Magellan Midstream Partners LP (NYSE:MMP) Q2 2022 Earnings Conference Call July 28, 2022 1:30 PM ET
Aaron Milford - President, CEO & Director
Jeffrey Holman - Principal Accounting Officer, Senior VP, CFO & Treasurer
Conference Call Participants
Theresa Chen - Barclays
Jeremy Tonet - JPMorgan
Keith Stanley - Wolfe Research
Praneeth Satish - Wells Fargo
Neel Mitra - BofA Securities
Michael Cusimano - Pickering Energy Partners
James Carreker - U.S. Capital Advisors
Michael Lapides - Goldman Sachs
Greetings, and welcome to the Magellan Midstream Partners Second Quarter Earnings Conference Call. During the presentation, all participants will be in a listen-only mode. Later, we will conduct a question-and-answer session [Operator Instructions] As a reminder, this conference is being recorded Thursday, July 28, 2022.
It is now my pleasure to turn the conference over to Aaron Milford, President and CEO. Please go ahead.
Hello, and thank you for joining us today to discuss Magellan's second 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 Securities and Exchange Commission and form your own opinions about Magellan's future performance.
As we previously announced, we closed on the sale of our independent terminals network on June 8 and have been actively putting those proceeds to work. Including working capital adjustments, we received a total of $447 million for these assets and deployed $190 million during the second quarter into our equity buyback program, underscoring our commitment to maximizing long-term value for our investors. And today, we've continued our trend of solid financial performance with second quarter results that slightly beat our EPU guidance.
With that, I'll now turn the call over to our CFO, Jeff Holman, to briefly review our second quarter financial results versus the year-ago period, then I'll be back to discuss a few more areas of interest before answering your questions.
Thanks, Aaron. First, let me mention that, as usual, I will 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 second quarter net income of $354 million compared to $280 million in second quarter 2021. As noted in our press release, these results include a $162 million gain in the current period related to the sale of our independent terminals network, which is reflected in income from discontinued operations and a $70 million gain in the prior period primarily related to the sale of a portion of our interest in the Pasadena marine terminal joint venture. Excluding both of these gains, net income decreased about $18 million quarter-over-quarter.
Adjusted earnings per unit for the quarter, which excludes the impact of mark-to-market adjustments, was $1.94. And further excluding the $0.77 favorable impact of the gain on the sale of discontinued operations, earnings per unit was $1.17, exceeding our guidance for the quarter of $1.12. And I'll remind you that the EPU guidance we gave for the quarter did not include the gain on the sale.
DCF for the quarter at $228 million was $40 million lower than last year. Free cash flow for the quarter was $649 million, resulting in free cash flow after distributions of about $429 million. A detailed description of quarter-over-quarter variances is available in the earnings release we issued this morning. So as usual, I'll just touch on a few highlights of the quarterly results.
Starting with our refined products segment, operating margin of $246 million was 8% lower than the 2021 period. I'll provide more detail shortly, but in summary, the resulting decrease between periods was primarily due to an increase in operating expense, which is partially offset by an increase in transportation revenue and product margin.
Drivers of the increase in transportation and terminals revenue included record high quarterly transportation volumes resulting from additional contributions from our recent Texas expansions and higher South Texas volumes, which moved at a lower rate as well as continued demand recovery from pandemic levels, especially of aviation fuel. For the quarter, total refined products volumes were up 3% versus '21 levels.
In addition, our average transportation rates increased year-over-year due primarily to the midyear 2021 tariff increase while tender revenue benefited from a more favorable commodity environment. These benefits more than offset lower storage revenue, which similar to last quarter was impacted by lower utilization and rates following recent contract expiration.
As a reminder, the prior period still benefited from some contracts entered when the market was in steep contango. And now those contracts have rolled off, while the currently [vac-related] market has resulted in lower demand for our storage services.
Operating expenses for the refined segment increased during the second quarter 2022. I'll note that with the exception of power costs, which did increase slightly year-over-year, most of the increase for the quarter was not directly related to inflation but instead represented a couple of other discrete circumstances.
In particular, we experienced less favorable product overages during the quarter, which reduced operating expense. Product overages and shortages fluctuate period-to-period with the operation of the pipeline. And these fluctuations can have a more pronounced effect in periods of elevated prices, which we saw this quarter.
Additionally, the refined products segment experienced higher property taxes primarily as a result of recently completed expansion projects. Product margin was favorable compared to the second quarter of 2021 primarily due to higher gas liquids blending margins and slightly higher volumes.
Our realized margins increased year-over-year to about $0.40 per gallon versus closer to $0.35 per gallon in the prior year period. As we noted on last quarter's call, basis differentials have been wider than normal recently. And these wider differentials have offset some of the benefit we otherwise would have expected from our blending business.
Further, these favorable gas liquids blending results were partially offset by higher unrealized losses in the current period related to our hedging activities, just given the volatility in prices this year and the fact that we have outstanding hedges through next spring.
Turning to our crude oil business. Second quarter operating margin was approximately $108 million, slightly higher than the 2021 period. Longhorn volumes averaged a little over 200,000 barrels per day compared to 260,000 barrels a day in the second quarter of 2021 primarily due to the timing of when our committed shippers have elected to move volume under their commitments as well as the expiration of a few of our smaller marketing commitments over the past year, which moved at a lower rate.
Volumes on our Houston Distribution System increased versus the prior year period with more tariff shipments resulting from a new pipeline connection to our system. In addition, terminal throughput fees increased as more customers elected to use a simplified pricing structure for our services within this Houston area.
We continue to see growing customer interest in such arrangements with the result that while we have added connections to the HDS and the volume of physical barrels we move has increased, much of the resulting incremental revenues are showing up as terminal throughput fees rather than as transportation revenues that get reflected in our transportation statistics.
Looking briefly at expenses. Operating expenses for the crude oil segment increased slightly primarily due to the higher integrity and maintenance spending, in particular, on the splitter, which has -- which had a turnaround this quarter, partially offset by lower power costs as a result both of lower Longhorn volumes and our ongoing optimization efforts.
Moving on to our crude oil joint ventures. BridgeTex volumes were approximately 215,000 barrels per day in the second quarter of '22, down from nearly 315,000 barrels per day in '21 due primarily again to the timing of when our committed shippers have elected to move volumes under their commitments. We did once again recognize additional deficiency revenue for the BridgeTex pipeline during the quarter, which offset the lower volumes. And I'll note that although this recognition of deficiency revenue results in a benefit to 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.
Finally, on Saddlehorn, volumes averaged about 220,000 barrels per day, about the same as in the 2021 period albeit at lower rates due to the expiration of the initial contracts on the line late last year.
There are just a few other items I'd like to touch on. First, I'll note that net interest expense increased slightly primarily due to a higher average debt balance during the quarter. That balance came down somewhat when we received the proceeds from the independent terminal sale.
And as of June 30, the face value of our outstanding debt was $5 billion, with a weighted average interest rate on that debt of about 4.4%. 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.
And that brings us to the last item I'll touch on today, which is capital allocation. I want to reiterate what I know you've heard us say before. We remain committed to maintaining the financial discipline we are known for while delivering long-term value for our investors through a combination of capital investments, cash distributions and equity repurchases.
As already discussed, we received the proceeds from the sale of our independent terminals network during the second quarter and began actively putting those proceeds to work through our buyback program. We repurchased nearly 3.9 million units in the second quarter at an average purchase price of $48.79 for a total spend of $190 million.
Year-to-date, we have allocated $240 million senior repurchases, bringing the total since inception to $1.04 billion. So far in 2022, we have returned nearly $680 million to our investors through a combination of unit repurchases and cash distributions, including our recently announced distribution, which pays out next month, that number is closer to $900 million.
Further, we continue to see unit repurchases as an important focus of our ongoing capital allocation efforts. And as previously stated, we currently expect free cash flow after distributions to generally be used to repurchase our equity.
Of course, as we are always careful to note, timing, price and volume of any unit repurchases will depend on a number of factors, including expected expansion capital spending, free cash flow available, balance sheet metrics, legal and regulatory requirements as well as market conditions and the trading price of our equity. And in particular, I'll note that we remain committed to our long-standing 4x leverage limit.
With that, I'll turn the call back over to Aaron.
Thank you, Jeff. Concerning guidance, we're still projecting annual DCF of $1.09 billion, consistent with our previous expectations for 2022. You may recall that we increased our annual guidance last quarter to capture the benefit of the higher commodity pricing environment to Magellan's financial results.
As we look forward from here, there are a number of things we're keeping our eye on, including a volatile commodity environment, the impact of inflation on our expenses, the impact of higher prices on refined products demand as well as general economic conditions. But we do not expect a material impact from these items to our annual guidance.
Concerning refined products demand, while we didn't detect any notable demand disruption due to higher fuel prices during the first half of the year, we did see a little weakness during early July. But with declining fuel prices over the last few weeks, it's not yet clear to us that this early July weakness is a developing trend.
Specific to our commodity activities, we've continued to lock in additional hedges over the past few months related to gas liquids blending with more than 80% of our upcoming fall blending now hedged at margins of nearly $0.50 per gallon. All in, we still expect blending margins for the current year to average around $0.40 per gallon.
We have also made significant progress in hedging next year's blending as well with 70% of our expected spring 2023 activity hedged at margins in excess of $0.60 per gallon.
As we discussed last quarter, the recent basis differential between NYMEX futures hedged contract prices and actual prices for products physically settled in our Mid-Continent region continue to be wider and more volatile than normal, which negatively impacts the overall margin we realize from our blending activities. If this basis differential were to return to more historical levels, we would expect the margin we realize from future blending activity to increase by another $0.05 to $0.10 per gallon, including our hedged volumes.
Moving on to expansion capital. We continue to actively pursue additional projects to grow our business in a prudent manner. Based on projects already committed, we now expect to spend approximately $80 million in 2022 on expansion capital. This estimate is $10 million higher than last quarter, in part due to the addition of a new project to increase our gas liquids blending capabilities at our East Houston terminal.
As you may recall, we target low-risk expansion opportunities that meet or exceed our 6 to 8x EBITDA multiple threshold. And in the current environment, we still believe that around $100 million per year is a reasonable assumption for expansion capital spending.
Although not yet included in our spending estimates, the open season for the potential expansion of our Texas refined products pipeline to El Paso was previously extended and is currently set to expire tomorrow. Significant interest has been received from the industry with potential customers simply needing a bit more time to make a final decision and for us to finalize the scope of the project based on any commitments we receive.
Before wrapping up our prepared remarks, I'd like to briefly speak to inflation and tariff rates for a moment, knowing that this is a topic of interest. Consistent with our previous guidance, we increased our index rates by the 8.7% allowable by the index earlier this month, which, as you may recall, reflects about 30% of our refined products markets, while in the remainder of our markets, we increased tariffs by an average of 5% for an all-in increase of 6% effective July 1.
As we have discussed, we project these increases to outpace the increases in our expenses for the year, in part due to our continued focus on optimization opportunities that ensure we are operating as efficiently as possible while preserving the safety and integrity of our assets.
As I think everyone is probably aware, the PPI for finished goods metric used for the FERC index is up 15.5% year-to-date through June, which is the level we simply haven't seen since the index was established in the early '90s. As I just noted, we typically adjust our refined product tariff rates in the 30% of our markets that follow the index by the allowable FERC index change each year. And our baseline expectation is that we'll generally continue that approach going forward.
However, given the current inflation backdrop, we will be paying close attention to numerous factors between now and July of next year, including competitive conditions and customer dynamics as well as the trajectory of our own costs. And we'll approach next year's rate increases thoughtfully and deliberately as always with a view to long-term value creation for our unitholders.
With that, operator, we are now ready to open the call for questions.
[Operator Instructions] The first question comes from Theresa Chen of Barclays.
Aaron, I wanted to touch first on your comments about inflation and the expected rate increase going into 2023. Understand that for the 30% that is subject to FERC indexation, you have a very deliberate process there. For the rest of your refined products footprint, the 70% subject to market rates, is there upside risk to that single digit -- mid-single-digit rate increase that you've been able to get for the past few years given the inflation pressures that we're seeing today?
So when we think about our market rates and our index rates, as you mentioned, we have a thoughtful process. We go by market by market and make sure that we're making good long-term decisions.
When you look at the market rates versus the index rates, those haven't always followed by the same amount. And I don't feel that we're tied to the market rates needing to follow the index rates. And the process that we'll go through is looking at those market-based rates, looking at the competitive dynamics and making the decision at that time.
Obviously, this year, we didn't raise the market base rates as dramatically as we raised the index rates. I don't know if that pattern will necessarily continue. It may.
But I think on inflation for us, the general comment I would make is we feel that we'll be able to raise our rates at a rate that will exceed our cost inflation. And through that benefit, the question is going to be when we get to July, what's the market look like and how much of that benefit are we going to be able to realize. Does that answer your question, Theresa?
Yes. And then on the subject of cost inflation, the refined products operating expenses this quarter, I'm just seeing that significant step-up. Can you just remind us what a normalized run rate should be from here?
A normalized run rate for expenses generally?
For that refined products expense line, the 136.
Yes. I mean, this -- I don't know we've typically given a normalized rate per se. But I would say that this year, again, I mean, this quarter had a number of unusual onetime-type items. Again, as we went through them over or probably short is one of the big ones this quarter.
We had property taxes. The expected impact of overages, in particular, is going to be usually a slight positive on average. But it varies from month-to-month, quarter-to-quarter. Sometimes if you go back over the years in our transcripts, occasionally, it's a variance item. Sometimes positive, sometimes negative.
And when we have high prices, it can be a little bit more pronounced. But -- so we would expect that to normalize. It's not a run rate number this quarter at all. So you have to normalize for that, for sure. And again, there are a number of those onetime-type items that contributed to that.
Okay. And then on the equity earnings, just looking at the step down from last quarter and to your earlier point, Jeff, about the volume volatility as well as how you get paid from your equity joint ventures on a distributed basis, when would you expect the deficiency revenues to be paid back?
Paid back, well, just to be clear, on the crude side particularly where we've had those deficiency revenues, BridgeTex is the one we called out. We've received the payments and received the distributions related to those to the quarter. So there's -- it depends on the particular contracts if there's a deficiency like that. Sometimes there are credits that can be used in the future. But we've been paid, and we receive distributions related to that.
The next question comes from Jeremy Tonet of JPMorgan.
Just wanted to kind of parse through a little bit in the quarter here if you could help us think through, you might be able to quantify the impact of product overages as a headwind versus other cost headwinds?
Yes, Jeremy. That is area about $15 million.
Got it. Got it. And the other cost headwinds, I guess, if overages is kind of ephemeral, the other costs such as property taxes, higher power costs, are these sticky? Or just wondering gives and takes for that -- those costs over time.
Yes. Directionally, it's a fair question. Directionally, they're not sticky. Power is probably a little -- there's a little bit of inflation in power costs. And the property tax, there's a little bit that relates to our expansion projects coming online and being assessed at higher values. And we hope that's sticky because that means -- I mean, it's reflective of those assets performing well.
But most of it -- last year, we had some favorable property tax impacts, actually some true-ups from prior year. That was in the single digits million all-in effect on the quarter, that negative property tax. And so I'd say about half of that is probably sticking. About half of it isn't. And again, it just reflects the expansion of our asset base.
Power costs, it's really small increases at this point. We did have some other favorable power expenses at this time last year where we were still booking some of the favorability of power hedges we had in place during the winter storm, and some of that showed up in second quarter. So period-over-period, that contributed to a negative variance in comparison. So -- and that, of course, that's not sticky. So small digits on power, small digits on taxes, and the rest of it is just one time.
The next question comes from Keith Stanley, Wolfe Research.
Wanted to start on the approach to buybacks from here. Obviously, a lot of progress in Q2. The cash balance is kind of low now at the end of the quarter because you repaid some of the CP borrowings. So thinking about buybacks going forward, should we assume that's tied more to ongoing free cash flow? Or would you draw potentially on commercial paper to buy back stock in the future?
And then sorry, it's long-winded, but relatedly, Moody's about a month ago, they affirmed your obviously very good Baa1 rating, but there was a line in there about wanting to rebuild headroom under the leverage ceiling. Is that factoring into your thinking at all? Or is it we're under 4x, we're feeling good about that?
Let's take them in order. On the question around CP, I guess, yes, I mean, cash is fungible. So when cash from proceeds come in and we pay down CP, that's really just financing decisions in the form of that. It's really no magic. If we borrow -- now that having paid down CP, if we use the CP to finance repurchases, it's kind of a wash.
So yes, we could finance repurchases with CP. I would not look to our cash balance. And if you look back in history, we've never had a lot of cash to finance our repurchase activity for any stretch of time. So that's all just financing decisions.
It's really going to be driven by other factors like the ones I mentioned rather than short-term financial considerations like that.
On Moody's, is it coming into our thinking? No more than -- the 4x leverage limit has always come into our thinking. We've had good dialogue with Moody's. They understand what we're doing. I think if you look on a trailing period and not working in the proceeds, then it might look a little tighter than it looks currently on leverage. But I think our understanding with them is quite clear. We're committed to 4x, and I think they understand that. So it's really not changing our thinking, and I think they're just underscoring the importance of that commitment on their side.
And just a quick one. The refined products volume, so it sounds like you haven't seen very much at all as far as demand disruption to date. So is the forecast for the year for refined products volumes still to be up about 4% versus 2021?
As we think about the whole year, we think we're going to be pretty close to what we thought we'd be at the beginning of the year. There's a lot sort of moving around. You're right in that we haven't seen any direct evidence of what I would call any material demand disruption from higher prices.
As I mentioned in my comments, early July, we saw some weakness. But that seems to have abated as the pump prices have essentially fallen. So we don't see that trend continuing. So all in, I think we're going to be pretty close to what we had originally thought. So I don't think there's going to be any real surprises there, generally speaking.
The next question comes from Praneeth Satish of Wells Fargo.
Sorry to belabor this point. But on the product overages, I guess, I just wanted to be clear. Was this more of a onetime expense because this quarter, I guess, you had maybe a shortfall of product and therefore, had to make a payment, and it won't continue? Or is this going to remain kind of a volatile line item due to the higher oil price environment?
Well, volatile is probably a little strong, but it does fluctuate, and it has always fluctuated. That's not new. And like I said, usually, it's not enough to merit a mention, but it certainly has been many times before merit a mention. We've had to mention it as we try to explain variances. So I wouldn't expect to hear it, but I wouldn't be surprised to hear about it.
There's nothing unusual. It's just the typical operation of the pipeline. It's fairly complicated. A very, very small amount of the total amount of products we handle when we settle out in the month to compare our book inventory to our physical inventory. It doesn't take very much to have an impact, particularly when prices are high.
So again, the expected value from that on a typical year over any stretch of time, it's usually a small positive in our favor. But month-to-month, it can vary. And so the expected value is a slight positive.
But yes, you could -- it wouldn't be expected that we would have continued negatives. That would be not expected at all. And often, frankly, when you're doing this kind of calculation, a positive is followed by a negative and vice versa such as it all kind of evens out. But that's the way that works. Don't be surprised if you hear about it again, but it would be surprising to have a string of negatives.
Okay. Got it. That's clear. And then I'm sorry if I missed this, but just in terms of BridgeTex volumes, they were down quite a bit in Q2, I think, down 20% sequentially. I'm just wondering what's driving that.
Well, again, shippers on the line have commitments. And in some cases, they have commitments also as well, and they have their own operations, and they're just trying to optimize. So we had some volumes that normally would have been delivered to us and our commitments. The shipper made other arrangements with -- during the quarter and/or changed their pattern of behavior, but we still get paid. And that's the beauty of commitments.
So it's not something we prefer. We prefer to get tenders on that and everything else. So it has some small impacts on us if they don't ship. But that's a pattern that's unusual, and we don't expect it to recur.
Obviously, it's a particular set of events or circumstances that would cause that. We haven't seen it very often, and we don't expect -- we're not projecting it to continue through the year.
The next question comes from Neel Mitra of Bank of America.
I wanted to refer to a part of the release for the guidance for 2022 where you said the recent decline in commodity prices could offset some of the overages in terms of your budget that you've hit this year. Just trying to walk through the different line items there.
So are you kind of referring to RBOB butane spreads? With oil prices coming down, I would assume that with gasoline prices coming down as well that, that would eliminate some demand disruption, and that would be good. And then the other part would be the Midland to MEH spread, whether that's widening or contracting and what you're seeing there? And if you could just kind of walk through the puts and takes there when you look at commodity sensitivity for the second half of the year?
Yes. So I think you've hit on a key point overall, and that is with the commodities market and the volatility that's going on there, there are a lot of puts and takes. Generally speaking, our butane margins are still coming in fairly strong because usually compared to recent history, the volatility on the butane blending margins has been the basis differential between our hedges and when we actually physically settle them. That's muted what I would say some of the upside potential that we would have otherwise expected in our butane margins.
So that's one area that as you look at the back half of the year, we're going to be monitoring that basis volatility. Unfortunately, it's a very difficult risk to efficiently hedge.
If you look at commodity prices more generally on our business outside of butane blending margins, higher prices mean higher tender revenues. As Jeff mentioned earlier, as we look at a year or a long period of time, we are typically on the positive side of gains and losses such that higher prices drive better performance from that regard, so tender deductions, higher prices for the net product gains that we have, those are all tailwinds for us.
And as those prices go up or down, that potential obviously goes up and down with it.
In terms of high commodity prices and the gives and puts on demand, as we've mentioned many times in the past, gasoline and generally transportation demand is fairly inelastic. I think we were maybe testing that a little bit in early July with the prices we saw upon them.
But we haven't, I don't think, broken that inelasticity. I still think it's very inelastic. So even with higher commodity prices, as long as they stay within sort of an expected range, not too extreme, we don't see a lot of commodity risk up -- whether prices are up or down really driving that volume one way or the other unless you get to an extreme, which again, we may have tested in July, but we've come off of those extremes.
So when you put it all together, we had a really strong or high-priced commodity environment that we thought, obviously, it was going to provide a lot of benefits. As those prices have come down, some of that benefit is going to be more muted than what we had originally thought it might be.
So I mean, it's really that simple. But even when you put all that together, what I want to reiterate is our guidance of $1.90 billion is still intact. So taking all of that, all the puts and takes, all the ins and the outs, looking at the general economic environment for the back half of the year, we're keeping our eye on those things.
But we think as we sit here right now, our guidance and the expectations that we've set are still on the table and still what we're going to be able to achieve. I think part of the disconnect, which may not be the right word, but I think we had expectations that had commodity prices stayed where they were at and continue to go higher that we might see more upside than what we're essentially seeing right now. And it's for the reason we just talked about it. It's the basis differential. And it's just a lot of puts and takes that are sort of -- it seems like a little bit of a downer in terms of performance, to be honest with you. But the reality is we're hitting expectations. And even with all that volatility, we expect to perform well.
Right. And if I could follow up on the basis between the New York Harbor and Mid-Con, do you see when blending margins are higher that, that positively correlates to a higher basis? Or is that something that's uncorrelated, and you could see a lower basis and higher margins next year? Is there -- what's your thoughts on that?
Yes. I don't think the basis is driven by the outright margin or the outright price. It's relative to what's been going on in the world. We've been dealing with some really dynamic things.
New York Harbor with the events going on in Europe, we think, for many months is being bid up higher and higher and higher. And when you look at the Mid-Continent, and you look at that relative trade between New York Harbor being bid up and maybe Mid-Con not being bid up as much, it creates a wider basis. I don't think it's correlated to the margin level or correlated to the absolute price. I think it really is a relative phenomena between the two markets, one being impacted more so by world events than the other in this particular instance.
So no, I would not say that they're correlated. So my comments, we tried to point out that if that basis behavior goes back to what we think is more normal, there's some upside on the table for us as we look forward. But it continues to stay wide, and it continues to be volatile.
The next question comes from Michael Cusimano of Pickering Energy Partners.
I wanted to talk about the splitter, if you could frame out how you're thinking about maybe like the recontracting environment. And then depending on how that goes, maybe like what the sensitivity is with refined products revenues and what the upside or downside could look like?
Well, as we sit here today and we look at the splitter, there's a lot of fundamental value in the splitter. You may recall, not to rehash too much, but we operate it. We have a customer that provides the inputs and takes the outputs. And that initial contract will be up for renewal next year.
So the question, which is a logical one of what's going to happen, and that customer is still interested. We have other folks interested in the splitter. What I'd point to is that there's fundamental value in that splitter that we think provides a lot of comfort for us in terms of it continuing to be an economic and a contributor for us moving forward.
That may mean that we recontract it with our current customer. It may mean that we recontract with someone else. It may mean that we operate it potentially for ourselves.
I would say that third option is our least preferred, frankly, but it's something that we're thinking about. In terms of sensitivities, we've already sort of built in some views on how we think that, that could go in our own mind. And I don't think it's going to be material one way or the other, quite frankly, for us.
We think we've got a good setup here that the contracting of the splitter should become -- not be a material driver one way or the other.
In terms of specific sensitivity for you, I don't have a number for you other than what I've seen has been fairly immaterial in the aggregate. And again, we're pretty confident we're going to get it recontracted or find a different way to continue to see value because to be frank with you, I mean, the value of the splitter is probably high now as it's ever been when you look at it fundamentally.
Sure. Yes. That makes sense. And then one more. If I could revisit BridgeTex, on the commercial side, I was hoping you could talk through maybe what that dynamic that is driving the volumes down. Like are customers looking to bring volumes into Corpus for maybe like more Brent pricing with it being strong this past quarter? Or is there a Cushing pull maybe away from Houston that was temporary? Any color there as to what customers could be looking to do.
Well, I think what's happening is a customer -- they have a commitment to us. So they know that if they don't move on our line, they've got to pay a deficiency. It may be there are other markets they want to move into for a short period of time. Corpus could be one of those.
I'm looking at the dynamics, I'm not sure Cushing would be that market, but the international market or Corpus could be where they're making a decision where it's better for me to take it to Corpus, get a better value, pay the deficiency, and I'm still in that and better off. I mean, those are the decisions that they're making.
So that's an example of potential decisions that our shippers could be making, but that's also the value to us in terms of the commitment. We still earn the economics that we expected to earn. I don't think that's necessarily a trend. We don't expect that to continue forever. But there are moments where they may be making those decisions for sure.
Okay. Got it. And is your -- I know you get paid on it, but is your margin better or worse if they elect for deficiency payments? I guess does it -- as you offset the -- what would be the variable cost in flowing that...?
Yes. I mean, yes, generally speaking, we're going to make more money if they actually move it. I mean, on tender deductions, potential movements downstream, different revenue streams that come with it. We have a strong preference for folks to move it. But that's sort of -- yes, it's better if they move it.
But if they don't move it, it's not like the economics are such that we're harmed in a great deal. It's just that we're not earning some of the downstream revenue that we might otherwise earn, and we're not earning tender deduct.
So I guess you -- to answer your question specifically, the margin is probably less if they don't move it, but it's not such that we're losing money if they don't move it or it's still not a good economic proposition for us.
Yes. We're not losing a lot. We do save a little on power to your point. I mentioned that in the context of LongHorn. We did have slightly favorable crude power expenses partly due to the fact that Longhorn also had that dynamic this quarter.
The next question comes from James Carreker of U.S. Capital Advisors.
Just wondering if I could talk a little bit about the reaffirmation of guidance implicitly implies about $100 million more DCF in the second half of this year versus the first half of this year. Just wondering if you could walk through some of the drivers. Obviously, you've got the tariff increases that hit July 1, but you no longer own the independent terminals. So just trying to walk through maybe why the second half is looking up be so much stronger.
Sure. So the first thing I would note is, one, the tariff increase is in the middle part of the year. The second piece I would note is that there is a seasonality to our business. If you look, we often have because of the timing of the butane blending activity, the fall is usually a more significant activity in the fall than it is in the spring. So there's some seasonality that comes with particularly our blending business.
And then also our underlying pipeline has some seasonality to it. So there's some seasonality that's just sort of built in. In many ways, the second half of the year just tends to have more activity and do fundamentally better. So it's higher tariff rates, it's more activity due to seasonality in the back half of the year. Those are really probably the 2 primary drivers.
Yes. The locked in blending margins are a little bit higher as well. So again, subject to basis, we expect that to be stronger in the second half of the year than it was in the first.
Okay. And then just thinking bigger picture about the Permian. Just wondering if there's any indications about -- with continued growth on the production volumes there when you guys look at forward spreads, has there been any improvement even in, I guess, not spot necessarily, but looking out to '23, looking out to '24 to the extent that there are transactions happening on those time frames?
If you look at the forward curve for the differential between Midland and Houston or East Houston, the forward curve shows that there should be improving differentials over time. If you look right now what's happening, I wouldn't say that we're seeing dramatic improvements today in that differential, what we can earn today versus what we could earn yesterday, but directionally speaking, the forward curves pricing and wider differentials, so we would expect those to improve from here.
You're right, production continues to grow. As that production grows, it should minimize through time the amount of excess capacity out of the basin, which should continue to drive. So it all makes fundamental sense that we should start seeing some higher differentials.
I still think that the question is, when are they going to show up where you can actually realize them and start seeing them in the results. And we're just not there yet, but we certainly see the potential for improvement as we look out over 2023 and certainly as into 2024 and beyond.
And then just if I could fit one more in, it just seemed like the hedge adjustments this quarter were quite a bit bigger than we normally see. And obviously, that's a symptom of the volatility. Just wondering if there's anything else there.
And I know this is nitpicky accounting question, but I thought it was interesting. The net income adjustment had a positive adjustment with respect to the commodity-related adjustments, but the adjusted EBITDA from net income to adjusted EBITDA was negative. I'm just wondering why those are kind of in opposite directions? Or any other color on just kind of what happened with derivatives during the quarter.
Well, first, there is no other story other than just the volatility in prices. And it's just when you have large moves and just the timing sort of the path of hedges, if I can call it that, where depending on when you put your hedges on and when you took them off, you're going to see more or less of that.
We put on some hedges last fall, had large swings. In some cases, you've got hedges that you've taken off or you have hedges related to which you've had income impacts in prior periods, they don't affect current income at all but they do affect DCF the way we calculate where we say we're going to match up DCF with when the hedged transactions settle.
So even though the income statement was impacted in prior periods, the adjusted EBITDA will be hit in this period when we reconcile the DCF. So they're a little apples and oranges. They're definitely related, but you -- there's -- the pattern between the two is more complicated than I think than you're saying or then you can't -- you would not expect them, there's no reason to expect them to move together if that makes sense.
Okay. Appreciate that.
This is a good example of that where we had -- if we had losses in the first quarter, let's say, on some hedges, and they affected first quarter net income, but we bring that into a reconciliation for this quarter's DCF because when we settled the trades in this quarter, we said, okay, that prior period income hit, we're bringing into this period and now reducing EBITDA for those. Does that make sense?
I think so. Maybe we can follow up off-line.
Yes, it's a whole course Paul can put you through.
No, it's not too complicated, but you just have to get in the mindset to trace those through. It definitely flows, and it all evens out over time. It's just timing.
[Operator Instructions] The next question comes from Michael Lapides of Goldman Sachs.
Just curious, we're in late July. Obviously, you're doing your planning and probably starting that or well into it for next year. How should we think about capital allocation across, I don't know, growth CapEx and across your leverage metrics and kind of puts and takes there a little bit and across maybe utilization of the remaining almost, I don't know, almost $0.5 billion of the unit buyback program you have outstanding.
Just at this point in the year, it seems unless something just pops up, unlikely that there's a material growth CapEx project kind of hitting you that would start next year. But just I'll step back, and I would love your thoughts.
Well, on capital allocation, Michael, it really is as simple as we say. We want to look for projects that create value and grow if we find them. And if we don't find them, and we think there's value in units, we're going to buy it back.
And it's not going to be more complicated than that. As I look forward, in my comments, we mentioned the $100 million per year of expansion CapEx remaining to be a reasonable assumption. We still think that. So as we look forward, keeping expansion capital sort of on average around that $100 million based on what we see right now is probably a reasonable assumption.
So if you look at our leverage then and our 4x commitment, we're going to still have capacity to buy back units. And if you look at our free cash flow, we're going to have the capacity to buy back units. And that's what we'll expect to do, again, assuming there's still value there.
So I don't know if there's really -- there's not really more precision I can put on that right now, saying next year's CapEx is going to be Y, therefore, we're only going to buy back Z working units or have a certain amount of free cash flow. We're not quite in that equation at this moment.
As we sit here, we've got room left on our buyback program. We see value. We're going to continue to execute that buyback program while also to the extent we find growth capital, we'll deploy it and maximize value through all of those different avenues. But I don't have any specificity to give you beyond what we've already provided.
You used the term as long as you see value a number of times. How do you and the Board kind of figure out, hey, this is the valuation level where we're happy to be buying back units, and hey, this is a valuation level where maybe that's not the most appropriate use of our capital?
Well, look, we probably do it in a very similar way that you all may do it in that we run a discounted cash flow model. I'm not going to get into all of our assumptions. But we look at what we think the future potential of this company is.
What I would argue is we do it under a bunch of different scenarios, and we evaluate those scenarios from a discounted cash flow perspective. And that gives us what I'm going to say a range. I wouldn't say that it's point estimates, but it's a range.
It's an area, and it's with that analysis that we look at how things are going in the market today and evaluate it that way. So I think it's a little too complex just to have a point estimate. It's not so complex that we shouldn't have what we think is a really confident range with a broad set of considerations. But it's no more complicated than that.
That was our final question. Mr. Milford, I'm going to turn the call back over to you for any closing remarks.
Well, thank you all for your time today, and we continue to appreciate your continued interest in Magellan. Hope you all have a great day.
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 good day.