HF Sinclair Corporation (DINO) Q3 2014 Earnings Report, Transcript and Summary

Welcome to the HollyFrontier Corporation's Third Quarter 2014 Conference Call and Webcast. Hosting the call today from HollyFrontier is Mike Jennings, President and Chief Executive Officer. He's joined by Doug Aron, Executive Vice President and Chief Financial Officer; and George Damiris, Executive Vice President and Chief Operating Officer. [Operator Instructions] Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Julia Heidenreich, Vice President, Investor Relations. Julia, you may begin.

Good morning, everyone, and welcome to HollyFrontier Corporation's Third Quarter Earnings Call. I'm Julia Heidenreich, Vice President of Investor Relations. This morning, we issued a press release announcing results for the quarter ending September 30, 2014. If you'd like a copy of today's press release, you can find one on our website at hollyfrontier.com. Before Mike, George and Doug proceed with their prepared remarks, please do note the Safe Harbor disclosure statement in today's press release. In summary, it says statements made regarding management's expectations, judgments or predictions are forward-looking statements. These statements are intended to be covered under the safe harbor provisions of federal securities laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings. Today's statements are not guarantees of future outcome. The call today might also include some discussion of non-GAAP measures. Please see the press release for reconciliations to GAAP financial measures. And please note that any information presented on today's call speaks only as of today, November 5, 2014. Any time-sensitive information provided may no longer be accurate at the time of the webcast replay or any rereading of the transcript. And with that, I'll turn it over to Mike.

Great. Thanks, Julia. Good morning. Thank you for joining us on HollyFrontier's third quarter earnings call. I'm pleased to have our recently appointed Chief Operating Officer, George Damiris, join us on today's call. George has been a key member of our leadership team since his joining the company in 2007 and brings with him more than 25 years of refining industry experience. Today, we reported second quarter net income attributable to HFC shareholders of $175 million or $0.88 per diluted share. Third quarter EBITDA was $369 million, only 5% below second quarter EBITDA of $388 million, despite 7.5% lower throughput. Improved margin capture driven by strengthened coproduct cracks, attractive Midland crude differentials and good heavy crude economics helped to offset lower throughput narrower inland crude differentials, elevated regulatory costs relating to the RFS mandate and increased product inventory resulting from market access issues in the Rockies. On a per barrel basis, our third quarter consolidated refinery gross margin was $15.59 per produced barrel, slightly above the $14.54 of gross margin reported in the second quarter of 2014. Realized margins rose sequentially across all regions due to an improvement in capture rates, offsetting a decline of 14% and 4% WTI base gasoline and diesel cracks in the Mid-Con. Third quarter came in flat with second quarter earnings, despite lower crude throughput, continued cost pressure from RIN, a significantly backwardated WTI curve and a 30% compression in the Brent WTI crude spread. I expect the Brent WTI spread to rewiden as we exit 2014, with the startup of new pipeline capacity into the Cushing storage hub. We've seen a 20% build in Cushing inventories since July to over 21 million barrels and expect the 900,000 barrels per day of Cushing-bound crude capacity from Flanigan Sout, White Cliffs and Pony Express, which should all be operational by year end or early 2015, along with 700,000 to 1.2 million barrels per day of capacity recently announced around Saddlehorn, Grand Mesa and BTC pipelines from the Bakken and Niobrara to further contribute to Cushing crude availability. The fourth quarter is off to a good start, driven by seasonally strong demand in the Mid-Continent Rockies, due to unseasonably warm weather, a strong harvest and continued drilling activity. The Mid-Con sold at 17% per gallon premium to Gulf Coast gasoline due to high product -- type product inventories. PADD 2 utilization rates fell as low as 82% in the month due to turnaround activity and crude pipeline supply interruptions, forcing some refiners to cut rates. In the coming weeks, I expect the Group III premium to the Gulf Coast to moderate with increased utilization rates, as refineries exit turnaround and pipeline issues are resolved. We continue to invest in our core refining business, focused on increased crude flexibility and liquid yield improvement. Our El Dorado naphtha fractionation project is on track for completion in mid-2015. This investment will allow us to use natural gas as a source of hydrogen, improve liquid yield and reduce benzene and other coproducts. Our Woods Cross Phase 1 expansion underway will allow us to process greater quantities of black wax crude from the Uintah range. Holly Energy Partners substantially completed the expansion of its southeastern New Mexico gathering system in September, providing increased crude gathering volumes for our Navajo Refinery and connections to major market clearing points. The completion of Holly Energy Partners Southeast New Mexico gathering system, along with the optimization of HEP's existing pipeline system, has increased our access to Permian crudes. If economic, Permian barrels can account for 20% of our Mid-Con crude slate and 35% of our total refining system crude slate. Permian crude is on track to account for 1/4 of U.S. crude production. In the Malaga gathering region, in the immediate neighborhood of our Navajo Refinery, we expect to see 50% production growth by 2018 to over 560,000 barrels per day. While crude price is a risk, I do not expect the current weakness in WTI to result in any near-term slowdowns in crude production. I continue to believe longer term -- in longer-term fundamentals driven by crude oil production growth and our refinery locations close to the lowest price feedstock for refined products in the country will lead us to higher sustained earnings levels over time. And with that, let me turn it over to George Damiris, our Chief Operating Officer.

Thanks, Mike. Third quarter crude throughput was approximately 410,000 barrels per day versus our guidance of 405,000 barrels a day. We ran 25% sour and 15% WCS black wax crude. Our average laid-in crude cost was $3.21 per barrel under WTI. Total refinery operating costs for the quarter were $255 million. Operating costs were higher as a result of higher maintenance-related costs. In the Rockies, crude throughput was 59,000 barrels a day. We ran 2% sour and 41% WCS black wax crude. Average laid-in crude cost was $8.49 per barrel under WTI. Refinery operating cost was $10 per throughput barrel. We trimmed crude rate and built product inventory at the Cheyenne refinery in the quarter, due to a temporary shutdown in the [indiscernible] Rocky Mountain pipeline in August, limiting our access to the Denver market. We have reversed this inventory build in the fourth quarter. For the Mid-con region, crude throughput was 252,000 barrels a day. We ran 10% sour and 15% WTS crude. Average laid-in crude cost was $1.42 per barrel under WTI. Refinery operating costs were $5.36 per throughput barrel. Total lube sales in the third quarter were approximately 10,700 barrels a day with an average price of $70 per barrel. We were able to take advantage of the sharp reversal in Group III margins in August by running more crude than originally planned. We are completing our El Dorado turnaround work on the gofiner FCC and alky units, which began in late September. For the Southwest region, crude throughput was 98,000 barrels a day. We ran 100% Permian crude, of which 76% was sour. Our average laid-in crude cost was $4.61 per barrel under WTI. Refinery operating costs were $5.34 per throughput barrel. We began our planned turnaround on the hydrocracker in late September. Total opportunity in the quarter was $58 million, primarily at Cheyenne due to the distillate hydrotreater outage, which limited crude rate and at El Dorado, due to a hydrogen plant outage. For the fourth quarter, we expect to run 375,000 barrels a day of crude, with 32% of the slate being sour and 12% WCS black wax crude. In addition to completing our El Dorado turnaround work, we also completed our turnaround work at the Navajo Refinery. Our remaining turnaround activity in the quarter includes work on the Woods Cross reformer, distillate hydrotreater, and the Tulsa West crude unit in November. With that, I'll turn it over to Doug for some closing remarks.

Thank you, George. For the third quarter of 2014, cash flow provided by operations totaled $84 million or $253 million, if you exclude the effects of working capital. Third quarter capital expenditures totaled $101 million, which excludes HEP's $23 million capital spend. Turnaround spending in the quarter totaled $23 million. We are raising our full year turnaround spending slightly to guide from $77 million to approximately $90 million, due to turnaround work planned at our Tulsa and Woods Cross refineries in the fourth quarter. We maintain our full year 2014 CapEx guidance of approximately $400 million. As of September 30, our total cash and marketable securities balance stood at $1.5 billion, a $300 million reduction from June 30. We announced and paid $0.32 regular and $0.50 special dividends in the third quarter, distributing $163 million to shareholders. Also, our Board of Directors authorized a $500 million share repurchase program in September, replacing all existing share repurchase authorizations. We have purchased 2.8 million shares at an average price of $47 since June 30 and currently have $447 million remaining on our share repurchase authorization. Since our July 2011 merger, HollyFrontier has returned $2.5 billion in capital to shareholders through regular dividends, special dividends and share repurchases. Our trailing 12-month cash dividend yield stands at 7.2% relative to yesterday's closing price of $45.21. Holly's debt totaled $188 million, excluding non-recourse HEP debt of $851 million. On July 1 of this year, we terminated our $1 billion senior secured credit agreement and replaced it with a new $1 billion senior unsecured revolving credit facility, which matures in July of 2019. It brings us in line with standard for investment grade rated companies and will save us approximately $1.7 million a year, while also giving us additional flexibility. HollyFrontier owns 39% of Holly Energy Partners, 22.4 million common units plus our 2% general partner interest. The current market value of our L.P. units is approximately $708 million, as of last night's closing price. Third quarter general partner incentive distributions were $8.5 million. And through the first 9 months of the year, we received approximately $60 million in cash distributions from HEP. Lastly, a reminder that you can find monthly WTI based 3:2:1 indicators for our Mid-Con, Rockies and Southwest regions posted on HollyFrontier's investor webpage. These regional indicators do not reflect actual sales that are meant to show monthly trends. Realized gross margins per barrel may differ from the indicators for a variety of reasons. And with that, Beth, I think we're ready to open the floor to questions.

[Operator Instructions] Our first question is coming from the line of Doug Leggate, Bank of America.

I'll take my 2 questions, if I may. I guess, Mike, in prior years coming into this time of year, you've kind of signaled the ramp up in or the increase in supply of gasoline in the Gulf Coast that sometime has been problematic to your markets. But at the same time, you've made a pretty good effort of moving gasoline out of your markets to alleviate some of that bottleneck. So I wonder if you could just give us a prognosis as to how you see things looking for your backyard, as you move through into the fourth and first quarter? And I've got a follow-up, please.

Sure, Doug. Indeed, the inland states tend to have a greater drop-off in demand due to weather in the winter months and for that reason tend to get long in gasoline in particular. What we've done over the last couple of years in anticipation of that is to expand our market footprints into surrounding states and are now capable to place 20,000, 25,000 barrels a day of product into markets not previously served. As so we think that, that reduces our dependence on both sales within the Mid-Con and then will position us better, as we go through these slower demand periods.

Okay. I appreciate that. I guess an unrelated question, Mike, is this is probably also for you. But earlier this year, I guess you got more involved in what was happening down at HEP, and I'm just curious as to as you see the strategies of some of your peers expand beyond, I guess, what you could call the traditional refining businesses to drive growth. What are your latest thoughts on the options for maximizing the value of your own [indiscernible]? And I'll leave it at that.

Certainly. We're hitting that in 2 particular areas. The first is attempting to grow our Southeast New Mexico and Permian Basin based crude business, most recently through the Malaga gathering system expansion. We're running about 25,000 barrels a day of new gathering through that system. And it was brought on-stream finally just in September. So that's been a great win for HEP, and we'll be looking to extend that in that same Delaware Basin area. Beyond that, HEP will continue to work with HFC, particularly around our growth projects, the largest of which rely on that Uintah crude and the expansion of our Salt Lake City or Woods Cross refining facility. But the point there is one of building very new competent refining capacity that has high margin potential and being able to work with HEP on the logistics-related assets to participate in some of that. We see that as a great strategy to help drive their growth and also realize better value for the margin that we're going to create out in Woods Cross.

That's very kind of -- I guess, the rights that are related to your existing business. I guess not to push you too much on this, but is acquisitions outside of your traditional assets? For example, as we saw with Tesoro getting involved in gas gathering, for example. Is that the kind of thing that you would anticipate HEP could do in its own right? Or is it going to stay very much a facilitator for the refining? And I'll leave it there.

Sure. Doug, we participate in any and all of these auctions that we see as strategic for HEP. But we tend not to build those into our growth plans. We want to find acquisitions where we can add value. And so when we find the one that's going to work for us from a value perspective, we'll chase it hard. To date, we have not found one.

Your next question comes from the line of Paul Sankey, Wolfe Research.

The traditional question about M&A and what you're seeing in that market, if I could. And then the follow-up is also the usual question on demand and how things are. I think the latter one is perhaps you can probably say more about. I mean it does seem that we've got more demand strength out there. And I just wondered if that people perceive, and I wanted to see your perspective.

Well, it is. I'm going to let George answer the latter question on demand. And unfortunately, I'm going to give a very traditional answer to the M&A question. Obviously, there are a few assets out in the market right now, some of which have very complementary location to our existing business. We desire to grow the company. We think that there's value in what is available for sale, but I'm not going to go further than that. And, George, on demand?

Yes, on the demand side, things are strong, especially on the distal side of the barrel, where I think we have record crops being harvested right now. So a lot of distal demand and some good deal of cracks as a result of that.

And beyond that, the economy is stronger than, I think, a lot of people give it credit for. Gasoline demand through the summer set some near-term record, and then we found demand in our core markets to be pretty robust.

FInally, Keystone pipeline, if that was approved, what does it mean for you guys? And I'll leave it there.

Keystone would be a net positive, we believe, to help rebalance Cushing to historical levels, especially bring in heavy Canadian crude down for our El Dorado refinery.

Your next question comes from the line of Roger Read, Wells Fargo.

Sounds like most of the operational stuff has been at least reasonably covered. So I'm going to turn to the share repurchase program and the special dividend. And I was just kind of curious, understand going to a larger declared share repurchase program, but what if it's something even bigger, maybe scale back on the special dividend. Historically, you've talked about increasing the regular, and then maybe lowering the special and keeping the overall payout. Instead, you've generally raised the regular and kept the special. And I was just wondering how you all evaluate special dividend versus larger share repurchase program.

Yes, well, to date, we're doing both in a material way. And I think we have the capacity to do both. Our repurchase program, traditional, was geared toward trying to find a discount to what we thought the fundamental value of the company was, and it was construed as opportunistic to the Street. We have taken perhaps a more conventional approach to that more recently. We announced the $500 million program, and we're executing on it much more regularly than we have in the past. So I guess I would say, that to me is a substantial program, and we have a track record of putting a program out there and completing it. So we're not limited in terms of balance sheet at this point. And I think our Board of Directors were receptive to putting cash to work for benefit of shareholders, be it through dividends or share repurchase. So for the time being, we anticipate maintaining both, but accentuating the share repurchase more than we have, certainly through the first 9 months.

Okay. And then sort of a long side capital allocation question. You obviously highlighted some things you can do with HEP, which I guess, to some extent, it could even fund. But what are you -- are there any particular projects on the wish list here in the refining space that, I guess, from a return criteria might look fine but from a evaluation relative to share repos may not have quite as good a return that we should be watching going forward. I'm thinking along the lines, if Keystone XL came through, would there be some upgrades or expansion projects you'd like to pursue?

Our highest value growth right now really is in Woods Cross and focused on the local crudes produced out there. That is a big capital spend for our company with Phase I at 350 to 400, and due to complete here in the fourth quarter of 2015. Phase 2, we're branching up right now, have not yet approved the project, but it's very attractive though high capital costs. We see HEP participation in those projects as a great way to help, both fund the project and provide growth to the MLP. So I think we've got a good slate of executable growth ahead of us and that importantly is not predicated on growth in U.S. gasoline demand. We're really focused on working on local crude supply and producing high-value products, particularly in the lube sector in order to generate the bulk of this return.

Your next question comes from the line of Brad Heffern, RBC Capital Markets.

Maybe just following up on the last question slightly on Woods Cross Phase 2. What is the -- what's going to make the decision there? Is it simply looking at what the engineering costs are going to be? Or is there something else you need to see like growth out of the Uintah or maybe how product is going into the Las Vegas Market before you make that decision?

Yes. Well, certainly the markets for the products are important. As with crude supply, I mean, the decision is made as a commercial package. Right now, we're focused on getting the project cost estimation and engineering completed to a point that we have good faith in what it will cost to execute it. But our commercial efforts are ongoing. So I'd say it's a package deal, and we hope to have a quality conversation with our board in the first or second quarter of 2015 on that project.

Okay, perfect. And then just thinking about leverage levels long term. I think you can make the argument that the company is a little bit underlevered at this point. Is there a reason that you guys would think about changing that? Or do you want to keep the balance sheet relatively clean, maybe to accommodate an acquisition?

Yes. We don't warehouse capital in anticipation of an acquisition. We have a strategy of trying to pay out steady returns to our shareholders as opposed to sort of a one fell swoop type of distribution. That resulted in industry-leading yields on our stock in terms of the dividends we pay out. We also are stepping up our share repurchase activity. I think long term, to directly answer your question, our target is sort of 1 turn of debt relative to company EBITDA. So we have quite a ways to go in terms of getting to that point, and we'll continue both with share repurchase, dividending and also -- and importantly, our growth spending. Because we've got quite a bit of that going on, particularly, as far as Phase 2 is approved.

Your next question comes from the line of Evan Calio, Morgan Stanley.

Look, I have a different strategic follow-up question on refining M&A and you guys have historically made very accretive investments. I mean, generally, you look at a 2x your cost of capital as your hurdle rate. But how -- can you maybe talk about how you account that for an uplift at HEP? Or what -- anything could have -- impact could be on your GP interest in that analysis, as well as when you look to a normal return? I mean, how are you thinking about differentials given some of the policy flux?

Let me try to clarify 2x our positive capital. I think what we've said is we attempt to double our money. We want to see our way to doubling our money on that which we buy. That can come through a lot of different mechanisms. One would be a different margin assumption than somebody else might use. Another could be a different source of capital, be it HEP or otherwise MLP Capital. Growth projects within the purchased asset consolidation and synergies as we did with the Tulsa refineries and ultimately with Tulsa and El Dorado. So the doubling of our money is not just applying a 25% discount rate to a cash flow stream, rather it's about what can we do incrementally through time to make money on what we buy so that we can generate strong returns for our shareholders. And clearly, in this environment, the MLP is a critical tool in trying to do that given the multiple discrepancy between [indiscernible] refining cash flow and that which would fit in MLP.

Okay, that's helpful. And doubling, what kind of timeframe? Is it the hard stop? Or is it just over a longer period of time?

That's where the magic is. I don't think that we've been that specific, but we all have reasonable expectations that this it isn't going to take 20 years, right. So I think probably 3 to 5 would be a reasonable expectation.

Right. And then maybe to the differential piece. I mean, just kind of given we've come through a kind of unique period since 2011. How do you -- I mean, do you take a conservative view on what the long-term differential earnings power would be? Or how do you -- when you're making a much, kind of longer-term investment, how do you handle that piece [indiscernible] ?

We had a great run in 2011, '12, related to what I would call bottleneck differentials. We don't assume bottlenecks when we look forward. We talk about differentials as they pertain to great differentials and transportation cost. And certainly, crudes can trade inside and outside transportation cost for a period of time, but that's the median around which they should trade. And I think that's what we've seen in the past generally. So that's what we tend to use for differentials. Obviously, there's the factor of exports relative to crude, and so we have to take note of that. But generally, as we look at potential markets reached by U.S. coastal sweet barrels, there is a transportation cost involved, okay. So it's not as though these markets are going to be penetrated without a price concession by the producer, and we think about that as well.

Your next question comes from the line of Jeff Dietert, Simmons.

It's Jeff Dietert with Simmons. With the election yesterday and the new congress in, I was wondering if you could share your thoughts on crude exports in the renewable fuel standard.

Sure. You'll probably catch me ranting here, but I'll try to maintain. So the RFS in particular, Jeff. I mean that's something that was created specifically in response to perceived threat to U.S. energy security. I think the market has done an outstanding job of resolving that threat, and we're now pointing toward potential energy independence within 3 to 5 years. And certainly on a continental basis, we're practically there today. So I think that mandate has far outlived its useful purpose. It's created a lot of discontinuity within the supply chain and unnecessary regulatory tension, while also taxing consumers who pump. So I guess I can emphatically say it's broken, and it needs to be repealed. We will be working to that effect to get it repealed, or at least materially changed. The crude exports, I view that, frankly, as part of the same conversation. We hear a lot about how crude exports are from an era gone by. And I certainly agree with that. The '70s and today are very different periods of time, just as 2007 and today are different periods of time. And so I think we have to look at this as a combined whole -- RFS crude exports, even Jones Act, though that's politically a lot more intractable. These things have to be on the table if we're going to open up markets. I don't think you can put -- singularly pull a straw from the pile and expect the pile to stay standing. So that's what we'll work towards. We're not in opposition to crude exports. We're an opposition to lifting that ban by itself..

Your next question comes from the line of Ryan Todd, Deutsche Bank.

If I could start with a question on New Mexico, you referenced that the New Mexico, the crude gathering system is running, I think, up to 25,000 barrels a day at this point. Can you remind us what the incremental cost savings on crude supply is to your refinery there in the region?

Well, that obviously, varies with crude differential. And so, George, second -- the third quarter Midland Cushing differential was what?

It was about $10 on sweet, about $8.50 on sour.

Okay. So we tend to capture much of that. Certainly for those barrels that are being shipped to Cushing, our gathering costs represent tariffs paid to HEP, which will vary between $0.50 and $1 per barrel. But that's normal transportation cost, costs another $1 or more and to get it over to Cushing. So that can give you an idea of crude economics, obviously, heavily dependent upon Midland-Cushing differential.

Okay, and if we stay there in Midland, that's -- can you remind us that there's been expectations for a significant narrowing in Midland debt and obviously have narrowed some in recent months. So what are your expectations for the timing of ramping pipeline flows over the next 6 months out of the region and kind of long-term transport base differentials to your refinery there?

Yes, sure. So to our refinery there, our costs are going to represent that same $0.50 to $1 of gathering. The real question is how does Midland trade relative to Cushing or the Gulf Coast. And there is certainly a wealth of pipeline assets that have been built or are being built to carry that crude to the Gulf Coast. There's also been dramatic growth year-over-year in terms of the Permian, in particular Delaware Basin, which is the area that we focus on. That growth is going to interact with crude price. And the differentials, likely swing around, certainly they do around any time a new line is commissioned, and you have the line fill process, which effectively, you're buying a lot of crude to bury it back on your ground. Once that normalizes, we see a continued mid-single-digit differential between Midland and the Gulf Coast, and Cushing probably sits somewhere between there.

Okay. And then maybe one last one on the Southwest. In the -- is there anything for us to be aware of -- in October, if we look at your -- the HollyFrontier index, you've seen a little bit more of a rollover in October than maybe would've expected in the Southwest. Is there anything going on there that we should be aware of? Or is it just monthly volatility?

Well, the Southwest is influenced by U.S. Gulf Coast and U.S. West Coast pricing, okay? So while the Mid-Con has been pretty stout in terms of margins through October, the coastal areas have been less, particularly for gasoline. And so the Southwest is reflecting that gasoline crack tradeoff during the month of October.

[Operator Instructions] Your next question comes from the line of Phil Gresh, JP Morgan.

Couple of quick follow-ups here. One is just on the buyback. Obviously, you stepped up pretty meaningfully in the quarter. Just wondering if you would calibrate some of that as still being opportunistic? Or if this is kind of your real run rate we should be thinking about moving forward?

I think that it's probably some of both. We saw -- buying back stock, I guess -- taking a step back. Buying back stock in a volatile industry like ours, sometimes can be challenging. And I would tell you we're not perfect market timers, but when we see opportunity, we tend to be more aggressive. When we see a 30-day or longer strong run in the stock price, we would tend to be less aggressive. But I do think the announcement of that $500 million program by the board to replace what was already existing was an indication that, yes, we'll be more aggressive than we have been historically. I don't think it means that you can expect $125 million per quarter of buybacks in every quarter sort of no matter what. And appreciate that that's not really easy for modeling, but that's the way we tend to run it.

Now that's fair. I appreciate that. Second question just on Woods Cross Phase 1. I don't think you mentioned any update on the project cost or the return expectation. Just wondering kind of where your feel those are right now? I think recently you had raised the cost estimate, but just wondering about comfort levels on both sides of that equation.

We're good with our previous disclosures and announcements. The range that we provided is still one that we can live well within. Completion period, it looks like October, November of 2015, bringing it onstream in terms of production toward the end of the year there, and the economics remain as we've announced them previously.

Okay. Last question is just, you had mentioned you expect Brent WTI to widen. You also just made the comment in reference to the previous question about WTI to the Gulf Coast having kind of a, I guess, low single-digit differential. So I guess I should interpret that to mean that you expect Brent LLS to be the rewidener. So I'm just kind of curious what you think will ultimately lead to that rewinding, just given what we've seen with the Brent markets recently?

It's a fair question. Obviously, there's a lot that's happened recently that has caused us to scratch our heads and question assumptions that we thought were accurate. I think what is fair to say is that through time, there's a strong need on the part of the producing nations, perhaps less so in respect of Saudi Arabia, but certainly others have a fairly high marginal cost of maintaining social stability. And I think you're going to see volumetric action on the part of OPEC and others to try to sustain that. That price in its own that allows them to run their countries and their fiscal budgets reasonably. And there are obviously differences by country and by producing regime around cost of production, and otherwise, social cost. But I don't believe that price for crude in the '70s is going to meet the bar in terms of providing that stability that allows production to continue. So one way or another, I believe production or crude prices will be higher and the Brent price will be higher than the U.S. coastal price.

There are no further questions. I will turn the floor back over to Julia Heidenreich for closing remarks.

Thanks, everyone, for joining us. If you have any follow-up questions, give us a call. I'll be at my desk all day. And otherwise, have a great holiday season, and we look forward to sharing our full year and fourth quarter results in February.

Thank you. This concludes today's teleconference. Please disconnect your lines at this time, and have a wonderful day. Thank you.