HF Sinclair Corporation (DINO) Q4 2012 Earnings Report, Transcript and Summary

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. [Operator Instructions] 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.

Thank you, Jackie. Good morning, everyone, and welcome to HollyFrontier Corporation's Fourth Quarter Earnings Call. I'm 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'd 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 cause results to differ from expectations, including those noted in our SEC filings. Today's statements are not guarantees of future outcome. Today's call may also include discussion of non-GAAP financial measures. Please see today's press release for reconciliations to GAAP financial measures. Also, please note the 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 rereading of the transcript. And with that, I'll turn the call over to Mike Jennings.

Great. 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 we reported for the fourth quarter of 2011. We generated a record $3.1 billion of EBITDA in 2012, more than 1.5x 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 us expected, 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 this strength continue, with margins far stronger than historically realized at this time of the year. Lastly, the Bloomberg Mid-Con 321 crack was $38, well above the Q1 levels seen from 2007 to 2012 which range from $7 to $24. Our February WTI-based gasoline and diesel cracks have rebounded strongly from the seasonal low levels observed from about 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 was strong relative to the fourth quarter of 2011 was impacted by some significant onetime 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've doubled our regular dividend from $0.10 to $0.20 per share per quarter and issued 5 $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, contribute to strong operating margins and free cash generation at HollyFrontier. As this process evolves, we've become more bullish about likely forward differentials for 2 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, the process of bringing these barrels to market, including startup of new logistic systems, will likely include volatility in realized crude differentials; sometimes in our favor, other times not. Our particular strategy involves making an 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.

Thanks, Mike. Throughput for the fourth quarter was below plan at 408,000 barrels a day of crude versus guidance of 424,000 and 458,000 barrels a day of total charge. Crude slate was 18% disadvantaged crudes. I'll 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 cost for our system was $3.92 a barrel under WTI. Brent versus WTI differential was $21.90 for the quarter. And 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 U crude 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 $8.06 under WTI. Refining 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 2 benzene reduction unit at our Woods Cross Refinery during the quarter. Throughputs 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's sells at a $7 discount to 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 plant turnaround in the quarter, but was extended 3 weeks over plan due 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 startup of our new coker furnace at the El Dorado refinery in the quarter. We also incurred, probably due to this turnaround, about a $40 million impact in earnings, and that included the El Dorado outage on the coker furnace but also, a lost opportunity due to Tulsa Refinery. Throughput for the fourth quarter in the Southwest region was 100,000 barrels per day of crude and a 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 $4.47 a barrel under WTI, and the operating costs were approximately $7.48. The high operating costs were due to an increased environmental accrual in the fourth quarter. For the fourth -- 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 due to a freeze-up issue, which significantly affected our total crude runs, specifically our WCS runs. We have several turnarounds scheduled for the first quarter and full year of 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 an additional week of downtime to repair. We have a planned turnaround at our El Dorado refinery on the crude, coker and coke-fire [ph] units starting the third week of March. We shifted our Tulsa East fault [ph] plant turnaround to May for March. Our Tulsa turnaround will include work on our crude unit reformer and naphtha hydrotreaters and Panex units. We also plan to 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 onetime issue and is mainly the result of the merger of Holly and Frontier. In the future, we plan to time major turnarounds to better smooth out our earnings effects. Our permit on the Woods Cross black wax expansion completed its public comment period and is awaiting final period -- final approval by the agencies. Engineering procurement activities are continuing, and we're expecting Mechanical Completion of Phase 1 in late fourth quarter of 2014. With that, I'll turn it over to Doug for some closing remarks.

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 quarter -- current quarter, taking our expected 2013 capital expenditures to approximately $400 million to $450 million, and $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 non-recourse 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 repurchase 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 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'd like to update you on our quarter-to-date crack spreads. These are all based on West Texas Intermediate, not on necessarily the advantaged crude oils that we run on 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-Con and 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 is about $39 a barrel and the lubes crack spread at $65 barrels a barrel for February. And 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're ready to take questions.

[Operator Instructions] Our first question is coming from Jeff Dietert with Simmons & Company.

I think I want to dig -- I have to dig through the transcript to make sure I got everything. But could you talk about the Navajo downtime in January and just the opportunity cost associated with that outage?

Well, cracks are very good, Jeff, as you know in the Navajo system. But the additional week we're taking is probably about a $20 million impact in the first quarter. That's overplan.

Got you. And now second question with regard to the UNEV line, it looks like your Rockies gasoline cracks were really low in January, but they’ve rebounded strongly in February. Is the UNEV line providing some benefit there for Woods Cross? Or are you expecting most of that to accrue with the expansions?

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 costs. 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. Did I have that right, Dave?

Yes,

With most of those deliveries going down to Salt Lake.

But I guess, Jeff, further to the point that once the margins have rebounded in February, we're not shipping quite as much in UNEV and yes, we'll see more benefit of that line post expansion.

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

Doug, on hedging, you mentioned that most of the hedging loss in the first quarter was due to WTS. What sort of positions do you have going forward here on your heavy Canadian hedging as well as your crack spread hedging here in 2015?

Okay. Sure, Chi. First, on the WCS piece, most of the hedging actually have 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. And 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.

Okay. And then any updates on the crack spread hedges?

There aren't. We'd have the same numbers as roughly where we were at the end of the fourth quarter -- or rather, the end of the third quarter when we communicated with you. Actually, I'd tell you there's really no material change to the crack spread hedging.

Okay. I guess the second question is back on operating expenses. Do you have a breakout of the items you mentioned on the environmental accrual and the project write-down by region? And also, it sounds like you've still got some downtime going on both planned and unplanned here in the first quarter. Would you expect the same sort of trend on higher OpEx that you saw in the fourth quarter to kind of carry forward in here in the 1Q?

Well, we had the onetime environmental accruals. We don't expect those to repeat. The write-off of the Cheyenne engineering on the 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.

Yes, the environmental piece largely in Artesia, so Southwest region. The Cheyenne gas hydrotreater that Dave mentioned was the Rockies. That was $7 million or so pretax of the amount we provided.

That gotten -- had a little pension. So the pension is largely SG&A as well as Southwest region. And we'll take more of that through the course of this year, with timing uncertain. But as we complete the termination of that plan, which is materially funded, it's really an accounting issue transferring from other comprehensive income through expense on the P&L.

Do you have a total dollar amount, Mike, on that?

Mid-30s.

Yes, we had said $37 million is the expected P&L impact, Chi, 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 a very favorable position to be able to terminate that plan.

Effectively, we're out of the defined benefit pension business upon this termination, which we consider to be an important goal.

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

On hedging, what is your current strategy on overall longer-term basis? I mean, given the bonds 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 effort to do any hedging going forward?

Well, 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 is procurement based, that being crude differentials on a 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 we accept that it blew out during late December and January, but those differentials are right back toward 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.

And [indiscernible], maybe this is for Doug, the difference for the WTI Midland blowout starting in November -- mid-November and same as WCS, can you maybe share with us that how much of the benefit that for WCS blowout in the fourth quarter that you have seen [indiscernible] both -- and in both cases that the benefit is going to show up in the first quarter?

It's -- Paul, we haven't seen -- particularly for Navajo and El Dorado, most of that Western Canadian Select blowout won't show up until January because there's about a 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'd expect to see first quarter WCS realize margins and hedging gain sort of reverse a lot of what occurred in Q4.

How about the WTI Midland for your Southwest system?

About a 30-day delay there. So it started coming in the December, but you'll really see it in January and February.

The challenge with that, Paul, is that as much as we'd be a beneficiary of it, we were sort of the cause of it with our Navajo turnaround. And so we won't realize a tremendous amount of that benefit because the Lovington crude unit of $60 a day or $65 a 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.

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

Yes, sorry if I missed some of your opening comments. But I mean, could you or did you give any color on the OpEx at Navajo? And that's up from $5.14 to $7.48 in the quarter? And any color there on unit costs will be helpful.

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.

Okay. Sorry about that.

Yes. So onetime certainly on -- we would expect onetime on that incremental environmental accrual, Evan. You wouldn't expect to see that high OpEx going forward.

Understood. Helpful. Secondly, on dividends, and it's kind of always asked, but I mean, you guys continue to lead the sector on yield, increased your regular dividend materially again. How do you think about it? 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.

Yes, Evan, we continue to march the regular dividend up, recognizing 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 the forward crude differentials. We obviously have a very strong and liquid balance sheet, and we consider ourselves to be a significant yield play in that we've got a big free cash flow yield and we intend to pay a lot of that out to our shareholders.

That's great. Maybe my last question, if I could, just if there's any update on a Phase 2 expansion Woods Cross, any progress or updated timing on a new CSA there? And I leave it that.

As far as Phase 2 goes, Evan, we are in the design phase, Schedule A development of that. That'll 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.

Your next question comes from the line of Roger Read with 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're maybe designing a longer-term view of what's the right way to go forward with returning capital to shareholders?

Yes, 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. We'll be purchasing our own stock in parallel, certainly to offset the dilution from our equity compensation plans and opportunistically as we see 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're going to try to do and capitalize on some of this free cash we're generating, push it out to shareholders.

That's helpful. 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 wintertime here. But it looks like just to 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 natural gas into hydrocrackers and that sort of thing?

Sure. Natural gas is a charge for us and an operating expense, and not only do we use it to produce hydrogen on purpose, but as well as provides incremental utilities. Our sensitivity to that is I think about $35 million that's EBITDA per dollar increase in that gas price. So you can see in sort of the impact to us of $0.70 is probably in the $27 million, $25 million range.

And Roger, it still stands today that the investment in additional hydrogen and additional liquid yield for these 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 as continuing because the unconventional resource out there and with gas being clearly economic in a lot of these basins at $4. That works very well inside our refineries.

Absolutely. I just -- I wanted to understand as things are moving around, what some of the impacts were.

Yes.

[Operator Instructions] Your next question comes from the line of Clay Rynd with 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?

Well, we use a 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 dry bitumen from Canada. And at those differentials, that probably makes sense, anticipating uncertainty around XL pipeline or other such pipelines that might be a good artery for us. Otherwise, probably not.

Yes, I guess that was my follow-up. Do you have anything kind of current that's going to be pulling anything in WCS? Or is it all kind of just thinking about it right now?

I'd put it in the latter category.

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

I guess, one of the impacts that we've been seeing for a while is discounts on sort of gasoline in particular in the winter in the Rocky Mountains, the Mid-Con region and even, I think, perhaps discounts against the posted prices that we're getting off Platts. 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 to run crude?

I see that as a feature going forward, apart from additional investment in logistics 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, January: easy 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 into 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.

And 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 movement on some of those systems, that can cause bottlenecks?

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.

Okay. And then in terms of just any debottlenecking projects, any updates there or thoughts outside of, obviously, the great projects that you've got for the black wax?

The de-bottleneck 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.

Your final question comes from the line of Doug Leggate with Bank of America Merrill Lynch.

It's actually -- it's 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 2 quarters. Any reason behind that? And what shall we think of a run rate going forward?

Well, the G&A step-up would've been in '13...

D&A.

Oh, D&A. Okay. Well...

I think that we're capturing the effects of amortization expense from the new turnarounds, that's probably the most of it. And we probably won't be to the run rate on that until end of this year.

And 60 to 65, I guess, a quarter is probably a pretty good run rate going forward.

And you do have a question from the line of Chi Chow with Macquarie.

Mike, I just got a follow-up on your comments regarding the sort of backyard crudes. We can see what's going on with volume pricing at when associating with WTS. But we can't really see is what's going on in kind of the Niobrara or Mississippian. Can you give us some comments on what you're seeing on production levels in those basins? Are you taking advantage of those crudes? And what sort of pricing dynamics are you seeing? Just any sort of general thoughts on that.

Yes, so the Niobrara is not that relevant for us yet, interestingly enough. All those barrels are committed to White Cliffs and shipping toward Cushing. There are also refineries in the Rockies that are more geared toward the more heavy sweets than we are in Cheyenne because of their sulphur recovery capacity up in Cheyenne. So as yet, not that relevant. But if you listen in on Noble and Anadarko and others, I think that's going to be an opportunity for us here within the next 6 months to 1 year, and that the differentials will widen and cause 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's nicely discounted relative to WTI on most days.

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

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

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