Okay. Next up on the energy frac today we have Jeff Beyersdorfer from Western Refining. He is the SVP and Treasurer of the company. For those of you who haven’t seen him stick with the conference before he is actually going to keep you awake. He is going to walk around and make it interesting. So it’s very good for late in the afternoon. So, with no further ado.
Thank you, (inaudible). All right. Good afternoon. I’m Jeff Beyersdorfer, again SVP and Treasurer of the company. 20 minutes, I want to go through little bit about the company. What it is we do but mostly talk about the Permian and the opportunities we have there, and what it means for us as a refining company.
So for those that don't know the company, these slides are kind of hard to see you’ve got them in front of you. Very briefly we’ve got our asset base in the Southwest. Two refineries, 150,000 barrel a day capacity, total one in El Paso, one in Gallup.
We also have two distribution networks, one a retail service chain, convenience stores chain, about 222 stores throughout Southwest. And then secondly, these little black dots up here are sales offices for our wholesale business. So we have a wholesale business.
We think unlike anybody else’s and that we sell all the way through to the end customer. So the big mining companies here in Arizona, our customers are those small little fleet provider, fleet service providers or the guy preparing air conditioners here in Phoenix that’s our customer also.
We don’t think there many others of our peer group have a wholesale network and infrastructure to support 3,000 customers the way we do and it help us just to keep a pulse on the end market for demand and things alike.
What I want to talk about are five things. Two have to do with our geography, the Southwest that we enjoy. Through shared unlock its access to this Permian Basin phenomenon that we’ve got going on. And also we’ve got pretty good product market that I’ll talk you about specifically Phoenix is a very good product market for us for gasoline.
The wholesale retail integration I want to quickly touch on. We are in a transition period for the company. We are no longer paying down debt. We think this fix the balance sheet. We are growing through capital expenditure I’ll talk about that. And then talk a little about the capital structure from the things we are thinking about in terms of the capital structure.
But first of all, the crude dynamic, we buy a 100% of our crude on a WTI basis. So it’s either Cushing or Gallup or Midland or El Paso and then we also buy from West Texas seller, it’s about 15% of El Paso crude diet. But for the most part we are 100% leverage for this WTI Brent phenomena that I’m sure everybody knows about.
And what we are doing now is that, because this new shale crude play is happening, we are trying to go in and discuss with some of the producers about coming directly to our refinery with their crude rather then sending it to Cushing or sending it to the Gulf Coast. And we’ve got a couple of projects we are doing and I’ll show you those projects graphically and what they might mean for the company.
Here's West Texas, here is the Permian Basin. Looks if this work. Okay. Here is the Permian Basin, this white outline here. This is Texas. This is New Mexico. And what we’ve tried to show here is the supply/demand scenario for El Paso and less importantly for Gallup.
Here is El Paso. These are all crude line here that are existing or the dotted lines are to be built crude line that take crude from the Permian either to Cushing, here is Cushing, Oklahoma or to the Gulf Coast.
For El Paso we are benefiting from three-differential for crude. The first differential that you know about is this TI Brent spread placing between Cushing and the Gulf Coast. The TI Brent spread, this morning it was $22, it has run around $15 to $17 over the last several months.
As [few] announcement last year made it go back to 8 bucks. We’ll talk about what is going to do longer term, but right now it’s benefiting us on a couple of other that can process this WTI crude. So that’s one differential.
The second differential is the cost between Cushing and Midland. Recall what I said for El Paso. We are buying our Midland-based WTI. And the differential there between Cushing and Midland is about $1.70 today per barrel. Historically, it went about $0.50 per barrel.
During the second quarter of this year it blew out to around $3 or $4 a barrel. And the reason is because there is only one line, this Basin line it’s about 450,000 barrels a day that goes between Midland and Cushing.
So what happened is they spend more production of crude that could be supported on this line, therefore crude got backed up at Midland and led to that wider differential between Midland and Cushing therefore benefiting us, since we are buying on a Midland Basin.
And then, finally, here is this, what I call field differential and that is buying crude directly from the producers in the Bone Spring and Avalon Shale plays here versus their alternative is to send it to Midland.
So we are negotiating directly with the producers in procuring this crude to come to El Paso rather going to Cushing or Midland or the Gulf Coast. So there is different differentials we are benefiting from at El Paso. The Brent TI, Cushing, Midland and then Midland field difference, that’s what leading to the EBITDA that you’ve been seeing us generate so far this year.
All together these pipelines when built are probably going to result in about 1.8 million barrels of takeaway capacity. And the last one to be built is this Permian Express line that’s schedule for 2014. Once that’s build all that adds up to about 1.8 million barrels of takeaway capacity.
The production depending upon estimates that you believe, there are lots of guys out there who have estimates. We subscribe to the service offered by Bentek and their estimate is about 1.9 million barrels of production out of the Permian by 2016.
Today, the estimate is about 1 million barrels of production out of the Permian, that’s going to grow from 1 million today to about 1.9 million barrels by 2016. So, it’s going to -- its sound like it’s going to be in a supply/demand situation and that’s probably pretty balanced if all these pipelines do get build.
So where do we think the crude differentials are going to go to its probably ultimately going to settle right around pipeline economics or little more than pipeline economics, the differential between Brent and WTI pipeline economic are about $4, $5 a barrel.
So we subscribe to probably conventional wisdom that it’s probably going to settle in the future once all these stuff like to fell and all the logistics gets build out somewhere around $5, $6 a barrel for WTI differential to Brent which we’re going to continue to benefit from four differentials, okay.
There is also some crude production estimate happening up in the Four Corners area. There is play up there called the Mancos Shale crude play in the San Juan Basin, production estimates are pretty modest right now.
But there are some majors up there who are gathering land, massive land right now and looking at drilling. And if that production comes online, we only, only pipeline, this tech new make line to get crude out of that market but we might find an opportunity to maybe dictate where that crude goes along with. We may have an opportunity not only to run some of that crude at Gallup, but also bringing maybe some of the crude down to [Brent TI].
On the product side, this map on page seven shows all of the markets that we serve and all the product pipeline. So the major markets we serve are El Paso, Northern Mexico, Phoenix, here we supply about 50% of Phoenix gasoline requirement, Tucson, Albuquerque, Flagstaff, Four Corners.
We like these markets pretty well and I’ll show you a graph in a second that why Phoenix tend to show a pretty good margin environment versus some of the other benchmark indicators. But basically it’s a Southwest where we supply into from El Paso and from Gallup.
These shows from a gasoline margin perspective and a diesel margin perspective, the various pricing in various markets. I know it’s a busy slide but the one that speaks out here the yellow or the gold are Phoenix margin for gasoline and diesel.
The blue, if you see up on the top there is Salt Lake. Well, Salt Lake is probably the strongest refining margin environment period, but Phoenix it looks to be doing pretty well and then you’ve got Gulf Coast, West Coast and then the Mid-Continent down below here. So we like this margin environment for Phoenix and again about 15% of Phoenix gasoline supply that we supply.
And then one other comment about the margin environment for our refinery, again this is easier to read if you look at the printed copy you have in front of you. But this is a ranking of all the independent refiners out there on an operating margin basis, so gross margin minus cash operating expenses and they are rated from top to bottom.
Here is 2007 and obviously, the highlighted ones are ours and here is the moment we’ve made since '07 more towards the top of the list. But the commonality amongst all these refiners in this first quartile, are the following.
They sit on top of their crude sources. They are very close to WTI crude sources, mostly inland. There are not necessarily big refiners or big refineries. They tend to be more in the modest price. They are not very complex. And they serve geographies that are pretty attractive, that’s the common thing for all the guys, who are displaying pretty good margins these days, okay.
Turning to the distribution network, I mentioned upfront, wholesale and retail. Again, we tend to think of these businesses as simply an outlet for our products. So some others believe retail stores have a benefit because the gasoline is sold to in essence merchandize sales and they are doing well on merchandize sales. We like merchandize sales but the primary reasons that we have retail and wholesale is to distribute our refinery product.
So the only areas where we only this and we have been growing this, but the only area where we only is where we can supply with our refiners. Hence the distribution network in the Southwest. So you won’t see us buying retail in the Northeast, to the Midwest, expanding anywhere there, we are only going to buy retail or expand wholesale to compliment our refining assets, okay.
I mentioned upfront that we are in a transition period. So we have been fortunate enough to sit in the middle of this crude dynamic, and we have been able to generate a significant amount of cash flow and that cash flow we have been using to repair the balance sheet that was a little challenge through 2008, 2009, 2010.
Now that we’ve got the balance sheet and repair, returning our focus to reinvesting in the business and returning back to shareholders. Well, couple of initiatives we have for cash or some discretionary projects that we are doing currently, the Delaware Basin, crude logistic project that I mentioned and I’ll show you in map in a second. We just got through with an expansion of our Gallup facility by 2000 barrels a day both went from 23,000 barrels a day to 25,000 barrels a day feel very modest, it’s a pretty profitable refinery.
Also we are returning cash to shareholder. We announced the dividend earlier this year. We uptick the third quarter and we also in July announced the share repurchase program $200 million. The primarily is being used to address the convertible debt in our capital structure and I’ll mentioned and describe that in a second, when we get to the capital structure.
We’re also building cash, minimum cash on our balance sheet. A year ago we were out telling the market we wanted $150 million of cash on our balance sheet. Today we want $300 million the minimum of cash on our balance sheet. Because we know inevitably refining market are cyclical, this is going to turndown again at some point in time. We want to make sure we’ve got plenty of liquidity to weather it through that inevitable downturn that will come at some point of time a year.
Here is that project I mentioned in the Delaware Basin its part of the Permian. So again, here is the Delaware Basin. This is Texas. This is New Mexico. We are building about 50 miles of pipe directly into the fields and going directly to the producers and negotiating with them to be able to spend their crude to our pipeline directly to El Paso rather sending them back to Midland or Cushing or down to the Gulf Coast.
We’re spending about $30 million in capital. The timing is to complete this by the end of the first quarter next year. And when it's completed, this will facilitate the delivery of up to about 100,000 barrels a day of this new shale crude to El Paso, again versus hopefully they are not sending it to Midland or Cushing. We prefer them to send it out into El Paso. It’s a better crude for us. We get better gasoline yield, better distillate yields. It’s just the better crude than what perhaps we are buying today.
The second project I just mentioned we finished, we expanded Gallup by about 2000 barrels a day and we just completed a turnaround, that’s preventative maintenance at Gallup. We are just on the tail end of that. We introduced crude oil for the facility over the weekend. So we are hopeful that once that facilities up and running again, we’ll lower the OpEx cost per barrels, which runs today about $7.50 which will and we’ll also see that 2000 barrel incremental capacity.
Okay. The final page, we will talk about to your -- the second final page we’ll talk about is the capital structure. So here is a capital structure as of June and as you can see, we've got about $500 million of debt, where a year and half ago we had a little over $1 billion of debt. So we reduce debt in half in the last year and frankly, it come from cash from operation. We are very fortunate, as I mentioned, upfront to be able to sit in the middle of this crude dynamic capital.
So $500 million we think is the right level of debt for this asset base. So we’ve done with debt reduction. But the composition of the debt is not what we want it, so you can see you’ve got this $11.25 coupon note, it becomes callable in June of next year.
We look to tendering it using new issue proceeds and we continue to look at it, the economics haven’t been as attractive to us as we would have like. So we are continuing to look at potentially tendering for the 11 and a quarter to get it out of our capital structure and replace it with a unsecured fees of paper, probably somewhere between $300 million and $500 million in size and it’d be a 10-year an unfold five or eight-year unfold four, maybe coupon is, we’ll see how it might structure, at a minimum though, if the high yield market is there we will most definitely call that piece of paper in June of next year and refinance it at a much better coupons.
The five and three quarters are little trickier in that they don’t mature until May of 2014 and we can’t call them prior to that and they are well in the month, the strike price is $10.80 and our share price today is $25, so we are well in the money. And they are trading very well. They trade at about 250% at all.
So that’s the reason for the share repurchase, as we think that buying back share today, retiring those share and then reissuing those shares, when the convert matures will help to partially mitigate some of the potential shareholder dilution from that convert when it matures in 2014. So that’s the reason for the share repurchase. Not necessarily return cash to shareholders but to mitigate some of the dilution from this converts when it does mature in 2014.
Ultimately what we’ve like is a $1 billion revolver which is what we have today, an ABL revolver and a $500 million of unsecured high yield paper that’s the ultimate capital structure for us going forward for this appendix.
We also continue to enter into forward hedges and that simply selling our product forward. As you know we started this back witness Brent TI spread widen pretty dramatically beginning of last year.
That forwarded us an opportunity to go sell forward our product for longer period of time than historically we could have. So now we are looking into 2015 for selling forward some of our product both gas and diesel.
Our objective is to hedge about 30% of our plant product. Today we are at about 20%, 21% for 2013 or little under 20% for ‘14 and we are little under 10% for ’15. But you can see from this graph, this graph shows gasoline here, diesel here, it also shows by quarter, let’s look at the diesel because it’s more instructive than the gas.
The diesel per quarter here is the volume we’ve hedge so looks like next year about 40% of diesel being hedge and then here is the strike price at which we are hedging as you can see it pretty attractive based on business. So we think it’s still pretty important to opportunistically hedge, take some of that risk off the table and we’ll continue to do that up to about 30% through 2015.
So hopefully I’ve been able to give you an overview of the company, the markets we are in, we like our asset base very much, we like the geography we are in, we are benefiting from the discounted crude, we like the product markets, talked about the retail and wholesale distribution that being very important to us, talked about our focus changing from reducing debt, we are comfortable now with $500 million of debt, it evolving now into capital expenditure looking at investing in some of the logistic assets we’ve talked about, fixing the capital structure composition is important to us near-term, so we’ll look at doing that also.
And as I said, from a debt perspective, we are looking to target and maintain this BB credit profile which is (inaudible). We think we are there today. We’d like to remain there today and from the BB credit profile in the future.
So that’s it. I’ll answer the questions. Yeah.
Okay. The question, I’ll repeat the question for the web -- the web. So the question was what exactly are we hedging? So let’s go back to this graph on page 15. So our product sales, we sell gasoline and we sell diesel and typically when we sell product it tie to U.S. Gulf Coast 87 octane gasoline that’s the basis for it or ultra-low sulfur diesel Gulf Coast. Those are the two products that our product sales or two metric that our product sales are tied to.
And the crude we are buying is WTI Midland. The hedging we are doing are those exact indices save for the crude which is WTI Cushing versus WTI NYMEX. We are hedging Cushing rather NYMEX.
But what we are doing is selling forward the crack spread so the difference between the gasoline versus WTI, that crack spread we are selling forward in ’13, ’14 and ’15 or that diesel spread we are selling forward ’13, ’14 and ’15. We are locking in the spread.
So we got very little basis spread because our product, our physical products are also tied to those same benchmark that are used in the paper market for the hedging with our counterpart and we are using bank in our credit facility, Deutsche Bank being one that we are using for hedging accounts.
It’s not a traditional inventory bank. Yeah and I will say, the hedges don’t qualify for hedge accounting, so in the third quarter we -- because the margin environment has been so robust. We are going to record about a $70 million to $75 million hedging loss that flows through the income statement, realize hedging loss that flows through the income statement.
So again it because the margin environment has been so robust versus where we had, so the hedges haven't performed in the third quarter what we thought that we are going to do, but our unhedge portion has done better than what we expected.
So about $70 million, $75 million, about $40 million to $45 million of that are crack spread hedges and as Matt mentioned the balance are some inventory hedges that we put on. Yeah. Go ahead.
So the question is with respect to the 11 and a quarter. We most likely will call them that was your question, right, with as my comment. But if, what’s the thing that’s holding a top from maybe tendering for them earlier and it’s been just pure economic.
The tender price has been prohibited and we’ve been looking at this three year. And so tender price has been fairly prohibitive from our standpoint, but if you understand bond map, the tender price which we will all do, bond map tells us that tender prices keep coming down as we are closely to the call date. So every month the tender price becomes less.
It may become more profitable to us sometime before the call date given where the high yield market and given the strength of the high yield market. So that what’s attracted to us now as we as long as -- as well as you have never seen a high yield market like we are seeing and so we may contemplate maybe doing something certainly rather than that. Yeah.
The question is what’s the magic behind the 30% metric we are using for crack spread hedges? And there is no magic other than we think it’s a nice balance between an equity investor and a debt investor.
Debt investors want us to hedge everything. Equity wanted us to hedge nothing. So we thought 30% is a nice balance. Plus also we have to contemplate the liquidity available to us. There is not a lot of liquidity, particularly the further out you go, so practically it’s a little tough for us to hedge anymore than probably 30%.
Yeah. The Gallup, good question is, what do we spend on the Gallup expansion? The capital expenditure amount was about $6 million and that funded that 2000-barrel a day expansion. And for 2013 the question is, what’s our capital budget? We have not yet provided that number to the market. We will probably do that later this year on the earnings call.
Yeah. The question was -- the question was composition around our maintenance CapEx versus our regulatory CapEx? Our maintenance CapEx typically runs around $30 million to $40 million a year for both El Paso and Gallup.
The regulatory expenditure all refiners are going to experience a honeymoon for the next couple years when it comes to regulatory spend, because we don’t have any governmental regulations to compile with.
So Tier 2 fields was the last one, it was reduction of benzene in gasoline -- benzene in sulfur and gasoline and diesel. We’ve got through that, now that ended last year and everybody complied. The next phase of regulatory spending is probably 2017 and ’18.
So for the next couple of years the regulatory spend for most refiners is going to be pretty modest and that include us. Our regulatory spend is probably going to be $25 million give or take for the next couple of years, until the next phase of regulations come along. Any other question? Okay. Good. Thank you for your time.
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