Magellan Midstream Partners LP (NYSE:MMP) Q3 2022 Earnings Conference Call October 27, 2022 1:30 PM ET
Company Participants
Aaron Milford – President, CEO & Director
Jeff Holman – Principal Accounting Officer, Senior VP, CFO & Treasurer
Conference Call Participants
Jeremy Tonet – JPMorgan
Theresa Chen – Barclays
Keith Stanley – Wolfe Research
Praneeth Satish – Wells Fargo
Neel Mitra – Bank of America
Gabe Moreen – Mizuho Securities
Michael Cusimano – Pickering Energy Partners
Operator
Greetings, and welcome to the Magellan Midstream Partners Third Quarter Earnings Call. During the presentation, all participants will be in a listen-only mode. Afterwards, we will conduct a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded Thursday, October 27, 2022.
I would now like to turn the conference over to Aaron Milford, CEO. Please go ahead.
Aaron Milford
Hello, and thank you for joining us today to discuss Magellan’s third 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.
As you saw this morning, we reported third quarter results that beat our EPU guidance, continuing our trend of solid financial performance so far this year. Most notably, our refined products transportation revenues exceeded our expectations primarily due to higher average tariff rates and our commodity margin benefited in part from the basis differential that flipped positive briefly, just as the gas liquids blending season began at the end of the quarter. There were a number of other favorable items including overall lower expenses that led to our outperformance.
In addition, we announced a $0.01 increase to our quarterly cash distribution last week, consistent with our guidance in general approach from last year. At current yield of over 8%, our yield remains attractive, and we recognize the distribution growth is important to a portion of our investors. Magellan is proud to continue our trend of increasing the pay out to investors each year.
I’ll now turn the call over to our CFO, Jeff Holman, to briefly review our third quarter financial results versus the year ago period. Then I’ll be back to discuss guidance for the remainder of the year before answering your questions.
Jeff Holman
Thanks, Aaron. First I will note 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.
This morning, we reported third quarter net income of $330 million, compared to $237 million in third quarter 2021. Adjusted earnings per unit for the quarter, which excludes the impact of commodity related mark-to-market adjustments, was $1.29, which is Aaron pointed out exceeded our guidance of $1.15. DCF for the quarter increased to $290 million up $30 million from last year. Free cash flow for the quarter was $273 million, resulting in free cash flow after distributions of $58 million. A detailed description of quarter-over-quarter variances is available in the earnings release. So as usual, I’m just going to touch on a few highlights.
Starting refined products, operating margin of $384 million was 40% higher than the 2021 period, driven primarily by a more favorable commodity environment, as well as higher average tariff rates. Total refined products volumes were slightly lower between periods. The day increase in the average transportation rate more than offset this modest volume decline. A higher average rate was driven primarily by the mid-year 2022 increase in our tariffs of about 6% on average. Just as a reminder, this 6% average increase consists of an 8.7% increase in the 30% of our markets with index rates, and an average increase of approximately 5% in our markets deemed workably competitive. In addition, rates in the current period benefited from more long haul shipments which move at higher rates. The increase in long haul shipments was driven in part by our customers using the extensive connectivity of our system to satisfy market demand in areas of along our network that were impacted by refinery disruptions during the quarter.
Operating expenses for the refined segment decreased during the third quarter 2022 primarily due to favorable product overages which reduce operating expense. You may recall that we discussed product overages last quarter as an unfavorable item. And as we mentioned then, they can fluctuate period to period with the operation of the pipeline. But we generally expect these variances to more or less even out over time as we’ve recently experienced.
Product margin increased between periods in part due to higher margins and volumes on our gas liquids blending activities. Our realized plenty margins increased year-over-year to about $0.75 per gallon versus closer to $0.40 per gallon in the prior year period. On our last couple of calls, you’ve heard us talk about how basis differentials between the Mid-Continent and New York Harbor have been wider than normal, negatively impacting the margins we earn on our blending activities. More recently, we saw that basis move in the other direction, resulting in a benefit to our realized margins as we kicked off the fall blending season before widening again of late.
In addition to favorable gas liquids blending results, we have significant unrealized gains on futures contracts related to our hedging activities, which favorably impacted operating margin in the current period. Of course, we ignore these out-of-period gains on futures contracts in our calculations of DCF for the period to better match their DCF impact with the underlying product sales activity that will occur in future periods.
Turning to our crude oil business. Third quarter operating margin increased to $127 million, nearly 14% higher than in the ’21 period. LongHorn volumes averaged 225,000 barrels per day compared to around 240,000 in the third quarter of 2021, primarily due to lower committed shipments based on the timing of when our customers have elected to move volumes under their commitments. Volumes in our Houston distribution system increased versus the prior year period with more tariff shipments resulting from a recent pipeline connection to our system. In addition, terminal throughput fees increased as a result of more customers electing to move barrels under a simplified pricing structure for our services within the Houston area.
Similarly to last quarter, storage revenue declined due to lower utilization and rates, as we continue to see general softness in storage demand due to prolonged market backwardation. Crude oil product margin benefited from additional crude oil marketing activities in the current period as well as unrealized gains on futures contracts related to our hedging activities.
Moving on to our crude oil joint ventures. BridgeTex volumes were approximately 250,000 barrels per day in the third quarter of ’22, down from just over 315,000 barrels per day in 2021 primarily due again to the timing of when our committed shippers have elected to move volumes under their commitments, while Saddlehorn volumes averaged a little more than 215,000 barrels per day, basically in line with the 2021 period. From an equity earnings perspective, we once again recognized additional deficiency revenue for both the BridgeTex and Double Eagle pipelines, which offset lower average rates on Saddlehorn, resulting in essentially flat equity earnings for the segment. It’s important to note that although this recognition of deficiency revenue at our joint ventures results in higher equity earnings, the associated cash payments were 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 as DCF at that time.
Moving beyond the individual segments, there are just a few other items I’d like to highlight from our year-over-year results. G&A expense increased between periods, primarily due to higher overall compensation costs, due in part to an increase in incentive comp reflecting our strong results year-to-date. In addition, some miscellaneous non-comp related items, including elevated legal and technology costs contributed to the year-over-year increase. Other expense was unfavorable, primarily due to additional expense recognized during the quarter associated with ongoing legal matters previously disclosed in our SEC filings.
And finally, as everyone is aware, we sold our independent terminals in June, which of course resulted in lower income from discontinued operations.
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. As of September 30th, the face value of the long term debt was still about $5 billion with $29 million of commercial paper outstanding. The weighted average interest rate on our debt remains about 4.4%, with our next bond maturity in 2025. Our leverage ratio at the end of the quarter was 3.3x for compliance purposes, which incorporates the gain we realized on the sale of our independent terminals. Excluding that gain, leverage would have been about 3.7x.
After capital allocation, as you’ve heard us say before, we remain committed to maintaining the financial discipline we’re known for, while delivering long term value for our investors through a combination of capital investments, cash distributions, and equity repurchases. We continue to execute on our buyback strategy during the quarter repurchasing 2.7 million units, at an average price of about $50 per unit for a total spend of nearly $138 million. Year-to-date, we spent $377 million on unit repurchases bringing the total since inception to a little under $1.2 billion.
So far in 2022, we have returned a total of over $1 billion to our investors through a combination of unit repurchases and cash distributions. Including our recently announced distribution, which pays out next month, that number will be over $1.2 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 our longstanding 4x leverage limit.
And with that, I’ll turn the call back over to Aaron.
Aaron Milford
Thank you, Jeff. Based on our results and our expectations for the rest of the year, we are increasing our annual DCF guidance by $10 million to $1.1 billion. While we were pleased with Magellan’s performance so far this year, you may have noticed that our new annual guidance did not increase by the full amount of our outperformance during the third quarter. Like last quarter, we continue to keep our eye on a number of factors including the volatile commodity environment, as well as economic conditions generally. They have led us to remain somewhat conservative in our expectations for the remainder of the year.
Specific to our commodity activities, we’ve continued to lock in additional hedges over the past few months related to gas liquids blending, with 90% of our fall blending currently hedged at margins in excess of $0.50 per gallon. All in, we now expect blending margins for the full year 2022 to average around $0.45 per gallon, which is a bit higher than our previous estimate and consistent with the five year average blending margin. The primary reason for the annual increase is related to the short-term improvement in the basis differential Jeff just discussed and we will be paying close attention to further moves in this basis differential as we finish up the year and look ahead to next year. We’ve also continued to make significant progress in hedging next year’s blending with 50% of our expected 2023 blending now hedged at an average margin of $0.65 per gallon.
Broken down further, we have 70% of spring 2023 activity hedged at margins of $0.75 per gallon. And have even started to hedge fall ’23 activity with about 25% head at $0.55 so far. This is a bit earlier than usual to hedge out that far. But margins are attractive. So we’re locking in prices to the extent there’s opportunity and depth in the market to do so.
Moving on to expansion capital, we now expect to spend approximately $90 million in 2022 with $100 million in 2023, and $40 million in 2024 on expansion projects that have already been committed. The increased estimates primarily related to the recently announced $125 million expansion of our Texas refined products pipeline system from Houston to El Paso, which is supported by take or pay commitments from quality counterparties.
Based on our current construction schedule, we expect the expanded capacity to be available in early 2024. As usual, we continue to assess new opportunities for infrastructure projects with attractive risk and return profiles. Most recently, we’ve estimated that around $100 million of expansion capital per year is a reasonable assumption for undefined projects, as we continuously analyze and develop value creating projects. As we’ve mentioned in the past, this $100 million estimate is just that an estimate was some years possibly a little higher, other years possibly below. But we don’t foresee a material shift to significantly higher organic growth spending levels at this time.
Since we’re already planning to spend $100 million next year for currently committed projects, it is likely our expansion spending will ultimately be above that level in 2023, as we bring additional projects across the finish line. Consistent with our usual approach, we plan to provide overall financial guidance as well as key assumptions specific to 2023 when we report fourth quarter financial results early next year. In the meantime, however, I’ll end my prepared remarks today, but briefly noting a couple of recent positive developments in our crude oil business. In particular, we’re pleased to receive a new commitment on Longhorn at a rate and on terms that we found constructive, resulting in 80% of Longhorn’s capacity being committed beginning next year, with an average remaining life of six years.
In addition, the customer who has exclusive use of our Corpus Christi condensates flitter recently extended its take or pay agreement for the facility until the end of 2024, providing additional link to that contract. We think both of these developments underscore the quality of our assets and the value that our customers see in working with us.
Operator, we are now ready to open the call for questions.
Question-and-Answer Session
Operator
[Operator Instructions] And our first question is from the line of Jeremy Tonet with JPMorgan.
Jeremy Tonet
Just want to kind of pick up a little bit more on capital allocation and all of your comments there were very helpful. Just wondering, within the context of rates moving kind of as quickly and sharply as they have recently, does this impact your calculus going forward or if you could just talk a bit more, I guess on rates and if that changes anything you’re thinking?
Aaron Milford
Well, just to clarify your question, Jeremy, are you talking about the rates we charge for pipeline movements or the general interest rate environment and its impact on how we may see our valuation?
Jeremy Tonet
Apologies. I meant interest rates, specifically. I’ll save other rates for later.
Aaron Milford
Yes. So as we look at it, we keep an eye on what we think fair value of the company is. And an increasing rate environment does impact that evaluation. I’m not going to go into all the details of that evaluation, but we certainly consider it. So that will continue to weigh into our decision about the value we see in buying units back, but we certainly consider it.
Jeremy Tonet
Got it. So implicit that you are happy with your leverage ratio. And so you don’t need to kind of adjust any of that at this point. You are at a good point.
Aaron Milford
Well, I’m not sure it’s related to the leverage ratio. I think it’s important, in rates — in the general environment, recall, we have been a long-term issuer of 30 year paper. So in terms of rising rates and an immediate impact in our interest expense and cash flows, we have essentially paid for that insurance over the last several years. So we just don’t see that same headwind given the fixed nature of our debt and the duration of that debt. So rising interest rates aren’t going to impact sort of our interest expense or cash flows here over the short-term with the debt that we have.
Jeremy Tonet
That makes perfect sense. Not everyone takes the same conservative approach to stacking out debt. So thank you. Thank you for that. And then maybe just for tariffs, real quick turning that direction. It seems like you’re going to have a lot of headroom for rate increases going into next year here, not finalized just yet. But just how do you think about I guess pacing in increases, whether it’s on a multiyear timeframe or just any other thoughts on strategy and tariff rate increases under what’s allowed under the indexation methodology?
Aaron Milford
So I think we spent a little time on this last quarter and I don’t think our perspective is changing. We want to be thoughtful about how we move our rates. And we are taking the time to really dig into our markets and understand the competitive dynamics of where we are. I mean I always like to remind folks, even our index rates, we have competition. There are other service providers in that market. So we have to be cognizant of that. So we haven’t made any decisions about how we want to pace into it or not pace into it. So I don’t have any specifics to add to that Jeremy other than to say, we are going to be thoughtful. And in any event, as we sit here today, the rate increases that we are expecting, we still think are going to be quite healthy, the question is going to be around the margin, how healthy they are going to be?
Operator
Our next question is from the line of Theresa Chen with Barclays. Please go ahead.
Theresa Chen
Hello. Thank you for taking my question. Aaron, I’d like to go back to your comment about the annual guidance first, just related to the annual bump not reflecting the full outperformance of third quarter and the conservatism baked into it. Can you elaborate on what exactly do you mean by conservatism? Which areas of your business, whether it be refined product volumes or costs that you could see underperforming a bit in the fourth quarter?
Aaron Milford
Well, I think the one item I would point you to specifically is just the volatility in the commodity markets, in particular basis differential, that’s one. We have, as I mentioned in my comments, most of our margin for the fourth quarter already locked in. But as we have also talked about in the past, we can’t really hedge the majority of our basis risk. And it’s been very volatile. As Jeff mentioned in his comments, there was a point in time earlier in October, where the typical differential would be New York Harbor minus $0.10. This year, it’s been New York Harbor minus $0.30, and sometimes even wider. But then we had the complete opposite thing happen, where that went from minus call it $0.20, to a positive $0.30 or $0.40, and in some cases, higher at moments.
So we’ve got a lot of — it’s not just that it’s wider, but it’s a lot more volatile. And to give you some sense, a nickel move in that basis is worth about $10 million on an annual basis to us. So when you’re talking about swings of minus 30, or minus 20 to positive 60, it causes us to feel a little cautious about how’s that market really going to move in the fourth quarter. So that’s one specific thing that I would point to.
The other thing I would point to is just a recognition on our part that general economic conditions are important. Our business has proven through the years to be really resilient, even through recessionary times. And we expect that resilience to continue. But as you get into shorter durations of time where you’re trying to provide guidance and what to expect, we don’t want to ignore that there’s still some economic uncertainty out there. And if or when that uncertainty actually starts to manifest itself, when is that going to occur. So we’re trying to be, at least recognize that potential as well. But it’s not anything specific to volumes, we expect to be higher. It’s not really that. It’s really more of the commodity-related volatility around basis. And just the general recognition that the overall macroeconomy has some uncertainties in it at the moment.
Theresa Chen
And speaking of macro uncertainty, as it relates to your refined products business, what are you seeing in terms of demand, just taking into account the quarter-over-quarter slight decrease in total volumes shipped? And it seems to be tracking below the previous annual guide of being 4% above 2021. So curious what you’re seeing there?
Aaron Milford
Well, it’s interesting in the schedules we, I think, attached to our earnings report, if you do the math on total resigned refined products for year-over-year, year-to-date, we are up about 4% versus the 2021 period. So in terms of volume, it was down slightly, almost 0%, I think if you did the straight math quarter-over-quarter. But for the year, so far, we are up around 4%. As we look at the whole year, I think we’re going to be in that — around that 4%, maybe a little below, maybe a little above, but I think we’re going to be sort of in that range.
So from a volume perspective, things are tracking, and it’s holding in there. One piece of color I would add to the volume. We’ve in the past been talking about coming out of 2020 and post-COVID and the growth. And as we sit here today, and as we look forward, I think we’ve seen probably most of the rebound or quick rebound that we’re going to see. Our rural markets, of course, rebounded quite quickly and quite significantly. But the markets we’ve been waiting to see are our more metropolitan markets. So think of Minneapolis, St. Paul, think of Kansas City. Think of some of those more metropolitan areas, and they still seem to be a little behind the pre-COVID era volumes.
So that just may be with us for a little bit, Theresa, and we’re not necessarily giving up hope that it won’t get back there. But it just may be over a longer period of time as many of those cities still sort of get back to normal, as defined in 2019. We could debate whether we’re in a new normal or not, but I think that’s the reality of where we’re at. But I think we’ve seen most of the recovery we’re going to see from the COVID — pre-COVID period of time, with our metropolitan areas still lagging a little bit, but many of our rural markets are above where they were in 2019. Boil it all together, sorry for the long answer, volumes we expect to still grow year-over-year.
Theresa Chen
And then for the rates, when you saw in the third quarter related to longer haul movements from imagine the Gulf Coast to the Mid-Con due to refinery supply disruptions, would you expect that to continue given the ongoing downtime at BP Whiting, Toledo?
Aaron Milford
I think so. I mean, as long as the refineries Toledo and Whiting are down, I think there’s the potential for us to have to supplant with longer haul supply into those markets, as we’ve shown that demand is pretty resilient, it’s seasonal, but it’s pretty resilient. So that bodes well for us, so forever, how long that condition exists.
In terms of, how long or to what extent that continues to exist? That’s yet to be seen. Markets are fluid and they move around. And the longer conditions exist, they adapt in different ways. But generally, we think that’s a positive tailwind for us for as long as it exists. With refineries running at high 94% and 95% with inventory being fairly low across the country and on our system in many ways, the market has lost the ability to just respond to short-term disruptions, and it has to find barrels to match those disruptions from other places, so to speak. So we think that bodes well. It’s unpredictable, it’s hard to predict, if or when further disruptions may occur. But that lack of sort of built in resiliency that has existed in the past in the market, we think is also a contributor to through time seeing longer hauls, when we see disruptions. But it wasn’t just the Mid-Con. You’ve got longer hauls out to the West Texas, the Gulf, the group movement, obviously, we had longer hauls. But we also have longer hauls within sort of the footprint of our system as our shippers and customers adjusted to this new market. So it’s really long haul shipments generally in almost all areas of our pipeline system.
Operator
Our next question is from the line of Keith Stanley with Wolfe Research.
Keith Stanley
First, just the crude product margin for the quarter, so I think it was 27 million. And there’s probably some mark-to-market type stuff in there. But it’s a pretty big number versus history for the company. Can you can you talk a little about what the opportunity was in Q3? Was it just the marketing arm moving volumes where you had space? Or was it other types of activities?
Aaron Milford
Well it was really spread among many different activities. And I think how I would talk about and really encourage you to think about our crude marketing activities is very much an optimization game for us. And it’s one that — relatively speaking, we are still fairly new to the crude space. We have been doing it for 10 years, but in the grand scheme of everyone we are competing against and how that market has evolved over centuries, we are still new in many ways. So we are continuing to learn and we are continuing to get better frankly at taking advantage of opportunities that present themselves to us than we have in the past. And I think that’s going to continue. Our ability to maximize the value of our assets, based on opportunities that present themselves. Will it always be an outperformance by 27 million whatever? I don’t know. The point is, we are working to make sure we are maximizing that value as much as we can. And what’s driving that value is things like quality differentials, it’s things like location differentials, it’s things like the combination of quality differentials and location differentials. There’s a lot of different sort of opportunities that present themselves that frankly were just better today than we were even a year ago being able to capture, but they are going to be unpredictable in terms of exactly how they present themselves. And we also, as we are learning and executing on these opportunities remaining mindful of the quality expectations and quality service that our customers expect.
So we are trying to — we’re rebalancing our ability to maximize the opportunities we see with the expectations of our customers and what they want see. And as we see opportunities, we’re going to try and grab them and we’re just getting better at it.
Keith Stanley
Interesting. Thanks. Second question, big picture one. Just with the IRA passing and Aaron you spent a lot of time at the Analyst Day, kind of going through the data and the details on EV adoption and long-term views on impact to the company. Any updated thoughts you would share on how you look at the IRA and some of the benefits for EVs and just updated views on the topic since you have kind of delve into this in detail before?
Aaron Milford
I’m happy to talk a little bit about it. I think at a summary level, the IRA doesn’t change really the views that we expressed back in April of this year. And the reason it doesn’t change it much is implicit in a lot of our conversations assumed that we would have significant EV subsidies. So that was sort of implicit. So the fact that there is not really new information to us. And one thing I will say about the EVs is, the manufacturing requirement and the input requirements in terms of being domestic or not coming from foreign sources is one that makes getting the full benefit of that incentive more difficult. There is no way I think around that. It’s going to be more difficult for consumers to achieve, because the product — it’s going to be really hard to meet the threshold to get it.
So I can make an argument that the incentives in place are probably more restrictive than the incentives we thought would be in place when we were talking about this in April. But that’s sort of getting into the minutia of it.
I think the other area about IRA that I would focus on are the incentives for CO2 sequestration. They have increased the benefit there from the 45Q credits from where they were before, that’s incrementally making CO2 projects and things like that more competitive or more economic. But I’m not sure that it’s a game changer in terms of the opportunities set overall. Much of the cost to capture CO2, if you are really trying to get at the heart of where the emissions are $85 with the incentives still really don’t chin that bar in most bases. So I am not sure that changes our view from April again on what that opportunity set might look like. But it could in the margin on very specific projects down the road. But as a general rule, probably doesn’t move the needle.
The additional incentives for things like sustainable aviation fuel. I think those could be interesting. It’s certainly making it more economic for the producers of renewable diesel to consider taking some of that capacity or adding capacity to produce more sustainable aviation fuels. That’s a net positive. But if I were to put all that together, I would just say that it’s not materially changing the views that we had in April.
Operator
Our next question is from the line of Praneeth Satish with Wells Fargo.
Praneeth Satish
I think if I heard correctly, at the end of your prepared remarks you mentioned signing up for a new contract on LongHorn. I was wondering if you’d provide any more details on that, how large of a contract and the duration? And then I guess, how do you balance contracting more capacity on LongHorn versus waiting for takeaway to tighten in the Permian, and maybe contract at a better rate in the 2025 timeframe? I mean, do you have a view that takeway may not tighten that quickly and that’s why you’re kind of contracting now?
Aaron Milford
Well, I’m going to start with your multi-pronged question with the last part, which is the general thesis of differentials are low right now, why wouldn’t just wait till they’re better before you contract it. I mean what I would say is, we certainly think about that, and how do we balance that with being able to get committed barrels and reduce cash flow risk over the long-term and that’s the balance.
In this particular case, we had a customer where our views of the world overlapped in such a way that we thought it was a constructive rate, even if you look longer term at the forward curve on the differential, which we can all debate whether that forward curve and the differential is accurate or not, but if you look at it, which we do, when you look at what the customer was wanting to accomplish, we overlapped in a way that we think it made sense to do.
But it’s a case by case, I’m not sure it’s a general philosophy on our part, we’re going to go lock everything up, or we’re not going to lock it up. It’s very much a case by case, deal by deal evaluation on our part. In this case, we thought it made a lot of sense to do.
So going to the first part of your question, in my notes, when I comment, I mentioned that the average utilization committed on LongHorn beginning in January 2023 will be around 80%. So before the contract, as we sit here today, we would have told you it was 75%. So it’s about a 5% increase on the average overall. Of course, you also have to think about where would that utilization be next year, the years after that. But at the end of the day, from where we sit right now, we’re going from roughly 75% utilized to 80%.
And then if you were to think about the duration of it, essentially, what’s happening is, we were at a five year duration, six year duration, and we’re keeping that same duration essentially going forward. So we’re going to get higher utilization essentially committed over roughly a six year period versus if you hadn’t gotten it, that weighted average term would have gone down probably by about a year just because of the years passed since we last talked about it.
So hopefully that gives you enough detail. And I just don’t want to get in all the details on specific contracts. Just suffice to say higher utilization for a longer period of time. And I think it’s really interesting that we’ve got a crude contract generally, if you overlay with the period of time between ’24 and ’26, when I think most estimates would show capacity tightening. I like where our contract termination sort of sit in relation to that tightening.
Praneeth Satish
And I just — I guess I wanted to go back to Jeremy’s question on rates and the impact on capital return. But I guess I would just ask it a different way. Specifically, has there been a thought to potentially shift more of the capital return to distribution growth? Interest rates are moving higher, and now you can get a high single digit yield from a lot of places. So do you feel like your yield is competitive enough in the current environment to attract capital?
Aaron Milford
I would hope so. I know yields have gone up. But when I look at the absolute yield on our units, and compare that and risk adjust it versus some of the other higher yielding things that are out there, and you truly risk adjust it, I think we have a really strong value proposition, frankly. And as an MLP, depending on where you’re at in your own individual tax status and you start taxing some of those yields, and I think that’s an additional benefit to investors in our units our ability to defer a lot of that yield for some period of time, again, depending on when they’ve come in and where they’re at. So I think it’s extremely attractive. Frankly…
Jeff Holman
It’s probably also worth keeping in mind that the historical spread between treasuries and our yield and corporate borrowing rates and our yield has been all time highs recently, those aren’t normal. I mean, that’s not the norm for the last 20 years, those spreads have been a lot narrower than they were a couple of years ago for this recent run up in rates. There’s no reason to think that what they were before this run up in rates was the proper rate they should hold going forward. It’s probably the opposite being is more true. And so this would represent more of a normalization.
Aaron Milford
So as we think about in totality, the distribution we think is attractive. We’re going to continue to — we understand that’s an important part of our value proposition, and at the same time on unit buybacks, it’s going to remain subject to our views of value, and timing, and so I don’t think that changes that a great deal for us.
Operator
Our next question is from the line of Neel Mitra with Bank of America.
Neel Mitra
I wanted to touch on the crude segment. This is the second quarter in a row that LongHorn and BridgeTex have had lower volumes, and you’ve collected deficiency revenues, but it seems like the language around it has changed. It seems like this time you said timing versus second quarter, it seemed like more volumes were flowing to Corpus Christi to generate a higher net back from the export market. Could you comment on the timing of volumes there and what you mean by that?
Aaron Milford
Well, I think the timing comment really is meant to encompass the fact that our shippers are making different decisions with what they’re going to do with the barrels coming out of the basin. And they still have a commitment to us from a revenue perspective. So they are either going to pay us efficiency or they are going to move the barrels later. So the idea is that we expect them to move the barrels. They are just doing something different with them right now than what we would otherwise expect. So that’s what drives the timing comment is, is really we expect the barrels to flow. They just may flow at a different time or at a later time in their commitment than if you were just ratably — and you are sort of charting it out. And the reason behind why they may be shifting their timing is a desire to go to a Corpus or take advantage of some other differential that they want to see.
As we look long-term, we think Houston is well-positioned and those barrels will want to come back and go to Houston for one reason or another. So it’s really both of those items. The timing comment is meant to be I think more general in terms of we expect the barrels to flow just at a different point in time than you would have if you put them on ratably and the reason why it’s maybe less ratable is because shippers are making different decisions of what they are doing with the barrel right now. Does that clarify it for you?
Neel Mitra
It does. And maybe I can ask a more specific question with your new customer on LongHorn going from 75% to 80%. You said you had a shared philosophy on rates in the Houston market. Can you share what that philosophy is, and why you think the volumes will eventually return back to Houston as kind of the market that we should look to?
Aaron Milford
Well, I think there is a couple of things happening. One, I think some of it’s going to depend on what do you view about exports. If you just look at the state of play today, I don’t think there is any question that, if I’m a producer and all I want to do is export it. That’s it. That’s all I’m interested in doing. Corpus has some advantages over Houston. It’s a little cheaper to get there over the pipeline. Some of the terminal capacity is a little more efficient for large scale export. So it’s more cost-efficient today to get down to Corpus if all you want to do is exports. The question is, how long is that going to occur and is that really permanent solution? And how will Houston evolve through time, given that?
Our expectation is that Houston provides you a lot more optionality as a producer than to a large refining complex, which Corpus has some refining complex there but not as much as Houston. If you move it to Houston, you can also get it over to Louisiana. Through time, we think exports in Houston are going to continue to become more competitive with Corpus for exports. So as we look at Houston and we think about it, as that market evolves, it should again, through time, pull more barrels to Houston.
Secondly, we are dealing with a pretty exacerbated condition right now in terms of crude oil market leaving the world market and meeting those exports. You can come up with a bunch of different sort of assumptions or beliefs around how long it’s going to continue to the extent that it’s going to continue. But if some of the pressure on exports abates, again, we think Houston for the reasons I just mentioned is the more attractive market over the long run.
Neel Mitra
That’s sort of helpful. If I could ask one last question, you mentioned the gas liquids blending margin was $0.75 during the third quarter and the basis really worked in your favor kind of in September. Is it fair to say that, that $0.75 is either kind of flat or moving up in Q4 just right now, because you’re getting the full advantage of the better basis versus Q3, where you only saw it towards the end of the quarter?
Aaron Milford
I would love to tell you that the basis has not as we speak already flipped back to the other sort of condition. So it was a short lived benefit that really impacted a portion of the third quarter that has abated since we’ve entered the fourth quarter. So unfortunately, no, I can’t say that, that benefit is going to flow through to the entire full quarter. So that’s just the reality of it.
Neel Mitra
Is there anything to be able to track that basis? It seemed like the Mid-Con was short product. So it was able to attract some product back. But is there anything we can look at to maybe try to predict that?
Aaron Milford
Well, you may not be able to predict it perfectly, because the markets I’m about to reference, well, I think give you an indication of view of things. But the market being volatile, it’s day to day, hour to hour, in some cases in terms of what the basis will be. But if you’re trying to get a sense for what that basis is, look at the NYMEX, New York Harbor price, and look at a Platts pick your serve as Group 3 price. And the difference between those two will be indicative of the basis that we’re talking about. Again, it won’t be perfect, but it is something that you can look at to get a sense for it.
And just to round out, if you’re trying to do that on a futures basis, you have to be a little careful because the Mid-Continent market is much more of a physical market than it is a futures market. Hence why it’s difficult to hedge this basis. If they were both futures markets, you would have a better — a more efficient instrument to sort of deal with it. But the fact that the mid-con much more of a physical — I don’t want to call it spot but sort of right now business compared to NYMEX being more of a futures market in most cases, at least as we’re referring to it, that creates some noise in being able to compare those. You just have to make sure you’re taking into account time and a futures market dynamic compared to a more physical market dynamic in the Mid-Con.
Operator
Our next question is from the line of Gabe Moreen with Mizuho Securities.
Gabe Moreen
Can I ask about the splitter contract and maybe relative or the reup there, the extension through ’24 at a time, I guess when the economics for that asset are pretty healthy, to put it mildly. To what extent that may have been paired with the LongHorn contract as well? And then also, as you look through alternatives, do you I guess consider a lot of other things for that asset, which is pretty well positioned at the moment?
Aaron Milford
Yes. So the LongHorn contract and the splitter renewal are unrelated. So that there isn’t any interplay there. In terms of the term to 2024, it was a term that we were happy with, frankly, going out to 2024 and our customer was happy going out to 2024. I think both of us realized the economics are pretty favorable for the splitter right now. But getting a little more term on that was we thought beneficial to us. And I also have to highlight that as we talked about the splitter in the past that our exclusive customer had renewal options on the splitter, and the sort of economic terms of those options were pretty much set. So what we’ve ended up doing is getting what we expected to get. We’re getting the economic trade that we got, and we’re getting the term out to 2024, which we found attractive.
In terms of how we think about the splitter long-term, we do look at other alternatives, is it something that we would be comfortable operating ourselves? For now, we decided that we’re very happy that our customers are staying in it long-term. Is that going to be the case? I don’t know. We’ll get down to 2024, and we’ll have those discussions at that point in time and figure out where we’re at. But we were happy to get the additional term as we sit here today, we’re happy with our customer, but we’re also not ignoring the long-term economics of the splitter either in terms of what it might be able to do for us. So maybe we don’t want to lock it up for ever such the — maybe something changes. For now, we’re pretty happy.
Gabe Moreen
Thanks, Aaron. And then maybe if I could just ask a quick one on the El Paso contract, where that — expansion where that stands on the usual 6x to 8x multiple that your reference with expansion projects?
Aaron Milford
Yes, it’s going to be in that range, probably the lower end of that range. If things work out the way we expect them to work out, it could even be better.
Operator
Our next question is from the line of Michael Cusimano from Pickering Energy Partners.
Michael Cusimano
Coming into the year, I believe you guided refined products transport rates to flat year-over-year, despite the higher uplift. And it looks like the average tariff is trending higher than that. Can you kind of update us on how you see that going forward? And if there was conservatism coming in, or if it’s just trending higher with some of the dislocations you’re seeing in the markets?
Aaron Milford
Well, as we think about and we provide guidance on tariff rates, there’s really a couple of assumptions that we make. One is what is going to be our midyear tariff adjustment? And really, the beginning of the year, we haven’t made that adjustment yet. But we have some ideas about where we think that’s going to come in. But the second assumption that we’re making there is what happens to the supply patterns on our pipeline? In other words, put it in specific terms, what’s the average haul per barrel, so to speak, on our pipeline system? And our approach has often been as we’ve got a long history of knowing sort of how long those pipeline movements are. And if that average haul times a tariff is what gives us that actual tariff to realize. So as we came into the year, even with the expected increase midyear on the rate itself, the average haul wasn’t necessarily increasing or changing from our historical patterns. And that led to — if you put that in the machine and put those two things together, it led to generally a fairly flattish, overall expected rate that we would realize. Hence the guidance we gave.
As we sit here today, what we’ve experienced so far this year, some of it due to market disruptions, is the length of our haul is getting longer than what we thought it would be. So now we’re getting longer hauls at the higher tariff given the midyear tariff increase, and that’s resulting in essentially a higher realized rate. So that’s the sort of detail of guidance. We were not assuming the haul in our system to necessarily get longer. In many cases stay the same or in some cases get a little shorter. And what’s happened is the opposite is actually getting longer and some of that’s driven by unforeseen disruptions in the markets that we serve with refineries being down. So I’ll stop there and see if you have any additional comment or question around that.
Michael Cusimano
Yes. No, that’s very helpful, Aaron. Yes, one follow-up on that. Do you think that there has been a structural shift to where that longer, call it, like more barrel miles in your system continues or is it hard to quantify or forecast because it’s just short-term dislocations that we have seen in the market so far?
Aaron Milford
As we bring on our expansion for instance to El Paso and you compare that haul to our average haul, that’s a longer haul. So that would lead to net-net potentially a longer haul in the system as a whole, especially as we are going all the way out to El Paso. So I think there may be in some areas some structural shifts that could benefit us.
In terms of the disruptions, it’s hard to predict where disruptions are going to occur, what’s the nature of the disruption, the duration of the disruption. But I think something that we need to keep in mind is that, whatever resiliency was built into the system before in terms of inventory levels and then refineries, there is less resiliency in the system today. And then you have had things like refiners just shut down, refinery in Cheyenne, refinery in New Mexico, and as those shut down and we backfill those, it leads to a longer haul.
So I know this is a long winded answer to say, there could be some structural shifts that repeat themselves that ends up to a longer haul. We haven’t done all of our work to see how we think that’s going to shake out for ’23, but it’s possible that we do start experiencing some longer hauls than what we had experienced three or four years ago. Longer haul than what we are experiencing this year, I don’t know. But certainly over three or four years ago, that’s a longer haul. And then as refinery rationalization and disruptions happen, I think we are well-positioned to benefit as that occurs, but it’s just less predictable.
Michael Cusimano
Okay. Yes, that makes a lot of sense. And then one more if I can. Aaron, your comment on the metro areas that are somewhat lagging the recovery. I just wanted to make sure that is — that’s the metro area as a whole, their consumption not specific to your system. Is that right?
Aaron Milford
Well, in some of these metro systems, we are a significant part of the supply into those. So it may not be on the whole, but what we are seeing at least for the share that we supply, maybe down a little bit. But my comments are reflected more of what we are experiencing in the metro areas.
Operator
And there are no further questions on the line. I’ll turn the call back to Aaron for any closing
remarks.
Aaron Milford
Well, thank you all for your time today. Just to reiterate, we are pleased with the third quarter financial results, as well as a new project to expand our refined products pipeline capabilities, El Paso. We remain focused on finishing the year strong, managing our business in a responsible manner and focusing on maximizing the value for our investors over the long-term. So on behalf of Magellan, we appreciate your continued support. Thank you, and have a nice day.
Operator
That does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your lines.
Be the first to comment