HF Sinclair Corporation (DINO) Q3 2012 Earnings Report, Transcript and Summary

Welcome to HollyFrontier Corporation's Third Quarter 2012 Conference Call and Webcast. Hosting the call today from HollyFrontier Corporation is Mike Jennings, President, and Chief Executive Officer. He is joined by Doug Aron, Executive Vice President and Chief Financial Officer; and Dave Lamp, 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. Ms. Heidenreich, you may begin your conference.

Hello. Welcome to HollyFrontier Corporation's third quarter conference call. I'm Julia Heidenreich, Manager, Investor Relations. In addition to Mike, Dave, and Doug, we also have several other members of senior management in the room to help out with Q&A. If you would like a copy of today's press release, you can find one on our website, www.hollyfrontier.com. Before we proceed, please note the Safe Harbor disclosure statement in today's press release. In summary, it says statements made regarding management 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 outcomes. And today's call may also include discussion of non-GAAP measures. Please see the press release for reconciliations to GAAP financials. Also, please note that information presented on today's call speaks only as of today, November 7, 2012 and any time sensitive information provided may no longer be accurate at the time of any webcast replay or rereading of the transcript. And with that, I'll turn the call over to Mike.

Thanks, Julia. Good morning. Thank you for joining us. Today, we are pleased to announce record third quarter results for HollyFrontier. Net income attributable to HFC shareholders was $600 million or $2.94 per diluted share, a 15% improvement over the $2.48 per diluted share posted in the third quarter of 2011. During current quarter, we generated $1 billion in EBITDA versus third quarter 2011 EBITDA of $895 million. This exceptional financial result was generated from high throughput rates through a very constructive margin environment. The sustained light/heavy differential and widening inland coastal differentials provided additional uplift for our product margins. The company's consolidated refinery gross margin per barrel was over $30, a 9% improvement versus Q3 2011 levels. Margins in the Rockies and the Mid-Con were particularly strong throughout the quarter, and we continue to see very high distillate margins, particularly in the Rockies. Overall, we ran at 97.8 utilization rate and strong cracks across our markets helped to offset some of the impact from a fire at our distillate hydrotreater in Tulsa, which occurred in early August. During the third quarter, we continue to execute upon our strategy of providing high cash returns to our shareholders. In addition to our regular quarterly cash dividend of $0.15 a share announced in August, we declared our fifth special dividend of $0.50. And shortly following our August dividend declarations, we announced the sixth special dividend of $0.50 per share to be paid in September. This repeat special during the third quarter was justified based on robust cash generation. Last week we announced a 33% increase in our regular dividend rate, taking our fourth quarter regular dividend payment up to $0.20 a share from the previous rate of $0.15. At the same time, we declared a seventh $0.50 special dividend, which was our fifth during 2012. As of today, our trailing 12-month cash dividend yield stands at 7.7% relative to yesterday's closing price of $40.08 per share. In addition to distributing cash to our shareholders, we continue to invest in our core refining business, focusing on projects where we have distinct competitive advantage which typically relates to unique access to crude and other feedstocks that support more predictable refining margins. Our first phase of Woods Cross expansion program remains in the permitting process. We're also moving forward with initial engineering work on the second phase of that project for a potential expansion up to 60,000 barrels a day of crude processing and addition of a Group III lubricants plant. Additional investment opportunities are being reviewed internally, including potential for de-bottlenecking and crude rate expansion within our Mid-Continent refining system. During the third quarter, HollyFrontier sold its 75% interest in UNEV pipeline to Holly Energy Partners. This generated cash proceeds for HollyFrontier of $260 million, plus an additional million limited partnership units. HEP's development of crude oil and refined product logistics in and around our refineries remains a fundamental component of our company’s forward strategy. From an industry standpoint, increasing North American crude oil production, particularly from unconventional resources, remains a significant driver of refining profitability. This addition of cheaper and more secure refining feedstocks, when coupled with lower cost natural gas for plant fuel and increasing refined product exports, has been a game changer throughout our sector. HollyFrontier's particularly advantaged for 2 reasons: first, we're closer to the source than most refineries; and second, we have high complexity plants that provide us with flexibility to optimize our feedstocks based on current costs and differentials. Our forward view of crude dips tends to reflect the consensus outlook that pipeline transportation will ultimately set prices for many of these differentials. The question is when does ultimately begin. Today, the crude by rail fleet continues to grow throughout the country, and rail transport provides an essential link from wellhead to market. This means that pipeline tariffs are not setting crude dips and this scenario is likely to continue, assuming continuing drilling for crude production in the United States. Our company's view is that it will be multiple years before U.S. crude differentials, relative to Brent, reflect only the cost of pipeline transit. With that, and with compliments to our employees who helped produce an outstanding quarterly result, let me turn it over to Dave Lamp, our Chief Operating Officer, for an operational review.

Thanks, Mike. Throughput for the third quarter was 433,000 barrels a day of crude and 471 of total charge. The crude slate was 20% disadvantaged crude, which is made up of mainly Canadian drill bits and black wax, and 25% sour. During the quarter, light/heavy and sweet/sour spreads narrowed slightly versus WTI, but remains attractive. Laid-in -- averaged laid-in crude price cost for our system was $4.50 below WTI. Just to give you some flavor for the market. The Brent-WTI spread was about $17.17 for the quarter. WCS versus WTI was about $50.41. WTS was about $3.31 under WTI and North Dakota light was about $1.12 below WTI. Total refining and operating costs for the quarter was $202 million. Throughputs for the third quarter in the Rocky region was 75,000 barrels a day of crude and 82,000 barrels a day of total charge. Disadvantaged crudes were approximately 44% of the slate and there was no sour. Average laid-in crude cost for the Rockies region was $10.50 under WTI. Refinery operating costs were approximately $6.30 per barrel. We are able to minimize the impact of the Cheyenne coker turnaround, which was completed during the quarter, by running more light crudes and syncrudes versus WCS. Throughputs in the third quarter for the Mid-Continent region were 256,000 barrels a day of crude and $2.78 of total charge. Disadvantaged crudes were approximately 16% of the slate and 8% sour. Additionally, we ran about 6,700 barrels a day of high asset number Christina Lake crude, which sold at a discount to WCS. The average discount for Christina Lake to WCS for the quarter was approximately $5.50 a barrel. Average laid-in cost of -- for crude in the Mid-Con region was $2.75 a barrel under WTI. Refinery operating costs were approximately $4.71 per barrel. The Tulsa Refinery had an unscheduled outage of the distillate hydrotreater as a result of the fire in early August that Mike mentioned. We're able to keep crude rates at Tulsa up through the sale of raw diesel at a discount to ultra low sulfur diesel. Our El Dorado refinery crude rate was also affected by a continuing repair of its large reformer from the second quarter. Tulsa lube sales in the quarter were about 13,000-plus barrels a day, with an average crack of $73.48. Throughput in the third quarter for the Southwest region was 101,000 barrels per day, $110 of total charge. Disadvantaged crudes were approximately 13% of the slate and the rest was 85% sour. Average laid-in crude cost for the Southwest region was $4.50 under WTI. Refinery operating costs were approximately $5.14 per barrel. Navajo ran at record rates, averaging over 100,000 barrels of crude for the 5 months in a row through September. For the fourth quarter of 2012, we expect to run approximately 424,000 barrels a day of crude, with 20% of the slate being disadvantaged heavy crudes and 28% sour. The Woods Cross, FCC and alky turnaround began at the end of the third quarter, with most of the impact falling in the fourth quarter. The FCC has since started up and the alky is finishing up. Woods Cross also has a turnaround in its reformer unit and will tie in its new MSAT 2 unit in the fourth quarter. The Tulsa West plant turnaround is underway and should be -- begin to complete in early December. During the West plant turnaround, the East plant will continue to operate at approximately 70,000 barrels per day. The Navajo FCC was down for 7 days in October to repair its flue gas, waste gas boiler on an unscheduled basis. No other downtime was planned in the fourth quarter that will affect crude rates. We have a very heavy turnaround schedule in the first quarter of 2013. Navajo plans do turnaround in its Lovington crude units, FCC unit and alky unit beginning in January. El Dorado is planning to do to turnarounds on its crude unit, coker and [indiscernible] refinery units in March. And Tulsa is planning to do turnarounds on its East crude, CCR, and Panex units also in March. Our permit for the Utah black wax expansion that Mike mentioned for the Woods Cross Refinery completed its 60-day review by federal land managers. The next step is a 30-day public comment period, which should start within a week or 2. We expect this permit to be approved by the end of the year. Detailed engineering is proceeding on Phase 1 and major long lead equipment will be ready for purchase at about the time the permit is approved. With that, I'll turn it over to Doug for some closing remarks.

Thank you, Dave. For the third quarter of 2012, cash flow provided by operations totaled $742.3 million. Third quarter capital expenditures totaled $73.8 million, excluding HEP's $5.7 million capital spend. Turnaround spending in the quarter totaled $27.6 million. Our previous guidance of $350 million of expected capital spending for 2012 is still accurate. Although at this point, we aren't sure we'll actually get all of that spent before year end. At this point, we will spend between $275 million and $300 million this calendar year, with the balance slipping into the first quarter of next year. Not including the carried over amount, our preliminary expected capital spending for 2013 is also approximately $350 million. In the third quarter, we declared $235 million in dividends to shareholders, of which $113 million was paid out by quarter end. The $100 million structured repurchase contract we entered into last quarter expired during the third quarter. Because our share price was significantly above the set strike price upon expiration, we received $108 million in cash rather than the 3.7 million shares. Year-to-date, we've returned over $830 million through regular dividends, special dividends and share repurchases. And overall, since our July 2011 merger, HollyFrontier has returned nearly $1.1 billion in capital to shareholders. We currently have $509 million of our repurchase authorization remaining. As of September 30, 2012, our total cash balance, including marketable securities, totaled $2.3 billion versus $1.6 billion at the end of the second quarter. On September 15, we redeemed our outstanding 8.5% senior notes that were due 2016 for approximately $208 million. Remaining HollyFrontier debt totaled $471.8 million at the end of the third quarter, excluding non-recourse HEP debt of $874.4 million. Now I'd like to update you on our hedging program. Most of this is a recap. However, we have added some additional hedges. Last year, we sold forward a total of 40,000 barrels a day of gasoline and diesel for calendar 2012 at an average 2:1:1 crack spread of $27.63. We sold forward 18,000 barrels a day of gasoline and diesel, that's 9,000 of each product for the fourth quarter of this year at an average 2:1:1 crack spread of $20.60, and we also sold forward 12,000 barrels a day of gasoline and diesel, that's 6,000 of each product for the first quarter of 2013, at an average 2:1:1 crack spread of $18.50. Now for some of the new hedges that we've entered into. We sold forward an additional 4,000 barrels a day of gasoline for the first quarter of 2013 at an average price of $20.10. And for calendar '13, this is for all 12 months, we have sold forward 26,000 barrels a day of ultra low sulfur diesel at an average price of $31 a barrel that is for Mid-Continent or Group III ultra low sulfur diesel. Lastly, I'd like to update you on quarter-to-date crack spreads. And these again, as a reminder, are based on West Texas Intermediate crude, not necessarily the advantaged crudes that we run. For the Rockies region, the October gasoline crack spread averaged about $38, and the diesel crack spread averaged about $57 for October. Thus far, in November, albeit only a few days in, we're seeing our gasoline crack slightly improved up to almost $40 a barrel, and the distillate crack spread at about $54 a barrel. In the Mid-Continent, the gasoline crack spread for October averaged $34, with the diesel crack spread averaging $49 a barrel. And as a reminder, in Tulsa, we make lubricants where the crack spread for October averaged a little better than $80 a barrel. Looking at the Mid-Continent so far in November, we're seeing certainly a decline in the gasoline crack spread to about $23 a barrel. However, diesel hanging in there very nicely at just over $38 a barrel a month today. And lastly on our Southwest region, the guest crack spread averaged almost $39.50 for the month of October, and the diesel crack spread again almost $49 in October for the Southwest region. Month-to-date in November, about $35 on gasoline and $40 a barrel on diesel. And with that, Lyn, that concludes our prepared remarks. We're ready to begin taking questions.

[Operator Instructions] Our first question is coming from Evan Calio with Morgan Stanley.

I agree with you guys on your differential perspective. My first question on dividends. Look, another great quarter on a cash build despite 2 specials and regular. Two questions here. One, you raised your regular dividend 33% while increasing specials. How do you think about the shift from special to regular over time? Is the nomenclature matters to some? And then secondly, given the election outcome with potential tax implication for investors, I know while it's a Board decision, do you see any potential for a larger cash distribution into year end? And I have a second question.

Yes. Evan, what we're trying to do with regular dividend is to grow it steadily. And I think we've got that track record. It continues to grow. I think at some point in time it starts to consume special dividend, we're not anywhere near that at this point, obviously. We're still adding to net cash. And so we've got our foot on the accelerator with respect to both specials and regular. But our goal is to grow the regular meaningfully over time. We think that will add to share value. As it relates to an incremental, call it large dividend in the fourth quarter, anticipating change in tax policy, that really isn't our strategy. We're looking at something steadier and more visible to shareholders through time, as we think it will drive share value.

Great. And then my second question is look, I know seasonally your markets do tighten and other than UNEV's impact for Salt Lake, which we'll see for a full season this year, are there other changes year-on-year that may allow you to move more projects out of your markets and less at any seasonal effect? Or are there any new project potentials, may be you could be able -- half that you can discuss for product evacuation?

Well, Evan, we -- most of our pinch point comes in the Mid-Con typically in the winter season. And the -- this year, probably is going to be a little different just because of the level of turnarounds we have, personally, or within the HollyFrontier fleet. But there are other turnarounds occurring at the same time, so I don't see near the pinch. We have been working on outlets for an RFG market in Chicago, which we do have the ability to do if we need to. That is constrained a little bit by refining tankage, but we do have that option if we need it.

That's great. If I could slip in just kind of one last one on Tulsa. I mean any updates there on your permitting efforts to collide or run closer to your 140 capacity versus your 125 permitted?

No real update other than we're working on it. We probably don't anticipate it until some time in '14.

Your next question comes from the line of Chi Chow with Macquarie.

Just to clarify on hydrotreater, Dave. Did you say 2014 is the restart date?

Oh no. The distillate hydrotreater, it took us about 60 days to repair it. It's up and running. This is for the crude expected -- to realize 160 total crude rate at Tulsa.

I got it. So the repairs on the hydrotreater are done and you're producing the oil [indiscernible], right?

Yes, they're completely done.

Got it. I guess second question on UNEV. What sort of volumes are you flowing on the pipe right now? And do you believe that's had an impact on tightening that Rocky supply demand balance on products?

Chi, we're still flowing product volumes that are reflective of a summer market, if you will, and near the minimums. The Salt Lake market remains pretty tight with respect to product and then thus, you see the crack spreads that are out there right now. We expect some seasonality and UNEV is obviously a great outlet when that happens, but we haven't seen it yet.

And some of that, Chi, were in turnaround. So I mean the market’s kind of snug.

Yes.

Right. But you believe that the Vegas market is there if needed, is that correct?

Yes.

Okay, great. And final question just on the Midland-Cushing disk, which is really widening out again here. How sustainable do you think that is? And what's your outlook on that Midland spread into next year?

It's going to be a roller coaster ride, Chi. You got a lot of logistics coming on screen. Obviously, a large plant in the Panhandle had a big turnaround in that extended long, which is a big driver of current pressure on Midland prices. I think the answer is that West Texas is still a very long way from incremental refining markets on a Gulf Coast, and you'll see some of that variability despite new logistics capacity coming on to relieve some of it.

Your next question comes from the line of Doug Leggate with Bank of America.

It's actually Jason Smith, on for Doug. I just wanted to know if you could give, potentially, the opportunity cost for the downtime at Tulsa?

Well net of insurance, we're estimating it to be around $50 million.

In the third quarter, not the fourth quarter.

Yes, that's on a pretax basis.

Got you. Okay. And just, Dave, I missed in your remarks, how much Christina Lake did you guys run into third quarter?

About 1,600 barrels -- excuse me 6,700 a day.

And we should expect that kind of run rate in 4Q?

Yes.

And given the move we've seen in Western Canadian dips, I mean has Christina Lake kind of moved the same and still treating at the same level?

It narrowed some. We expect it to widen out a bit more as WCS has widened up.

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

I guess maybe to follow up a little bit on the question on the differentials and your opening comments about expecting the differential above pipeline transportation to remain in place for quite a while. What are you seeing that specifically gives you that level of comfort here?

Production growth in the Permian and the Bakken, the Mississippian, or Mississippi Lime. Generally, the producers have been very effective in growing production. And incremental pipeline capacity is slow to follow. You take an example project as Magellan's Longhorn conversion out of West Texas. It will drain a significant volume accrued out of the Permian. But Permian is growing at 150,000 barrels per day per year, so that fills that pipe in, effectively, a year's growth. I guess that's our point. We also see the investment going into rail and the amount of crude moving by rail, and we're drawing conclusions from that to say rail is going to be here for a while and the incremental cost of moving that crude by rail is substantially more than cost of putting it through the pipes.

Fair enough. I guess the other thing I had was -- and I guess following yesterday's election, expectation that permitting and emission CO2, et cetera, I mean everything that you'd had to permit before and then maybe some new things coming down the pipe, what do you think you can get done before expected rules changes? Or do you have to wait at this point? I mean you can't get permits through or there's too much uncertainty. Is your thinking about what some of the things you'd like to do, some of which you highlighted and then some have, obviously, which would be on a wish list, so to speak?

I think it's a little bit dependent on the state you're in. Some states have – everywhere has greenhouse gas permit requirements now. And we're -- we have several of those filed. We really haven't been held up by them, but there's 1 state in particular, like Wyoming, that has not been delegated by EPA to do a greenhouse gas. And we are diving into that quagmire of going to EPA to get 1 approved that we haven't done yet. So I already agreed here I don't think it's going to get easier, but I don't see it as a major impediment yet in the states we operate in.

Your next question comes from the line of Blake Fernandez with Howard Weil.

Mike, I had a question for you on MLPs. I'm sure you've figured this might be coming. But some of your smaller peers with inland refiners had seemed to have substantial free cash flow have been using that as a vehicle. Obviously you have several assets that fit that bill. I'm just curious if you had any thoughts there.

Well, we obviously watch carefully. And it looks like those MLPs are getting paid in the current environment good value for what they've put out in terms of securities. So we're interested. At the same time, there's not a lot of liquidity in those markets, and we're going to watch carefully, I guess, is the best that I can tell you. We don't have near-term plans on changing our strategy. Our fixed rate, or fixed tariff MLP trades at a substantially higher multiple than do the variable rates. And so our near-term strategy is to use that principally insofar as we have assets to put into an MLP structure. And that's been real productive for us in the past. If we find huge pockets of liquidity going forward for these variable-rate MLPs, we'll look carefully.

Okay, great. Second question, maybe I missed this, but throughput seemed to be well above guidance. Can you just talk where that discount came from?

I think our guidance for the second quarter was, let me get it here real quick, was about 410,000 barrels per day. We actually did 433,000. I think we were just thinking our crude unit was going to -- our reformer is going to take longer at El Dorado than it did, and we were able to run higher rates at Navajo.

And when we provided that guidance, we had just had a Tulsa fire. We weren't sure of the impact on that plant and so we were conservative. What transpired was we were able to run that plant at very high crude rates while disposing within our system, and commercially the high sulfur diesel. So 2 things: one, a tip of the hat to the folks and marketing that got that done; but second, and as importantly, the refining system that we now have as HollyFrontier really gave us additional alternatives to just simply due to the merger within other plants to dispose this high sulfur product and keep crude rates high.

Okay, fair enough. Then last one, if I could just ask one more. I know it may be premature, but you talked about some potential projects. Just thinking forward into CapEx for '13, should $350 million -- is that a good range? Or do you have any directional bias you could give us on that number?

I think for right now, Blake, we will see our Board here one more time before the end of the year, at which time we would look for an approval for our budget for next year. But right now, our estimate is $350 million is pretty good. That does include spending for the Phase 1 of the Woods Cross expansion. That does not include the $75 million or so million dollars that we may not get spent as part of the 2012 budget. As we have sort of indicated, we don't think we're going to quite make it to $350 million by the end of this year given a few unexpected events that we had occur.

Your next question comes from the line of Paul Cheng with Barclays.

A number of quick questions. I think I missed early, didn't you guys mention what is your fourth quarter total throughput estimate? I think that you gave a guidance on the crude, it's 424,000. Do you have a number therefore, the total, including EBITDA?

No, I don't have that, but it's typically 40,000 barrels higher. [indiscernible]

So no particular changes that the main research has based on the lateral run rate?

That's right.

And also, Doug, given you have quite a lot turnaround also in the fourth quarter, what type of operating cost we should be assuming? How that impact your operating cost is going to look like?

Well, throughput will be lower and spending typically isn't much changed. So they tend to go up.

But there are [indiscernible]

So do you think that the absolute costs would be roughly flat from the third quarter?

Yes. I'd estimate in that $200 million range, total.

Okay. Doug, can you -- will you be kind enough to give us, say the gasoline, diesel and new crack for the third quarter, so that we can use that as a comparison?

Sure. Let's see. Insurance, okay. Yes, okay. So on a WTI basis, Paul, Q3 cracks, Rockies gasoline $34; Rockies diesel $43; Southwest gasoline $30.61; Southwest diesel $38.97; Mid-Con gasoline $34; Mid-Con diesel $30; Mid-Con lubes $69.27.

And Doug, do you have the market lending of your inventory in excess of book? Also that do you have the Holly logistic, their working capital as well as that your own working capital?

I'm not sure we have the working capital numbers here with us, Paul, but J. Gann does have the market value in excess of book for our inventory. We'll have to follow up with our working capital numbers.

Yes. The market value in excess of book is $285 million, which gives a market value of $1,000,692,000.

$285 million, right, you say?

That's correct.

Okay. And Mike, earlier that you're talking about looking at opportunity to match between your crude unit to your conversion unit in Pan. Is that primarily just in the Mid-Continent system? Do you have other opportunity outside that?

Paul, we have a lack of conversant capacity in Cheyenne, Wyoming relative to crude capacity. And we also have, in the Mid-Continent, additional crude capacity that's currently not being used, not permitted, but crude capacity that could come up within a reasonable length of time given the permit timing that Dave indicated, 2014-ish. And that would require most likely some additional conversion capacity. But that rationalization of Mid-Continent operations around a higher crude rate is something that we're looking very carefully at.

But not in the Cheyenne?

Sorry. Yes, in Cheyenne as well.

Oh, also in Cheyenne. So when that you may -- which point that you would decide okay, the economy is justifiable for you to do? I mean that this whole process, what, it's going to take another year before that you feel you get the economic analysis pretty much done?

I think that's right. I mean first we have to come up with a hydrocarbon plant then an engineering estimate, and it takes some time. So I think within 1 year's time we will know whether we want to proceed with those projects or not. We speak of them publicly because they are opportunities within our system to get better and get bigger.

And Doug, do you have -- in the past when you guys were at Frontier, I think you gave what is the heavy oil discount you received in Cheyenne and El Dorado? That -- do you have those number now?

We don't do it by refinery anymore, Paul. We do it by region. I think Dave has what the crude discounts were for the quarter.

You're talking specifically Cheyenne or Rocky Mountain?

No, just Rocky Mountain.

I see it's pretty -- let's see Rocky, 1 second, about $1 discount to WTI on asphalt.

No, no, the heavy oil discount.

I'm sorry, in WCS...

That your actual realized discount comparing to WTI.

Paul, we gave you the $10.50, it was the third quarter discount. That's --

And do you have a number at what they may be looking like in October?

Well, I don't have that handy -- marginally better, where heavy crude is widened out.

So marginally better?

Yes, sure.

A final one, I think other people have asked about the regular dividend. I'm just trying to understand that when the Board looking at -- to determine how much that they want to increase the regular dividend and how frequently they increase, what kind of criteria they are looking at? I mean I think maybe we are warm but that based on your own estimate that you believe -- it seems like that the earning power for the company for extended period of time is going to be quite high. And so we've been looking at -- and we understand the desire for management to steadily raise the dividend. But the dividend current run rate of, say $0.60, seems like way too low comparing to your earnings power. And even if your raise it to a $2 per share, it looks like that you still have room for you to future grow your dividend payout. So is there any reason why can't the companies, they raise it up into, say, $2 right away, and then steadily rising afterward?

Paul, I have a number of answers for you. The first is that the yield on our stock is nearly 8% right now. We articulated almost 1.5 years ago a strategy of paying sustainable special dividends, and we have executed on that. I don't think the market is ignoring the special in looking at our yield. And we're certainly not ignoring the notion that we want it to be sustainable. So I think that, that is an important piece of looking at the stock and its potential return relative to the regular dividend. Our view is simple. We look 2 and 3 years forward at the earnings of our business, of cash flow, of likely internal capital spending, as many companies do, and try to figure out what portion of cash should be distributed to shareholders. We want a growing regular dividend stream, and we want things to be transparent to shareholders and predictable. So I think if your question is geared toward how about get rid of the special, call it all-regular, and get on with life? And that is not our strategy. We're trying to maintain the special dividend, because we've had it in place. We think it's valued by the shareholders. And at the same time, we're growing the regular alongside it. Regular payout is now $0.80 on an annual basis after this most recent $0.05 increase to $20 per quarter. So I understand if you see the world differently, but I think we're trying to maintain some consistency and do what we've said. So that's our goal. That's our goal.

Your next question comes from the line of Faisel Khan with Citigroup.

Citi. I believe that you said in your prepared remarks, or in the question that was answered earlier, that Woods Cross would be expanded to 60,000 barrels a day. The current expansion you're adding about 15,000. Could you elaborate a little bit more on getting to 60,000?

Yes. Our Phase 1 takes us to 45,000, roughly; 44,000, 45,000. And that's on a feedstock of pure black wax on the increment. We do have a Phase 2 that we're looking at, which involves a lube facility that basically takes the characteristics of that wax with an additional volume of wax and turn it into a Group III lubricant. With that comes a significant diesel yield as well as the Group III lubricant. That one is less defined and that does take the capacity of the plant to 60,000 when we do accomplish that. It is all in our existing -- the permit that we have under review right now and out for approval. But it's far less certain than the Phase 1 approach.

Okay, understood. And if you could just give me the number on the share repurchase program that still remains I think in your existing program? And what you guys bought back in the third quarter?

Sure. I'll do that. I'll tell you that the third quarter because we had seen did see a pretty healthy run-up, we didn't see much activity. We got back 13,600 shares at an average price of a little better than $39 a share. In the fourth quarter to date, we repurchased 424,231 shares, spent about $15.8 million repurchasing shares at an average price of $37.60. So for the year, we've repurchased 6,775,000, spent about $205,600,000, which means under our current authorizations, we have $494.4 million left.

Okay. And then the last question for me. Just if you could help me one more time, the Mid-Continent, you guys performed extremely well. Your margins sequentially looked like they went up by almost $5 a barrel, $450 a barrel. One more time, can you help me get from the second quarter to the third quarter? I think you talked about the WCS differentials and some of the Foster Creek, Christina Lake discount, but that seems to be that was partially offset by the diesel, distillate hydrotreater issue. If you could help me bridge the gap from the second and third quarter, that would be helpful.

I think bottom line, the cracks were just up so much more, second quarter to third quarter.

Okay. Because it seems like a lot more than in the Southwest and in the Rockies. And the Rockies and Southwest seem to be a lot less of a progression from Q2 to the Q3. But in the Mid-Con, you guys had a major shift in margins in 2Q to 3Q.

And we had higher rates too in the third quarter which is the second quarter because the El Dorado had several operating problems.

In the second quarter.

But remember, the Mid-Con went over the Gulf significantly on progress in the third quarter. So it was a step change.

And that was materially different than the Southwest and the Rockies?

Not so much the Rockies, but certainly the Southwest.

Your next question comes from the line of Edward Westlake with Credit Suisse.

I guess just a quick question. You -- obviously there is a lot of rail moving around crude. Some of the crude coming out of some of the place has advantaged characteristics for processing. Could you just sort of give us an update on where you are in terms of receiving any crude by rail, and any plans to increase that across the system?

We do not have the ability to unload by rail except for a railcar or 2 at selected facilities. We really have no plans to do that. We are looking at a couple of opportunities, but they're very much in the developmental phase right now.

Right. And then coming back then to the overall CapEx. It feels like 2014 could be a big year in terms of driving the next rates of growth across -- following on from Paul's question, and with the Woods Cross Phase 2 and Phase 1. Would that be fair?

Yes, I think so. And we have some other projects in Q2 that are under development, as Mike mentioned, that we think have potential too. And so I think we're headed into a pretty heavy CapEx period.

Really apart from the Phase 1 expansion, a lot of these projects are being studied right now. But we're trying to look at the most obvious and efficient projects to take advantage of the capacity and accrued opportunities that we have. So in terms of the cash cycle, you've got it properly identified that '14 and '15 are probably steps up if we go forward with these projects.

Yes, and I presume most people will be happy given the types of paybacks and returns. But do you know roughly when you'll be able to communicate in a bit more detail around that sort of the projects and the CapEx ramp?

We'll have next years budget laid out by February of next year. So I mean at that point, the Board will review it. We'll have a better handle on it. But most of our focus is around feedstock flexibility, gas to liquids, how do we swirl a barrel and low-hanging fruit such as Creek on many of our process units.

Ladies and gentlemen, this concludes today's question-and-answer. I would now turn the floor back over to Julia for any closing remarks.

Hi, everyone. Thank you very much for participating, and I guess we'll talk to you in February with our full year results. Thank you very much.

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