Q1 2022 Magellan Midstream Partners LP Earnings Call
Greetings and welcome to the Magellan Midstream partners first quarter 'twenty two earnings call. During the presentation. All participants will be in a listen only mode. Afterwards, we will conduct a question and answer session at that time. If you have a question. Please press star one.
One followed by the four on your telephone if at any time during the conference you need to reach an operator, Please press star zero.
As a reminder, this conference is being recorded Thursday may five 2022.
I would now like to turn the conference over to the President and Chief Executive Officer, Aaron Milford. Please go ahead.
Hello, and thank you for joining us today to discuss Magellan's first quarter financial results before getting started we must 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 and form your own opinions about magellan's future performance.
This is my first opportunity to speak publicly as magellan's CEO I'd like to express how honored I am to lead this exceptional organization as you know I've spent my entire career with the company, including serving as Chief Financial Officer, and most recently as Chief operating officer, So, even though I'm new to the CEO role I have been around for a while and.
I intend to remain focused on the overarching goal of maximizing long term investor value, while retaining our strong financial position and consistent disciplined approach. The Magellan is known for.
As reviewed at our recent analyst day, no matter, which industry projections you consider.
Our services to be needed for a very long time in our company is poised to serve our nation's critical energy needs for decades to come.
We remain committed to doing things the right way and ensuring that we are operating a safe and efficient manner at all times I am confident the magellan's future and our ability to create long term value for our investors.
With that I'll turn the call over to our CFO , Jeff Holman to briefly review our first quarter financial results, then I'll be back to discuss our latest outlook for the year as well as the status of a few of our expansion projects before answering your questions.
Thanks, Darren first let me mention that as usual I'll be making references to certain non-GAAP financial metrics, including operating margin 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 measures.
Earlier. This morning, we reported first quarter net income of $166 million compared to $221 million in the first quarter of 2021.
At a high level the year over year decline, primarily resulted from mark to market adjustments on commodity hedges in the current period as well as from the favorable impact of winter storms on our 2021 results.
Adjusted earnings per unit for the quarter, which excludes the impact of market to market adjustments was $1 <unk> exceeding our guidance for the quarter of $1 <unk>.
Primarily due to the impact of higher commodity prices and our tender revenue and product gains as well as higher than expected refined product shipments.
DCF for the quarter of $10 $65 million was.
It was $11 million lower than last year.
Primarily due to the favorable impact on the prior year results of the 2021 winter storms just mentioned as.
As a reminder, we estimated a favorable impact of about $25 million from the storms last year.
Free cash flow for the quarter was $240 million, resulting in free cash flow after distributions of about $19 million.
A detailed description of quarter over quarter variances is available in the earnings release, we issued this morning, so as usual I'll just touch on a few highlights of the quarterly results.
Starting with our refined products segment operating margin of $235 million was approximately 10% lower than the 'twenty one period, mainly due to the mark to market adjustment as I already mentioned.
Our fee based refined products business actually increased between periods as we've seen throughout the past year. We continued to benefit from overall demand recovery as life has gotten more and more back to normal along with additional contributions from our Texas expansion projects. Overall, we saw an 11% increase in total refined transportation volumes relative to the buyer.
A year period.
Average transportation rates were slightly lower as a higher proportion of short haul shipments, which moved at a lower tariff.
More than offset mid year 2021 tariff increases.
As we've noted before we expect this trend to continue throughout the year, mainly due to the final ramp up commitments on our east Houston to Hearne project. It means a shorter distance and at a lower rate than our average.
Operating expenses for the refined products segment decreased slightly between periods.
<unk> from more favorable product overages, which reduced operating expenses more than offset other expense increases we experienced this quarter, including higher power costs, which were higher primarily due to the benefit in the prior year from gains on power hedges again in connection with the winter storms already mentioned.
Equity earnings decreased due to the sale of a portion of our interest in our Pasadena joint venture.
You'll recall that that sale occurred in April of last year. So this should be the last time, we need to mention this variance.
Product margin the largest variance for the quarter decreased between periods as already noted this was due to unrealized losses on our hedging activities in the current period as a result of the recent increase in commodity prices versus the unrealized gains in the prior year.
With respect to our gas liquids blending sales are realized margins actually increased year over year to about 40 cents per gallon versus closer to 30 cents per gallon in the prior year period.
Turning to our crude oil business first quarter operating margin was approximately $104 million.
Down 5% from the same period last year.
Longhorn volumes averaged about 235000 barrels per day during both periods, while we benefited from a higher average rate during the recent quarter.
The mix of customer volumes move during the period.
On our Houston distribution system, lower tariffs shipments were offset by higher terminal throughput fees as more customers elected the simplified pricing structure for our services within the Houston area.
We are seeing growing customer interest in such simplified pricing arrangements with the result that even though we have added connections to the HTS and the volume of physical barrels we move has increased.
Resulting incremental revenues are showing up as terminal throughput fees.
Other than as transportation revenues that are reflected in our transportation statistics.
So to be clear, while this change impacts our reported volumes such that our Acs volumes for the year will be different tomorrow for original guidance. This change really just reflects a change in which bucket the related revenue falls out.
Looking briefly at expenses, although operating expenses for the crude oil segment declined only slightly I'll note that the 'twenty. One period also benefited from the winter storm related power hedge gains already mentioned.
Lower integrity spending lower pipeline rental costs more than offset the relatively higher power expense in the current period.
Moving on to our crude oil joint ventures, Bridgetex volumes were approximately 285000 barrels per day in the first quarter of 'twenty two down from nearly 300000 barrels per day in 2021, partially due to the timing of when our committed shippers have elected to move volumes under their commitment.
While saddle horn volumes increased more than 220000 barrels per day compared to approximately 180000 barrels per day, and even before primarily driven by the ramp up of new commitments associated with the pipeline expansion.
I did also want to point out that we recognized additional deficiency revenue for both the Bridgetex and I believe our pipelines during the quarter, which more than offset lower average rates on saddle horn, resulting in a slight increase in overall equity earnings for the crude oil segment.
It's important to note that although this recognition of deficiency revenue, resulting in higher equity earnings associated cash payments were already youre seeing from customers in prior periods and our proportionate share of those payments were distributed to us by our joint ventures and recognized by us at DCF at that time.
Just a few other items I'd like to touch on first G&A expense increased $18 million between periods, primarily due to higher incentive compensation costs related to the recent retirement of our former CEO , which resulted in an acceleration of the expense associated with his outstanding incentive comp awards.
In addition, we also reported higher incentive comp expense overall, just due to the Johns improved financial results.
Interest expense increased slightly during the current quarter, primarily due to a higher average debt balance as of March 31, the face value of outstanding debt was $5 3 billion.
The weighted average interest rate on that debt of about four 2%.
Our leverage ratio at the end of the quarter. It was 365 times for compliance purposes, which incorporates the gain we realized on the sale of part of our interest in Pasadena into 2021.
Excluding that gain leverage would have been a little over three eight times.
And that brings us to the last item I'll touch on today, which is capital allocation as you've heard us say before we remain committed to maintaining the financial discipline. We are known for while delivering long term value for our investors through a combination of capital investments cash distributions and equity repurchases.
During the first quarter, we repurchased over 1 million units at an average purchase price of just under $48 or total spend of $50 million, bringing.
Bringing total repurchases since inception to $17 5 million units per year.
$150 million.
As previously stated we currently expect free cash flow after distributions to generally be used to repurchase our equity.
Of course, as we are always careful to note the timing price and volumes and unit repurchases will depend on a number of factors, including expected expansion capital spending free cash flow available balance sheet metrics legal and regulatory requirements as well as market conditions and the trading price of our equity in.
In particular I'll note that we remain committed to our long standing four times leverage limit and also the timing of the proceeds from the independent terminal sale remains subject to the government review process, which we believe is nearing completion.
With that I'll turn the call back over to Ara.
Thank you Jeff.
Considering our better than expected first quarter results as well as our outlook for the remainder of the year, we have increased our <unk>.
22, DCF guidance by $15 million to 1.09 billion.
As everyone knows the commodity pricing environment is higher than originally expected for the year, which has benefited the value of our product Overages as Jeff just noted.
When might naturally expect our butane blending margins to also benefit from the increase in commodity prices. However were still forecasting an average blending margin of about 40.
Per gallon for the full year.
A significant reason for the muted impact of higher prices on our blending business is that we had already hedged margins for most of our spring blending activity before most of the run up in prices had occurred.
In addition, as we discussed a few weeks ago at our analyst day the basis differential for gasoline sold in our mid continent markets has been quite unfavorable recently and has resulted in lower net margins than we had originally expected.
Although we utilized futures contracts to hedge most of the product margin exposure related to our liquids blending activity our ability to hedge mid continent basis differentials efficiently is limited and so we are generally subject to those differentials at the time, we actually sell the blended guests which of course means lower net margins when differentials.
Or is unfavorable as they have been lately.
For the year. These lower near term margins are expected to be essentially offset by higher margins for the fall blending season.
We have made significant progress locking in fall blending margins at this point with about 80% of expected fall activity hedged at margins of around 50 per gallon.
Given the attractive margins currently available. We've also started hedging next spring as well with.
It was about 40% of our spring 2023 activity hedged at margins of about <unk> 60 per gallon of note. These margin estimates assume the <unk>.
<unk> differential returns to be more in line with historical trends as the year progresses.
With our higher overall DCF guidance, we now expect distribution coverage of 124 times for 2022, which represents more than $200 million of that.
That's cash.
Combined with the $435 million proceeds we expect to receive in the next month or so from the pending sale of our independent terminals, we should have significant cash flow available to create additional value for our investors consistent with our capital allocation priorities.
As Jeff previously mentioned, we currently expect free cash flow after distributions to generally be used to repurchase our equity.
However, we also continue to pursue low risk expansion capital projects that meet or exceed our 6% to eight times EBITDA multiple threshold to create future value for our investors.
Based on projects already committed we now expect to spend approximately $70 million in 2022 on expansion capital. This estimate is $20 million higher than last quarter in part due to the addition of the new investment to further improve connectivity of our crude Cushing crude oil terminal.
We also launched an open season last week for a potential 15000 barrel per day expansion of our Texas refined products pipeline to El Paso.
From El Paso, the gasoline and diesel fuel can be further distributed to new Mexico through our system, we'll continue on to Arizona, where Mexico via connections to third party pipelines are delivered to those important markets.
We ended up moving forward with this project, which we have not yet included in our updated spending estimate for the year, we expect the expansion to cost around $25 million and to be completed by mid 2023.
This potential opportunity is consistent with the theme of other pipeline expansions currently underway, which have also been designed to fill.
<unk> gaps created by changing market conditions, mainly resulting from recent closures, we're repurposing of refineries within our asset footprint.
Because of the extensive nature of our system, we were able to satisfy market demand by sourcing products from a broad set of origin points demonstrating the flexibility of our refined product system that can access nearly 50% of our nation's refining capacity.
Along those lines, our current refined products pipeline expansion to Albuquerque is expected to start up next week. After a short delay related to some additional pump works that needed that was needed. In addition, our Kansas, Colorado expansion is progressing and still expected to be in service by the end of the year to help meet demand.
In the Denver market.
That concludes our prepared remarks operator.
We're ready to open the call for questions.
Thank you.
I would like to register a question. Please press the one followed by the four on your telephone you wish you were three Tom prompt to acknowledge your request. If your question has been answered and you would like to withdraw your registration. Please press the one followed by the three.
One moment please for the first question.
First question comes from the line of Pardon Me Satish with Wells Fargo. Please proceed with your question.
Thanks, Good afternoon, I guess I just wanted to see if I could get an update on.
On the potential project to reverse Longhorn I guess, what feedback have you received from from customers and shippers so far and if you do get enough contracts to move forward, but one when would you expect more information on that and two do you anticipate any significant permitting challenges.
Starting with the first part of your question, we continue to evaluate.
The potential to reverse longhorn.
We don't have a significant update for you today as what we really want to see and understand is what does the market need and want.
First step to that in some respects is to understand what kind of demand we get for this open season, we have out there.
Started last week.
We can do the 15000 barrel a day expansion with our current assets without the need to reverse longhorn, but depending upon the demand.
May or may not bring the longhorn reversal potential forward.
The second part of your question regarding regulatory hurdles.
Reverse the line.
Crude refined products and recall that the line was originally in refined products. We do expect a permitting process that we're going to have to go through.
And Thats one of the things that we continue to evaluate so the reversal of a longhorn isn't something that we can just sort of snap our fingers and make happen overnight, it's something that we'll need to evolve first step and that is to really evaluate whats the demand for refined products out west.
And as needed.
Got it and maybe just to follow up on this on longhorn I mean, it sounds like the whole process to convert longhorn if we did it would take would take a while.
And at the same time.
Production is starting to pick up in the Permian.
Permian oil could kind of tightened back up in the 2025 timeframe. So is it fair to assume that if you did convert longhorn you'd you'd do it. So that you would earn a higher return than if you kept it in crude service and potentially benefited in in 2025 from contracting at say $1 50 or $1 75.
Yes.
Yes, certainly part of the analysis is the longhorn it's valuable today and the service that exam.
So it doesn't make the decision to reverse it it would be along the lines of what you. Just described we've seen more value when reversing it and keeping it in its current service. So you're right. That's part of the overall valuation and certainly.
Permian production, increasing youre seeing some fundamentals I think improve.
In the Permian basin crude pipeline transportation.
That's part of the equation is evaluated where do we think it's going to be and what creates the most value for us.
Got it thank you.
Our next question comes from the line of Theresa Chen with Barclays. Please proceed with your question.
Hi.
Thanks for taking my questions I first wanted to ask about the FCC process as far as the southeast terminal sales go how is that going and are related.
Related to your comments about using excess cash flow towards repurchases, especially once you get.
The proceeds can you give us a sense of the pace of repurchases that you plan.
Okay.
Well two reasons I'm going to start with your first question. The FTC process has been a long one started sort of last year. The good news is is where we're hopeful that we're approaching the end of that process.
You may recall the guidance, we gave this year assume that we.
Owned the independent terminals to the middle part of the year as we seem to be on that track. So we think we're reaching the end of that process and we're hopeful that we're going to close as I said in the next month or so.
In terms of the pace of buybacks.
The pace is one that.
It will depend it will depend on where our units are trading it would depend on what growth.
Capital projects to come up with so we don't have sort of a defined pays to tell you. It's reasonably be X amount over these amount of months. All would tell you is obviously, we are going to generate free cash flow from operations that we're going to have these proceeds on top of it. So we're gonna have ample opportunity to make the decisions of any delay in terms of.
Buying our units by but I don't have a.
Ah prescribed pace for you to think about it all with all it would suggest.
That you consider the amount of proceeds that we have in our ability to buy back units contingent upon.
All the caveat that we put around it.
Understood.
And on the refined products side.
Clearly spent a lot of time on.
Going through.
The various projects.
<unk> opportunities.
And additional capacity.
Westward.
Including your service to Albuquerque expansion currently under contemplation commitments to El Paso by mid 2023, as well as additional capacity towards the Colorado market.
One of your large cap MLP competitors.
Similar projects out there too.
Very similar markets or exact markets I'm. Just curious you know as you look towards the medium term.
Do you think there could be some overcrowding in these spaces such that the tariffs or the commitments could be competed away how should we think about that.
Well in terms of competing projects.
We think our expansions that we have into <unk>.
El Paso specifically.
We are considering those competing projects that are out there as are the folks making commitments to us so it's a known.
Quantity in terms of what we're each trying to do we still think there's a lot of demand.
Going west So we're still very optimistic about getting the commitments that we will need to expand our pipeline and then if you look at the markets themselves. They don't overlap perfectly if you put them on a map there in a slightly different geographic areas, but we're not ignoring the fact that there is.
The new capacity come into these markets.
Which you can access all the way up to western Colorado.
So we're taking that into account we think if you look at the growth that's happening in Colorado overall, if you look at the growth in volume Thats occurring.
Paso, Mexico and points further west of that look at the growth that can occur.
Within that even the Permian.
I don't think we're at a point, where we're overly worried about too much capacity.
As we move forward, we still see quite a bit of opportunity out there.
Let's see.
Got it.
Lastly, just as we think about.
Balances in shifts and specifically the Gulf Coast.
Was wondering one are you connected it to the lined out Houston refinery and its that eventually shuts down or will that be taking some volumes off of your refined product system.
Q as the Gulf Coast seems to be the incremental supplier of clean product, especially diesel to international markets that seems to be tighter and tighter given.
Russian distillate, what's coming off the market.
Can you see kind of like a pull them away from your.
System that pipes, midcon and beyond in favor of exports, how should we think about that.
So, let's let's take the first part we do have a connection to.
The lyondell refinery, but what I would say is we don't have a lot of exposure. So I wouldn't I wouldn't draw any conclusions from that refinery shuts down.
That should mean something negative for our assets because frankly, we can add to a bunch of other refineries and the demand that we had at the end of our packages of demand. So I don't foresee any significant risks related specifically.
To Lyondell now to your question about how should we think about export markets.
And obviously things are really tight with diesel the world demand of the draw.
From the Gulf Coast is heavy crude.
For diesel demand, so that impacts the price in the Gulf Coast.
Which draw tends to draw barrels to the Gulf coast for sure, but you're also talking about many of the markets were connected to a still premium margins that have to be supplied so it all just starts working out in the netback equation for the refiners.
One refinery once the ship more barrels overseas the diesel price has changed in the markets have to adapt because reality is the demand is still there.
And someone has to fill it the beauty of our system is really the flexibility that we have Gulf coast origin up to the group potentially which hasnt made a lot of sense of late like it did last year because of exactly what you're talking about theres more demand in the Gulf coast for products, we are seeing fewer moves to the Gulf coast up into the mid continent.
But the opposite can also occur to some degree where it actually draws.
Gulf Coast refiners export more it can draw barrels from the mid continent places in Texas, and even potentially further west so theres a bit of a balance there that the thing I would keep in mind is.
At the end of our pipes.
We're serving the demand that exist and that demand is not going away. So as the supply is shift.
And given the breadth of our system.
We're able to adapt to that and keep those markets supplied from for many different origins, where not just of course singles.
Single threaded to the Gulf Coast. So that's that's the.
Really one of the strengths of our system does that answer your question.
Yes, thank you very much for the thorough responses.
As a reminder to register for a question press one four.
Our next question comes from the line of Jeremy Tonet with Jpmorgan. Please proceed with your question.
Hi, good afternoon.
Good afternoon Jeremy.
Thanks, just wanted to.
Pivot a little bit here and.
Talk about I guess your splitter here, where I think that the contract for the Corpus Christi condensate splitter is coming up in the not too distant future.
And just wondering how you think about that as at this point when that expires would you look to do another tolling arrangement with <unk> to sell the asset would you use the asset yourself. It seems like there's some pretty good economics, there with diesel and just wondering how you think about your options at that point.
We think we have a pretty good slate of options you know given that for the most part.
We don't like to take a lot of commodity risk, where it is not justified or we don't have expertise per se.
So we recently did a tolling deal a customer pays.
Pays a fee and then there's the arranging the crude oil and then taking the offtake in and making money doing so.
So if we can totally in a reasonable way.
Our preferred option frankly.
But at the same time, we're also developing a lot more expertise through the years. So if it came to we needed to run it.
We could probably do that even though thats not our first.
Our first choice I think we would have the capability to do that if we chose to do it so.
The splitter side of things how would think about it is the asset has gone up in value in terms of the money that you can make in the margin that is available with that asset. So we should have a number of options, including just renewing the toll that we have right now.
Sort of sustain the economic benefit of that split or to us which path we take.
<unk> is a little uncertain right now we just don't know we're not at the point where decisions have been made but.
Not overly concerned about continuing to drive significant value from exposure.
Got it.
Helpful context, there and maybe just kind of taking a step back and overall demand recovery. If you could just expand a bit more I guess on what trends Youre seeing out there currently in your markets and pace of demand recovery and expectations over the balance of this year or further if you're willing to share just trying to get a sense for how that works for you.
So you may recall at the beginning of the year, we gave guidance that we thought.
On a year over year basis, So 2022 for the year versus 2021 for the year, we expect volumes to increase 4% and.
And that's still where we expect it to be so on a serial basis, we expect growth in our refined products volumes in that growth of course is driven by recovery, which we're still seeing in some of our markets.
And also the contribution from our growth projects that we brought on over the last few years. So we continue to expect growth of year over year about 4%. We've got some markets up in the northern part of our system frankly, there has been a little slower to recover.
But they are recovering.
So we've got a pretty I think an optimistic outlook for our volumes youre going to grow this year versus last year.
Okay.
<unk>.
That's that's very helpful. I appreciate the color. Thank you for that.
Youre welcome.
Our next question comes from the line of Michael Lapides with Goldman Sachs. Please proceed with your question.
Hey, guys in and again I mentioned this at the analyst day, Congrats on the new role.
Just a cost question.
We all kind of know when you talk a lot about kind of what revenue per barrel increases are on both the indexed and on the competitive side for the refined product system can you talk to a little bit to us a little bit in this kind of high inflationary market. What you are expecting cost wise this year and whether you think it stays elevated that way going.
In the 2023.
Well, it's a good question Michael.
Michael and thank you for the well wishes as well.
Inflation, it's interesting we see pockets of our business today, where we're seeing some inflation primarily on labor and think about our maintenance capital, where we're doing work hiring contractors. We are seeing some rate inflation, there, although I wouldn't raise the alarm bell about the inflation.
We're seeing it but it's hard for us to really see how much that's going to translate to extrapolate where change from here.
And then when you so we're seeing some of it but again I wouldn't raise any alarm bells on the expense side.
Secondly, you have to combine what's happening on the inflationary front with a lot of the work we're doing to optimize our business. So when you look at overall expense growth for our business, we're shooting to come in well under inflation in total regardless of where that is because we're optimizing our business while at the <unk>.
Same time experiencing some inflation that we hope to offset most of.
So we think we have a good equation for managing our costs as we move forward, even if we do see some.
Inflation in certain parts of our business. So we're not changing our outlook with that.
But we're going to have to wait and see to some extent as well the rest of the year plays out.
Got it. Thank you much appreciate it.
Mr. <unk> there are no further questions at this time I will turn the call back to you. Please continue with your presentation or closing remarks.
Well. Thank you all for your time today and your interest in Magellan.
And I Hope you guys have a great day.
That does conclude the conference call for today, we thank you for your participation and ask that you. Please disconnect your line.
Okay.
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Okay.
Yes.
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