Carrizo Oil & Gas, Inc. (NASDAQ:CRZO)
Capital One Securities 2013 Energy Conference Call
December 11, 2013 9:40 AM ET
Sylvester P. Johnson, IV – President and Chief Executive Officer
Next on the agenda is Carrizo Oil & Gas, and from Carrizo, we’ve got Chip Johnson, who is President and CEO along with Jeff Hayden, who is VP of Investor Relations, and I think as folks know, Carrizo has an active drilling program in the Eagle Ford, Niobrara and Utica, and the company is actively experimenting with downspacing of both the Eagle Ford as well as the Niobrara and is planning to release well results from its first Utica effort around year-end. After a series of upward revisions throughout the year, the company achieved 40% growth in oil production and they intend to continue next year at roughly the same rate.
So with that, I’ll hand it over to Chip and we might welcome him.
Sylvester P. Johnson, IV
You can read that later. Our strategy is pretty consistent with what we’ve said for the last couple of years. our focus is on premier oil plays and less on natural gas. The two main plays we’ve been in, in the last couple of years have been Eagle Ford in South Texas and Niobrara in the Northeast Extension in Colorado. We’re now moving into the Utica also and we’ll have our first well tested in January. Right now it’s resting, we frac-ed it about six weeks ago and that’s in Southern Guernsey County.
Another big focus of ours has been to work on the balance sheet and bring our debt-to-EBITDA down and we’ve accomplished that by growing the EBITDA, cutting the CapEx, doing a better job of living within our means and also selling off some non-strategic assets, that’s what prudently manage the asset portfolio is and that’s essentially selling off dry gas in chunks, we sold off the last of our Barnett Shale about a month ago. We’ve also sold off some acreage in dry gas areas to people that have a, I guess, a more favorable gas price deck than we do and we’ve also been able to deliver predictable and sustainable results.
This is – our third quarter was outstanding in a string of good quarters, but that’s oil production not liquids production; oil production was 12,228 barrels of oil per day, 41% increase over the last year, and I’ll show you that that was a big increase over the year before. Revenue was up 37%. EBITDA was up 33%. CapEx for drilling and completing was $126.5 million. That was under budget, as we find ways to keep cutting our costs and getting some – especially some of our frac cost down.
We were able to acquire 3,500 net acres in the Eagle Ford and 5,900 acres in the Utica. The Eagle Ford 3,500 acres is almost one year of drilling inventory at a three rig rate, so just in the third quarter alone, we almost replaced this year’s drilling. Now we did increase our production guidance this year from 45% to 47%, because we had a better than expected third quarter and we are also going to accelerate some fracs in the Eagle Ford in the fourth quarter, and we gave our first 2014 guidance on oil production and we said that will be better than 40% and until we finish all of our modeling, that’s what we’re going to say.
This is where we operate, three oily plays and one gassy play that Eagle Ford in South Texas, Niobrara, Colorado, Utica in Southern Ohio and then we still have about a month of drilling left in the Marcellus and Northeast Pennsylvania that’s pure dry gas, no ethane or any other NGLs and we’ll have that all drilled up in about other month. After that, we’ll still test downspacing in the upper Marcellus, but it’s essentially done and it will peak in production about next summer, when we finish all of our fracs.
This is what our oil production has done over the last 11 quarters. That’s the top of the bar. Again, this is oil not liquids. We’re getting full price for this or premium sometimes in the Eagle Ford. You can see we have 11 quarters of growth. We really moved into the oil plays in the middle of 2010. So at that point, we were making about 400 barrels of oil per day. This other bar is margins; that’s our profit margin and that’s total margin and so you can see that that’s been growing steadily and we think that’s powerful even for generalist E&P people and this is the improvement in margin we got by selling off the Barnett Shale in the third quarter, so that’ kind of a pro forma.
And then the fourth quarter guidance is on there, which we think is really good number. This chart shows our revenue growth on the left side, and green is oil, light green is NGLs, red is natural gas, that – can you now hear me?
Yes, very well.
Sylvester P. Johnson, IV
Okay. Stand more like this, is that better? And in the chart on the right is EBITDA growth and that’s been very steady even though we’ve sold off some dry gas assets at three different points on there and done some JVs as another way to raise capital.
This is what the balance sheet improvements look like. We dropped from debt-to-EBITDA in the fours down to under 2x now, which puts us in the – about the top quartile of our peer group and our goal is to run around 2x – between 2x and 2.5x, but that’s the result of growing EBITDA, holding CapEx flat and also selling off some dry gas assets.
This is what our reserve picture looks like. Reserves are – this chart broken up by area; light green is proven, dark green is probables. As you know in shale plays, most of the probables, if not all, are going to turn into PUDs and then PDPs, and we are very confident of that especially in the Eagle Ford, Niobrara, Utica, those are very well understood plays now, where we are. Total reserves are shown here, also as impressive is our PV-10 including all those probables of $6.2 billion and right now our enterprise value is about $2.5 billion.
This shows on the left what our plans were going into this year, and then on the right, what the outcomes were, so we wanted to run three rigs in the Eagle Ford and test downspacing. We’ve done that. We’ve grown production. We’ve added to our inventory. We now have 552 wells left to drill. In the Niobrara, we are running two rigs, we’ve also tested downspacing, narrowed down to 80 acres, we’re now going to test 60 acres and some other zones. We call this managed frac programs.
Basically, those are frac holidays, where to save capital we just don’t frac for about one month per quarter, but in the fourth quarter, we’re going to frac through the whole quarter. We raised some capital a month ago with an equity sale and that’s going to speed our fracing in Eagle Ford. We’ll still have an inventory at the end of the quarter of about 25 to 29 net wells, but that gives us a big surge in production at the end of this year and all through next year. And then, we’re going to have our first Utica well being tested next month.
Hedging, that’s this last bullet. We are about 80% hedged through December and we’re about 70% hedged on oil next year. We’re about 70% hedged on gas next year. We’re putting in more hedges right now to kind of light these prices today.
This is what our capital program looks like on this pie chart. Drilling and completing is all of the stuff on the right. This was how much we spent on land this year. This was a big year for land, because we exercised our options with our private equity partner in Utica to buy up to half and then a month ago we bought their half out of some of the best acreage. So this was a big year for us in the Utica. We don’t expect that next year. I don’t think there are going to be that many opportunities like we saw this year, so I think next year’s capital is going to be closer to 2012 and not as much as 2013. We still plan to run three rigs in the Eagle Ford, two in the Niobrara, one in Appalachia. It’s just that the rig in the Marcellus now, well maybe not the same rig, but a rig we’ll be drilling in the Utica starting in about April.
This is our NAV slide. I think we put more detail in this than almost anybody and we can backup all these numbers. You start out with your acreage in a given play, how much you can drill. In the Eagle Ford, we are very confident of our acreage count there. We can show you every well that adds up to these 552 wells. We know a type curve for every well, the GOR, the length, the stages, the CapEx, and we can grind through all that to come up with $3.9 billion of 2P PV-10, and if you look at the recent sales to Devon and by Abraxas to Sanchez, I think you can come up with that same number. So that we are very confident of these numbers.
We seem to struggle with the analysts all discounting these numbers more than we do and we’re going to have an Analyst Day in January to try to straighten them out on that and convince them that the fact that we have wells drilled on every lease we have means the wells around them are going to be good also. You can see in different areas like the Niobrara, we discount that acreage much more heavily. A lot of our acres are in low resistivity areas. We’re not putting that as high somewhere in gassy areas. We’re kicking that out.
So that’s all factored in. Same in Utica, we have a little bit of acreage that we think is too far north, we kicked that out. Marcellus, we actually have about 50,000 acres in the Marcellus, but a lot of it is in Central Pennsylvania and at $3.50 to $4 gas, we’re not going to drill it, so we have not included that, but anyway, that gets you through all the machination towards $6.2 billion in PV-10 with our capital program that’s three rigs in the Eagle Ford and no acceleration.
This is our Eagle Ford position and there’s a lot of information on here. We are in this lime-ish green area in the middle of the page, which is the volatile oil area in South Texas, mostly the LaSalle County a little bit up here. These are depth contours. All our wells are shallow than 10,000 feet, which is great for us; we don’t need high strength proppant, we don’t need high pressure frac equipment, that was by design. In every play we’re in, we’re above 10,000 feet.
Our acreage is in yellow, the little red stars are our drill sites. We’ve been pad drilling here since we started. We started pad drilling in those six in the Barnett. That’s nothing new to us. One thing we’ve added here are who is around us. This is El Paso and I think that’s for EP Energy, that’s going to be the highlight of their IPO. I think EOG is here, here. Chesapeake is here and here with the good stuff they didn’t sell three months ago, Marathon up here. So we’re in good company here. We think this is a great position. We can drill about 50 net wells a year with three rigs running. This is what the decline curves look like in terms of daily production and cumulative production. This is based on seven different riders got type curves to go across our acreage position and factor in depth pressure and GOR on all of those. So we’re very comfortable with this.
our engineers don’t know when they pick a well site whether it’s a PUD or a probable, but they know what the economics are going to be in that area based on all this data we have. This is what the economics look like. For about an $8 million well, that’s our average well cost, that’s about $2 million to drill, $6 million to frac, 23.3 stages and that’s our average well. We’ve drilled 10,000 foot wells and we have some 5,000 foot wells. It just depends on your lease geometry. We’d love to drill all 10,000 foot wells.
For 2,162 a barrel of F&D cost, we can make an 87% rate of return at $100 NYMEX and that’s because 92% of our revenue is oil, not liquids or not NGLs or not gas and the oil we produce, 97% of it has an API gravity of 50 or less. So we do not get any discounts for having really high gravity condensate.
This is the Utica in Southern Ohio. Our acreage is kind of hard to see here and we have a lot of data on here. we are the yellow acreage like this and the red acreage like this, and the yellow, we own 50% and the red we own a 100%. The red is where we bought our private equity partner out a month ago, so that we could get a 100%. This red outline is what we think our buy area is. All the wells that have made 1,000 barrels of condensate per day on an IP are inside that red outline and that’s been our focus.
the economics as you move, east get wet gas and then dry gas and that might work, but we like oil and condensate and that’s what we’ve been focusing on. and we’re basically in between Gulfport up here these brown dots, PDC in this area with their – not the Washington County well they just announced, but the Guernsey County wells and then this is Antero’s best Utica acreage and we’re right in the middle of their business.
So we think this is a great spot. The well we drilled and frac-ed is right here. It’s about an 8,000 foot lateral. That will be the longest lateral in that part of the play and we should finish resting that about the first week of January and bring that on. This is what the decline curve looks like that we’re using in the Utica. We don’t have a well yet, so you ask where we get this, this is basically an average of Gulfport, PDC and Antero’s public data, and especially on Antero, there was a lot of public data for the IPO and that’s how we came up with these decline curves and these economics. So we can see we’re at 85% rate of return at $100 NYMEX.
The well costs are much higher here. We hope over time we can get those down, but we know in the beginning, we have huge surface cost to build the drill sites and you have to build a lot of your own roads, you also have to avoid old coal mines when you drill, there are a lot of things to get in the way on the capital side. The good news is the royalties are less in the Eagle Ford and the severance taxes are very low right now in Ohio and we think they’ll stay that way at least in the early years. So very profitable play, but we need to test this and prove it before we decide that this is where a lot of capital should go. Right now, this looks better than the Niobrara and about even with the Eagle Ford.
This is the Niobrara, Northeast of the Wattenberg field. Wattenberg is somewhere down here. We’re in the Northeast Extension. We bought into this acreage in 2010, focusing on high resistivity in Niobrara B bench and that’s what nearly all of our acreage is in. We have a little bit of acreage up here that’s not, but we had to buy that to get this, and so that’s why we had it, but this is our area. Noble and Whiting talk about this so much. We’ve added this to help people figure out where we are. This is the East Pony area that Noble talks about. This is the Whiting Redtail area. The interesting thing that’s going on right now is both of those companies have some big pilots going on right now, like 28 well pilots in two sections to test not only the B bench at different spacing down to 40 acres, but the A and the C bench separately at the same time, and we are partners in those wells.
so we’re excited about this. I mean potentially, we could see our drilling inventory here go up by 6x. I think that’s optimistic, but still we know there’s oil in the A and the C. We have cores logged through that. We just – we assume we are probably getting most of that oil with the fracs in the B, but until you test those separately, you really can’t determine that. So this is going to be some exciting results that we’ll probably see in the first half of next year.
This is what the economics look like for our wells in the B bench only. You can see a little sharper decline than you see in the other plays and that’s because there is more natural fractures. But still the fact you have such a low well cost gives you a decent rate of return anyway, about a 56% IRR. Our wells make 80% to 85% oil. We are off to the northeast of Wattenberg. so we don’t get hit with the air quality issues that they do and we were far enough out that we didn’t get hit with any of the floods that happened out there either, and because we make so little gas, one may have a big compression issue in Wattenberg. We are kind of immune from that too, but we don’t make much revenue of gas either.
Then finally, here is the Marcellus. this is northeast PA, Susquehanna County, Wyoming County. Cabot basically is everything in the middle; Chesapeake is over here, Chief is over here, excellent area. This is about 10,000 gross acres that we and Reliance own and have drilled up and this will peak at about 300 million a day gross next summer, and we’ve been producing this now for two years already, and that’s the good news and the bad news. It’s a great play, but we can add production, and so can Cabot and Chesapeake and everybody else out here, so fast that we don’t think gas prices can go up until 2017 or whenever LNG starts happening.
We are finishing up our drilling right now down here on this Pluschanski pad in Wyoming County. We can sell gas here into – through Penn Virginia Resources to Transco or to Tennessee. This gas nearly all goes up to Millennium. I heard this morning that price at Ramapo was $5.70 today, which is fantastic news. Unfortunately, the price on Transco is about $3.70 today. so it just depends on where you’re going.
We think the summers in northeast PA and Ohio are going to be a problem for gas prices for the next two or three years. So we’re trying to lock in prices right now for next summer, so we don’t have to shut in gas when the prices are too low. That’s a type curve for the Marcellus. Probably the best dry gas economics in the country, but still at $4 NYMEX maybe you’re at about 39% IRR, so profitable, but not competitive with the oil plays for our capital.
So to summarize, we’ve built a inventory – large inventory of high quality oil assets. we started drilling those. We’ve had great success. We’ve been able to consistently raise and then beat our oil production targets. Our NAV PV-10 for 2P reserves is about $6.2 billion and that’s before further downspacing in the Eagle Ford or the Niobrara or any additional zones in the Niobrara. So we have more upside there and still that’s against the enterprise value of $2.5 for us.
We’ve worked hard on the balance sheet. I think that was one of the things holding us back the last couple of years, gotten our debt-to-EBITDA now down under 2x, which is better than most of our peers and we can keep it there. We don’t have anything that forces us to spend capital if there is some sort of reason that we have to slow down. So I’ll jump, that’s the beauty of the Eagle Ford, just why we like it, no one who complains about how much of noise you make.
This is the slide we’ve added recently that shows what we think each of our plays is worth, Eagle Ford. This is our NAV in the Eagle Ford on of that detailed chart I showed you, and this is the range from the analyst community and I think we have 22 analysts that covers now with the average here. So the difference between the average and here is about $33 a share and we just really struggled with that, because we – we think we can prove to anybody that those results are there.
The Utica, we have about a $15 GAAP, but a lot of people don’t even realize we’re in the Utica and they’re about to, once we announce the Rector well in January and then we think that will be a very high IP and we got some acreage right next to a lot of other, really good operators that are announcing big wells. So this is what we’re working on and why we’re going to have an Analyst Day in January, to see if we can close this gap and maybe close some of this gap and see what we can do for the stock price.
So with that, thank you very much.
[No Q&A session for this event]
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