Q4 2022 Magellan Midstream Partners LP Earnings Call
Okay.
Okay.
Greetings and welcome to the Magellan Midstream partners fourth quarter earnings Conference call.
All participants will be in a listen only mode. Later, we will conduct a question and answer session at that time. If you have a question. Please press the one followed by the four on your telephone.
If at any time during the conference you need to reach the operator, Please press star zero.
As a reminder, this conference is being recorded.
What day February 2nd 2023.
It is now my pleasure to turn the conference over to Aaron Milford C. E. O. Please go ahead.
Hello, and thank you for joining us today to discuss magellan's fourth quarter.
Financial results and perhaps even more of interest our outlook for the new year.
Before getting started and 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.
Magellan wrapped up the year with another solid quarter supported by record refined products transportation volumes and financial results that exceeded our expectations, excluding the noncash impairment taken in the quarter.
During 2022, we delivered over one $3 billion of value to our investors via opportunistic equity repurchases and magellan's attractive cash distributions, marking 21 years of continuous annual distribution growth.
I will now turn the call over to our CFO , Jeff Holman to review, our fourth quarter financial results versus the year ago period, then I'll be back to discuss our annual guidance for 2023 before answering your questions.
Thanks, Erin first I'll note as usual that 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 fourth quarter net income of $187 million compared.
Compared to $244 million in fourth quarter of 2021.
These results include the $58 million impairment of our investment in the double Eagle pipeline joint venture.
Adjusted earnings per unit for the quarter, which excludes the impact of commodity related mark to market adjustments was $1 six <unk>.
Excluding the 28 negative impact of the double Eagle impairment adjusted earnings per unit was $1.34 exceeding our.
Our guidance of $1 22 centers.
DCF for the quarter increased to $345 million up $48 million from last year, while free cash flow for the quarter was $324 million, resulting in free cash flow after distributions of $109 million.
For the full year 2022, DCF was one $1 billion to $8 billion, an increase of $10 million from 2021.
DCF per unit in 2022 was $5 46.
About 6% higher than in 2021.
This per unit perspective reflects the significant impact of our buyback program and highlights our ability to deliver per unit growth in excess of the underlying DCF growth that our business experiences full year free cash flow for 2022 with 1.4 $86 billion, resulting in free cash flow after distributions of 660.
For the year.
A detailed description of quarter over quarter variances is available in the earnings release, So as usual I'll just touch on a few highlights.
Starting with with refined products fourth quarter operating margin of $303 million was essentially flat with fourth quarter 2021.
Record quarterly transportation volumes and higher average transportation rates from our core fee based transportation and Terminalling activities offset unfavorable mark to market adjustments on our commodity hedges.
Higher rates were driven primarily by the midyear 2022 increase in our terrorist but about 6% on average in addition rates in the current period continued to benefit from more long haul shipments, which moved at higher rates.
Similar to the third quarter the increase in long haul shipments was driven largely by our customers using the extensive connectivity of our system to satisfy market demand in areas along our network. They continued to be impacted by refinery outages.
Operating expenses for the refined segment increased about $6 million versus the prior year period, primarily due to less favorable product overages, which reduced operating expense as well as higher power costs, primarily as a result of the increase in long haul movements just mentioned.
These unfavorable expense items were partially offset by a favorable property tax true up in the current quarter.
Product margin decreased between periods as favorable results from our gas liquids blending activities, which saw with higher margins and higher sales volume were more than offset by the recognition of additional unrealized losses on commodity hedges in fourth quarter 2022.
Our realized blending margins increased year over year to about 55 cents per gallon versus closer to 45 cents per gallon in the prior year period.
Turning to our crude oil business fourth quarter operating margin increased to $128 million nearly 24% higher than in the 'twenty one period.
Longhorn volumes averaged just over 245000 barrels per day slightly down from 250000 in the fourth quarter of 2021 did.
<unk> marketing affiliate shipments, partially offset by higher committed volumes.
Longhorn revenue actually increased overall as the margin we earn uncommitted barrels is currently higher than the margin we realize on marketing affiliate.
Volumes on our Houston distribution system increased versus the prior year period.
Due to higher tier shipments, resulting from a new pipeline connection in 2022.
These shipments moved at a lower rate than long haul volumes. So this increased HTS activity resulted in a lower average rate for the segment overall.
In addition terminal throughput fees increased partially as a result of more customers electing to move barrels under a simplified pricing structure for our services within the Houston area as well as higher dock activity in the quarter driven by the recent increase in export demand.
Crude oil product margin increased versus the prior year period, as we again benefited from additional crude oil marketing opportunities as.
As we noted on our call last quarter. These opportunities involve different factors, such as quality or location differentials and are less ratable than our core transportation and terminalling business, but provide low risk returns. So that we continue to pursue when available.
Moving onto our crude oil joint ventures, Bridgetex volumes were nearly 270000 barrels per day in the fourth quarter of 22 down from nearly 300000 barrels per day in 2021, and saddle Horn volumes averaged nearly 230000 barrels per day slightly lower than 235000 barrels per day in the 'twenty one period.
For both of these pipelines the decrease in volume is primarily due to the timing of when our committed shippers to utilize our services and emphasizes the importance of take or pay commitments from our from quality counterparties to ensure we get paid regardless of our customer short term logistics decisions.
From an equity earnings perspective, we once again recognized additional deficiency revenue for both the Bridgetex and double Eagle pipelines, resulting in an increase in equity earnings for the segment.
It's worth noting that although this recognition of deficiency revenue result in higher equity earnings associated cash payments already received 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 Tcf at that time.
Moving beyond the individual segments that are just a few other items I'd like to highlight our quarterly results depreciation amortization and impairment expense increased primarily due to the previously mentioned impairment of our investment in double Eagle.
You'll recall that the double Eagle pipeline, which delivers condensate from the Eagle Ford basin directly to corpus and indirectly to Houston through a connection to a third party pipeline was backed by long term customer commitments. When it began operations nearly 10 years ago.
Those initial contracts expire later this year and our customers did not provide notice of their intention to extend their commitments as provided for in those contracts.
Further those customers have consistently shipped below their commitment levels and consequently pay deficiency payments, while current market rates for transportation out of the Eagle Ford are significantly lower than the rates provided for in their expiring contracts.
As a result, we recorded an impairment of our investment in double Eagle during the fourth quarter.
Finally, as everyone will remember we sold our independent terminals in June which of course resulted in lower income from discontinued operations in the current period.
Moving on to capital allocation and balance sheet metrics and liquidity.
First in terms of liquidity, we continue to have a $1 billion credit facility available with the maturity of most of those commitments under that facility extended to 2027 during the fourth quarter.
As of December 31, the face value of our long term debt was still about $5 billion.
With $32 million of commercial paper outstanding.
Weighted average interest rate on our debt remains about four 4% with our next bond maturity in 2025.
And as a reminder, essentially all of our interest rates remain fixed other than that small amount of commercial paper borrowings.
Our leverage ratio at the end of the quarter was three two times for compliance purposes, which incorporates the gain we realized on the sale of our independent terminals.
<unk> that gain leverage would have been about three six times.
As for our capital allocation our story Hasnt changed we continue to believe it is important for us to execute a balanced capital allocation strategy.
Using a combination of capital investments cash distributions and equity repurchases all while remaining committed to the financial discipline, we are known for.
We continue to execute on our buyback strategy during the quarter repurchasing $1 9 million units at an average price of about $50 per unit for a total spend of $95 million.
For the full year 2022, we invested $472 million in unit repurchases, bringing the total since inception to nearly $1 3 billion.
We continue to see unit repurchases as an important focus of our ongoing capital allocation efforts and we continue to expect free cash flow after distributions to generally be used to repurchase our equity.
But as we are always careful to note the timing price and volume of any unit repurchases will depend on a number of factors, including expected expansion capital spending available free cash flow balance sheet metrics legal and regulatory requirements as well as market conditions and the trading price of our equity.
And of course, we remain committed to a strong balance sheet and our long standing four times leverage limit.
With that I'll turn the call back over to Aaron.
Thanks, Jeff.
Turning to our outlook for the new year. This morning, we announced DCF guidance of $1, one $8 billion for 2023.
Which is about four 5% higher than our 2022 results.
I'd like to spend a few moments walking you through the key assumptions used to develop our 2023 guidance to help you better understand how we're thinking about the new year.
Starting with our refined product segment, which comprises about 70% of our operating margin.
We expect refined product shipments to be about 1% higher than the record annual volume moves in 2022.
Due to continued stable demand and contributions from small system expansion, including the expansion of our pipeline between Kansas, and Colorado, which will come online in the first quarter of the year.
As discussed last quarter, we believe that most of our markets have essentially returned to their pre pandemic levels, while a few outliers in our larger metropolitan markets, such as Kansas City, and Minneapolis remains slightly lower.
It's still not clear to us if these outlet or markets will return to historical demand or if they are now at their new normal.
These estimates assume drilling activity remains robust and that our nation's economy does not slow notably.
Both of which impact our diesel fuel demand.
While not a part of our 2023 guidance. Our current project increased pipeline capabilities to El Paso is underway.
I would expect it to become operational in early 2024, which should contribute to volume growth next year.
The other key metric for our refined products pipeline system as the average tariff would charge.
Our forecast assumes we increase our refined products' rates by an all in average of approximately 8% on July one.
For those who have been tracking the producer price index, you're aware that the change in PPI is currently estimated to be an increase of approximately 13, 5% based on the preliminary results through December of 2022.
We've indicated to the investment community over the last few quarters, our intention to be very thoughtful in our approach to tariff increases this year due to the unprecedented level of the allowable increase.
Should we decide to not take two full allowed index within the 30% of our markets subject to the FERC index, we will retain the ability to make up the difference in the future period.
The other 70% of our refined products market is not subject to the index will be adjusted according to market conditions.
We have not finalized our decisions that we will take effect on July one.
And do not plan to break out the components of the 8% all in average assumed in our guidance today, but we will provide more detail later in the year once we finalize our rate decisions.
For reference every 1% change in either total transportation volumes or the average tariff for our refined products pipeline system impacts DCF by approximately $10 million on a full year basis.
Specific to our commodity activities, we have continued to make significant progress hedging our gas liquids blending.
With 70% of our 2023 blending now hedged.
Between the margins, we have already hedged in last week's forward curve for the unhedged volume. We currently forecast an average blending margin of about 60 per gallon for the year, which compares favorably to our 2022 results of <unk> 50 per gallon and our five year average margin, which is closer to <unk>.
<unk> 45 per gallon.
Breaking down our 23 estimates further we have nearly 90% of spring activity hedged at expected margins of 70 cents per gallon and 40% of fall blending hedged with margins closer to 50.
Our estimates for 2023 blending incorporate RIN costs of nearly <unk> 20 per gallon due to the ongoing high pricing environment for Rems.
We also continue to pay close attention to moves in the basis differential.
Between our Nymex based hedges and the price of gasoline, we sell and the markets located along our pipeline system in the middle of the country.
Our projections currently include an average basis differential of negative <unk> 10 per gallon, which is about double historical levels, but <unk> better than the average basis differential experienced in 2022.
Moving to our crude oil segment, which comprises the remaining 30% of our operating margin. We expect volumes on our wholly owned pipelines to increase about 20% over 2022 results primarily related to the full year impact of higher shipments on our Houston distribution system from a REIT.
Current pipeline connection.
We also expect longhorn pipeline shipments to increase averaging approximately 245000 barrels per day compared to 230000 barrels per day in 2022.
As discussed last quarter, we recently added a new third party commitment to longhorn, resulting in approximately 80% of the pipes 275000 barrel per day capacity being committed at this point with an average remaining life of six years.
Similar to 2022 shipments on our joint venture pipelines are expected to be lower.
Then commitment levels and customers will be paying deficiency payments as a result.
Specific to Bridgetex, we expect shipments to average around 215000 barrels per day during 2023.
About 40000 barrels per day lower than 2022 average annual volume with even lower shipments during the first quarter based on recent customer activity.
For saddle Horn, we expect to move about 220000 barrels per day during 2023, which is similar to 2022 shipments.
<unk> currently has commitments for approximately 80% of the pipelines 290000 barrel per day capacity with an average remaining life of four years.
We expect storage revenues to be lower in 2023 for both our refined products and crude oil storage assets.
We saw during 2022 as well.
Although we generally target longer term contracts for our storage business that are somewhat agnostic to short term price movements.
Ongoing backward dated pricing curve has made it more difficult to renew expiring contracts.
Further the $20 million contribution we received from the independent terminals. During 2022 will not repeat followed on a sale of those assets in June of last year.
On the expense side.
We've discussed in the past the Magellan kicked off and optimization initiatives several years ago to identify efficiency opportunities throughout the organization.
This initiative has served as well to ensure that we are operating as efficiently as possible, especially considering the current inflationary environment.
Safeguarding the integrity of our assets.
With the benefit of these optimization efforts as well as few a few onetime cost we don't expect to recur again in the new year. We currently expect total cash expenses to increase by about 2% in 2023.
Concerning maintenance capital, we expect to spend around $90 million during 2023, which is 10% above last year's actuals, but not out of the normal range for our company.
The higher annual estimate is simply based on the timing of specific project work with nearly $10 million in 2023 related to large one time projects.
Associated with a pipeline relocation and in an electrical upgrade.
Safe and reliable operations are critical to our success and we spent significant time and effort each year to ensure the integrity of our assets and to protect the communities, where we live and work.
In fact, consistent with recent years, we expect to spend in excess of $200 million on maintenance and integrity work in 2023, considering both capital and expense projects.
As an aside.
We also mentioned in todays earnings release that our guidance assumes an average crude oil price of $80 per barrel for the year, which is consistent with recent futures pricing.
For sensitivity purposes, we currently estimate that each $10 change in the price of crude oil will impact our DCF by approximately $35 million in 2023, primarily related to our unhedged gas liquids blending activities and the value of our pipeline tender deductions and product Overages.
In summary, all of these key assumptions buildup to our DCF guidance of $1, one 8 billion for 2023.
Coupled with our currently planned 1% annual distribution growth.
Distribution coverage of 138 times, resulting in more than $215 million of free cash flow after distributions.
It can be used to reinvest in the business buyback equity or otherwise create additional value for our investors.
Magellan remains committed to a balanced capital allocation approach.
We continue to see opportunity to create value through repurchasing units, but distributions will remain an important component of our capital allocation plans.
We plan to increase our annual distribution by 1% this year similar to the past two years, which results in a yield of nearly 8% based on recent MMP trading prices.
While we're not providing specific financial guidance beyond 2023 at this time.
We expect DCF to continue to grow modestly over the next few years.
Combining this modest underlying growth with our expectation to continue to repurchase units results and even higher growth potential for our distributable cash flow per unit.
As we have seen in recent years for example, our DCF grew at an average annual rate of just under 4% between 2020 and 2022, while our DCF per unit grew at an annual average rate of just over 8% during the same.
Period.
This example, we believe demonstrates the power and our capital allocation approach and our ability to create long term value for our investors through a healthy current distribution combined with the potential for capital appreciation as DCF per unit increases.
Moving on to expansion capital.
We remain intent on developing attractive investments to create future value for our company.
We currently expect to spend approximately $110 million in 2023 and $40 million in 2024 on expansion capital projects already underway.
As you probably know the largest project included in their spending profile relates to the expansion of our refined products pipeline to El Paso, which as mentioned earlier is expected to be operational in 2024.
We continue to assess new opportunities to enhance magellan's footprint and expect to find incremental projects that leverage the flexibility of our extensive network.
Most likely around filling logistical gaps that may arise between market demand and available supply.
You may recall that we've generally estimated around $100 million of expansion capital spending per year is a reasonable assumption for potential projects.
As just noted we're already planning to spend above that level for 2023, so depending on how successful we are at identifying near term new projects a number closer to $150 million is a reasonable placeholder for this year.
Even though we were aggressively pursuing additional projects to grow our DCF. We also remain committed to magellan's consistent disciplined investment approach quite simply if the set of projects that meet or exceed our 6% to eight times EBITDA multiple thresholds remained relatively low.
We intend to stay patient.
For the right opportunities and believe additional long term value is achievable through continued optimization of our existing assets and utilization of our other capital allocation tools.
<unk>.
Operator.
We are now ready to open the call for questions.
Thank you if you would like to register any question or comment. Please press. The one followed by the four on your telephone you will hear us retail and prompt technology 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 our first question.
The first question comes from Theresa Chen of Barclays. Please go ahead.
Thank you for taking my questions and I, just wanted to unpack that 8%.
Refined products tariffs understanding that youre not giving the exact breakdown at this point, but just the way the math has to work given the 70 30 split between.
Competitive rates and the FERC index rates, either you would be increasing close to the ceiling wait for FERC rates or you would be increasing higher than that mid single digit clip that we've been doing for some time and the competitive rates and I'm. Just wondering have you gone through the process of talking with.
Customers and just the price discovery process, what they are willing to bear and if you are willing to lean more aggressively on the competitive rates are you confident that you wouldn't be giving up some market share with the big increase.
It's a good question Teresa and as I said in my comments, we haven't made any final decisions about what we're going to do in July one.
Or for July 1st I should say, but the 8% all in rate. We think is a good placeholder.
As we see things right now and if you think about in terms of we're always talking to our customers. We have a good feel for what's going on the markets, but we do very much a market by market buildup of what we think.
It is a rate increase that that wouldn't result in market share loss frankly, that's that's what we're trying to manage a little bit is make sure that we're increasing our rates which in any event.
We're going to be healthy, they're gonna be healthy rate increases, but we are trying to make sure that we don't push the envelope in such a way that we think that theres a risk of losing market share. So that's the sensitivity that we have if you look at that 8% all in rate, we think that the.
The combination of index and market rates that we may end up charging which we think.
Would reflect that 8% as we sit here today, we don't think we're running that risk.
What's most likely to happen is our indexed markets will likely go up at a higher rate than our market base rates, but but theyre, both going to be healthy.
Got it and then turning to the butane blending piece.
As we think about the building blocks for a D basis assumption of negative 10 cents for the year and clearly January has been more favorable.
Patient blending business than fourth quarter, but we.
Have several things going on and clearly there's a lot of planned and unplanned downtime at the refineries in the mid Con which helps you.
Pay ways that to go down sometime this quarter and so how should we think about the evolution of basis.
Throughout the spring planting season.
Well, it's we think it's going to remain volatile.
That's the simple answer to that and then you highlighted many of the reasons why we think it's going to remain volatile.
If you look at our expectations of negative 10 four.
2023, we think that's a reasonable assumption.
For sort of if you look through the whole year.
Last year, we saw some basis really go our way and I actually traded a positive not a negative we think that that could happen again. This year, it's hard to predict but we just see a lot of volatility around it. So when we chose the the minus 10 sense. It was looking at the future markets and where we're seeing them sort of sitting but it was also just considering as vol.
<unk> in both directions.
Can happen. So we just tried to pick a reasonable number we think theres a good chance that is going to be a little better this year.
What we experienced last year.
But in any event it's still.
Elevated versus where it has historically traded by a pretty substantial margin. So.
It's just us using our best estimate on what we see the full year turning out to look like which we are.
Forecasting it to be slightly better than last year, but certainly not as good as it has been historically.
Thank you.
Thank you.
The next question comes from <unk> Satish.
Of Wells Fargo. Please go ahead.
Thanks.
Good afternoon.
Capital allocation.
Wondering if you've given thought to to raising the pace of distribution growth I mean, ebitdas can be up projected to be up 4%. This year, but you are only growing the distribution, 1%. So it seems like theres, an active decision here not to grow distributions in line with with cash flow growth and I know youre doing buybacks, but I guess at what point.
Would you consider accelerating distribution growth.
Yes, it's an interesting question and when you think about it I think.
Fairly simply.
<unk>.
The first thing I want to mention is we view a healthy distribution.
An important part of our overall value proposition.
So for US it's really a question about what do you do incrementally from where you're right to your point growing the distribution faster emphasizing buyback that's really the the decision point that we have to make.
And for Us.
It seems like adding materially.
To an already attractive distribution.
At spreads that are still to treasuries still wider than we think they should be.
And we compare doing that.
Two the opportunity to buyback units and when we compare the two.
Which one of those that we think will create the most long term value for our investors long term and as we sit here right now we still think buybacks make the most sense for us.
The key I would make is that's true right now we've always tried to say things can change depending on what's happening and what where we see the best place to add value. So it's important that we see both of them being very important and if we look marginally right now we see opportunity in our enterprise.
And as long as we see that opportunity.
That's where we're going to focus.
But it's not set in stone.
That's just where we are.
Right now.
Got it that's helpful.
And then I think you mentioned that youre getting higher rates on contracted capacity on longhorn.
Versus the marketing margin. So I'm just wondering if theres plans to contract that small remaining piece of open capacity on longhorn in 2023 or or leave that open and contracted later when when things potentially tightened.
Yes, and I think some of that difference well first of all if we just see if we have a counterparty that wants to pay us an attractive rate as you look through time.
We're interested in talking about that and it's very counterparty specific as I've mentioned in the past people take different views of how much time, they want to think about how do they feel about capacity and different producers and customers have different motivations to either want to just sort of ride the spot market, so to speak or whether or not they want to make.
Our commitment for a term to have surety of Av.
Export out of the out of the basin.
So if we have counterparties out there that want to.
Come up with a fair rate with some term on it we will certainly consider it so one of the reasons why the commitments are typically at higher rates as those are with customers who are taking a longer term view and are wanting to have term and we're looking at that saying well if we're going to look at this over a longer period of time and you mentioned the rate is fair on the marketing side of the business that's much more of a what's happening today much more.
The spot market. So you don't see that same term structure necessarily and the optimization that we're trying to do with the.
The spot movements and our marketing affiliates, so just a little bit of difference in perspective, and the types of customers that are interested in working through our our marketing affiliate and those that want to make sure they've got capacity out of the basin and when you take those two different perspectives you have different price sensitivities to both of them with the ones wanting term typically willing to pay a little more for that.
As a result, so does that answer your question.
Yes. It does thank you.
Thank you.
The next question comes from Jeremy Tonet of Jpmorgan. Please go ahead.
Hi, good afternoon.
Good afternoon.
Thank you I just wanted to come in on the oil product margin a little bit more.
Might be able to.
<unk> as far as what specific activities benefited <unk> Q and do you see them repeating.
2023, and is that factored into the guidance.
Yes.
As we said I'm trying to not be super specific because more specifically are the less opportunity, we're probably going to have I think it's pretty much that simple, but the broad buckets. It was pretty broad really its quality differentials and its locational differentials.
And those are where the opportunities are and we do expect them to continue we cannot predict the level, but we expect to continue to find opportunities, but just to hopefully make us. This.
Answer a little more satisfying.
If you look at 2022.
Crude marketing activities contributed call it $25 million to $30 million.
And we are in our guidance basically assuming we will find a similar level of opportunities next year.
Got it.
Helpful. There.
And then just wanted to pivot towards the Capex I think you said $150 million might be a reasonable placeholder there and just wondering I guess the suite of potential growth project opportunities as you see it now would you say, that's kind of more or less than where it's been maybe earlier in 2022, just trying to see I guess how that could be.
Opportunity.
So as you see it might be evolving over time.
Well I would say generally.
The potential for investment opportunities for us I would say today.
Is probably a bit more optimistic today than it was even a year ago and a lot of that really has to do with our customers and what they're seeing and what they're trying to accomplish and the conversations we're having I would not describe it as saying that were going to a completely new environment or we're going back to the high levels that we saw.
In the recent past I don't see that.
But I do see some more optimism and we have customers that certainly have some objectives that we can help them with so I'm certainly more optimistic as I sit here today than it was a year ago, but we're not in a totally different ZIP code. So the $150 million. This year was really driven by we're already spending.
In excess of $100 million and what we've already committed of really good projects and we expect to find a few more things to do this year.
We wanted to at least give you some idea of the magnitude of that.
So does that answer your question.
Yes, that's very helpful and just if I could ask a quick bonus round one if I could just if you had any opinion about the delta we're seeing in the weekly versus monthly EIA product demand numbers and how that impacts Magellan.
I really don't have an opinion on it we're focused on really what our customers are doing and I just don't have a direct opinion on.
Fair enough. Thank you very much.
Thank you. The next question comes from Spiro <unk> of Citi. Please go ahead.
Thanks, operator, good afternoon guys.
Want to go back to the guidance and I'll try and keep it broad we kind of looked over the last five or six years or so it looks like you guys have beaten your initial guidance every single year other than 2020, and I think it's a pretty good reason to give you a pass on that one but from an outsider's perspective. It would seem like you all take a pretty conservative approach to guidance. So I guess I'm just curious.
And so you think about the guidance and maybe where some potential sources of upside surprise could be anything you'd kind of highlight maybe another way of asking is what's not in the guidance.
Well I mean, a couple of things I would highlight everything that we reasonably can foresee or expect we've tried to reflect in this guidance. For example, the basis differential we just talked about we tried to give you a really clear guidance of what we assume there we were assuming it's better than it was last year, but it's still not as great as it was historically.
We think thats going to hold but we'll see how the year plays out on the volatility around basis. So that's one area.
Commodity prices, what's going to happen with crude oil prices.
We're using an $80 strip basically for the year.
Is it any better or worse, that's an area. We tried to give you some sensitivities around that based on what's left to be unhedged and tenders in our products. So that's an area that depending on what commodity prices do.
In either direction that could influence where we end up.
Yeah.
The long haul shipments we do have some expectation that we're going to continue to get some longer haul shipments we've got a heavy slate of refinery maintenance.
Sort of expected in the first part of the year, we generally benefit.
But then there's the whole element of unexpected unplanned outages and refineries have been running really hard for a very long time.
And we've seen a higher level of unplanned outages frankly and to the extent we have unplanned outages. That's usually a good thing for us and it's difficult for us to predict.
What those unplanned outages are going to do but if we if we start seeing a lot of unplanned outages. We would expect on average to benefit from that so we've tried to take into account what we can see on outages, but the unplanned outages are just very difficult.
To predict it depends on where it happens how long it happens the nature of the outage itself. So it's difficult to predict but that's something that traditionally be good for us. So I think it's really that simple as what happens with the unplanned outages what happens with the actual commodity markets basis differential.
Sorry to those we've really tried to.
To provide the guidance that reflects what we think is going to happen this year.
Got it.
Aaron I appreciate that.
Second question is on storage I guess I'm just curious how would you characterize directionally how that market has been moving maybe since last year.
Subdued here, but just curious what is going to take to see the economics improve there. It's really just a function of the futures curve at this point or is it something structural that could occur to kind of get that moving higher.
At the end of the day I think on the margin. It's the structure of the curve itself I mean, the reality is right now when we go talk to the market about wanting to take storage.
The forward curve is really a difficult for those that are that are looking at future prices in order to justify taking stores. So I think.
The futures and the shape of the curve will have to move more back into a contango before we see what I would consider a market difference now there are some operational things exports wanting to leave the Gulf coast.
Continued.
Growth in our HEU contract there are some things that can create demand for our storage.
That could help us.
But I think those are those are going to be overshadowed by just the overall forward market structure in terms of for things to really turn on look a lot lot better for the storage market, but we think thats what has to happen with that said we've had some luck.
Renewing some contracts with some rates that we think we're we're pretty attractive but those are being done for for what I'm going to say more operational and logistical purposes more so than just the idea that I'm going to take storage out and the price is going to be higher tomorrow. We do have a set of customers that are less sensitive.
To that forward curve, but.
Again to change the real direction of the storage business will need to see the forward curve improve but it doesn't mean, we're lacking some opportunities to do a little better.
And to your close though it's the same.
Is it the same now as it was last year it feels about the same.
Some days feel a little better some days down so but it so it feels generally about the same.
Understood helpful as always thanks Darren.
Thank you.
Thank you. The next question comes from Keith Stanley Wolfe Research. Please go ahead.
Hi, good afternoon.
First.
Just thank you for all the disclosure and Aaron when you lay these things out.
The transparency really is top notch versus your peers.
Actually remove some of the questions we all have.
So first I wanted to start on just to follow up on distribution growth. So I get the logic of the buybacks and growing DCF per unit.
Whats a little interesting as your peers are doing the opposite so theyre growing distributions faster, especially the MLP peers doing less on buybacks, especially if the stocks have moved higher so I'm curious if what the peers are doing ways at all into your thinking on capital allocation over time as youre competing for investor dollars.
Or are you more focused just on what makes sense for Magellan economically.
Well first of all thanks for the compliment on the on the transparency, we try and I think we're successful most of the time, so I do appreciate that being recognized.
Now to your question about distribution growth.
Just to be brutally Frank.
We don't think a lot about what our peers are doing in terms of their distribution growth and thereby backs because we are not running their company. We're not responsible for their company they are and they need to make their decisions based on what they see about their company. So we focus on what we're trying to accomplish and what we see happening with our company.
And we think it's going to be really powerful to have a really healthy distribution I mean, it's an almost 8% yield we've never cut it.
We've always grown it for 21 years.
And that's important.
And then when you compare that to our ability to drive what we think could be significant capital appreciation. If we grow our DCF per unit you put that together and we think we've got a really powerful value proposition for our company.
Other people may view, the value proposition of what Youre trying to accomplish differently. So we're certainly aware of what others are doing but it doesn't influence how we're trying to run our company.
Understood. Thanks.
Second one just a clarification the oil sensitivity so $10 per barrel change is $35 million.
Is that holding all other variables like butane costs constant or it's.
Making the adjustment there in line with oil.
That's an overall cash flow sensitivity to a $10 change so its not holding everything constant as a result, it's letting everything sort of flow through as it would flow through but it's very much a sensitivity and keith meant to be.
What I would say a barometer of thumb in the air than it is meant to be an exact number but thats the magnitude of an impact of a $10 change overall.
Got it and one thing I would highlight though is that we are at we are considering the hedges we already have in place.
So that sensitivity only applies to the things that we have yet to hedge.
And our tenders and then also our product Overages, which we collect those throughout the year.
And so that's what the differences is unhedged butane blending tenders and products and a $10 change. So we have taken into account the hedges already in place.
Thank you.
Yeah.
Thank you.
Next question comes from John Mccain of Goldman Sachs. Please go ahead.
Hi, everyone. Thank you for the time I appreciate it I wanted to start maybe on the.
On the crude pipelines, we've seen obviously Permian overall kind of built from top overlap from a top down perspective Corpus line is getting a little bit tighter, though given the expert Paul I'd just be curious if you think we start to see.
Maybe any benefits for the Houston, the bounds pipes as corpus starts to fill up or really if that's more of a kind of 'twenty four 'twenty five star. It really just trying to think about how you think about those two markets.
How the pipeline.
Directions interact in 2023.
So I think as I think you've summarized the current situation pretty well there is certainly a pull through corpus for export purposes.
And those those pipes as a result are becoming more full which should lead to barrels flowing over into into the Houston pies.
As production in the Permian continues to grow so we think thats a positive setup. If you actually look at where you might see that playing out or that expectation playing out is in the differential between Midland and Houston. If you look at the forward curves would all point to increasing differentials that's good for pipes.
But the timeframe for that is when you look at the forward curve is in that 24 to <unk>.
<unk> thousand six sort of timeframe.
So I think that aligns with the statement made in your question. So I think it's probably a little bit further down the road more and more of the next year or slightly beyond before I think we start really seeing how that's going to play out.
But in the meantime, we've got really good contracts so.
We're insulated along the way, but I think youre out in that 24 to 26 timeframe, it's going to depend on what production does and then what happens with the export pull ultimately.
Makes a lot of sense, thanks, Brian maybe one.
Probably smaller micro question just on the double Eagle impairment, obviously, the overall number of small we just talk about maybe what the.
Financial impact on our kind of EBITDA basis could be.
Yes, if you look at this year.
We're expecting distributions of around $10 million for double Eagle. This year, that's opponents of partial year does it expires later in the year based on our assumptions, but it's about $10 million.
Historically, it's been closer to 15 on a full year basis.
Alright, I appreciate all the disclosures so again, thanks very much.
Okay.
Thank you. The next question comes from Michael Cusimano, Pickering Energy Partners. Please go ahead.
Hey, good afternoon, everyone.
Good afternoon, a little bit more about the assumptions in guidance.
I think historically Magellan hasnt assumed much in terms of like product dislocations between markets within the guidance. So I'm just wondering if you have better visibility today than maybe in years past or.
Just maybe a more aggressive approach.
When you say product dislocations, just help me with exactly what you mean, you mean price dislocation inventory down higher like higher barrel miles and year like products transport business.
Yes, that's been an area, that's always been difficult for us to.
Predict whether planned or unplanned refiners are typically pretty tight.
Tied to divest about when they plan to be down so what's happening is as we've just seen a more consistent.
Longer haul barrel.
Planned maintenance happened so it just becomes a little easier for us to have an expectation that we're going to get some benefit from that on those plans and those planned outages. So that's really all it is we're just getting a little bit of visibility a little more of a track record of seeing how it plays out and when you combine that for this year, just a higher maintenance.
Michael who refiners, we think that we're going to benefit from that and we've included some of that into our guidance and as I said previously the unplanned part is what's really difficult to predict so we really don't have any anything in the guidance that says we're planning X percent of unplanned we don't have that but to the extent, we can see turnaround where we are trying to include some.
So it's probably less about.
Visibility towards it more so than it has a track record of us seeing it more consistently is what I would say.
Okay, that's very helpful. Aaron.
Then one more on the.
On the guidance I was wondering if you don't meet any.
Like methodologies G adjustments or provided sensitivities. So just additional disclosure that you all want it because I don't think youll provided that in the past.
We have provided a different sensitivities or I should say we've tried to.
I'll provide some sensitivities, especially around commodities and crude prices, so thats not new for us.
And Theres really no methodology change in how we think about guide.
<unk>, we're looking at it the same way again, the changes will be speed to the extent for instance in the longer haul pipe movements. So we assume we have a more of a track record of seeing it.
We've got some of that in there, but there isn't any methodological change in how we're producing guidance, we're thinking about guidance.
And the sensitivities arent arent new.
Okay got it that's all for me I appreciate the help.
Thank you as a reminder, via the phone lines you may prefer one floor to register a question or comment.
The next question comes from James Carreker of U S Capital Advisors. Please go ahead.
Hey, guys. Thanks for the questions.
In previous years, you've talked about.
July one step up but then also talked about.
Due to mix shift.
Headline numbers that you kind of print on a tariff basis for the refined products segment paid may be lower than that just wondering if youre seeing any of that dynamic.
<unk>.
<unk> three <unk>.
Standing it's hard to predict planned and unplanned maintenance.
No we're not seeing anything.
No.
That's helpful. And then I guess, just also thinking about a higher than average.
Rate increase planned here in July .
However, its allocated between.
The competitive at index markets.
Assuming maybe.
Other high number in 'twenty four.
Is there a point at which you start becoming concerned about.
Over earning risk as it relates to I know the page 700 has pros and cons.
But over earning on that.
If we get a couple of years of these mid to high single digit growth rates on the tariffs.
I wouldn't say that we worry about it.
But it is something that we're aware of I mean, we certainly are aware of the calculations in the page 700, and we're trying to be sensitive to them.
At the end of the day.
We'll make our rate decisions.
Considering what that says but we.
We run a really good pipe take really good care of our customers and you look at where our rates are as a percentage of the overall mix of things.
It's not that material in the Grand scheme of things so as long as we're thoughtful.
I'm not worried about.
Over earning but it's something that we have to be aware of obviously.
That's helpful.
Maybe if I could fit.
Are still below 2019 levels and just may be the new normal, but I guess any kind of sensitivity with respect to if if certain markets did kind of get back to 2019 what.
What upside could that be to volume and so we know whether it happens in 2324 2030, whatever it is.
How material would be that would be to your existing system volumes.
Yes.
Yes, I really I really <unk>.
First of all I don't think its going to be material, one way or the other so if youre using that 1% sensitivity that we gave you it's probably within that bound.
With the rate and where the volume is probably within those bounds.
But I don't have that specific sensitivity right in front of me.
Okay. Thank you just going to depend on the different components is it multiple metro areas. They come all the way back a part of the way back and there's infinite kind of varieties. There. So it's the thing I would highlight is I don't want to I don't want to sort of.
It sounded overly pessimistic on those metropolitan areas, it's not like they are drastically different from where they were in 2019, So just down a little bit but the reality is we would've expected them to come back and they just haven't we're trying to make everyone aware of that but it's not it's not drastically different.
Yes.
Okay. Thanks for the color.
Thank you that was our final question I'll turn the call back over to you Ms <unk> for any closing remarks.
Well. Thank you for your time today, we're pleased with the solid results generated by Magellan in 2022, and look forward to an even stronger financial performance in the year ahead.
Remain committed to running our business responsibly, while maintaining our prudent financial discipline and balanced capital allocation strategy to maximize long term value for our investors on behalf of our company. We appreciate your continued support and hope you have a nice day.
Thank you. Thank you. This does conclude the conference call for today, we thank you for your participation and ask that you. Please disconnect. Your lines. Thank you and have a great day.
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