Chief Financial Officer and Treasurer

I don't think the capex backload really comes into it too much in our thinking one way or the other. We -- our coverage ratio, we think, is appropriate for our business. Other people may need a different coverage ratio and a lot of them, frankly, probably arrived at that ratio by cutting distributions drastically because they were maybe overstretched from whatever the particular reasons, we think it's appropriate for our business.

Mike Mears -- Chairman, President and Chief Executive Officer

I think the factors that are going to come into that for us are different than they are for other parties. As Jeff mentioned, in many cases, our peers have cut their distribution to increase their coverage specifically to lower their leverage level. Well, we don't have that issue. So we're not compelled to increase coverage to pay down debt. So the other reasons why we would allow that coverage level to increase is, for instance, we think that equity buybacks are a better use of cash rather than distributions. And so we would allow that coverage to grow. But that may not always be the case. I mean, that's really an evaluation at a point in time where we may think it's appropriate to distribute it rather than the buyback equity. So that's really for us. What we'll be looking at with regards to coverage ratio. But we think a security of the distribution standpoint, the 1.2 times is appropriate for the stability of our business.

Operator

Our next question is from Tristan Richardson with Truist.

Tristan Richardson -- Truist -- Analyst

Just a quick one on the model side. Just thinking about the power costs you noted, how much -- and progress your optimization team is making, how much of that should we think about it's permanent versus perhaps incidental benefit from the storm?

Mike Mears -- Chairman, President and Chief Executive Officer

Well, the incidental benefit from the storm is a portion of the $25 million number that we mentioned. The majority of the benefit we're getting from the power optimization is permanent. I mean, we are changing the way we schedule our pipes. We are changing the way we use drag producer versus electricity there's a whole host of things that we're doing that will structurally lower our power cost run rate.

Tristan Richardson -- Truist -- Analyst

That's great. And then just on the previous question around buybacks, I mean, I think we think of the framework that you guys think about a lot is just cash-on-cash return, but is distribution coverage a factor when you think about buyback? In other words, getting to that 1.2 times quicker or pulling that target forward rather than awaiting the continued demand recovery to progress?

Mike Mears -- Chairman, President and Chief Executive Officer

No. That's not a driver at all behind our buyback strategy. Our buyback strategy is almost entirely driven by value. We believe that there's value to buy back our equity then we'll buy back our equity. And because it's a good investment, not because it's increasing our distribution coverage.

Operator

And our next question is from Spiro Dounis, Credit Suisse.

Spiro Dounis -- Credit Suisse -- Analyst

I want to ask first on capex. In the past, you'd always sort of referenced the backlog. I think for '21 at one point, it was $100 million, I think you mentioned earlier, something below that now. If all these projects come to fruition. Just curious, when you look at 2022, with $15 million in the hopper now, just curious if you have a similar backlog number you could share in terms of how much that could fill up and then just as we're talking about that, thinking about '21, is it safe to say that $75 million is pretty firm at this point in the year? I know you mentioned below $100 million. So just curious if we should still be expecting something small to trickle in and when we could expect to hear about that?

Mike Mears -- Chairman, President and Chief Executive Officer

Yes. So let me be clear on the distinction between what we announced and a backlog. So what we announced the $75 million this year and $15 million next year. Those are projects that are already approved and they're under construction. The backlog we didn't mention in our notes, which I would define as projects that are potential, but we're not spending any money on them right now, and they're not in the forecast we just gave you. That number is a pretty big number still. I mean there's a lot of potential projects out there that we're looking at. But when we look at the probability of success on those, of achieving the returns we are interested in and the low-risk capital environment that we're in right now.

We're not going to spend money without secure credit-worthy commitments. That's where we're projecting in -- the sense I would give you is that our expectations would be that our capital -- our growth capital budget is probably going to be in the $100 million range per year for the next few years. Now for this year, that's just an estimate. I mean there's a possibility some of these projects we're looking at can be secured at attractive returns, which could move that number. There's also a chance that they won't, and it would lower that number. So I don't want to give a prediction. I'm not trying to forecast 2022, but $100 million is kind of a good rule of thumb. As far as this year, sure, there's the potential that we will approve additional projects this year that would raise the spending this year above $75 million. And probably roll over into '22 and increase the spending in 2022. It's likely that if we get any of those done, they are not going to be gigantic projects, they're really kind of smaller in scale, like the one we just announced or even smaller, even though there's still high-returning projects.

So I think in the last call, I stated that our expectation is that for the year, it wouldn't be higher than $100 million for the year. We just said it's going to be $75 million for the year. And I think $100 million for the year is probably still kind of an upper range. But I just want to caveat that, but that's just an estimate. I mean, we're not going to -- if we have a very attractive, high returning, low-risk project that we're able to secure, we're not going to use that $100 million as a cap. I mean, we will continue to invest in those types of projects. It's just as we look at the landscape right now, we think the most likely case is we're going to be in the $75 million to $100 million range by the end of the year.

Spiro Dounis -- Credit Suisse -- Analyst

Got it. That's helpful, Mike. Second question, just curious, KMI noted that their customer behaviors have changed following the storm, and that was driving renewed interest in transport, other services, obviously, you're in a very different business. I haven't seen the same price actions to the extent we saw in natural gas. But just curious if you've noticed the shift or change in customer interest or behavior following the storm.

Mike Mears -- Chairman, President and Chief Executive Officer

We haven't. I mean I think it's just a very different experience through the storm. I mean there was obviously a considerable stress in the natural gas markets that I would imagine would lead to customers thinking about doing things differently, but that didn't happen on the refined products market. So we were able to operate through the winter event or products pipe with almost no disruption of any consequence. So no, we're not seeing any change in customer behavior.

Operator

Our next question is from Keith Stanley, Wolfe Research.

Keith Stanley -- Wolfe Research -- Analyst

First question just on the refined products volume outlook. Is there any way to sort of roughly characterize where you think volumes were versus normal in Q1? And than what the guidance assumes over the balance of the year, just the trajectory of volumes versus normal?

Mike Mears -- Chairman, President and Chief Executive Officer

Well, I think, overall, our experience in the first quarter was consistent with what we expected. In total, it was a little different than what we expected by product. Our diesel volumes were probably a little higher than we expected. Our gasoline volumes were probably a little lower than expected. But in total, they were consistent with our overall volume, and that's what led to tweaking the forward numbers a little bit. So I don't know if I have any more to add to it than that.

Keith Stanley -- Wolfe Research -- Analyst

Just any...

Mike Mears -- Chairman, President and Chief Executive Officer

I would just add to this, too. I mean -- and I've said this in past calls, but projecting refined product demand, in this environment is, to some extent, a fools game because there's so many variables that impact things. And for instance, we didn't talk about this earlier. It's likely that some of the softness we saw in the gasoline demand in the first quarter versus expectations, had to do with the weather events. That, that likely affected those numbers somewhat downward. We can't quantify that, but it just stands to reason that people were out and about less during the extreme cold weather events than they would have been otherwise.

But going forward, when you look at the pace of the vaccinations, all the things are relevant to reopening the economy fully, the paces of vaccinations, the spikes in certain states, the comfort level that businesses have to bring people back to their offices. To a large extent, it's hard to predict that with great precision. So I'd just -- I would highlight that as we talk about forward forecast.

Keith Stanley -- Wolfe Research -- Analyst

Okay. Second question, just in the release, and you guys have talked about this before, having a six to 8 times EBITDA multiple target for growth projects. Can you remind me how you think about return thresholds for acquisitions relative to that six to 8 times multiple? And then relatedly, if you were to consider acquisitions, is it more likely you'd look at bolt-ons within your kind of core refined products network? Or would you look more at diversification opportunities?

Mike Mears -- Chairman, President and Chief Executive Officer

Well, I can tell you that our view on acquisitions is fairly conservative. As you can expect, since we've done very few in recent years. I don't know if the six to eight multiple really is applicable to an acquisition depending on what the acquisition is and the nature of what it is you're buying. But we still look to risk -- appropriate risk compensated return. So if we're buying the refined products, pipeline or terminal that was a bolt-on to our system, where we had a clear line of sight to the value. We -- the risk around that, in our view, is lower then, say, for instance, in going buying a crude gathering system in West Texas. So we would probably have a lower return threshold than that type of business. So that being said, you're right. I mean, bolt-on type assets would be more attractive. But we would look at assets that aren't bolt-on. We would look at diversification.

But I would tell you, just by the -- the M&A market or acquisitions, especially at the asset level, are not at the top of our priority list at the moment. We look at things. We evaluate opportunities we determine whether we think we can be competitive with our conservative view to acquisitions, and we'll participate. But as you know, and I keep highlighting this, our track record suggests that the likelihood we're going to be successful is not extremely high. And when I say that, it sounds like a negative, but I can tell you, we've -- when we look back historically, the assets we've evaluated, and I say historically, in the past five or six years. In hindsight, there's probably not a single asset that we looked at bid on. That we wish we had beat the high bidder and acquired it. We're actually in the opposite position. We're thankful we didn't buy it. And so that colors our view and our analysis when we're looking at current assets.

Operator

Our next question is from Shneur Gershuni, UBS.

Shneur Gershuni -- UBS -- Analyst

Most of my questions have been asked and answered. So I just have a few follow-ups to some of the questions that were asked. I think you had multiple questions with respect to coverage ratio and so forth. Just to clarify, if you're doing buybacks, does that not naturally improve your coverage ratio? I just wanted to clarify because there sort of seems to be some back and forth on that.

Mike Mears -- Chairman, President and Chief Executive Officer

It does. So let me clarify what we mean when we talk about the 1.2 times coverage ratio because I think most people are perceiving that as a cap. And it's not -- I mean, when we put the 1.2 times, really, what we're -- the way we're looking at that is what level of coverage do we feel comfortable with -- related to the stability of our business operating at. In other words, we prefer not to go below that unless there's an extreme dislocation like we saw last year when we went below that. But under normal circumstances, we wouldn't want to go below 1.2 times.

Now that doesn't mean it wouldn't naturally go above 1.2 times, just with the growth in the business. And historically, when that's happened, we've raised our distribution. And we've kept that coverage right around that 1.2 times level. Going forward, as our business grows and adds we buy back units and the business improves from an EBITDA basis. That coverage will grow, and it will go above 1.2 times. In this environment, the old practice of just raising your distribution to keep the coverage near 1.2 times is still an option, but it's not the only option given the valuation of the equity. Buybacks are now real. Use of proceeds for capital is diminished.

Obviously, that was the other option for the use of excess cash above our 1.2 times coverage. So that's the way we think about it. 1.2 times is what we feel comfortable in. We don't really want to go below that too much. But if we go above it, then it's just a matter of what do we do with the available cash above that? Do we buy back equity to increase the distribution, do we invest in capital? We don't make that decision based on where we want the coverage to be. Mean if it's at 1.5 times, and we're still in an environment, we're buying back equity is the right choice, then we're fine with 1.5 times, and we'll buy back equity. If we're in an environment where we think it's better to raise the distribution, we'll raise the distribution and bring that coverage back down. But all that will be a point in time analysis when it's time to make it.

Shneur Gershuni -- UBS -- Analyst

Right. Just to clarify, so basically, if you buy back 10% of your units, your coverage would be 10% higher, and then you would have a decision to make.

Mike Mears -- Chairman, President and Chief Executive Officer

No.

Shneur Gershuni -- UBS -- Analyst

Sorry.

Mike Mears -- Chairman, President and Chief Executive Officer

I mean just a caveat there. I mean, in general, that's true. But if we sell an asset to buy back units, it's not one-for-one because we're reducing income but if it's just from free cash flow above our distributions, yes.

Shneur Gershuni -- UBS -- Analyst

Okay. Perfect. And my follow-up question, you sort of talk about refined products being above the 2019 level. But there's been a lot of assets that have been added as well, too. Is there a way to give us -- and I know this question was asked on the call during the fourth quarter, but is there a way to give us a kind of like where your expectations rest with respect to kind of an apples-to-apples capacity utilization of your system as it sits today on the refined product side with respect to your guidance?

Mike Mears -- Chairman, President and Chief Executive Officer

Well, at this point in time, no. And the reason is there's so many moving parts, and I think we've tried to explain that in the last call. It's possible perhaps if we get down the road and we get back to a stable environment for refined product demand, which I don't know when we'll know we're at that point. But then maybe you can make some comparisons. But when everything is in flex, again, trying to determine whether a barrel that shipped on a pipeline has been expanded, is a barrel that would have shipped anyway or if it's only shifting because of the commitment, it's very difficult to determine when the overall demand has dropped so dramatically. So that's the difficulty we have and why we don't try to carve that out.

Jeff Holman -- Senior Vice President, Chief Financial Officer and Treasurer

We also just now -- we don't -- we wouldn't typically think about that question in terms of capacity utilization on our system because it's a network that's just not usually the way we would be characterizing that. First of all, second of all, I will say, our projections do have lower demand for all products versus 2019 as opposed and then that's improving throughout the year. But it's very difficult to start, as we discussed on the last call, to parse out base versus growth with any specificity for the reasons Mike just mentioned.

Operator

And our next question is from Theresa Chen, Barclays.

Theresa Chen -- Barclays -- Analyst

I just had a follow-up for Jeff, actually related to the cost savings. Granted this quarter, there were some volatile items in that line item. And I just wanted to get a sense of what the cash run rate in OpEx should be going forward once you strip out like the gains that were experienced for -- are the most recent quarter?

Jeff Holman -- Senior Vice President, Chief Financial Officer and Treasurer

Well, without getting in too much detail, I would say we -- Mike mentioned a bucket of around $25 million total impact related to the storm, which was made up of a number of things, revenue items and expense items. Less than half of that was related to expenses. So if you were looking for one-off things related to the storm, that I would say that's kind of the bookend, I would give you. But we also had some other onetime items in the quarter. I think Mike mentioned that as well, that we expect some of that to reverse later in the year. So it's a little bit more kind of complicated than that. Maybe worth mentioning as well, we -- when we came into the year, we gave a figure of I believe $50 million of lower expenses we expected versus what would have been the case, absent our optimization effort.

And so those are on pace, I'd just say that to be realized this year versus what we would have otherwise been. And so some of the year-over-year type variances, you will see, incorporate that. And the first quarter was reflective of that.

Operator

And our next question is from Michael Cusimano, Heikkinen Energy.

Michael Cusimano -- Heikkinen Energy -- Analyst

Just one question for me. On the crude oil transportation revenue per barrel, I thought it was up quarter-to-quarter. And I was just hoping for more details if that was a function of lower Houston distribution volumes? Or if there are any deficiency payments in that number? And then also like how we think about that going forward.

Jeff Holman -- Senior Vice President, Chief Financial Officer and Treasurer

Bear with us for a minute. Yes. The single biggest variance is the change in HDS volumes. So you're right. That's really it. And as we've tried to point out typically, when it was -- those move a lot, they can definitely impact that average rate per barrel quite a bit. That's why we try to give a little bit more color about pipeline.

Michael Cusimano -- Heikkinen Energy -- Analyst

Okay. And did you all have any deficiency payments in 1Q related to the storm?

Jeff Holman -- Senior Vice President, Chief Financial Officer and Treasurer

Not material.

Mike Mears -- Chairman, President and Chief Executive Officer

Not -- we didn't have anything related to the storm. But otherwise, they were not material.

Operator

And our last question is Michael Lapides, Goldman Sachs.

Michael Lapides -- Goldman Sachs -- Analyst

Just curious, coming back to the Permian oil pipeline markets. If we don't see a rationalization of supply or a material pickup in production, how do you think about kind of when you get to that three to five years from now, how do you think about today or over the next year about managing what the risk would be if the kind of the mark-to-market on tariff seeds kind of closer to what some of the newer pipes are getting in the to $1.25 or $1.35 a barrel range. Are you at a stage yet where you have to think about how do I manage my balance sheet in case kind of everybody's tariff goes to $1.25 whether it's in year three or year five or as contracts roll, and it's not just you, it's kind of the industry wide. You've got some runway given the contracts you have right now, but I'm just curious about how you're thinking about the long term.

Mike Mears -- Chairman, President and Chief Executive Officer

Well, that's a good question. I mean, first of all, I'd say we've been through a round of contract renewals on Longhorn already. So our rates on Longhorn are already substantially lower than they were under the original contract structure. So we've rerated considerably with regards to that already on Walmart. On BridgeTex, that risk is there, even though the gap between our contracted rates in kind of the current market. Well, current market, I'll set that aside for a second. But the range of rates you mentioned is not as large as it was a Longhorn before we recontract, but it's still a risk of re rating.

I mean the fact of the matter is, if you get to -- if you fast forward to a point where all the contracts on all the pipes have expired. And you still have material overcapacity. And that's a big assumption. Again, if you go out five years from now, hopefully, the production in the basin has come up to a level or something that's been rationalized such that you don't have an acute problem. But assuming that nothing's changed, it's -- you're going to have a very low tariff environment. And it's real -- and again, it's not a matter of contract. It's going to be a matter of spot movements on pipes. And what we're trying to do, first of all, is to position ourselves to get the volume.

Before we even talk about the rate, you need to get the volume. The rates are going to be very competitive. There's analysis now that shows that Corp... It's cheaper to ship the Corpus than it is to Houston. Well, that's based on current contracts. If there are no contracts in place, the rates are all going to be the same. I mean, everyone's going to be trying to move the barrel to their destination, the rates are all going to be the same. You're not going to have one that's lower than the other. And so what we're working on is creating an environment where shippers prefer to go to Houston. And there's reasons to go to Houston, you've got a large demand market. You have export capability.

That's sufficient to handle all the pipe capacity to Houston. Corpus can argue perhaps that it's got a less congested port. But one thing that we announced a few months ago is that we are advancing a futures contract in Houston that we believe will make it an attractive market for traders to ship to. We don't have anything to announce on that today, but it is under development, and we hope to have something to announce in the future. It's still -- and we think it's going to be very attractive when it's in place.

So that being said, and I should've mentioned this earlier, we think about rationalization frequently. And I don't want to go into too many details on what we're looking at for the possibilities for our pipes. But we evaluate alternative store pipe, optimizing our crude portfolio independent of partnering with other parties. So that activity is going to go on. And over the -- when you talk about a three to 5-year time horizon, there's potential for us to find opportunities that make sense to optimize the use of the assets. Just as all of our peers are certainly doing and to the extent that they're successful in doing it, it helps everyone else have. So I'll just leave it at that.

Operator

And gentlemen, I will turn the call back over to you for closing remarks.

Mike Mears -- Chairman, President and Chief Executive Officer

All right. Well, thank you, everyone, for your time today. Thank you for your interest in Magellan, and we will talk to you soon.

Operator

[Operator Closing Remarks]

Duration: 59 minutes

Call participants:

Mike Mears -- Chairman, President and Chief Executive Officer

Jeff Holman -- Senior Vice President, Chief Financial Officer and Treasurer

Theresa Chen -- Barclays -- Analyst

Jeremy Tonet -- JPMorgan -- Analyst

Praneeth Satish -- Wells Fargo -- Analyst

Tristan Richardson -- Truist -- Analyst

Spiro Dounis -- Credit Suisse -- Analyst

Keith Stanley -- Wolfe Research -- Analyst

Shneur Gershuni -- UBS -- Analyst

Michael Cusimano -- Heikkinen Energy -- Analyst

Michael Lapides -- Goldman Sachs -- Analyst

More MMP analysis

All earnings call transcripts

AlphaStreet Logo

Invest Smarter with The Motley Fool

Join Over 1 Million Premium Members Receiving…

  • New Stock Picks Each Month
  • Detailed Analysis of Companies
  • Model Portfolios
  • Live Streaming During Market Hours
  • And Much More
Get Started Now

Stocks Mentioned

Magellan Midstream Partners, L.P. Stock Quote
Magellan Midstream Partners, L.P.
MMP
$48.18 (0.88%) $0.42

*Average returns of all recommendations since inception. Cost basis and return based on previous market day close.

Related Articles

Motley Fool Returns

Motley Fool Stock Advisor

Market-beating stocks from our award-winning analyst team.

Stock Advisor Returns
316%
 
S&P 500 Returns
112%

Calculated by average return of all stock recommendations since inception of the Stock Advisor service in February of 2002. Returns as of 07/03/2022.

Discounted offers are only available to new members. Stock Advisor list price is $199 per year.

Premium Investing Services

Invest better with The Motley Fool. Get stock recommendations, portfolio guidance, and more from The Motley Fool's premium services.