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Earnings Transcript for MMP - Q4 Fiscal Year 2021

Operator: Greetings and welcome to Magellan's Fourth Quarter 2021 Earnings Call. During the presentation, all participants will be in a listen-only mode. After, we will conduct a question-and-answer session. As a reminder, this conference is being recorded Wednesday, February 2nd, 2022. I would now like to turn the conference over to Mike Mears, Chief Executive Officer. Please go ahead.
Mike Mears: Well, good afternoon, and thank you for joining us today to discuss Magellan's fourth quarter financial results and our guidance for the new year. Before we get started, I'll remind you that management will be making forward-looking statements as defined by the Securities and Exchange Commission. Such statements are based on our current judgments regarding the factors that could impact the future performance of Magellan, but actual outcomes could be materially different. You should review the risk factors and other information discussed in our filings with the SEC and form your own opinions about Magellan's future performance. Magellan finished 2021 with another strong quarter, generating financial and operational results that exceeded our expectations and solidified 2021 as a year of robust demand recovery for our services. Our CFO, Jeff Holman, will now review our fourth quarter financial results in general, then I'll be back to discuss our guidance before answering your questions.
Jeff Holman: Thanks Mike. First, let me mention that as usual, I'll be making references to certain non-GAAP financial metrics, including operating margin, distributable cash flow, or DCF, and free cash flow and we've included exhibits to our earnings release that reconcile these metrics to their nearest GAAP measures. Earlier this morning, we reported fourth quarter net income of $244 million compared to $184 million in fourth quarter 2020. Adjusted earnings per unit for the quarter, which excludes the impact of commodity-related mark-to-market adjustments, was $1.24, which, as Mike pointed out, exceeded our guidance for the quarter of $1.10. DCF for the quarter of $297 million was 10% higher than the fourth quarter of 2020 and similarly to last quarter, the primary driver of that increase was additional contributions from our refined products segment. Free cash flow for the quarter was $291 million, resulting in free cash flow after distributions of $70 million. Full year 2021 DCF was $1.118 billion, approximately 7% higher than in 2020, resulting in a distribution coverage ratio for 2021 of 1.24 times. DCF per unit in 2021 was $5.14, about 10% higher than in 2020. This per unit perspective reflects the significant impact of our buyback program and underscores our ability to deliver per unit growth in excess of the topline ACS growth that our business experiences. I should note that the DCF per unit calculation I just mentioned is based on the weighted average number of units outstanding on the record dates related to the period. Full year free cash flow for 2021 was $1.316 billion, resulting in free cash flow after distributions of about $410 million for the year. A detailed description of quarter-over-quarter variances is available in our earnings release we issued this morning. So, as usual, I'll just touch on a few of the highlights of the fourth quarter results. Starting with our refined products segment, operating margin of $303 million for the quarter was approximately 27% higher than the 2020 period. Our refined products business continued to benefit from the recovery in travel, economic, and drilling activity in 2021 compared to the pandemic-driven reductions experienced in 2020 as well as from the final revenue commitment ramp on our Texas expansion projects. Overall, refined transportation volumes were up 14% relative to the prior year period, with significant increases in all products and on an absolute basis, volumes once again set a new quarterly record. Reflecting the sharp rebound in travel, aviation fuel once again saw an 80% plus increase versus the prior year period. Though as usual, I'll note for context that aviation fuel typically constitutes less than 10% of our overall volumes. Refined products revenues also benefited from the 3% overall average tariff increase that went into effect on July 1st of 2021. As a reminder, this 3% increase consisted of a 0.6% decrease to our index rate and an average increase of more than 4% to our remaining rate. As I imagine most of you are probably aware, the FERC recently revisited the index calculation. With the result, we will be reducing our index rates by about 1% effective March 2022, which Mike will discuss further in a few moments as part of our guidance discussion. Product margin was favorable compared to the fourth quarter of 2020, primarily due to the higher -- due to higher gas liquids blending margins and volumes as a result of the better commodity environment and improved blending opportunities. In addition, we had lower unrealized losses in the current period related to our hedging activities. Turning to our crude oil business. Fourth quarter operating margin was approximately $104 million, down 5% from the fourth quarter of 2020 due to reductions in some of our rates, lower volume shipped and reduced storage revenue. Longhorn volumes of 250,000 barrels per day were in line with the prior year. While the story on Longhorn for most of 2021 has been the contract expirations on the pipeline in late 2020, the fourth quarter was a full year past that change, resulting in a pretty consistent performance on the line between the 2021 and 2020 periods. Volumes on our Houston distribution system decreased versus the prior year period and were lower than we had expected, primarily due to the delay in the start of the new necking pipeline, which we now believe will begin delivering to us in early 2022. Just as a reminder, although we often see volatility in our Houston distribution system volumes for two quarters, those volumes move at significantly lower rates and longer haul Longhorn shipments, which means that their impact on our reported volumes and average rate is much greater than their impact on actual revenues, which brings me to our average crude oil tariff rate. Even though the competitive environment we are currently operating in has led to generally lower tariffs across our crude pipes. The overall average rate per barrel should actually increase between periods due to proportionately lower volume of those short-haul Houston distribution movements at lower rates. Similar to last quarter, we also saw reduced storage revenues due to lower utilization and rates following recent contract expirations. You may recall that we entered numerous short-term contracts during the early period of the pandemic and the market was in steep contango and storage in general, was a very high demand. As those short-term contracts have evolved and the market has been pretty backwardated, we've seen lower rates for our storage services. Moving on to our joint ventures, BridgeTex volumes were approximately 300,000 barrels per day in the fourth quarter of 2021 compared to nearly 350,000 barrels per day in 2020, partially due just to the timing of when our committed shippers have elected to move volume under their commitments as well as due to the expiration of the few smaller commitments earlier in the year. Saddlehorn volumes increased to 235,000 barrels per day compared to about 165,000 barrels per day the year before, primarily as a result of new commitments in 2021 associated with the pipeline expansion. Moving on to capital allocation, balance sheet metrics and liquidity. First, in terms of liquidity, we continue to have our $1 billion credit facility available to us through mid-2024 with $108 million outstanding on our commercial paper program as of December 31. Additionally, our next bond maturity isn't until 2025. The face value of our long-term debt as of the end of 2021 was $5.1 billion, with a weighted average interest rate on net debt of about 4.4%. Our leverage ratio at the end of the quarter was a little less than 3.5 times for compliance purposes, which incorporates the gain we realized on the sale of part of our interest in Pasadena earlier in 2021. Excluding that gain, leverage would have been a little over 3.6 times, and it is really that metric, excluding the gain on sale that we are looking to as we manage leverage, including, of course, the impact on leverage of our unit repurchase program. And that brings us to the last slide we'll touch on today, which is capital allocation. As you've heard us say before, we remain committed to maintaining the financial discipline we are known for, while delivering long-term value for our investors through a combination of capital investments, cash distributions and equity repurchases. During the fourth quarter, we repurchased nearly 1.1 million units at an average purchase price of $47.29 for a total spend of $50 million, bringing the cumulative amount of units repurchased during 2021 to 10.9 million units for $523 million. Since we began our buyback program in 2020, Magellan has repurchased $800 million worth of units under our $1.5 billion repurchase program. The unit repurchases made over the past two years have decreased our units outstanding by about 7%, thereby, of course, increasing our DCF per unit by a similar amount and in addition, contributing to better distribution coverage going forward. Of course, as we are always careful to know, the 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, the yield regulatory requirements as well as market conditions and the trading price of our equity. In particular, all note that we remain committed to our longstanding four times leverage limit and also that the timing of the proceeds from the independent terminal sale remains subject to the government review process. With that, I'll turn the call back over to Mike.
Mike Mears: Thank you, Jeff. Turning to our outlook for the New Year. This morning, we announced DCF guidance of $1.075 billion for 2022. We recognize this guidance is a bit lower than the Street was expecting, but considering that there is about $35 million of assumed reduced earnings associated with recently completed and pending asset sales, we have essentially forecast the remainder of our business to generate results very similar to our 2021 actuals. While we expect continued growth in refined products demand and healthy midyear tariff increases this year, we further expect these positives to be offset by a few unfavorable items, including reduced revenues for both refined products and crude oil storage, which is a theme we've mentioned to you in the last few quarters as well as the $25 million overall favorable impact from the 2021 winter storms that we do not expect to recur in the new year. As usual, I'd like to spend the next few minutes walking you through the key assumptions we have used to develop our 2022 projections, which we hope will help you better understand how we're thinking about the New Year. Starting with our refined products segment, which comprises about 70% of our operating margin, we assume that refined products pipeline shipments continue to increase during 2022 due to a combination of improved overall demand at the economy, drilling and travel in general continue to recover as well as the full year benefit of our Texas expansion projects to now that committed volumes have ramped up to their full commitment level. As a result, we expect refined product shipments to increase about 4% compared to 2021 result, driven by 4% higher gasoline, 2% higher distillate and 15% higher aviation fuel demand. For sensitivity purposes, we ballpark estimate that every 1% change in total refined products transportation volumes represents about $10 million of DCF on an annual basis. In addition to volume, the average tariff rate for our refined products pipeline system is an important component to model the segment, especially in the current inflationary environment. Our current plan assumes that we will increase our refined products rates by an average of approximately 6% on July 1. There are multiple components in the calculation of this average. So I'll briefly go through them. Currently, about 30% of our refined product shipments follow the FERC's index methodology for annual tariff adjustments with the remaining 70% deemed to be competitive markets and are generally adjusted as market conditions allow. As Jeff mentioned, the FERC recently changed its methodology for the industry's index rates. For a bit of background, the index calculation have been based on the change in the producer price index plus 0.78%. With that adjustment going to effect on July 1, 2021, resulting in a 0.6% decline in our index markets last year. Just a few weeks ago, the FERC adjusted the methodology to now be based on the change in producer price index minus 0.21%, so essentially 1% below the initial approach. This change will become effective on March 1. So we will lower our index rates by 1% next month, then follow the typical July 1 cycle after that through the year 2025 using this new formula. In case of interest, we estimate that a negative 1% change in the index currently results in about $3 million annually to Magellan. As you may know, the preliminary change in PPI for 2021 is a positive 8.9%, which will result in an index rate increase of 8.7% on July 1 using this new methodology, which is the planned tariff increase for these markets. The remaining 70% of our refined markets are either interstate movements or markets that have been deemed to be workably competitive by the FERC. As a result, they are not subject to the index methodology and would generally adjust these rates each year as competitive forces allow. We have been increasing our competitive rates in the 3% to 4% annual range over the last few years, which has been higher than the corresponding index change over the same time frame. For instance, as we've already mentioned, the index declined by 0.6% last year, which given the recent FERC index change discussed, will now be at a 1.6% decline. Comparatively, we increased our competitive market rates by more than 4% on average last year. While we'll continue to analyze our rates on a market-by-market basis to ensure we remain competitive, our guidance assumes that we increased the rates for the 70% of our market-based tariffs by approximately 5% on July 1. I will point out that because of the complexity of our pipeline system, the average rate per barrel we report is based on a mixture of long-haul and short-haul movements, and therefore, changes based on the actual point-to-point movements we make. In the New Year, we expect more short-haul movements due to additional volumes on our East Houston-to-Hearne expansion products as well as fewer barrels moving from Texas into the Mid-Continent, both of which resulted in lower overall average rates. In addition, we do not currently expect approximately $20 million of deficiency revenue recognized in 2021 to recur again, which also negatively impacts the average rate per barrel as deficiencies represent revenue recognized with no related barrels. Considering these factors, we expect our overall average rate per barrel ship to remain relatively flat to 2021 results, even though we intend to raise refined products tariffs by an average of 6% in mid-2022. Also for our refined products segment, the commodity price environment is important as it directly impacts our gas liquids blending profits. We have hedged essentially all of our spring blending margin at this point at a $0.40 margin, which equates to about 50% of our total expected blending sales volume for the year. Between the margins we have already hedged and last week's forward curve for the unhedged volume, we currently expect an average funding margin of about $0.40 per gallon for 2022, which is similar to 2021 results was slightly lower than the $0.45 average margin over the last five years. Following our typical approach, we would expect to begin hedging blending activity for the fall of 2022 in the next few months once the markets become more liquid for the fall season. Moving to our crude oil segment, which comprises the remaining 30% of our operating margin, we expect volumes on our Longhorn pipeline to average 240,000 barrels per day, which is very similar to the 245,000 we averaged in 2021. We have recently added a new third-party commitment to Longhorn and a tariff rate, which generally reflects the current market differentials, resulting in approximately 75% of the pipe's 275,000 barrel per day capacity being committed at this point with an average remaining life of six years. Although, we prefer third parties to move product on our pipes whenever possible, any incremental movements above the committed level are expected to result from our marketing affiliates stepping in until the unused space as market conditions allow. But as we've discussed in the past, the profitability of these marketing activities closely reflects the prevailing Permian to Houston differential, which currently remains very low. Our other wholly-owned crude oil pipeline is the Houston distribution system, which as Jeff pointed out, can fluctuate between periods. We have recently connected our Houston distribution system to new long-haul pipelines moving crude oil to the Houston area. So we expect volume on the HDS or the distribution system to rebound by more than 50% during 2022 as more barrels utilize our extensive system to connect to all the refineries in the Houston and Texas City area. As a reminder, rates charged on the Houston Distribution System are significantly lower than Longhorn due to the short distance move, which impacts the overall average crude oil rate per barrel that we reported in our financials. With the expected volumes in 2022, our average crude oil rate per barrel shipped should be closer to $0.60 per barrel this year versus $0.80 per barrel in 2021, reflecting the incremental proportion of shorter-haul movements. Concerning our joint venture pipelines, we expect shipments on BridgeTex to average around 300,000 barrels per day during 2022, which is similar to activity in 2021. At this point, BridgeTex has commitments for approximately 70% of the pipeline's 440,000 barrel per day capacity with an average remaining life of four years. With the current low differential between the Permian and Houston, spot shipments generally remain uneconomical, so we expect shipments basically in line with commitment levels. For Saddlehorn, we expect to move about 230,000 barrels per day during 2022, which is in line with current contracted levels. Based on the final step-up of commitments under the new contracts for the recent expansion of the line, Saddlehorn has commitments for 80% of the pipeline's 290,000 barrels per day capacity with an average remaining life of five years. On the expense side, we've discussed in the past that Magellan kicked off initiative a few years ago to identify cost savings and efficiency opportunities throughout the organization. This initiative has served us well to ensure we are operating as efficiently as possible, especially considering the current inflationary environment, while safeguarding the integrity of our assets. With the benefit of these initiatives, we currently expect total expenses, inclusive of both operating expenses and G&A costs to increase by about 2% in 2022. Concerning maintenance capital, we expect to spend around $80 million during 2022, which is very similar to last year's actuals. At Magellan, we believe that our most important social obligation is to safely and reliably transport and store the fuels that are nationwide on every day while protecting the communities where we live and work. Our dedicated workforce spend significant time and effort each year to ensure the integrity of our assets. Between capital and expense, we expect to spend more than $200 million on maintenance and integrity work in 2022. As you are aware, both maintenance capital and expense are considered in determining distributable cash flows and free cash flow. As a quick reminder, we still await regulatory approval for the pending sale of our independent terminals announced last June. We continue to expect the transaction to close this year, although exact timing is still a bit unclear. For guidance purposes, we have assumed that we own these assets through the first half of the year. In summary, all of these key assumptions build up to our DCF guidance of $1.075 billion for 2022, recognizing that investors by steady increases to the cash distribution, we currently target annual distribution growth for 2022, similar to the increase provided last year, which would result in distribution coverage of 1.2 times the amount necessary to pay cash distributions declared on the current unit count for 2022. While we are not providing guidance beyond 2022, we do expect DCF growth for the next few years from the tailwinds of modest refined product demand growth, a higher inflationary period, which will benefit tariff rates and continued strength in commodity prices. Management continues to expect that free cash flow after distributions will generally be used to repurchase equity, subject to the considerations Jeff mentioned previously. As a result, DCF per unit is expected to grow at a greater rate than DCF, providing increased value for our investors in the future. Although we have executed on substantial equity repurchase to date and expect to continue our equity repurchase strategy going forward, we also remain focused on developing attractive growth capital investments to create future value for our company. Based on projects already committed, we expect to spend approximately $50 million in 2022 on expansion capital. Following a successful open season, these estimates now include a 5,000 barrel per day expansion of our fine product system from Kansas to Colorado that should be operational by late 2022. In addition, the previously announced expansion of our New Mexico refined products pipeline is nearing completion and expect to be operational in April of this year. Both of these projects are fully underwritten by commitments from strong counterparties and demonstrate the flexibility of our network to step up to fill market supply gaps that may arise. As you know, the environment for large scale capital investments has been challenging over the last few years. However, we expect to add more growth projects throughout the year, although most likely smaller scale like these recent pipeline expansions. As a result, we still expect our expansion capital spending to be close to $100 million for 2022 as additional projects are approved as the year progresses. Bottom line, is we remain patient and committed to our disciplined investment approach and continue to look for opportunities to invest in attractive low-risk projects that meet or exceed our 6x to 8x EBITDA multiple threshold. Before we open the phone lines, I would like to briefly comment on my announcement last week that I will be retiring from Magellan on April 30. I spent my entire career with the company and couldn't be more proud of the organization we have created over the last 20 years. My role as CEO for the last 11 years has been rewarding, and I sincerely appreciate the support I received from the investor and analyst community. I truly believe Magellan is a best-in-class company in the energy space from almost every perspective, including financial performance, dedication to operational safety and company culture. We have been intentional to build the company on these strong principles from the very beginning to ensure our long-term success. Aaron Milford, who is here with us today, will be my successor as President and CEO, and I and our Board of Directors have complete confidence in his abilities to lead Magellan into the future. The investment community should be familiar with Aaron as he served as CFO prior to taking on his current COO responsibilities. Aaron has also spent his entire career at the company, and we have worked together closely for many years. His leadership capabilities, strategic vision and disciplined approach should ensure a seamless transition. Magellan is in a strong financial position with a resilient business model and experienced management team that prepares us well for the future. And with that, operator, I will now open it -- open the call for questions.
Operator: And our first question comes from the line of Theresa Chen with Barclays. Please proceed.
Theresa Chen: Hello. Congratulations, Mike, on your retirement and congratulations also to Aaron on the new role.
Mike Mears: Thank you, Theresa.
Theresa Chen: Sure. I wanted to ask first on the refined products segment. So Mike, just summing all of the puts and takes up and all your commentary about the many variables related to this, net-net, 2022 relative to 2021 volumes up 4%, tariffs flat for the transportation portion, correct?
Mike Mears: That's correct.
Theresa Chen: Okay. And then for the butane blending business. So, you've hedged all spring at $0.40 and it looks like you expect the fall to also be similar as the average for the year is $0.40. And I was wondering why that may be given that the forward curves seem to indicate a little bit more favorable spot margins from here?
Mike Mears: Well, the curves are moving all the time, as you would expect. So, we've taken a point in time in the forward curves net of the cost of RINs, which we have to acquire is roughly $0.40 right now.
Theresa Chen: Okay. And just lastly, in terms of getting the proceeds for the sale of the Southeast terminals, is there an expectation that the buyer may have to divest something? What are the gating factors at this point for you to close by midyear? Or do you expect that this could be kicked down the line further?
Mike Mears: Well, I don't really want to comment on what the expectations are from the FTC because that's really a process between the buyer and the FTC, but we firmly believe that we're going to close. And we think it's highly likely we're going to close within the timeframe we have within our guidance, but that's probably all I can really say about the process at this point.
Theresa Chen: Got it. Thank you.
Operator: And our next question comes from the line of Keith Stanley with Wolfe Research. Please proceed.
Keith Stanley: Hi, good afternoon. Could I start just on the buybacks and capital allocation. So how do you think about repurchases in the first half of the year, assuming you closed the terminal sale midyear, you'll have some excess free cash flow, but a big chunk of cash coming midyear. Would you be willing to use short-term borrowings in the first half of the year to repurchase equity, just given you're pretty decently below the leverage target? Or is that not something you'd be interested in?
Jeff Holman: We -- this is Jeff. We would be open to that in theory. It always comes down to specifics. So if you look at the times we bought back, it has not always been with current free cash flow and the real regulator will be leveraged. And so we'll have one eye on leverage and we'll have an eye on the proceeds and the timing there. There's other factors too. We'll be looking at what kind of investment opportunities we see and we'll be wanting to pay attention to how we're trading as well. Obviously, if there's a dislocation in the price, we might be incentivized to be a little bit more aggressive on repurchases and the converse would be true as well. So in theory, yes. In practice, I think you'll see us be pretty measured as we have been in the past.
Keith Stanley: Got it. And then Mike, thanks for all the detailed drivers for 2022, that was very helpful. I just want to clarify. So in the release, it was noted that butane blending profits are expected to be higher year-over-year in 2022. I think the margins you gave were pretty similar though. So is it fair to say that's a pretty small driver? And then a similar question for the storage side of things. Should we think of that as a pretty small overall driver -- in that case, a negative driver for 2022?
Mike Mears: Well, on the storage side, we are in a soft market at the moment. And as we've talked about before, the -- many of our storage contracts are relatively short term one or two years. And so we had frequent rotation of those contracts. And so in the current environment with a strong backwardation in the market, it's a challenging market to recontract story. So we expect that to be soft this year versus last year. And as we mentioned in our comments, it also -- if you look at 2021, it was benefited early in the year from short-term contracts we put in place during the pandemic, which were pretty high-rate contracts. So we expect this year to be soft in that regard. We don't expect it to persist long-term. The market goes through cycles and at some point, we'll be back in a contango market and we expect there to be a recovery there. But in 2022, we do expect some softness there. With regards to butane blending, I think year-over-year, we are expecting an increase. Even though the margins are relatively the same, we are projecting a growth in blending volume that's going to drive that higher.
Keith Stanley: Got it. Thank you very much.
Operator: And our next question comes from the line of Praneeth Satish with Wells Fargo. Please proceed.
Praneeth Satish: Thanks. Mike, congrats on your retirement, and Aaron, congrats on the new role. I just have two questions. I guess. First, you noted that you signed a new third-party contract on Longhorn. So just curious if you could talk about the contracting environment for Permian crude and whether you see any green shoots forming? Are you talking to any other customers? Or do you think this was kind of a one-off contract addition?
Mike Mears: The contracting environment in the Permian is extremely tight. I mean, quite honestly, shippers don't have a huge incentive to make commitments when spot rates are as low as they are. And the long-term picture doesn't look like those differentials will grow to -- grow significantly over the next year or two. In this case, even though we've signed a contract on Longhorn at what I would characterize as marginal profitability, those barrels ultimately get into our distribution system, where there's some buyers to us there. And I think with regards to prospective shippers, the access we have to multiple demand points along our distribution system attracts customers. And so that was one of the drivers behind their willingness to sign a contract. And our willingness, again, we look at the entire pie when we're signing a contract. It's not just what we make on Longhorn, it's also what we make once a barrel gets to Houston. So all of that factors into our decision to contract. But I would not consider that necessarily as something you would expect to be continuing at least for the next year or two to sign incremental contracts, which doesn't mean that our marketing affiliate isn't opportunistically taking advantage of shipper interest in getting from the Permian to Houston and into our distribution system. That will continue.
Praneeth Satish: And wondering if you could talk about the FERC's decision to lower the PPI adjuster from 0.78 to negative 0.21. And just whether you think that has broader implications in terms of the FERC maybe taking a less friendly approach to oil and gas pipelines. I mean it's made up of majority Democratic commissioners now. So curious for your views on that and whether you think there's any political motives behind the adjustment?
Mike Mears: I don't think it's an indicator that there is a developing bias against the pipeline. If you'll recall, when the initial decision was made a little over a year ago, the Chairman issued a very strongly worded descent against the decision. So we knew as an industry that the risk on rehearing existed that once a Democratic commission was in place that they would move more in the direction of the commissioner’s view than what the original order was and that's what happened. I don't see that as a big shift in focus by the commission. The argument that the commission overturned on rehearing to lower the rate. Our arguments that have strong arguments on both sides. It's really -- I don't believe, a biased decision. So I'll stop there. I don't think there's a political motivation behind it.
Praneeth Satish: Got it. Thank you.
Operator: And our next question comes from the line of Spiro Dounis with Credit Suisse. Please proceed.
Spiro Dounis: Thank, operator. Good afternoon, guys. Congrats again to Mike and Aaron. I wanted to go back to the guidance, if you could quickly. I think a lot of the context was helpful and sort of bridging between full year 2021 and 2022. I guess where I'm still struggling, I'm bridging everything is, when I look at your performance in the back half of 2021 specifically, right? So no Uri impact there, and I annualize that. And then, of course, back out $35 million sale. I still have a doubt of about $65 million between what that implies between that number and your guidance. And of course, you called out I think the contract renewals on storage is kind of a big item. But to me, it still seemed like too big of a delta to sort of bridge that gap. So curious, if you look at it from a back half performance of 2021 perspective, Mike, can you help me sort of bridge that number a little bit better?
Mike Mears: I'll try. I don't know exactly how you came up with your $65 million, but let me just comment on a couple of things. We've talked about the asset sales, which is roughly $35 million. We've talked about the winter storm effects, which is about $25 million. We really didn't talk about the lower Saddlehorn tariffs in detail. But with -- when we recontracted Saddlehorn, we agreed to incremental rate reductions in exchange for volume over time and for long-term contracts. And so there's a little bit of a reduction in 2022 from that rate reduction, which is about $10 million probably year-over-year. When we talk about the refined products volumes, there's a number of elements. We didn't go through those in great detail that's dropping the average rate back down to basically equal with 2021, and that's a significant move. But there are some specific reasons. One is -- one we mentioned is that there is a slightly higher proportion of lower short-haul volumes there, but I also mentioned -- and I think we mentioned it in the comments, last year, we benefited from some long-haul movements from Houston up into the Mid-Continent, due to some refinery issues in the Mid-Continent that we aren't expecting to repeat. And I think, materially, we recognized deficiency revenue last year, which affected rate per barrel that's not going to recur or I should say, we don't expect it to recur in 2022. That's in the neighborhood of $20 million. All of that, we didn't spell out specifically. It's embedded in that -- the assumption that our average rate per barrel is going to be even last year. So those positives for 2021 versus 2022 or what's bringing it down, we're not -- it's not that we view as anything negative happening in 2022 associated with rate per barrel. It's really just an offset of positives. I mean that, we had in 2021 and -- all of that being said, that should get closer, I guess, to your $65 million number. I didn't add all that up in my head, but those are probably the things that you're missing in your calculation.
Jeff Holman: This is Jeff. I might just add, too. I mean, I think we haven't done the exercise you talked about, partly because we wouldn't consider it really totally a value way to do it. There's enough seasonality in the business. If you look at the four quarters of the last year, volumes are much stronger in the last six months than they were in the first six months and some of that is going to recur. So I'd caution, I guess, trying to annualize the back half of last year just on so.
Spiro Dounis: Okay. No, that's helpful. I think all those items together probably bridge that gap. So I appreciate the color there, guys. Second one, just a really quick one here. It sounds like your expectation for buybacks is to utilize most or all of that $575 million or so of free cash flow throughout the year. And I guess just curious, what are some of the items that could come up that maybe change that view or change that allocation? Is there a potential for M&A even on sort of a smaller scale bolt-on basis to move in there? Just curious what other factors you're looking at potentially?
Mike Mears: Well, certainly, the opportunity for capital investment is something that we are actively looking for finding projects that have attractive returns is challenging, but we're looking. It's probably less focused on M&A, even though I'd never rule that out. It's probably more focused on internal development. So to the extent that an opportunity were to arise that has an attractive return, it would impact that. And then again, all the other caveats that Jeff mentioned, the price of the equity those sorts of things will factor into that also. And so I mean, it's not really more complicated than that.
Spiro Dounis: No worries. Keep it simple. All right. That's perfect. Thanks, Mike. We’ll see you guys at the Analyst Day.
Operator: And our next question comes from the line of Jeremy Tonet with JPMorgan. Please proceed.
Jeremy Tonet: Hi. Good afternoon.
Mike Mears: Good afternoon.
Jeremy Tonet: Congratulations, Mike, on a successful career. We'll miss you and Aaron, best of luck taking the reins here. Just wanted to kind of start off one question here really in a few different facets to it, I guess. With the Permian growth is in the upswing again, and I was just wondering, if you could walk us through the different permutations of how this impacts Magellan. Be it increased drilling demand from diesel, more oil logistics, whether conversion of pipelines make sense or just trying to think through the different impacts as well as maybe a more favorable environment when you look to roll those contracts?
Mike Mears: Okay. Well, that's a broad question. Let me try to break it down into those pieces. I mean, first and foremost, I mean, we do see the most material benefit to us from increased drilling in the Permian is diesel demand on our refined product system. And so certainly, to the extent that, that grows, we have a direct benefit throughput on our West Texas system. On the crude oil side, it's -- because there's such significant overcapacity today, the production is going to have to grow quite a bit before you're going to see any material change in the differential from Midland to Houston and willingness for shippers to make any kind of commitments at firm rates. So obviously, we haven't built any of that into a 2022 plan. When we look out long term, when you get out to 2024 or 2025, I think the prospects of that are start to improve, but again, trying to forecast what the world looks like three or four years from now is difficult to do. But there is potentially some benefit out there that capacity does start to tighten. And if that happens, then we would expect margins to widen and shippers to perhaps be more interested in making some level of commitment. All of that is somewhat speculative, as I said, three or four years out. So, we'll have to see how that goes. As far as repurposing pipes, I'm sure everybody who has a Permian pipe is evaluating that. To the extent that someone does that doesn't have to be us. It can be anyone. It's going to benefit everyone else. I don't have any insight as to what other folks are doing. I can tell you that we continue to actively look at repurposing. And as I said in the last call, there's nothing actionable to talk about today. There may not be anything actual to talk about for some time, but I can tell you that there's a lot of activity taking place within the company to try to put a project together to do that. And I would say that the probability of that is not zero, that there's some real opportunity here, but there's some real challenges to get it done, but we're focused on that. So, I mean stay tuned on how that develops.
Jeremy Tonet: Got it. Very helpful there. And one last one, if I could. Just with regards to the Cushing storage market, I wonder if you could provide a bit more color there. The current environment, how that's, I guess, impacting your business?
Mike Mears: Well, it's not impacting us to a large extent right now because we've got significant contracts. I don't have on the top of my finger as the percentage of Cushing's storage that's contracted, but most of it is contracted. And so we're not seeing any significant issue right now at Cushing, and the life of those contracts has a number of years left. So, it will really depend on what the market looks like when they expire, which isn't imminent.
Jeremy Tonet: Got it. I actually have one last one just to touch on quick. I think there was some things reported out there with regards to union issues with other energy companies and kind of impasses there and that impacted maybe inflation. You talked a lot about inflation before, but just wondering, specifically on the labor side, if there's anything to note there.
Mike Mears: Well, there's nothing to note. I mean we've implemented our salary increases this year. We do have a union and that union contract is up for renewal. And we expect we're going to have an outcome that all -- everyone will be happy with. Those negotiations really haven't started yet. I mean as you may know that the way this works is, there's a pattern of negotiation that happens first. That's happening now, and we're all waiting for that to end before we start our negotiations, but we expect that we're going to wind up a place where everybody is happy at the end of that.
Jeremy Tonet: Got it. I'll leave it there. Thank you very much.
Operator: And the next question comes from the line of Michael Lapides with Goldman Sachs. Please proceed.
Michael Lapides: Hey guys thanks for taking my questions. Just curious, so you're expecting, in kind of true free cash flow, about $575 million in 2022 and a large chunk of that comes from the asset sale. Just curious on the debt side. What happens in 2022? Do you use any of that $575 million to pay down debt? Or is that $575 million available for either growth CapEx or buybacks or other forms of capital allocation? And how do you think you end the year or kind of how you're thinking about debt-to-EBITDA at the end of the year as we enter 2023?
Jeff Holman: Yes. Well, we're not projecting really to use those proceeds for any specified purpose on it then generally our expectation would be to use free cash flow to repurchase units, but that will depend on all those factors as we talked about. So, depending on how those play out and whether the growth projects show up on the octane, as Mike mentioned, the M&A showed up, obviously, we can use it for any of those purposes and it's fungible. If none of those show up, and we don't undertake repurchase activity, we could repurchase units. I mean -- excuse me, we could pay down debt, that's not our first plan. It's kind of the last options for us, just if we don't like any of the other options in front of us. So we don't project increasing debt during the year based on what we see today for sure. And if we used all the proceeds for repurchases, debt would end up pretty much where it is now. And so you can calculate the leverage ratio from sort of projections. I don't have that number right in front of me right this minute, but that's the way we would be thinking about that, Michael.
Michael Lapides: Got it. Okay. And you made a little bit of a comment about M&A. And over the last couple of years, last two, to three, three to four years, you've done a host or a number of kind of small asset sales. Is there anything that when you look at the portfolio where you would look at it and say, hey, you know what, I could actually like these types of assets, not specific ones, but types of assets, I'd much rather be a buyer of at this point in time, like things that when you look at the markets might look attractive in the M&A market today versus maybe where they were three or four years ago.
Jeff Holman: Well, certainly, the market is probably more attractive than it was three or four years ago, but that's not saying much three or four years ago, it was astronomically high. We -- specific to answer your question specifically, there's not a set of assets out there right now that we're targeting to say, we have to go buy. We like the kind of assets we already have the refined products assets. And a couple of years ago, there were some of those in the market, but we felt that they were still too high, which is why we were a seller rather than a buyer. We'll continue to watch that. And if those assets come back to the market and the prices are more reasonable than we might get into it. We're not looking to really diversify outside of what we do right now. We don't really feel like this is the time for us to make big bets on things outside of our space, especially since we have what we believe to be an attractive opportunity to buy back our equity. All of that's a point-in-time decision. I mean, you never know what opportunity might fall in our lap next week and we'll evaluate it. But right now, we're not actively pursuing anything transformational out there.
Michael Lapides: Got it. Thank you, Mike. Thanks guys. Much appreciate it.
Operator: And our next question comes from the line of James Carreker with U.S. Capital Advisors. Please proceed.
James Carreker: Hi. Thanks and congrats again to Mike and Aaron. I had one clarifying question. Mike, you talked about it in the press release about $100 million of growth CapEx and then the official guidance in the financial schedule had a number in there for 50. So just wondering if you know what maybe the difference is there?
Mike Mears: Yes, that's just generic assumption about what we think will actually get done. If we put only what we've committed, it'd be that lower 50 number, we also got to be kind of under billing what we actually expect that happen. So during the year, there's a number of projects we're evaluating that are at various stages of development that could toggle into being committed relatively soon as we kind of handicap the probabilities, we come up with an area another 50 or so, and so we come up that about $100 million number. So that's the difference.
James Carreker: Okay. I thought that might be the case. Just wanted to clarify. And then I guess, kind of, a big picture question, and I know we've gotten away from talking about growth versus normal and x growth projects. But when you look at the 2022 refined product outlook, I guess taking into account growth projects that you put into place, like how normal does that feel relative to, say, 2019 levels? Does that feel like we fully caught up? Do you think there's still some parts of the economy holding back when you look at that 2022 number?
Mike Mears: Well, I don't have the numbers in front of me, but I think just directionally, on gasoline, we aren't quite back to 2019 numbers. Diesel fuel is strong and probably above 2019 numbers, and jet fuel, obviously, still not back to 2019 numbers. But I don't have any kind of percentages on my fingertips here to give you on that. And when I say gasoline is not there. I'm not talking about a big miss, I'm talking about it's not above where we were in 2019. And I think -- and again, and I've talked about this before, it really gets into the geography. I mean, as I said, in the rural markets, it's there in the cities. It hasn't quite gotten back there. I mean you still have businesses that don't have people back to work, which is surprising to us, but it's true. And so I think there's still a little bit of a lag there.
Jeff Holman: And there are some few minor things like Mike said, on our system that are specific. I think overall, for the markets we serve, gasoline, we project it to be pretty much back to those 2019 levels. There's some ins and outs just based on things going with our system contract roll-offs in small places here and there that can affect volumes, et cetera. So overall, really, it's only aviation that continues to lag by the end of next -- this year.
James Carreker: Okay. That's all helpful color. If I could say maybe one more in. One question is, when you guys put the West Texas expansion into service, you noted a 7x multiple with potentially significant additional upside. I assume that, that's probably not in your guidance for 2022, but I guess what would it take to achieve some of that significant upside that you laid out when you went forward with that project?
Mike Mears: Well, we do have some growth in our West Texas volumes in our guidance, but beyond that -- and we haven't put it in our guidance. I mean, we have a number of initiatives underway in West Texas, attractive initiatives that potentially can bring material new volumes to our assets. And I'm not going to go into the details of those, but I can tell you it's across the breadth of the markets we serve. And we say West Texas, but we say all the time that it's not just West Texas that this pipeline serves. It's markets in Mexico, Arizona, New Mexico are all connected to our system. And so there's opportunities really across that spectrum that we're pursuing. And again, we haven't built those opportunities into our guidance. Some of those opportunities are probably more than a 2022 type horizon, they're beyond that. But I think it's safe to say there's material upside with regards to our West Texas assets that we're looking at that we haven't built into 2022.
Jeff Holman: I might just also point back to Mike's earlier answer around drilling as well because if drilling exceeds our expectations without an as an initiative as Mike's talking about, we can see further upside from that expansion project.
Jeremy Tonet: And just to clarify, these initiatives would -- you be able to do them without having to repurpose any pipes. These are just with existing space on existing assets?
Mike Mears: Well, some of it is, but there are what I'd call home run scenarios that would require repurposing assets. And we're actively working on those also, but even absent that, like I said, there's opportunities for growth.
Jeremy Tonet: Thanks a lot. Congrats.
Mike Mears: Thank you.
Operator: And our next question comes from the line of Timm Schneider with Citi. Please proceed.
Timm Schneider: Hey good afternoon. Just a quick question. On the butane blending, can you remind us what are you most exposed to in the RIN side? Is that D4, D6 or a combination of those?
Jeff Holman: It's really composite. When we look at it, we have to meet the percentages that are in the new RBOs. And as we hedge, we look at that as totality to make sure that we're getting each of the specific types of rents that we need. So we're exposed to essentially all of them at different points in time. So there's a composite basket for us.
Timm Schneider: Got it. And then in your assumptions right now, are you guys just using the forward curves for that? Or do you have your own kind of views on what that bid pricing is going to look like through 2022?
Jeff Holman: Yes, we're looking at the forward curves and paying attention to what's happening in the market. We have, I would say, our own opinions about maybe directionally where that is, but for the most part, it's forward curves. And the other point to point out is that we've already got a significant amount of 2022 rent obligations hedged. I think it's around 70% of what we view our obligation for 2022 to be. So we do have some more to go hedge, but we've got a lot of that taken care of already.
Timm Schneider: Got it. And then that's all inclusive of that -- I think you said, it was a $0.40 margin. Is that right?
Jeff Holman: That's a net margin. So that's the gross margin less our operating expenses, less the cost of rents on a per gallon basis net $0.40.
Timm Schneider: Okay. But that includes the 70% hedged?
Jeff Holman: Yes.
Timm Schneider: Okay. Got it. Sorry, I was just trying to reconcile that. Yes, go ahead.
Mike Mears: That's it.
Timm Schneider: All right. Sorry. That’s great answer. It’s all I had. Thank you.
Mike Mears: Operator, there’s probably time for one more question.
Operator: There's no questions. I'll turn the call back over to Mr. Mears. Please go ahead.
Mike Mears: All right. Well, thank you. Well, we appreciate your continued interest in Magellan, and we hope to see many of you at our Analyst Day next month. And until then, have a good day.
Operator: Thank you. That does conclude the call for today. We thank you for your participation and ask that you please disconnect your lines. Have a great day.