HollyFrontier Corp HFC
Q4 2012 Earnings Call Transcript
Transcript Call Date 02/26/2013

Operator: Welcome to HollyFrontier Corporation's Fourth 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. At this time, all participants have been placed in a listen-only mode and the floor will be opened for your questions following the presentation. Please note that this conference is being recorded.

It is now my pleasure to turn the floor over to Julia Heidenreich. Julia, you may begin.

Julia Heidenreich - VP, IR: Thank you, Jackie. Good morning, everyone, and welcome to HollyFrontier Corporation's fourth quarter earnings call. I am Julia Heidenreich, Vice President of Investor Relations. In addition to Mike, Dave and Doug, we also have other members from our management team to assist in the Q&A portion of the call.

This morning, we issued a press release announcing results for the quarter ending December 31, 2012. If you would like a copy of today's release, you can find one on our website www.hollyfrontier.com.

Before Mike, Dave and Doug proceed with their prepared remarks, please 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 results to differ from expectations including those noted in our SEC filings. Today's statements are not guarantees of future outcomes.

Today's call may also include discussion of non-GAAP measures. Please see today's press release for reconciliations to GAAP financials. Also please note that information presented on today's call speaks only as of today, February 26. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or re-reading of the transcript.

With that, I will turn the call over to Mike Jennings.

Michael C. Jennings - Chairman, CEO and President: Thank you, Julia. Good morning. Thanks for joining us on HollyFrontier's fourth quarter earnings call. Today I'm pleased to announce record full year results for HollyFrontier. Full year 2012 net income attributable to HFC shareholders was $1.7 billion, or $8.38 per diluted share, a 69% improvement over the $1 billion or $6.42 per share posted for the full year 2011.

Fourth quarter net income attributable to HFC shareholders was $392 million, or $1.92 per diluted share, a 68% improvement over the $233 million or $1.06 per share reported for the fourth quarter of 2011. We generated a record $3.1 billion of EBITDA in 2012, more than 1.5 times our 2011 EBITDA of $1.8 billion. Fourth quarter EBITDA of $730 million was more than a 75% improvement on fourth quarter 2011 EBITDA of $414 million.

Rather than contracting towards year-end, as many of suspected, the inland coastal crude differential widened with Brent TI averaging over $20 for the quarter. This contributed to gross margin levels well above our historical fourth quarter average. During the quarter, our consolidated refining gross margins were $24 per produced barrel, 57% above the $15.32 of gross margin we recorded in fourth quarter of 2011 and more than 200% above the fourth quarter 2010 gross margin per barrel of $8.79.

Looking into the first quarter of 2013, we're seeing the strength continue, with margins far stronger than historically realized at this time of the year. Last week, the Bloomberg Mid-Con 321 crack was $38, well above the Q1 levels seen from 2007 to 2012 which ranged from $7 to $24.

Our February WTI-base gasoline diesel cracks have rebounded strongly from the seasonal low levels observed from mid-December through January. Our February realized WTI-based gasoline cracks are averaging around $20 across all regions and diesel cracks again relative to TI and for the month of February are nearly $40 across our markets. These structurally higher crack spreads are a function of strong crude differentials and improving global refined product margins, which are combining to drive our expectation of higher downstream margins and earnings for the foreseeable future.

HollyFrontier's fourth quarter performance, while strong relative to the fourth quarter of 2011 was impacted by some significant one-time items, including lower than expected crude throughput related to extended maintenance activities as well as higher OpEx. Dave and Doug will provide additional detail on these items.

Through 2012, we executed our strategy of returning a significant portion of our cash earnings to shareholders, with dividends totaling $3.10 per share through the 12 months or about 39% of our net income. Through the year, we doubled our regular dividend from $0.10 to $0.20 per share per quarter and issued five $0.50 specials. Looking forward in the current year, we plan to continue our use of both regular and special dividend payments to shareholders. Last week, our Board authorized another strong step forward with our regular dividend, hiking this quarterly payment 50% to $0.30 per share from the previous $0.20 per share. At the same time, we declared our eighth $0.50 special dividend since our July 2011 merger. As of today, our trailing 12-month cash dividend yield stands at 5.7% relative to yesterday's closing price of $54.60.

In addition to our cash return strategy, we continue investing in our core refining business, with focus on serving niche product markets and realizing more from our crude supply advantages. Several high return investment opportunities are underway or in the planning process, which include, our Woods Cross expansion plan centered on processing black wax, additional discounted niche crude processing, such as high TAN crudes, increasing the use of nat gas as a source of hydrogen and accompanying improvements in refining liquid yields, and optimizing our Mid-Continent refining system, including more access to further product markets.

We expect the tremendous growth in North American crude production to continue and in the process to contribute to strong operating margins and free cash generation at HollyFrontier. As this process evolves, we will become more bullish about likely forward differentials for two reasons. First, rail is becoming a go-to form of transportation to move many of these barrels to market; and second, the producers are achieving unanticipated success with both initial production rates and ultimate recovery estimates from individual wells in many different unconventional plays. These wells and their economics are driving higher upstream returns despite relatively high transportation costs from inland production basins to coastal crude markets, and the liquids targeted rig count appears poised for continued growth.

With all that said, in the process of bringing these barrels to market, including startup of new logistics systems, will likely include volatility and realize crude differentials. Sometimes in our favor, other times not.

Our particular strategy involves making efficient local market in terms of both logistics and refining capability for crude produced in our backyard. In this way we expect to realize as crude differentials, the marginal logistics costs associated with shipping crude barrels to coastal markets on a combination of truck rail and pipe.

So, with that, let me turn it over to Dave Lamp, our Chief Operating Officer, for a review of our fourth quarter operations.

David L. Lamp - EVP and COO: Thanks Mike. Throughput for the fourth quarter was below plan at 408,000 barrels per day of crude, versus guidance of 424,000 and 458,000 barrels a day of total charge. Crude slate was 18% disadvantage crudes. Remind you that's mainly WCS, Christina Lake and Black Wax type crudes and 21% sour.

During the quarter, light, heavy and sweet sour spreads widened versus WTI. The average laid in crude costs for our system was $3.92 a barrel under WTI. Brent versus WTI differential was $21.90 for the quarter. Just some other crude differentials here; WCS was about $18.11 under WTI. WTS was $5.12 under WTI. Black Wax was $19.28 under WTI and (indiscernible) was approximately $6.85 under WTI.

Total refinery operating costs were higher for the quarter at $269 million, as a result of increased environmental accruals and the write-off of the Cheyenne gasoline hydrotreater engineering.

Throughputs for the fourth quarter in the Rockies region were 71,000 barrels a day of crude and 79,000 barrels a day of total charge. Disadvantaged crudes were approximately 40% of the slate, and 1% sour. The average laid-in cost of crude for the Rockies region was (806) under WTI.

Refining and operating costs were approximately $8.92 a barrel. We completed an FCC alky reformer and naphtha hydrotreater turnaround as well as tied in our new MSAT II benzene reduction unit at our Woods Cross Refinery during the quarter.

Throughput for the fourth quarter for the Mid-Continent region were 237,000 barrels a day of crude and 268,000 barrels of total charge. Disadvantaged crudes were approximately 13% of the slate and 6% sour.

Additionally, we ran about 11,000 barrels a day of Christina Lake which is a high asset crude that sells at $7 discount at WCS during the quarter. The average laid-in cost for the Mid-Con region was $2.45 a barrel under WTI.

Refinery operating costs were approximately $5.12 per barrel. The Tulsa West Refinery completed a planned turnaround in the quarter, but was extended three weeks over-plan to a major equipment reliability issue. This was our first full turnaround at the West Refinery at Tulsa since the acquisition. Discovery work was what we would consider extreme. We also completed the start-up of our new coker furnace at the El Dorado Refinery in the quarter.

We also incurred, probably due to this turnaround, about $40 million impact in earnings, and that included the El Dorado outage on the coker furnace, but also lost opportunity due to Tulsa Refinery.

Throughput for the fourth quarter in the Southwest region was 100,000 barrels per day of crude and 111,000 of total charge. Disadvantaged crudes were approximately 15% of the slate and 72% sour. Average laid-in cost for the Southwest region was a $4.47 a barrel under WTI. The operating costs were approximately $7.48. The high operating costs were due to an increased environment accrual in the fourth quarter.

For the first quarter of 2013 we expect to run between 390,000 and 380,000 barrels of crude with 20% of the slate being disadvantaged crudes and 21% sour. Our Cheyenne coker had an unscheduled outage in January to a freeze up issue which significantly affected our total crude runs, specifically our WCS runs. We have several turnaround scheduled for the first quarter and full year 2013. In February, we completed our work at Navajo on the Lovington crude unit, FCC and alky units. On restart we had a failure of the main air blower which required additional week of downtime to repair. We have a planned turnaround at our El Dorado refinery on the crude, cocker and build fire units starting in the third week or March. We shifted our Tulsa East full plant turnaround to May from March. The Tulsa turnaround will include work on our crude unit reform, our naphtha hydrotreater and PEMEX units.

We also planned turnaround our Cheyenne crude unit, reformer, distillate hydrotreater and naphtha hydrotreaters units in the fourth quarter of this year. HollyFrontier has had an unusually high number of large turnarounds across this refinery fleet in the fourth quarter and first quarter. This is a one-time issue and is mainly the result of the merger of Holly and Frontier. In the future, we plan to tie in major turnarounds because it smooth out earnings effects. Our permit on the Woods Cross black wax expansion completed its public comment period and is awaiting final approval by agencies. Engineering and procurement activities are continuing and we expect mechanical completion of Phase 1 in later fourth quarter of 2014.

With that, I'll turn it over to Doug for some closing remarks.

Doug S. Aron - EVP and CFO: Thanks, Dave. For the fourth quarter, cash flow provided by operations totaled $491 million. Full year 2012 cash flow provided by operations was $1.67 billion. Fourth quarter capital expenditures totaled $112 million which excludes HEP's $15.6 million. This takes our full year capital expenditure to $290 million, excluding HEP's $45 million.

As mentioned on our last call, the unspent balance versus our $350 million guidance will carry over into the current quarter, taking our expected 2013 capital expenditures to approximately $400 million to $450 million, and a $150 million to be spent on turnarounds and tank maintenance which includes catalyst costs.

As of December 31, 2012, our total cash balance, including marketable securities, totaled $2.4 billion versus $2.3 billion at the end of the third quarter. Remaining HollyFrontier debt totaled $472 million at year-end 2012, which excludes the nonrecourse HEP debt of $865 million.

In the fourth quarter, we distributed $275 million in dividends to shareholders and repurchased approximately 424,000 shares at an average price of $37.60, leaving 494 million of our repurchased authorization remaining. Since our July 2011 merger, HollyFrontier has returned $1.3 billion in capital to shareholders through regular dividends, special dividends, and share repurchases, $867 million of which was returned in 2012.

I'd like to mention a few items that were unusual items in the quarter and occurred in the fourth quarter of 2012. We incurred charges totaling $23.3 million or $0.12 per share after tax as a result of increased long term environmental accruals a partial termination of the company's defined benefit retirement plan and we wrote off a previously capitalized project in Cheyenne as Dave mentioned earlier. As it relates to the defined benefit termination we expect to record expenses totaling approximately $37 million pretax in 2013 as we complete the termination of that plant.

We also recorded a hedging loss in the fourth quarter of approximately $26.6 million after-tax or $0.13 per share most of which was related to hedging of Western Canadian select crude oil differentials.

Finally in the quarter we increased our provision for uncertain tax provisions, or positions rather by $7.3 million or approximately $0.04 per share.

Lastly I would like to update you on our quarter-to-date crack spreads. These are all based on West Texas intermediate not unnecessarily the advantaged crude oils that we run in our refineries.

Starting in the Rockies region the gasoline crack spread averaged $3 below WTI or $3 negative for the month of January and the distillate crack spread averaged $25 per barrel. Moving to the Mid-Continent the gasoline crack spread averaged $11 for January and the diesel crack spread averaged $33.

Also in the Mid-Continent Tulsa we make lubricants where the average crack spread in January was $69 per barrel.

In the Southwest region the gasoline crack spread averaged $14 for January and diesel averaged $34 per barrel.

For February month-to-date at least as of the end of last week the gasoline crack spread averaged $21 per barrel in the Rockies region and $41 per barrel for diesel again in the Rockies this is for February moving to the Mid-Continent in February the gasoline crack spreads averaged about $22 per barrel where the diesel crack spread's about $39 a barrel and the lubes crack spread at $65 a barrel for February.

Finally in the Southwest region the gasoline crack spread averaged $28 per barrel in February and the diesel crack spread about $42 per barrel for February.

With that Jackie I believe we are ready to take questions.

Transcript Call Date 02/26/2013

Operator: Jeff Dietert, Simmons and Company.

Jeff Dietert - Simmons and Company: Thanks for the detail, especially from Dave. I am going to have to dig through the transcript and make sure I got everything. But could you talk about the Navajo downtime in January and just the opportunity cost associated with that outage?

David L. Lamp - EVP and COO: Well, cracks are very good Jeff as you know in the Navajo system. But the additional week we are taking it's probably about $20 million impact in the first quarter. That's over plan.

Jeff Dietert - Simmons and Company: Second question with regard to the UNEV line it looks like your Rockies gasoline cracks were really low in January, but that's rebounded strongly in February. Is the UNEV line providing some benefit there for Woods Cross are you expecting most of that to accrue with the expansions?

David L. Lamp - EVP and COO: Jeff the UNEV line has provided substantial relief on the western side of the divide. It was really the eastern side of the divide that caused the most trouble during the month of January as the Denver market was heavily discounted and in fact trucking barrels to the Mid-Con supported that much logistics cost. So, January was tough on the eastern side of the divide; UNEV was really pretty good. The throughput rates through UNEV were in the high 20s – I have that right, Dave?

David L. Lamp - EVP and COO: Yes.

Michael C. Jennings - Chairman, CEO and President: With most of those delivering going down to Salt Lake.

Doug S. Aron - EVP and CFO: But I guess, Jeff, further to the point, that once the margins have rebounded in February, we are not shipping quite as much in UNEV, and yes, we'll see more benefit of that line post expansion.

Operator: Chi Chow, Macquarie.

Chi Chow - Macquarie: Doug, on hedging, you mentioned that most of the hedging loss in the first quarter was due to WCS. What sort of positions do you have going forward here on your heavy Canadian hedging as well as your crack spread hedging…?

Doug S. Aron - EVP and CFO: Okay, sure. Chi, first on the WCS piece, most of the hedging actually had been done for 2013 as we had bought forward or rather sold forward, and at the end of the year, because we don't get accounting hedging treatment for those, what we saw was a big mark-to-market as WCS blew out in December and we really didn't get the benefit of that as most of that crude hasn't yet come to us. So, we've seen that come back. WCS traded as wide as $39 or so and now it's back in the sort of $25 under WTI range. What I would tell you is we've hedged about 45,000 barrels a day for 2013. That includes both physical deals as well as paper deals, Chi. Those deals were done in an average range of about $23.25 per barrel, which is pretty close to where the market is. So, you'd expect to see some of that flow back through in terms of mark-to-market in the first quarter positively. We're comfortable with that position and happy at that price. Reminder, we're running about 80,000 a day in total of Canadian heavy. So we've got a little more than half of that hedged.

Chi Chow - Macquarie: And any updates on the crack spread?

Doug S. Aron - EVP and CFO: There aren't. We'd have the same numbers as roughly where we were at the end of the fourth quarter or rather at the end of the third quarter when we communicated with you. So, I'd tell you there is really no material change to the crack spread hedging.

Chi Chow - Macquarie: I guess second question is back on operating expenses. Do you a breakout of the items you mentioned on the environmental accrual and the project write-down by region? And also, it sounds like you still got some downtime going on (indiscernible) first quarter, would you expect the same sort of trends on higher OpEx that you saw in fourth quarter to kind of carry forward here in 1Q?

David L. Lamp - EVP and COO: We had the one-time environmental accruals. We don't expect those to repeat. The write-off of the Cheyenne engineering on a gasoline hydrotreater; we don't expect to repeat. And then I think we had some pension true-ups too that we don't expect to repeat. So, that's the majority of it, Chi.

Doug S. Aron - EVP and CFO: The environmental piece largely in Artesia, so Southwest region. The Cheyenne, cal gas hydrotreater that Dave mentioned was with Rockies, that was $7 million or so pre-tax of the amount we provided.

David L. Lamp - EVP and COO: Mid-Con had a little.

Michael C. Jennings - Chairman, CEO and President: Yeah, the pension is largely SG&A as well as Southwest restoration. And we'll take more of that through the course of this year with timing uncertain. But as we complete the termination of that plant, which is materially funded, it's really an accounting issues transferring from other comprehensive income through expense on the P&L.

Chi Chow - Macquarie: Do you have a total dollar amount, Mike on that (indiscernible)?

Michael C. Jennings - Chairman, CEO and President: Mid-30s.

Doug S. Aron - EVP and CFO: Yeah, we have said $37 million is the expected P&L impact achieved likely in the second quarter if we had to guess and the unfunded portion of that is – in terms of additional cash is about $17 million, which I believe against really the rest of the peer group puts us in very favorable position to be able to terminate that plan.

Michael C. Jennings - Chairman, CEO and President: Effectively we are out of the defined benefit pension business upon this termination which we consider to be an important goal.

Operator: Paul Cheng, Barclays.

Paul Cheng - Barclays Capital: On hedging, what is your current strategy on overall longer-term basis? I mean, given the bounce is much stronger and the Company is much bigger than when you were Frontier or Holly individually? So, does it even makes sense that for you to say spend management time and efforts to do any hedging going forward?

Michael C. Jennings - Chairman, CEO and President: Paul, what I can tell you is, we don't particularly like the noise in the P&L that results from it. I think that the hedging that probably does make some sense for us procurement based. That being crude differentials on longer term basis, it gets us into a mode in making investments in terms of processing the heavy barrel and providing for those logistics where we know we've got 12 months or 24 months of in the money WCS runs and for that reason in the mid-20s we find that barrel to be very attractive now except that it blew out during late December and January. But those differentials are right back towards where they started from which was mid-20s prior to that. So on the crude barrels we think that it probably does make some sense there may be some opportunity as well in nat gas relative to its value in hydrogen and through liquid yield in the refinery. Apart from that I would tell you hedging doesn't occupy a great deal of management time or focus because it's just not that material to operations.

Paul Cheng - Barclays Capital: This is for Doug. The defense for the WTI mid though starting in mid-November and same as WCS can you maybe share with us that how much of the benefit that for WCS and fourth quarter that you have seen over that and in both cases that the benefit is going to show up in the first quarter?

Doug S. Aron - EVP and CFO: Paul we haven't seen particularly for Navajo and El Dorado most of that Western Canadian select blow out won't show up until January because there is about 60 day lag. Additionally we had as I mentioned a big mark-to-market hedging loss that will be reversed in the first quarter. So, you would expect to see first quarter WCS realized margins and hedging gains sort of reversed a lot of what occurred at Q4.

Paul Cheng - Barclays Capital: How about the WTI Midland on our Southwest system.

Michael C. Jennings - Chairman, CEO and President: It's about a 30 day delay there. so, it started coming in the December but you really see it in January and February.

David L. Lamp - EVP and COO: The challenge with that, Paul, is the as much as we would be a beneficiary of it, we were sort of a cause of it with our Navajo turnaround and so we won't realize a tremendous amount that benefit because the Lovington crude unit at 60 day or 65 day was down through a lot of that period. So, I wouldn't anticipate large economics in the first quarter from the Midland widened differentials in December, January.

Operator: Evan Calio, Morgan Stanley.

Evan Calio - Morgan Stanley: Sorry if I miss some of your opening comments but could you or did you give any color on the OpEx at Navajo is up from 5.14 to 7.48 in the quarter and any color there on unit cost would be helpful?

David L. Lamp - EVP and COO: Evan, that's mostly as we mentioned is the effect of the environmental accrual that was increased for remediation of known environmental events that was increased in the fourth quarter.

Doug S. Aron - EVP and CFO: So one time certainly on – we would expect one time on that incremental environmental accrual, I mean you wouldn't expect to see that high OpEx going forward.

Evan Calio - Morgan Stanley: Secondly on dividends and it's kind of always asked, but I mean you guys continue to lead the sector on yield, increase your regular dividend materially again. How do you think about or do you expect to shift that regular dividend into or special dividend into more of a regular dividend in 2013? I know it's a change in nomenclature around these distributions, but nonetheless important.

Michael C. Jennings - Chairman, CEO and President: Yeah, Evan, we continue to march the regular dividend up. Recognize it started at about $0.10 this time last year; it's now at $0.30. It has not yet encroached on the special dividend. At some point as we take it up, it may do so, of course, but what we've said is that we want to continue to increase that regular dividend. We've got a lot of confidence in forward crude differentials. We obviously have a very strong and liquid balance sheet and we consider ourselves to be a significant yield play and that we've got a big free cash flow yield and we intend to pay a lot of that out to our shareholders.

Evan Calio - Morgan Stanley: Maybe last question if I could. Just if there was any update on the Phase II expansion Woods Cross, any progress or updated timing on a new CSA there, and I'll leave it at that?

David L. Lamp - EVP and COO: As far as Phase II goes, Evan, we are in the design phase; Schedule A development of that. That will take approximately all of '13 to complete. At that point we hope to either secure additional black wax for that deal or make a decision on whether we go forward?

Operator: Roger Read, Wells Fargo.

Roger Read - Wells Fargo: I guess kind of following up on Evan's question there about share repos, regular versus special – excuse me; dividend, regular versus special and then share repurchases how that fits in, what are some of the – and also your view that the differentials are going to be wider for longer. How does that fit in as you are maybe designing a longer term view of what's the right way to go forward with returning capital to shareholders.

Michael C. Jennings - Chairman, CEO and President: Well, in a way, the government did us a favor and relative to putting dividend taxation right on top of cap gains and our dividend policy to us feels an efficient way to return capital to shareholders. But we will be purchasing our own stock in parallel, certainly to offset the dilution from our equity compensation plans and opportunistically as we value, but the principal tool for returning cash to shareholders for our strategy is through dividends and we see these dividends as sustainable through a period of time. So, that's what we are going to try to do and capitalize on some of this free cash we are generating to push it out shareholders.

Roger Read - Wells Fargo: And then the other thing just maybe more broad operating cost question, as you look at natural gas, that's obviously elevated somewhat with the winter time here, but it looks like just at the futures curve, compared to 2012 it's going to be I don't know $0.50, $0.60 higher. Can you kind of walk us through the impact of natural gas on your cost structure and then maybe how that fits into your comments in the beginning about more nature gas and the hydrocrackers and that sort of thing.

David L. Lamp - EVP and COO: Sure. Natural gas is a charge for us and then operating expense and not only do we use it to produce hydrogen on purpose but as well as provides incremental utility. Our sensitivity to that is I think about – million that's EBITDA per dollar increase in nat gas price. So, you can see sort of the impact to us of $0.70 as probably in $27 million, $25 million range.

Michael C. Jennings - Chairman, CEO and President: It still stands to bear that the investment in additional hydrogen and additional liquid yield for this plants through nat gas is a very quick payback type project just due to the depressed prices of gas relative to liquids and we see that trend is continuing because the unconventional resource out there. And with gas being clearly economic in lot of these basins at four bucks, that works very well inside our refineries.

Roger Read - Wells Fargo: Absolutely, I was just wanted to understand, these things are moving around, what some of the impacts were?

Michael C. Jennings - Chairman, CEO and President: Yes.

Operator: Clay Rynd, Tudor Pickering Holt.

Clay Rynd - Tudor Pickering Holt: Quick question you mentioned rail in your opening statements. I wanted to make sure you guys aren't currently using any rail for your system are you?

Michael C. Jennings - Chairman, CEO and President: Well, we use lot of rail but more on the product and intermediate side than the crude side. The rail opportunity for us relative to crude really would be drive bitumen from Canada. And those differentials that probably make sense anticipating uncertainty around XL pipeline or other such pipelines that might be a good artery for us otherwise probably not.

Clay Rynd - Tudor Pickering Holt: I guess that was my follow-up, do you have anything kind of current that there is going pulling anything the ECS or is it all kind of just thinking about right now.

Michael C. Jennings - Chairman, CEO and President: I'd put it in the latter category.

Operator: Edward Westlake, Credit Suisse.

Edward Westlake - Credit Suisse: I guess one of the impacts we have been seeing for a while is discounts on sort of gasoline in particular in the winter in the Rocky Mountains in the Mid-Con region, and even, I think, perhaps discounts against the posted prices that we're getting off plants. Any changes in terms of how we should think about that going forward or if that's just going to be a feature from here given the strong incentives from crude?

Michael C. Jennings - Chairman, CEO and President: I'd see that as a feature going forward apart from additional investment in logistics just to clear some of those markets, UNEV being an example. But the Rockies, certainly the eastern side of the Rockies, for many years has been characterized as a roach motel in December and January; easier to get into, hard to get out of, with respect to gasoline. So, that hasn't changed. We now just have a much stronger incentive to run crude due to the regional crude discounts, thus you see the truck barrels run to the Mid-Con this January, and then Mid-Con barrels pushing south in the new Magellan extension. So, I think products will start to flow from north to south as crude has been.

Clay Rynd - Tudor Pickering Holt: The sort of the severity that we'd expect this year is probably a fair reflection or any other funnies that you see? I know sometimes that inventory movements on some of those systems that can close bottlenecks.

Michael C. Jennings - Chairman, CEO and President: I think it's a fair reflection. We've seen tough Decembers and Januaries in the Rockies in the past and the discounts this year were those necessary to clear the market obviously, but tough margins during the month of January.

Clay Rynd - Tudor Pickering Holt: Then in terms of just any debottlenecking projects and any updates there on thoughts outside of obviously the great projects that you've got for the black wax?

Michael C. Jennings - Chairman, CEO and President: The debottleneck work that we're looking at right now really relates to the Mid-Con refining complex and how to run more crude and convert all that to products, and so a lot of that is in the planning phase. We were also looking a bit more in the Rockies in terms of gas oil conversion, but really don't have any projects ready to announce.

Operator: Doug Leggate, Bank of America Merrill Lynch.

Jason Smith - Bank of America Merrill Lynch: It's actually (Jason Smith) on for Doug. Most of my questions have been answered, but just for Doug maybe, just a quick one. The D&A rate seems to have stepped up quite a bit in the last two quarters, any reason behind that and what should we think of as a run rate going forward?

Doug S. Aron - EVP and CFO: Well, the G&A step-up would have been in third – oh, D&A, okay. Well…

David L. Lamp - EVP and COO: I think we're capturing the effects of amortization expense from the new turnarounds and that's probably the most of it. We probably won't beat run rate on that until end of this year.

Doug S. Aron - EVP and CFO: (60) to (65), I guess a quarter is probably a pretty good run rate going forward.

Operator: Chi Chow, Macquarie.

Chi Chow - Macquarie: Mike, I just got a follow-up on your comments regarding the – sort of backyard crude. We can see what's going on with volume, pricing, (indiscernible) at WCS, but what we can't really see is what's going on in the Niobrara or Mississippian. Can you give us just some comments on what you're seeing on production levels in those basins? Are you taking advantage of those crudes, what sort of pricing dynamics are you seeing, so just any sort of general comments on it?

Doug S. Aron - EVP and CFO: The Niobrara is not that relevant for us yet. Interestingly enough, a lot of those barrels are committed to White Cliffs and shipping towards Cushing. There are also refineries in the Rockies that are more geared towards the more heavy suites than we are in Cheyenne because of their soft recovery capacity up in Cheyenne. So, as yet not that relevant. But if you listen in on Nobel and Anadarko and others, I think that's going to be an opportunity for us here within next six months to a year and that the differentials are widen and caused that to be competitive with North Dakota light at Guernsey, which for our refinery it's not yet. So, in terms of the niche crude effects and the backyard effects, I think that that's today mostly in Woods Cross and Navajo and prospectively to include the Mid-Con and also Cheyenne. Obviously we've got (U crude) in Woods Cross as well, but it is nicely discounted relative to WTI on most days.

Operator: That was our final question. Now, I'd like to turn the floor back over to Julia for any closing remarks.

Julia Heidenreich - VP, IR: Thank you everyone for joining us today. If you have any follow-up question, we'll be in the office this afternoon and otherwise, we look forward to sharing our first quarter results with you in early May.

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