Carrizo Oil & Gas Inc. (NASDAQ:CRZO)
Imperial Capital 7th Annual Global Opportunities Conference
September 19, 2013 8:00 AM ET
Chip Johnson - President and CEO
Kim Pacanovsky - Imperial Capital
Kim Pacanovsky - Imperial Capital
Hello. Good morning, everyone. Thank you for joining us at this early hour and for those of you who are here last night I hope you had a great time. My name is Kim Pacanovsky. I am a new addition to the Imperial team, an oil and gas analyst. I just joined about a couple of months ago. And it is my pleasure on behalf of myself and Imperial to welcome Chip Johnson. He is the CEO and President of Carrizo Oil & Gas. And with that, Chip?
Thank you, Kim. Glad to be the first one today after the poker term and I see a few fellow losers in here, [inaudible] in here won the whole thing. You can read this later. This is Carrizo strategy and I’ll go through this pretty quickly. But we have just finished a strategic shift from being a natural gas company through from 2003 to 2008 to an oil company, which we started trying to become in 2010.
And in 2010 we kind of lost faith in the future of natural gas markets, we thought we should make a lot more money oil and we’d made the shift. That concluded recently by us on, number three, managing our asset portfolio. We just sold off the last piece of our Barnett Shale assets in Texas that were dry gas. We’ve done that in thirds. So now we’ve sold off all of our non-strategic assets, most of our producing gas assets and we shift -- we’ve moved to three really good oily basins in the Eagle Ford, Niobrara and Utica Shale.
These are our second quarter results which are the last results we announced about a month ago. Our strategy to move to oil has worked very well. This -- what this shows is that our production, oil production, has reached record levels.
Total production record levels, revenue, EBITDA record levels and everything is about 50% higher than it was a year ago. We also announced that we are now on track to increase our oil production 45% from 2012 to 2013. So I mean this is working very well.
We’ve been able to buy some more acreage in our favorite place, like the Eagle Ford we basically replaced all the acreage we drilled with new acquisitions. And we’ve been able to do this while managing our CapEx budget, most E&P companies outspend their cash flow and we feel like the key is to do that in a very predictable rate that the market can give their mind around and they can understand your debt metrics, and as long as you can deliver on that people can figure out where you are going to be.
So in our case, this last bullet says we’ve now reduced our debt-to-EBITDA to 2.5, back before the great recession people were comfortable carrying debt at 3 to 4 on that metric. Now the market is not comfortable with that, so we are now down to 2.5 and after we sell the Barnett Shale we will be down to 2, and actually our mid cap metric is about 2.2.
This is where our assets are. Green assets are oil. The Eagle Ford should be green; I don’t know why that didn’t come out that way. The red assets are dry gas in the Barnett and in North Texas is the one we are currently selling.
We are selling at basically because MLPs like to buy mature assets that are very predictable and with our cost-to-capital they can pay basically 10 times cash flow for something that we see with no upside. We can take that money and reinvested in wells to payout in 1.5 years in the Eagle Ford and Niobrara and Utica.
These bars show our oil production growth. At the top of the bar, the green bars, you can see, we were at 700 barrels a day three years ago, now we are at 12,000 barrels a day. A lot of companies have tried to make this shift to oil but almost no one has done as good a job as we have done, kind of pays to be small rather than a giant, be hard for a giant gassy company to make this shift but for us we were able to do it in about two years.
And then the other impressive thing here is the yellow bars are margins. So that’s our operating margin on all of our production. And if you could just look at the Eagle Ford margin, it’s at about $78 a barrel so it would be up here and we still have some gassy economics in there that bring that number down but those numbers are going to start going away.
This shows our revenue growth on the left chart and EBITDA on the right. And the other thing on that revenue chart is the green is how much is coming from oil. The light green here is how much come from NGL and the red comes from dry gas. So you can see we are now over 80% of our revenue is from oil, now more than half our production will come from oil.
EBITDA has been fairly steady growth but we in order to pay for this growth and reduce our debt we sold some assets which I talked about. We’ve also done joint ventures with six different Asian companies and one private equity company in the U.S. and that’s another form of selling assets, another way to raise equity, but it doesn’t force us to sell our stock when its depressed and we get hit pretty hard in 2008 as most small caps did and we just didn't want to sell any equity after that point.
This is what our reserve picture looks like; the proved and probable reserve are in that lower left chart, lime green is proved, dark green is probable. But if you understand resource plays most of the probables will become proven. I mean, they in some cases it’s just fast as you want them to become proven. You don’t want to do that too fast. And so we are pretty comfortable with all those Eagle Ford reserves are there. If we can drill the wells closer together that number will even go up and we are testing that now.
The Barnett reserve will go away, this whole chunk. That’s about half our reserves, 40% of our reserve but it was only about 7% of our cash flow. And then over here is the PV-10 of our reserve picture, you can see that that comes up to about $4.8 billion. We have 40 million shares outstanding, so that’s $120 per share and that’s PV-10 and that’s before downspacing. So we have about $20 per share of debt. So that still leaves $100 of NAV for a stock that’s trading at 36.
Here is the highlight of this year’s plan, three rigs running in the Eagle Ford with a downspacing pilot already drilled and flowing back now. We should have results on that in the next month or six weeks. Two rigs running in the Niobrara and Colorado. We’re getting carried by some partners there. So we’re very aggressively trying new areas and downspacing to see if we can prove all that acreage up and figure out exactly what it’s worth and how aggressively we need to be in the future.
In the Marcellus shale, that’s our last dry gas play. We have essentially drilled it up and will be finished at the end of this year. There could be another layer. Above the layer, we’re producing and we’ll test that this fall but if it works, we probably won’t develop it until 2015 or ‘16 after we’ve developed more oil resources first.
We mentioned utilize managed frac programs. Basically that means we don’t have enough capital to frac all year round in all of our plays. So we stopped and we call it a frac holiday which sounds like a holiday for us but it doesn’t to the service companies. But that let’s us keep our CapEx lower.
We feel like we’re already getting all the credit we’re going to get for 45% oil growth and will get hurt more if we increase that at the cost of debt. So we’re trying not to outspend our CapEx budget even if it means we just quit fracking for a while and go into these frac holidays.
So right now, we’re not even fracking in Pennsylvania. We just came off of frac holiday in the Niobrara. We’ll go into another frac holiday in early October in the Eagle Ford.
About the only other thing I have talked about here is our hedge portfolio on oil for about the next through 2014 were about 80% hedged at at least $90 a barrel. After that, I think we’re 40% hedged but we’re really struggling with hedging into the backward dated oil right now and locking in $88 oil prices in 2015.
So we will do that but we’re trying to be very strategic about that and try to get at least $90. On gas, now that we’ve sold our Barnett shale, we’ll be centrally 100% hedged this year and part of next year.
This is our capital program on these pie charts. This side is drilling and completion. The blue is the land budget this year. You see the Eagle Ford domination of the budget $380 million this year. That’s running three rigs. So you can see a rig in Eagle Ford is about $130 million a year drilling and fracking. Fracking is about three-fourth of that cost.
Next year, we plan to stay at the same drilling and completion pace. So the Eagle Ford will be pretty close to this. The Marcellus will wind down but we’ll move that rig to the Utica. So that all these pies will be -- the total pie will be about the same. Appalachia will be about the same. Niobrara will be a little more, Eagle Ford a little less because of the partner carries.
The land was high this year because we have the opportunity this year to equalize with our private equity partner in the Utica. We made a deal with Avista Capital couple of years ago where they put up 90% of the capital and we put up 10%. We bought all this acreage and they gave us an 18-month option to equalize at some cost with them. So it was like a free call option for us to see if the Utica worked and it did.
So in January this year, we wrote them a $70 million check and now we are 50-50 with them. We felt like that was a great deal. Next year, I hope we can find $140 million worth of leases to buy in the Eagle Ford and Utica but I’m skeptical. It’s just getting so competitive and acreage is so controlled. Now that’s going to be very hard to -- I think we can replace everything we drill but I’m not sure how much we can grow it.
This is our CapEx by quarter and this is pretty important to the Street that we’ve been able to moderate this. Back in 2012, we were still trying to hold a lot of acreage. So we’re running additional rigs in all these plays. And this year, we’ve been able to start dropping some drilling rigs. The fracking has stayed pretty constant.
So we’ve been able to grow the production but we haven’t had to -- had as many drilling rigs running around, tying up acreage. So we’ve been able to be pretty steady here for the last three or four quarters in the next two going forward.
This is our net asset value slide There is a lot of information here. We start out by discounting our acreage and all the plays but we are confident we can drill at today’s prices and that survived 3-D seismic scrutiny, lease geometry partner problems. And we end up with those drillable net acres. Then you can back out all the proved reserves and get to the undrilled wells.
We have about 900 undrilled wells to go. 417 of those are in the Eagle Ford. If the downspacing works in the Eagle Ford that 417 goes to about 530. Then you can come across the reserves and PV-10. At the profitability we have in each well and come up with these kind of numbers, $4.8 billion and that number is also constrained by our lack of capital. So that’s a 10-year drilling plan in the Eagle Ford.
If the bigger company had this portfolio and had more capital, they could do this in four years. And this number will go way up -- and this number would go way up. So obviously, some thing is wrong here. Stocks trading at 36 when we think we have $120 million of NAV. The biggest gap we have is in the Eagle Ford. And so we’re really focusing on trying to get the analyst in the investor community to buy into our Eagle Ford story.
This is where our Eagle Ford acres are and this is in the Southern Eagle Ford in LaSalle and McMullen County. San Antonio just to the North, [Alvarado] [ph] to the South. This lime green band is the volatile oil window in the Eagle Ford, that’s most profitable area.
If you are North of that in Frio County, the oil is pretty dead and shallow and you just can’t get it out. If you are deeper than that in this pink area, that’s where the play was discovered. But it’s dry gas or wet gas and is deeper and more expensive. So no one’s drilling down there. They are just like a line of drilling rig permit. It just goes right like this and goes for 100 miles up the trend towards Houston.
But anyway those yellow blocks are our acreage blocks. We’re all around EOG, Chesapeake, Anadarko and El Paso, those are our main competitors in this area. We have had Ryder Scott, third-party engineering firm build tight proves in economics for each in these areas that’s listed here which especially the name of the family that owns most of these leases and gets all the big worthy checks.
But we can show you in detail that these are the highest EUR wells. These are the highest IRR wells. That’s the gases wells. Those are the highest oil content wells but not great IRR. We can lay out and have laid out 417 locations on every single lease. We know how long every well is, what the GOR is, what the cost will be and what IRR is.
So, this is -- there is not much mystery here. We have drilled 130 wells already in this play. We are now up to 550 total horizontal wells we’ve drilled as a company. So we can do things in horizontal drilling that big companies can do and we have drilled more horizontal wells and shale. I think we have drilled more than Conoco in this play.
These are our type curves. The one coming down is a decline curve of production versus time; the one going up is a cumulative production versus time. A year ago we were on that red dotted curve and after we went through -- we always seem to be doing better than that. But once we had the third-party engineers, [Blessitt] [ph] then we have moved to this green curve.
And that’s one thing we have been doing a little bit at a time because we wanted to prove that it worked before we got greedy and said we are going to be on that, which is one of the reasons we have been able to keep raising our guidance of beating it. And so we have been working our way up to that green curve.
This is what the economics of any individual well look like. On the right is the column called current type curve is what we are drilling now and see that’s a 90% IRR at $100 NYMEX. This oil gets priced closer to Brent or less than WTI. So back in March we were getting about $12 premium to WTI.
Now that WTI has closed that gap, we are getting about a $2 benefit. But we are still getting about a $110 per barrel. So you can see for $8 million well with 23.3 stages because this is averaged over all these wells, you can make 98% rate return. Even a 66% rate return at $85 oil. And the key thing here is that we have $21 finding in developed costs and I told you we were making a $78 margin operating. I mean, this is -- we think this is the most profitable play in the U.S. and this is our main point.
The other things that matter here is the NGLs are big issue. There is a glut of ethane in the U.S. and it’s going to continue. It is going to get worse as the Utica gets drilled. You can see on that top chart only 2% of our revenues come from NGLs. All of our gas which isn’t very much goes into eventually enterprise products lines in their plants. So, that’s where they get processed.
The other thing we have is very suitable high priced condensate and oil so. There is a lot made up this last year that there was so much high-gravity condensate on the market that people are getting discounted. We are not -- we only have 3% of our oil that gets any kind of discount. The rest is the kind of oil they want to blend with the high oils, so we get good prices for that.
This is the Niobrara and Colorado. This is Northeast of Denver. The giant Wartenberg field is just to the Southwest of this picture. Our acreage is in yellow. The flight area is the area where the Niobrara B zone; there is three zones. But the B is thick and also has high electrical resistivity and resistivity normally means you’ve got no saltwater in the system and you have hydrocarbons or you have solid rocks. We know it’s not solid rocks. So we have oil and gas in the systems.
And if you are in the blue area, even though the zone is there, it’s non-productive and that’s our theory. So far no one has proven us wrong on this and so we are drilling mostly in these areas. If you ask why we own this acreage, [inaudible] this acreage we had to take it, we won’t drill it. It will probably expire worthless but we ended up with enough good acreage at very low prices that we have a five-year drilling inventory here.
In this area, we are basically drilling with Noble in the East Pony area across the middle of this. And we are sliding in the upper right which is they call that red tail. There are three different zones in the Niobrara, the A, B and C. The B is the most uniform across the area and that’s all we have drilled.
But the other companies are testing the A and C. So that could give us two or three more locations -- wells per locations. We’ve drilled down to about 80 acre spacing. We are currently drilling and testing 60-acre spacing and some of our competitors have gone to 40-acre spacing.
So we could have as many as six times the number of wells we have in this play in the future -- in our inventory. It could grow by six times. I don’t think it would be that good, but I bet it’s two or three. These wells decline faster than the Eagle Ford wells.
You can see that the rate of return is only 56%. The wells are cheaper but they decline faster and the results are more scattered. So we put more capital into Eagle Ford then we do here, mostly just chasing risked IRR as our main criteria.
This is the Marcellus shale. This is the only area we are actively drilling. It’s in Northeast Pennsylvania and Susquehanna, Wyoming County. Cabot is right in between our position here. Chesapeake is to the West and Chief. These areas we were able to -- they didn’t like this when we started, we made a lot of acreage trades with Cabot and Chesapeake and Williams to block all this up into these drilling units. Then we had pipelines built through the middle of all these.
We can now sell gas from the Northern area to the Millennium Pipeline. We can sell in the middle to Tennessee Pipeline. We can sell in the South to Transco Pipeline. So we had three Interstate lines we can get into, you are probably aware that right now there is no demand for gas on these Southern lines. If you don’t have a long-term contract you essentially can’t sell gas.
We were offered basically $0.30 in Mcf last weekend for new wells coming on line. Fortunately we quit fracking about two months ago. So we are not bringing a lot of new gas on line. But this problem is going to exists in the Northeast every summer from here on out because the Marcellus and the Utica can oversupply the East Coast by themselves.
And we have to all figure out how to work around this and how to get gas from this area to an area where somebody wants it which is ironic that after building all these pipelines to the East Coast now we are trying to get the gas going the other way.
This is what the economics look like on that. This is probably the most profitable dry gas play in the country and you can see at $4 NYMEX that makes about 39% rate of return, really low operating cost here, the well is like almost no water. So this is not a bad play but it’s still not as good as the other ones we have.
And then this is Utica, this is the hottest play in the country right now that’s working and this is the Southern Utica around Cambridge, Ohio, Southeast Ohio. That red area is the outline where we’re buying acreage and you can see that little clusters of yellow polygon, so that’s our acreage and our goal is to stay in this band where we know we’ll make condensate.
The red outline circles all the wells that have made 1,000 barrels of condensate per day or more from Antero, PDC and Gulfport. So we’re still trying to buy acreage in this area. We have about 16,000 net acres in the play. Our private equity partner Avista has 16,000 net acres and they’ve put theirs up for sale.
So we’re watching to see who is going to bid on that and what they will pay and decide whether we want to be the ones to come in and try to buy their half. But this area is booming now; MarkWest and Williams have built pipelines all through here. So I know we can get our product to market, the only downside here is going to be the ethane and the future is probably going to be worth zero and it’s going to get taken to the Gulf Coast, because that’s the only place we can store and handle it.
So to sum it up, we’ve made the shift into premium basins. We have core acreage in all of those. We can prove that to anybody. Our peers in those areas are the big names in those plays. We have been able to maximize margins. We have been able to cut our debt. So we’re at a place now where strategically we don’t have to do much, we just -- we don’t ever need another acre and we’ve got a 10-year inventory in Eagle Ford and a five-year inventory in the Niobrara.
And so we think going forward. We can keep putting up large growth numbers for several years at some point and about year nine we need to find something else to do. But I am not too worried about year nine at this point. So thank you very much.
Kim Pacanovsky - Imperial Capital
Thanks, Chip. We have about five minutes for questions if anybody with, yes?
I was just wondering if you can talk a little bit about what’s going on in Colorado, there’s some [inaudible]?
We don’t know much about what goes on in Wattenberg, which is, I mean this is 30 miles East of [Grealy] [ph] and 100 miles East of the mountain. So we’re out in prairies. So that’s helped. I mean we don’t -- we didn’t have the funnel that [Boulder] [ph] got.
And so we haven’t had any flooding out here. Our only problem has been everything is on production but we’re filling up all of our tanks with oil because there aren’t enough trucks that were able to move around to haul it away. So at some point, we might have to shut some wells in until we can get the oil off of lease or we have to find other ways to store it on the lease but…
Right. We’re far enough East that we didn’t get a lot of flooding. I mean this is where the ranchers wanted the rain, so it’s far enough away.
The North plat runs through here, I think it runs about through here, but I mean this terrain is pretty hilly and so we haven’t had any problems. And if there are people out here though that have lost water and food and power, and so we’re helping with Noble, especially to raise money to support these people for a while until all that gets put back together. But the farther the west you were the more damage you have.
Just talk about the acreage pricing in Utica, you said you might want to buy [inaudible] what’s happen with acreage pricing?
The acreage pricing in this area has, across those red bands, on the right band it’s at least 12,000 per acre, on the left edge it’s probably 5 to 6. We have tried to buy three different deals in the play that I think AEP has beaten us on Aubrey McClendon's new company and the big buyers here are AEP, Eclipse, Paloma out of Houston is buying. Antero’s aggressively buying, they are the blue dots at the bottom and they’re going to do an IPO. So they’re trying to add acreage.
Gulfport is a competitor of ours, but I think they have so much acreage already. They’re all those brown dots that they have a great position. I don’t know that they need to be trying to add any to it.
But we’re buying leases probably 500 acres to 1,000 acres a month from landowners. There’re still landowners that haven’t leased. Most of them have some terrible title problem like 70% of the leases out here fail title the first time because nobody knows what they own but we’re still trying. I’ve been cut off.
Kim Pacanovsky - Imperial Capital
Yeah. Thanks everybody.
Okay. Thank you.
Kim Pacanovsky - Imperial Capital
And thank you Chip.
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