© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day, ladies and gentlemen, and welcome to the Valero Energy Corporation's Second Quarter 2018 Earnings Call. At this time, all participants are in a listen-only mode. And I would now like to introduce your host for today's conference Mr. John Locke. Sir, you may begin.
Good morning. Welcome to Valero Energy Corporation's second 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; Jay Browning, 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.
Now I'd like to direct your attention to the forward-looking statement disclaimer contained in the press release which, in summary, 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'll turn the call over to Joe for opening remarks.
Thanks, John, and good morning everyone. During the second quarter, we operated well and delivered solid financial results despite having turnarounds in our Gulf Coast and North Atlantic regions. We processed near record volumes of light sweet crude and we maximized heavy sour crude runs in our refineries as discounts widened to levels we haven't seen since 2014. We were positioned to take advantage of these discounts more fully due to our logistics investments including the Diamond Pipeline which enabled our Memphis refinery to capture additional margin from running WTI instead of LLS. And with relatively wide discounts for WTI versus Brent, our commitment on Enbridge Line 9B also provided meaningful margin benefits.
Looking ahead, work continues to move forward as planned on the Central Texas pipelines and terminals and the Pasadena products terminal with completion expected in 2019 and 2020. We expect the Sunrise Pipeline expansion to start-up in early 2019 which will provide our Mid-Continent region with even greater access to cost advantage Permian crude.
Turning to our refining investments, the Diamond Green Diesel capacity expansion is nearing completion and start-up is scheduled in August. Construction is also progressing on the Houston and St. Charles alkylation units and the Pembroke cogeneration plant. We expect these projects to be completed in 2019 and 2020.
With regard to cash returns to stockholders, we paid out 51% of our year-to-date adjusted net cash provided by operating activities and we continue to target an annual payout ratio between 40% to 50%.
Looking ahead, we continue to have an optimistic outlook for the balance of the year. Global economic activity remains healthy and product demand is strong domestically and internationally. Gasoline and distillate export volumes are steady. Days of supply of light products remain below five-year averages despite recent high industry refinery utilization rates. And while crude discounts have narrowed recently, the oil market remains well supplied and we expect differentials to widen again as the industry enters turnaround season.
And with that, John, I'll hand the call back to you.
Thank you, Joe. For the second quarter, net income attributable to Valero stockholders was $845 million, or $1.96 per share, compared to $548 million, or $1.23 per share in the second quarter of 2017. Second quarter 2018 adjusted net income attributable to Valero stockholders was $928 million, or $2.15 per share. For reconciliations of actual to adjusted amounts, please refer to the financial tables that accompany this release.
Operating income for the refining segment in the second quarter of 2018 was $1.4 billion compared to $945 million for the second quarter of 2017. Excluding $21 million of other operating expenses primarily related to costs associated with the fire at the Texas City Refinery in April, adjusted operating income for the second quarter of 2018 was $463 million higher compared to the second quarter of 2017. The increase from 2017 is mostly attributed to higher distillate margins and wider discounts for sour and domestic sweet crudes versus Brent, partly offset by lower gasoline margins.
Refining throughput volumes in the second quarter of 2018 averaged 2.9 million barrels per day and throughput capacity utilization was 93%. Throughput volumes were 121,000 barrels per day lower than the second quarter of 2017 due to maintenance in the U.S. Gulf Coast and North Atlantic regions. Refining cash operating expenses of $3.67 per barrel were $0.11 per barrel higher than the second quarter of 2017, mainly due to lower throughput in the second quarter of 2018.
The ethanol segment generated $43 million of operating income in the second quarter of 2018, compared to $31 million in the second quarter of 2017. The increase from 2017 was primarily due to higher distiller grains prices and stronger production volumes in the second quarter of 2018.
Operating income for the VLP segment in the second quarter of 2018 was $83 million compared to $71 million in the second quarter of 2017. The increase from 2017 was mostly attributed to contributions from the Port Arthur terminal assets and Parkway Pipeline, which were acquired in November of 2017.
For the second quarter of 2018, general and administrative expenses were $248 million and net interest expense was $124 million. Depreciation and amortization expense was $523 million and the effective tax rate was 22%.
With respect to our balance sheet at quarter-end, total debt was $9.1 billion and cash and cash equivalents were $4.5 billion, of which $100 million was held by VLP. Valero's debt-to-capitalization ratio net of $2 billion in cash was 24%. At the end of June, we had $5.4 billion of available liquidity, excluding cash, of which $750 million was available for only VLP.
We generated $2.1 billion of cash from operating activities in the second quarter. Included in this amount is $581 million benefit from working capital. Excluding working capital, net cash provided by operating activities was approximately $1.5 billion.
Moving to capital investments, which excludes acquisitions, we made $718 million of growth and sustaining investment in the second quarter. Included in the $510 million of sustaining expenditures was $270 million for turnaround and catalyst costs. The balance of capital invested in the quarter was for growth.
With regard to financing activities, we returned $672 million to our stockholders in the second quarter. $345 million was paid as dividends, with the balance used to purchase 2.8 million shares of Valero common stock. As of June 30, we had approximately $3.2 billion of share repurchase authorization remaining. We completed a $750 million public debt offering in May, and in June we repaid $750 million of senior notes due in 2019.
We continue to expect 2018 capital investments to total $2.7 billion, with about $1.7 billion allocated to sustaining the business and $1 billion to growth. Included in the total are turnarounds, catalysts, and joint venture investments.
Now for modeling our third quarter operations, we expect throughput volumes to fall within the following ranges. U.S. Gulf Coast at 1.73 million to 1.78 million barrels per day, U.S. Mid-Continent at 430,000 to 450,000 barrels per day, U.S. West Coast at 270,000 to 290,000 barrels per day and North Atlantic at 445,000 to 465,000 barrels per day.
We expect refining cash operating expenses in the third quarter to be approximately $4 per barrel.
Our ethanol segment is expected to produce a total of 4 million gallons per day in the third quarter. Operating expenses should average $0.38 per gallon which includes $0.05 per gallon for noncash costs such as depreciation and amortization.
For 2018, we continue to expect the annual effective tax rate to be about 22%. For the third quarter, we expect G&A expenses, excluding corporate depreciation, to be approximately $215 million. Net interest expense is estimated at $110 million and total depreciation and amortization expense should be approximately $515 million. Lastly, we continue to expect RINs expense for the year to between $500 million and $600 million.
That concludes our opening remarks. And before we open the call to questions, we would again respectfully request that our callers adhere to the 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, as this will help us ensure all callers have time to ask their questions.
And our first question comes from the line of Roger Read with Wells Fargo. Your line is now open.
Thanks. Good morning. How are you all?
Hi, Roger.
I guess let's dive into the big question that's out there. Q2 was great. Q3 a year ago was really good. Q3 this year maybe doesn't look like it's starting off quite as strong, but if you can kind of walk us through maybe, Joe, how you see the market structure here as we look to the back half of the year. Maybe thoughts on turnarounds within the industry, where we are in terms of demand trends and then where you see, call it, crude access at this point given some of the issues out of nearby OPEC countries.
Yeah. Roger, that's great. We'll let Gary go ahead and take a whack at these.
Okay. Roger, I think you know on the diesel side, much like Joe commented in his opening remarks, demand remains very strong both domestically and to the export markets. Domestically, we're seeing about 125,000 barrels a day of demand growth. So despite the fact that we've had record high refinery utilization and distillate production that's above the five-year average range, we really haven't been able to replenish diesel inventories to pre-hurricane type levels. So we continue to see very low diesel inventories, very strong export demand and very strong domestic demand.
So moving forward into the third quarter, I think you see some production fall off as we get into turnaround season and refineries come down for turnarounds. And then, of course, as you get later in the year, you'd expect to see some improvement in demand as heating oil season kicks in with some colder weather. So, to me, I think diesel should even be stronger in the prompt market, but when you look at the fundamentals, I think we're in for a very strong diesel year.
On the gasoline side, again, gasoline demand looks good domestically and into the export markets. Here with the record-high refinery utilization and increase in gasoline production, gasoline production increases are outpacing the increases in demand a little bit, so we've been able to replenish gasoline inventories to kind of a pre-hurricane type level.
As we move forward in the gasoline markets, like diesel, I think you'll see production fall off some with turnaround season. But assuming you don't have some interruption in supply like we saw last year with the hurricanes, I would expect gasoline to follow more seasonal trends, and once you get through driving season through Labor Day and demand falls off a little bit, you'll see gasoline cracks weaken as we get into the fourth quarter.
On your crude question, we continue to see good availability in crudes despite declining production in Venezuela. We continue to get above our contract levels there. Seeing good supply from Canada. North American growth continues to exceed expectations and then we're starting to see more OPEC volume make its way to the United States as well.
Okay. So no problem on the crude side then?
No.
Okay. Then just a quick follow-up. Guidance on cash OpEx if I understood was $4 a barrel. You've consistently done much better than $4 a barrel. So my question is simply, is there something going on expense wise? Or is this just closer to budget and if you perform better you come in lower on a per-barrel basis?
Yeah. Roger, this is John. We take a view, right, as of a point in time and sometimes that changes over time. I think as you look at that number probably today, maybe there's – it's come off a little bit from there, but that is what the number is at the time we take the forecast.
Okay. So no major changes or anything that's changing sequentially, just part of the budgetary approach?
Right.
Okay. Thank you.
Thank you. And our next question comes from the line of Manav Gupta with Credit Suisse. Your line is now open.
Hi, guys. My question is; you recently made some acquisitions in Peru on the biodiesel side. I'm just trying to understand if you could give us some more color on that acquisition? And would the earnings of that new segment or whatever acquisition you have made go through in the refining segment or the ethanol business?
Okay. Good question. Rich, do you want to?
Yeah, you bet. I'll answer this. So just to be clear, the acquisition here was not a renewable diesel acquisition. There's an idol renewable diesel plant there but it's been out of service for several years. This was really a wholesale marketing and terminal acquisition. We acquired two terminals that have in excess of 1.2 million barrels of storage, two truck racks, two offshore mooring facilities to offload product. So this is really set up to bring product into the country and not a renewable diesel play.
Yeah, it fits into our overall approach to securing shorts essentially in different international markets. We've got the activities that are taking place with Mexico, we've got now Peru, we've got other facilities that we're into today and we're looking at. But we've talked about being more involved in having access to the supply chain from the refineries out, and this acquisition just fits right into that. Essentially what we bought was a business, an operating business, and not a particular asset. So we feel pretty good about it, we also believe it's going to allow us to expand the business around that. We've got a team on the ground, obviously, right now working this, and their focus is, okay, we've got a strong market in Peru, where else are we going to take barrels that pass through this terminal.
Thank you so much, guys, for taking my question.
Thank you. And our next question comes from the line of Paul Cheng with Barclays. Your line is now open.
Hey, guys. Good morning.
Morning, Paul.
I think this maybe is for Lane. Valero has continued to, seems like performing better and better in your refining operations. You've been consistently that I think outperform your throughput guidance even when you have some unplanned outages and all that, and that also seems like while you guys clearly are the leader here but the industry also doing better.
Lane, when we're looking at fundamentally, is it good reason other than, say, the pricing is good so everyone trying to run hot. Is there any other reason why that we've been despite more environmental standard, one would think that more stringent standards would make it more difficult for the industry to maintain a high run rate. Is there anything fundamental has shift?
Paul, this is Lane. Could you repeat that last couple of sentences, please.
Well, I'm just trying to understand that, is it just because the commodity pricing is attractive so everyone is trying to run hotter, which is understandable. But other than that, is there anything fundamentally that make the industry be able to run their system much better than in the past?
I think, generally, the industry has experienced through, whether it's through our shared understanding of via some things like Solomon, what good looks like and everybody's on their own individual journeys on how to get better in these spaces. And it's clearly been our focus to do that and we've improved our operation a great deal over the past 10 years, and we think we'll continue to improve. There's always room for improvement. But it's a focus to be safe and reliable, and obviously, environmentally compliant and all those things lend themselves to being a much more reliable operation.
Do you think that we have much more room to push on a sustainable basis to be better than what we have seen? I mean, it has been quite remarkable how well the industry has done.
Yeah. I'm not going to speak for the industry. I'll speak for Valero. Our real focus is to continue to minimize unplanned outages, and in particular to try to find ways to minimize our downtime, our turnaround downtime over an entire cycle, and make sure that our spend rates during that time is the right amount to achieve that. And that's really where we, in terms of going forward, that's where we see the most of our opportunity.
So you don't think that you max out yet?
No.
Okay. Final one for me, Texas City, can you give us an update, the fire, when that is going to be back to normal operation? And also do you give any color about, I think previously talking about the coker investment?
So, on the SCC question, the Texas City, the SCCs came back from current outlook, back to normal operation. The alkylation unit, we currently believe will sort of be mechanically restored at the end of August, so we'll resume full operation in the alky in early September.
With respect to the coker, we're just still working through the permitting process with all the stakeholders. We have to ultimately have an operating permit, a construction and operating permit to go forward, and really even to get in the position to make the final FID decision. I mean, and that's just the way our gating process works, so that's where we are.
Pleasure. Thank you.
Thank you. And our next question comes from the line of Doug Leggate with Bank of America. Your line is now open.
Thanks. Good morning, everybody. Thanks for taking my questions. Morning, Joe.
Morning, Doug.
Joe, you clearly are throwing off a great deal of cash, and obviously, we continue to admire the discipline at which you're returning cash to shareholders. So my question is kind of two-edged on that topic. And it is, why is 40% to 50% the right number? And given the substantial EBITDA you still hold at the parent company level, what's your latest thoughts on drop-down timing from an MLP standpoint? And I've got a macro follow-up, please.
Okay. Doug, good questions. Donna, you want to talk about the payout ratio.
Sure. On the capital allocation perspective, we just believe that 40% to 50% is the right balance between returning to the shareholder via cash in the dividend and share buybacks, but also preserving some cash back at the parent to reinvest in the company, that being in the form of sustaining capital, but also growth opportunities and acquisition opportunities.
So just to be clear, I guess, on the MLP question, if you did do some additional drop-downs, what would be the priority for the use of that cash? And, I guess, what I'm really getting at is the balance between the dividend and the buyback, do you see that changing at some point? Because, obviously, a lot of your rerating has been driven by, I think anyway, the move towards being more of a yield stock within the S&P. I'm just wondering if you can see a little bit more of a pivot back towards the dividend away from the buyback. And I do still have a micro follow-up, please.
Yeah. No, Doug. I mean, good question. On the drop-downs, I mean, the reality is that Valero receiving cash back via drop-downs, just hasn't materialize the way we all expected it to, and that's because the capital markets just aren't there for MLP equities today.
Right.
I think MLP debt is okay. But, essentially, the way it's working out is Valero is the financier for VLP. And so as far as the cash perspective goes, there is no windfall of cash to be achieved for Valero by dropping down assets to VLP. It's the way the market is today. Will the market be this way in six months? I don't know, okay, but that's the way it is today. So there's not a big windfall of cash, I would say, to be had because of a drop-down opportunity.
We continue to look at the balance between the share repurchases and the dividend. And our basic view is let's get the dividend up to where we're paying out towards the high-end of the peer group, so that we're competitive there. And then, we use the share repurchases as a flywheel. The 40% to 50% range we give you is essentially our target. And to the extent that free cash flows exceed our expectations, we've used that flywheel than to go ahead and repurchase additional shares. And I think we're very comfortable with that and that's probably what we'll continue to do going forward. But rest assured that the dividend is something we talk about regularly. We are absolutely 100% committed to it. And whenever we make changes to it, we want to be sure that we're able to deal with it in good times and in bad times.
I appreciate the extended answer and, obviously, the arbitrage has closed some. So hopefully a quick follow up, Joe. I just wanted to close out the micro comments. It's an IMO question, I'm afraid, but there's obviously a great deal of uncertainty on how this is going to play out. And I just wanted to get your updated perspectives because it seems that bunker fuel associations and others around the world are starting to talk about what the real challenges are going to be of meeting the 1/1/20 date and particularly the pivot back towards scrubber options amongst other things. The example that's been cited is that delay of the water ballast rules that was pushed out two years because the industry was not ready. And I'm just curious if you've got a perspective as to how confident you are that things are going to transpire as optimistically, let's say, as some in the market are currently talking about. I'll leave it there. Thanks
Doug, that's good, and we'll let Jason talk a little bit about IMO.
Yeah, we've seen the same thing you have with a lot of discussion about how practical (25:19) implemented, whether the timeline's right. But at least our view now is we expect it to be implemented and enforced internationally according to there's timeline they put out without any big disruptions. The definitely hadn't made any indications to backing off at this time and if anything, they're working to put in place more effective enforcement mechanisms, like looking at whether you lose your insurance if you don't, it you violate the provisions or also potentially prohibiting vessels without scrubbers from transporting the higher sulfur material. But it is a big change.
Exxon Mobil, Jason, suggests that it might not be a bad idea to be the last man standing from a high sulfur fuel oil standpoint. Do you concur with that?
Gary, would you like to mention that one?
Yeah, I don't know. We don't make a lot of high sulfur fuel oil and I don't really see it that way. I think you're going to see a lot of people, as you get closer to 2020, to liquidate what inventory of high sulfur fuel oil that they have.
Thank you. And our next question comes from the line of Phil Gresh with JPMorgan. Your line is now open.
Yes. Hi, good morning.
Morning, Phil.
Morning.
Yeah. The first question is just thinking ahead here with all the growth in U.S. light sweet crude production coming and, obviously, we have the Permian bottlenecks but those will be resolved, so all those barrels are going to be pointing towards the U.S. Gulf Coast and probably on the Houston side where you have a prime position. So how do you think about how that plays out? What might happen to discounts in the Gulf Coast and the export capabilities of the system today and where they're going?
Yeah, Phil, this is Gary. I think, overall, it looks like most people are focused to tie a pipeline project with the dock project which allows the barrels to get to the water. I think you'll still have an advantage by being able to buy the barrels inland and buy the barrels on the Gulf Coast before they make their way to the water. But it looks like people are investing in logistics all the way to the water, not just to the Gulf.
So do you have a specific long-term view on like a Brent, Houston spread and what's reasonable based on transport?
Yeah. So I think we look at it, did it cost anywhere from $0.50 to $2 to get the barrel on the water and then you have some transit cost to get the barrel actually to a market. And so that puts MEH to Brent spread somewhere in the $2 to $2.50 type range.
Got it. Okay. And then just a little bit of a follow-up to a prior question just on the heavy side. We have seen some tightening of, like, the LLS – Maya, LLS, Mars spread. So I'm just curious how you see that playing out for the rest of the year. You made the comments about the Middle East barrels coming back. So do you see a re-widening of that spread as we move into, call it, the fourth quarter?
So I think I'll start with the heavy sour. So far, the Maya formula has really been impacted by the widespread in Brent/TI and the volatility in that Brent/TI spread. I think where we could get some relief on the heavy sour discounts is our view is as you move into the third and fourth quarter and you some turnaround activity in the Mid-Continent, you'll see some Cushing inventory begin to build which will allow the Brent/TI spread to widen out. And as that does, the Maya formula would again be impacted. And so you could see the heavy sour discounts widen out some. Overall, I think to get big relief and see significant discounts in medium or heavy, you do need to get the OPEC production back on and so how fast the OPEC production ramps up will certainly have a big impact on those quality discounts.
Anything specifically on the mediums?
No, I don't, today, you look in pretty much all the crude grades are trading at their quality-adjusted breakeven values. And so I think that holds until you see the OPEC barrels come back to the Gulf and then you could see those discounts widen back out. Today, at least the barrels we're taking from OPEC, the Saudi barrels that we're taking are going to the West Coast and so we haven't seen an incentive to reintroduce those barrels into the Gulf. But as they make their way back to the Gulf, then I think you start to see the medium sours widen back out.
Okay. Thank you.
Thank you. And our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt. Your line is now open.
Hey. Good morning, everyone.
Morning, Matt.
Morning.
Maybe to stick on this heavy sour theme, I think, Joe, in your opening comments, you talked about how you maximized heavy sour crude runs in the quarter. If I look at the data, your Gulf Coast system ran approximately 36% heavy plus resid in Q2. And then if we look way, way back to 2006, you ran approximately 51% heavy crude plus resid. I appreciate the system make-up has changed a little bit with Aruba and the crude toppers, but if you saw an environment with wider heavy dips over the next couple years, could you run more incremental heavies through your Gulf Coast system?
Hey, Matt. This is Lane. So I think one of the things you mentioned accurately is our portfolio is a little bit different than it used to be. In particular, we have the two topping units that run sweet and then also because of the clear margin that we've had on crude, like what Gary alluded to the answer in the last question was that you sort of have all the grades are on a quality basis equivalent. So it's really just been max crude rate. And so to the extent that refinery gets leveraged from that particular crude diet, it will maximize it. If you had us work – heavy sour was very, very disconnected and that was clearly the winner way over the other two, then we would run more heavy, we just may not run as much crude.
Okay. Sounds good. And then also want to circle back to the comment on how Line 9B from Enbridge provided some margin upside, just keeping in mind that Québec had the big turnaround in the quarter. If you look at the EIA data, it seems to indicate that somebody is shipping WCS on Line 9B and then tankering it down and selling it to the Gulf Coast refineries. Is that a source of upside for Valero here?
It would be, but we didn't ship any heavy, and actually shipping heavy for us would be an issue because mainline, the Enbridge mainline is prorated and so actually being able to nominate heavy and ship it through Line 9B would be very difficult for us to do.
Sounds good. Thank you.
Thank you. And our next question comes from the line of Craig Shere with Tuohy Brothers. Your line is now open.
Good morning.
Morning, Craig.
Just wanted to expand on Doug's cash question and I think Donna's comment that you appropriately want to retain some powder dry for potential acquisitions and obviously growth projects. But the growth projects have been pretty stable, maybe about $1 billion annually, and think that you all have commented in the past the M&A market is not especially cheap. And cash flow certainly looked to be increasing second half over first on sequentially lower maintenance CapEx, prospects for improving cracks and then, of course, there's the outlook for IMO 2020 coming up. So my question is, is there a logical limit, an absolute limit to the size of the cash build as you kind of think of sticking to this 40% to 50% payout ratio over time?
So historically – and I'll let Donna tail onto this however she would like – but historically we have said that we were going to stick to our capital allocation framework, which we have for four years now and we'll continue to do it going forward. But a component of that really has been the commitment also to not build significant cash positions. And if you look at it, I would tell you – and, John, you can tell me I'm wrong, but we've been between $4 billion and $5 billion of cash now for a number of quarters in a row.
Yes.
We set the target of 40% to 50% on the payout ratio. We've consistently raised the dividend. So our commitment to the shareholders on an absolute basis has gone up, and we'll continue to look at that going forward. But we're going to stick to this. We're not going to continue – we're not going to allow ourselves to run the cash balances way up. We think it's fair to our investors that if we are building cash, we're going to deploy it. And when it makes sense to deploy it to them versus investing it in projects within the business, we're going to do that.
Now, Lane and the team continue to develop projects. We executed on some acquisitions this quarter, which chewed up some cash. So, it's not all committed to share repurchases. We are using it to continue to grow the earnings capability of the business. But I think we're generally comfortable with the way we've been allocating it thus far.
I guess my question is – and I understand the cash balance has been relatively under control in recent quarters. But, I guess, if there's a break out as many people kind of envisioned for the industry in coming quarters in the next couple of years, how you might respond to that?
Well – and I think that our expectation would be that over the next bunch of quarters, we are going to see – and certainly as we get closer to 2020, we should see significant increases in our free cash flow as a result to the IMO 2020, and we're going to maintain our commitment to our capital allocation framework through that process. Now, does that mean higher dividends? Could well be. Does it mean additional share repurchases? Could well be. We don't want to abort our disciplined process to executing capital projects. Okay?
Lane and the team have done an outstanding job over the last several years of really getting their arms around this and being sure that we knew what the project was going to cost and what we expected the returns to be before we made the commitments to it. To the extent you try to accelerate that, you potentially degrade that process and we really would prefer not to do that. So, if we have an abundance of cash, acquisitions may look better. Share repurchases will still be certainly probably a big part of our use of cash and potential dividend increases.
Great. I appreciate the color.
You bet.
Thank you. And our next question comes from the line of Peter Low with Redburn. Your line is now open.
Hi. Thanks for taking my question.
Good morning, Peter.
I have one on the Texas City outage. I think in the release, you kind of break out the exceptional expense. But what was actually kind of the impact on earnings in terms of kind of the lost opportunity from that outage during the quarter?
Hi. This is Lane. So, our lost opportunity due to the outage during the second quarter was $150 million.
Okay. That's great. Thank you very much.
Thank you. And our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt. Your line is now open.
Hey. Just one quick follow-up here. So, you have a couple of projects around expanding your alkylation capacity, and I was hoping you could just provide an update on where you stand regarding the EBITDA contribution potential from those projects. It looks like octane spreads have widened a little bit year-over-year, although we're nowhere near where we were, say, back in 2015. So, in general, do you expect that Tier 3 would reduce octane supply and maybe rising fuel economy standards would increase octane demand? Just any comments on that would be great.
Hi. So, Matt, this is Lane. You sort of answered the question, I believe. The Houston alky, we're still going to start-up in the first half of next year. Our strategic view on that is is that octane will get more valuable as we go forward via Tier 3 destroying octane and then, obviously, the fuel economy standards. And then, really, this increasing wide arbitrage between NGL and gasoline, or transportation fuel. So we still feel good about those. Our FID EBITDA at the time was $105 million. We're not going to – that's the number. We're not going to provide any other color with respect to sort of a forward market or even a prompt market view on that.
Okay. Thank you.
You bet.
Thank you. And that does conclude today's Q&A session and I'd like to return the call to Mr. John Locke for any closing remarks.
Okay. Thanks, Sandra. Look, we appreciate everybody joining us today and please contact me, the IR team, if you have additional questions. Thank you.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone, have a great day.