Valero Energy Corp (VLO) — Q4 2018 Earnings Call Transcript

Good morning. And welcome to Valero Energy Corporation's fourth quarter 2018 earnings conference call. With me today are Joe Gorder, our Chairman, President and Chief Executive Officer; Donna Titzman, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President and COO; Jason Fraser, our Executive Vice President and General Counsel, and several other members of Valero's senior management team. If you've not received the earnings release and would like a copy, you can find one on our website at valero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the Company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. Now, I will turn the call over to Joe for opening remarks.

Thanks, Homer, and good morning, everyone. We're pleased to report that we completed another strong quarter where we ran our business well and delivered solid financial results. Throughout the quarter, we maintained our unrelenting focus on operational excellence, which enabled us to operate safely and reliably in an environmentally responsible manner. We also delivered on our commitment to invest in growth projects and acquisitions that increased Valero's earnings capability while maintaining solid returns to our stockholders. In 2018, we matched 2017's record for process safety performance, and we continue to outperform the industry with our personal injury rates. Logistics investments made over the last several years are contributing significantly to earnings. Our investments in Line 9B, the Diamond Pipeline, and the Sunrise Pipeline expansion increased our system’s flexibility, allowing us to take advantage of the opportunities available in the fourth quarter of 2018. In fact, we set a record for total light crude runs at 1.5 million barrels per day and a record for North American light crude processed at over 1.3 million barrels per day. We also continued to maximize product exports into higher netback markets in Latin America. Turning to capital allocation, we continue to execute according to our disciplined framework. Our projects and execution remain on track. Construction is scheduled to finish on the Houston alkylation unit in the second quarter, and the Central Texas pipelines and terminals are expected to be completed in mid-2019. In November, the Board of Directors of Valero and Darling Ingredients approved an expansion of the Diamond Green Diesel plant to 675 million gallons per year of renewable diesel production and the construction of a renewable naphtha finishing facility. With respect to cash returns to stockholders in 2018, we paid out 54% of our annual adjusted net cash provided by operating activities, exceeding our target annual payout range of 40% to 50%. Our solid financial position and a favorable outlook for our business enabled us to further demonstrate our commitment to our investors, as last week our Board approved a 12.5% increase in the regular quarterly dividend to $0.90 per share or $3.60 annually. Lastly, earlier in January, we closed the acquisition of Valero Energy Partners. This transaction was immediately accretive and has greatly simplified our structure. While Valero will no longer have a publicly traded midstream business, VLP’s assets and ongoing logistics investments at Valero will continue to enhance our feedstock and product flexibility. Now, as we look ahead, we remain committed to our capital allocation framework. There has been no change in our capital discipline strategy, which prioritizes maintaining our investment-grade ratings, sustaining investments, and paying our dividends. We expect our annual CapEx for both 2019 and 2020 to be approximately $2.5 billion, in line with where it's been over the last several years. You should expect incremental discretionary cash flow to continue to compete with other discretionary uses, including cash returns, growth investments, and M&A. In closing, with a growing economy, a year-over-year increase in vehicle miles traveled, and low fuel prices, we’re encouraged for 2019. We expect good demand in domestic and export markets this year. Despite seasonal weakness in the gasoline market, days of supply for distillate inventories remained below the five-year average. Expected incremental diesel demand and discounts for sour feedstocks associated with the impending global fuel oil sulfur reduction also give us a reason to remain optimistic. We believe that our system’s flexibility to process a wide range of feedstocks and reliably supply quality fuels, as evidenced by our fourth quarter 2018 results, positions Valero well for whatever opportunity the market presents to us. So, with that, Homer, I'll hand the call back to you.

Thank you, Joe. For the fourth quarter, net income attributable to Valero stockholders was $952 million or $2.24 per share compared to $2.4 billion or $5.42 per share in the fourth quarter of 2017. Fourth-quarter 2018 adjusted net income attributable to Valero stockholders was $900 million or $2.12 per share, compared to $509 million or $1.16 per share for the fourth quarter of 2017. For 2018, net income attributable to Valero stockholders was $3.1 billion or $7.29 per share, compared to $4.1 billion or $9.16 per share in 2017. 2018 adjusted net income attributable to Valero stockholders was $3.2 billion or $7.37 per share, compared to $2.2 billion or $4.96 per share in 2017. The 2018 adjusted results exclude several items reflected in the financial tables that accompany this release, while the 2017 adjusted results exclude an income tax benefit of $1.9 billion from the Tax Cuts and Jobs Act. For reconciliations of actual to adjusted amounts, please refer to those financial tables. Operating income for the refining segment in the fourth quarter of 2018 was $1.5 billion, compared to $971 million for the fourth quarter of 2017. The increase from 2017 was mainly attributed to wider discounts for North American sweet crude and certain sour crudes relative to Brent, partly offset by weaker gasoline margins. Refining throughput volumes averaged 3 million barrels per day, which was in line with the fourth quarter of 2017. Throughput capacity utilization was 96% in the fourth quarter of 2018. Refining cash operating expenses of $3.92 per barrel were $0.34 per barrel higher than the fourth quarter of 2017, mostly due to higher natural gas costs in the fourth quarter of 2018. The ethanol segment generated a $27 million operating loss in the fourth quarter of 2018, compared to $37 million of operating income in the fourth quarter of 2017. The decrease from 2017 was primarily due to lower margins resulting from lower ethanol prices. Operating income for the VLP segment in the fourth quarter of 2018 was $88 million, compared to $80 million in the fourth quarter of 2017. The increase from 2017 was mainly due to contributions from the Port Arthur terminal assets and Parkway Pipeline, which were acquired in November 2017. For the fourth quarter of 2018, general and administrative expenses were $230 million, and net interest expense was $114 million. General and administrative expenses for 2018 of $925 million were higher than 2017, mainly due to adjustments to our environmental liabilities. For the fourth quarter of 2018, depreciation and amortization expense was $531 million. And income tax expense, which includes certain income tax benefits, as reflected in the accompanying earnings release tables, was $205 million. Excluding these benefits, the effective tax rate was 21%. With respect to our balance sheet at quarter-end, total debt was $9.1 billion and cash and cash equivalents were $3 billion. Valero’s debt to capitalization ratio net of $2 billion in cash was 24%. At the end of December, we had $4.4 billion of available liquidity, excluding cash. We generated $1.7 billion of net cash from operating activities in the fourth quarter. Excluding the unfavorable impact from a working capital decrease of approximately $120 million, net cash generated was $1.8 billion. With regard to investing activities, we made $771 million of growth and sustaining capital investments in the fourth quarter of 2018, of which $254 million was for turnarounds and catalyst. For 2018, we invested $2.7 billion, of which approximately $1.9 billion was for sustaining and $800 million was for growth. Moving to financing activities, we returned $965 million to our stockholders in the fourth quarter; $627 million was for the purchase of 7.7 million shares of Valero common stock and $338 million was paid as dividends. As of December 31st, we had approximately $2.2 billion of share repurchase authorization remaining. We expect capital investments for 2019 to be approximately $2.5 billion, with approximately 60% allocated to sustaining the business and approximately 40% to growth. Included in the total are turnarounds, catalyst, and joint venture investments. For modeling our first-quarter operations, we expect throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.67 million to 1.72 million barrels per day; U.S. Mid-Continent at 440,000 to 460,000 barrels per day; U.S. West Coast at 265,000 to 285,000 barrels per day; and North Atlantic at 475,000 to 495,000 barrels per day. We expect refining cash operating expenses in the first quarter to be approximately $4.05 per barrel. Our ethanol segment is expected to produce a total of 3.8 million gallons per day in the first quarter. Operating expenses should average $0.42 per gallon, which includes $0.06 per gallon for noncash costs, such as depreciation and amortization. For 2019, we expect G&A expenses excluding corporate depreciation to be approximately $840 million. The annual effective tax rate is estimated at 23%. For the first quarter, net interest expense should be about $110 million, and total depreciation and amortization expense should be approximately $550 million. Lastly, we expect RIN expenses for the year to be between $400 million and $500 million. That concludes our opening remarks. Before we open the call to questions, we again respectfully request that callers adhere to our protocol of limiting each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits. This helps us ensure other callers have time to ask their questions.

Good morning, guys. Congrats on the stellar results. I appreciate the outlook for two years on CapEx. I think there was some perception maybe with the project sanction last year that there would be upward pressure, and we're actually seeing a $200 million decrease year-over-year, and that sustained into 2020. Can you talk a little bit about where maybe some of that deflation has come from, whether it's the growth component or sustaining or turnarounds?

This is Lane. I wouldn't call it deflation; I would characterize that we had a lot of sustaining capital with respect to Tier 3 and plus the reliability project at our Corpus Christi refinery in 2018. Our run rate is like what we've said is normally about $1.5 billion to sustain our assets. We had a little bit more than that in this past year. There’s obviously timing involved and all that. Whether our turnarounds get a little bit lumpy or again we end up having to do something a little bit special on some environmental projects, currently we don't have anything on our forward view of that.

Okay, great. The second question is on Venezuela, obviously very topical. I guess, one, could you confirm how much you're currently importing crude there? But then, I guess more importantly, I’m just curious, in order to replace those barrels, are you looking to resort to more light sweet domestic crudes or just largely maxed out on light sweet to where you're actually going to have to resort to the global market for kind of medium and heavy sour replacement barrels? Thanks.

Yes. Blake, this is Gary. Of course, with the sanctions, we're currently not taking anything from Venezuela. Historically, about 20% of our heavy sour that we run was Venezuelan barrels. We're certainly hopeful that we’ll see a proper resolution to the crisis, not only for the benefit of the crude markets but for the welfare of the people of Venezuela. We've seen production decline in Venezuela for years, and we've also known there was a threat of sanctions. So, we’ve put alternatives in place to be prepared for this. Of course, the announcement was just made Monday; we've only had 48 hours to respond. Our top priority really has been to get our next 30-day supply plan covered. I can tell you we're in a much better position today than we were on Tuesday, but we still have some holes to fill in our supply plan. We really run Venezuelan barrels at two of our refineries in the Gulf, St. Charles and Port Arthur. The St. Charles refinery did begin a turnaround on their crude and coker unit. So, that definitely minimizes the impacts that the sanctions had on our system. To your point, current economics are certainly pushing us to maximize light sweet in the system.

I wanted to see if we could get some elaboration on Joe's points that you made a few minutes ago about market fundamentals. And typically, while distillate demand and inventories appear to be positive in both the U.S. and the Atlantic Basin, the converse seems true for gasoline, although seasonality and net exports should be supportive. And then, could you just spend a minute covering how fuel oil markets are likely to sort out this year, given the uncertainty that Blake just highlighted about Canada and Venezuela and heavy feedstocks and how you might adjust?

Yes. This is Gary again. Of course, it seems like early in the year, during this call, we always panic about the gasoline markets. We feel very good about gasoline demand moving forward. High employment and low gasoline prices should result in good gasoline demand. The wild card, of course, becomes refinery utilization. So, with the 20-year high refinery utilization we saw last year, we are starting the year with a bit of an overhang. The overhanging gasoline has primarily been in PADD 1, PADD 2, and PADD 3. If I look at those regions individually, I could see that we build a little bit more inventory in PADD 1. The market structure is such that there's an economic incentive to make summer grade gasoline and put it in tankage in New York Harbor, and there’s still tankage available. So, that would come. You could see some inventory again in PADD 1. I think you'll see significant improvements in both PADD 2 and PADD 3 moving forward. PADD 2, I think a lot of the gasoline build was a result of the crude discount. The margins were just very strong. Typically, at PADD 2, you see refinery utilization drop off in the winter to balance the market. But with the crude discounts, they ran hard. But if I look at the PADD 2 market now, there seems to be more planned maintenance this year than last year. As we move forward and with the current cold snap hitting PADD 2, there seem to be quite a few refinery issues in that region. In fact, the Explorer Pipeline between Group 3 and Chicago is now pro-rated, indicating there’s a big pull for products in that region. So, I think you'll see gasoline inventories draw in PADD 2. I also think you'll see good gasoline draws in PADD 3 as well. Then, in the Gulf, early in the year, we typically have fog issues which hinder our ability to export product, and we saw that again this year. We also saw a bottleneck trying to get gasoline into Mexico, which is obviously our largest export destination. Then, we saw a lot of refiner buying interest in the Gulf as well as people building some inventory in preparation for turnaround, so they could cover their supply during outages. All those things indicate that as you see lower utilization in the Gulf from planned maintenance beginning, and you see exports pick up, I'm confident you'll see inventories in PADD 3 grow as well. So, we feel pretty good about gasoline. We feel very good about gasoline demand. And again, the wildcard is what utilization is going to be going forward.

Okay. Any insight on fuel oil too?

Yes, fuel oil. I think, that definitely is the issue you've talked about. There has been a lot of significant hits to fuel on the supply side with OPEC cuts and the Iranian sanctions, now Venezuelan sanctions, and production cuts in Western Canada. If you look at the forward curve on fuel oil, it's backward about $1 a month, and a lot of that is tied to the IMO 2020 fuel spec change. We do see fuel moving weaker as a result of lower demand for high sulfur fuel oil. Then, there are some signs that some of the production can come on. The Alberta government did announce that they're going to go ahead and raise production in February, at least 75,000 barrels a day. So, some of those things will help as well.

Hi. Good morning, guys. Before I ask my question, since I told John Locke if your Gulf Coast realized margin is going to be filed probably in excess of 650, I will publicly lobby Joe to give Gary and his crude supply team a big bonus. So, I'm lobbying you.

Paul, you're really helpful to me here.

Anyway. So, other than that, two questions. First, looking at the current level in the fourth quarter, I mean, I think everyone is already trying to maximize the distillate yield. So, in your system, is there any more that you can actually do that to shift from gasoline to distillate? Also, you said you're running a record 1.5 million barrels per day in the light oil. Is there any more that you can quantify that, how much more if there's any that you can actually move from medium and heavy into light?

Yes. I would tell you on the gasoline to distillate swing, there's very little else we can do. We're pretty much maxed out on distillate today. On light crude, we would tell you that the numbers Joe gave you were about 90% of our light sweet capacity. So, there is some room there to push some additional light sweet crude into our system.

So, Gary, you mean that if 90%, that means that at most you can push another 100,000 to 150,000 barrel per day?

Exactly. So, we've been saying we have about 1.6 million barrels a day of light sweet crude capacity.

Secondly, do you expect the Mexico export that you're shipping there to increase in the coming weeks, given the fuel shortage there? If we look back on the last two months, have you seen any noticeable decline in your gasoline export to Mexico?

No, we really haven't. Historically, we see a lot of buying interest in December from Mexico and we see these bottlenecks then trying to get the barrels into the country. Obviously, the crackdown on fuels made that even worse. We're seeing good demand from Mexico, not only waterborne barrels, but we continue to ramp up our business of actually importing the barrels into the country and we're seeing very good demand for barrels delivered all the way into the country as well.

Joe, congrats on a good quarter. And Homer, congrats on joining a great team. We will all miss John Locke and would like to wish him all the best in his new role. So, I just have a quick question on Diamond Green Diesel expansion. If you look at the current margins, is it fair to assume that this is like a 35-plus percent return for the project for you? And the second follow-up on it is, what advantage does Darling Ingredients bring to the table? Are they just a financial partner or do they give you some kind of competitive edge on your peers, who are also trying similar projects?

This is Martin. Regarding Diamond Green, we anticipate that moving forward, the price will be around $1.25 per gallon, which suggests you are likely estimating the return on EBITDA margins correctly. Darling is more than a financial partner; they process about 10% of the world's meat byproducts and have significant operations in collecting used cooking oil. They have extensive experience in these markets. At Diamond Green, we have been involved in the fat market for approximately 5.5 years, while Darling has been engaged in it for much longer. They contribute greatly to sourcing and pre-treating the fat for our unit. This collaboration offers excellent synergy, combining our refining and marketing expertise with their pre-treatment skills and fat procurement for the joint venture. It's a strong partnership.

Joe, you guys do a great job of making the sell-side look really dumb every quarter; it’s a great quarter, obviously. But my question is, with a $30 correction in oil prices, obviously there's some lag effect in your capture rate. I'm just curious as to the capture rate move that we saw and off of 100% on our numbers is running about 30% to 40% above what you would normally deliver. Was that just a lag effect, or is there something structural going on such as the shift to the lighter grades that we should pay more attention to going forward?

Doug, that's a good question. Joe, why don’t I take a shot at it and Gary can recalibrate whatever I'm saying here. But there are really a few couple of reasons. One is, as we alluded to in the opening remarks, we've had the pipeline projects. We have the Line 9, the Diamond Pipeline, and the Sunrise. All of those put up the position in Mid-Continent and in our Quebec refinery position us to take advantage of essentially the distressed markets in the fourth quarter. The other side of that is on the product side, really lower rent price allowed us to capture essentially higher net-backs on our product prices. I'm sure there's a contribution on the other things, like pet coke, all the stuff that contributed our capture rate. But really, the first two things really drove our capture rate in the fourth quarter.

So, should we consider that the capture rate is structurally moving higher?

I would say you should expect an improvement on the product side due to the lower rent prices. On the crude side, it really depends on how distressed those markets are. You have a perspective on what the situation looks like and how it compares to Midland and Cushing.

Okay. Thank you for trying to answer that. I know it was a tough one. My follow-up is kind of a follow-up to Doug Terreson’s question, I guess. Normally, we would see the industry pivot obviously between distillate and gasoline to some extent, as you move through the summer, but obviously we've got this IMO even going into 2020. So, I'm wondering, is there a possibility that we see Valero specifically maintain a max distillate bias through the whole of 2019 as one part of the solution to the gasoline overhang? And I'll leave it there. Thanks.

This is Lane again. We absolutely believe that it’ll be the case. I mean, we've been in max distillate for a while now and will continue to be in that way through at least the way we see the rest of the year going in 2019. Obviously, it’s early but that's the way the forward market is pointing right now.

Good morning, everyone, and thank you for the question. I wanted to revisit the topic of crude sourcing and dive a bit deeper, as we have seen impressive performance in that area. As Paul mentioned, it seems we all underestimated your results this quarter. Regarding Maya or other Central American heavy sour grades, I’d like to confirm your purchasing activity for the fourth quarter. Many of those grades have priced themselves out of the market, as we noted in the fourth quarter. Were you buying less during that time, and how do you expect the situation to evolve now that we are seeing some price normalization moving into the first quarter?

So, I think on the heavy side, we've definitely seen that Maya is probably not the best marker for what we're paying for heavy sour crude. In the fourth quarter, if you look at it, Maya was priced at a $4.50 discount to Brent. WCS or Western Canadian Select in the U.S. Gulf Coast was trading at a $10.60 discount to Brent. We believe that the Canadian quote was much more representative of our actual delivered heavy sour into the system. In addition to that, there were certainly some things with the disconnect in western Canadian pricing. We had a significant uplift on the crude by rail; we did 43,000 barrels a day of heavy Canadian by rail in Port Arthur, and those were very discounted barrels.

Okay, thanks. And I guess that sort of leads nicely to my second question. My follow-up is on the Canadian barrels. It year-to-date seems like the import data and purchasing data, what we've heard in the market is that you continue to be able to get good access to those Canadian barrels. Just wondering if you could give some color on the sourcing, especially given that we've had production cuts up in Canada with the dynamics of those barrels also coming in by rail, or are there more available in the market, just any color on how we should think about the variety of sourcing there?

Yes. In the fourth quarter, we also set a record on the volume of Canadian heavy that we ran in our system. We ran over 180,000 barrels a day of heavy Canadian. It is sourced via pipe, delivered into the Gulf, and then we do about 40,000 barrels a day crude by rail. Our view is that crude by rail will be necessary until one of the major pipeline projects gets approved out of western Canada.

I guess, maybe to dig in a little deeper, thinking about the summertime here with gasoline. So, you're running max distillate, presumably most if not all the industry is doing the same. So, if we see, relatively speaking, weaker gasoline cracks this summer, does that imply that to get things in balance effectively, the industry has to employ run cuts? Or should we think about additional toggles you can do, if you ended up with a summertime situation with stronger distillate cracks relative to the gasoline, especially with IMO staring us in the face by the latter part of the summer?

Roger, it’s difficult to answer, certainly thinking of the gasoline situation is a combination of yield, which certainly we expect to be in the max distillate mode. The other thing I’d refer to is just what the utilization rate and the refining capacity is, and whether that 20-year high that we saw last year is sustainable.

Yes. I believe that with more light barrels available, there is no reason to think that U.S. refiners are not operating at capacity. It’s purely a margin decision. We’ve heard other companies discuss various strategies regarding how intensively they run their FCC units and other operational decisions. I was curious if there are similar considerations for IMO as you evaluate your overall system.

This is Lane. I'll address that. The FCC is a crucial part of our operation, and there are specific economic turning points to consider. It usually makes sense to keep our alkylation units operating at full capacity. We monitor whether it is beneficial to run beyond that point. Interestingly, the feed we use in these units can also be directed to the fuel market to help meet the half-a-percent requirement for the IMO regulation. We believe that, structurally, the FCC will likely not operate much beyond what is needed to support their alkylation units, especially in light of how IMO 2020 is expected to unfold.

Good morning, everyone, and thank you for the question. I wanted to revisit crude sourcing and delve a bit deeper, clearly, there was a remarkable performance in that area. As Paul mentioned, it seems we all underestimated you this quarter. Regarding the Maya or other Central American heavy sour grades, I’d like to confirm something. Many of these grades seem to have priced themselves out of the market we saw in the fourth quarter. What was your purchasing activity like in the fourth quarter, and did you not run as much? How should we anticipate that looking now with some price normalization moving into the first quarter?

So, I think on the heavy side, we've definitely seen that Maya is probably not the best marker for what we're paying for a heavy sour crude. So, in the fourth quarter, if you look at Maya was priced at a $4.50 discount to Brent. WCS or Western Canadian Select in the U.S. Gulf Coast was trading at a $10.60 discount to Brent. We believe that the Canadian quote was much more representative of our actual delivered heavy sour into the system. In addition to that, then there were certainly some things with the disconnect in western Canadian pricing. We had a significant uplift on the crude by rail; we did 43,000 barrels a day of heavy Canadian by rail in Port Arthur, and those were very discounted barrels.

Thank you. This leads me to my second question about Canadian barrels. Year-to-date, it seems that the import and purchasing data indicate that you still have good access to those Canadian barrels. Could you provide some insight on the sourcing, especially considering the production cuts in Canada and the fact that these barrels are coming in by rail? Are there more available in the market? I’d appreciate any details on how we should view the variety of sourcing in this context.

Yes. In the fourth quarter, we also set a record on the volume of Canadian heavy that we ran in our system. We ran over 180,000 barrels a day of heavy Canadian. It is sourced via pipe, delivered into the Gulf, and then we do about 40,000 barrels a day crude by rail. Our view is that crude by rail will be necessary until one of the major pipeline projects gets approved out of western Canada.

I guess, maybe to dig in a little deeper thinking about the summertime here with gasoline. So, you're running max distillate, presumably most if not all the industry is doing the same. So, if we see, relatively speaking, weaker gasoline cracks this summer, does that imply that to get things in balance effectively, the industry has to employ run cuts? Or should we think about additional toggles you can do, if you ended up with a summertime situation with stronger distillate cracks relative to the gasoline, especially with IMO staring us in the face by the latter part of the summer?

Roger, it’s difficult to answer; certainly thinking of the gasoline situation is a combination of yield, which we certainly expect to be in the max distillate mode. The other thing I’d refer to is just what the utilization rate and the refining capacity is, and whether that 20-year high that we saw last year is sustainable.

Hey, guys. Congrats on the quarter. Just a couple of questions. A follow-up on the comments about running the FCCs, just to maximize alky production. The inputs into the FCCs, are those able to be blended into the marine fuel pool, or is there from a technical standpoint, an issue with meeting marine fuel specs, if you try to blend that backing gas oil into the marine pool?

Hey, Jason. This is Lane. So, yes, the fees, particularly the marginal fee which is low sulfur VGO into these FCCs will fit into the half-a-way percent fuel oil market.

Okay, great. And there's not an issue with any of the other specs outside of meeting the sulfur spec?

We've done a lot of work on blends to ensure compatibility. The specifications aren't very strict, mostly focusing on the sulfur levels. The key is to ensure that any adjustments made to the blend promote compatibility. I'm quite confident that the industry will address these challenges effectively. While there might be some issues, we have collaborated with various stakeholders to refine our blends accordingly. This is essentially the only concern we anticipate.

And just looking more near term, obviously 4Q benefited from some better capture than anticipated and trying to figure out if that could continue into the first quarter. One area I think where there could be some upside is on the butane blending. It looks like butane prices have fallen pretty hard against where gasoline prices are. Do you expect that to support capture rates in the first quarter relative to its support in prior first quarters?

Yes. We see the spread. But, it's not a real meaningful contribution to our overall earnings for the quarter.

Thanks, Shannon. We appreciate everyone joining us. Please feel free to contact the IR team if you have any additional questions. Thank you.