Carrizo Oil & Gas' CEO Presents at Johnson Rice Energy Conference (Transcript)

| About: Carrizo Oil (CRZO)

Carrizo Oil & Gas, Inc. (NASDAQ:CRZO)

Johnson Rice & Company 2013 Energy Conference Call

October 1, 2013, 04:05 PM ET

Executives

S.P. “Chip” Johnson, IV - President and Chief Executive Officer

Analysts

Unidentified Analyst

[Call Starts Abruptly] …company has great acreage in the Eagle Ford, Niobrara, and Utica and has done a really impressive job transitioning to oil production.

Presenting for the company today is Chip Johnson, President and CEO.

S.P. “Chip” Johnson, IV

Thank you. I will get started. I don't know what caused the market to go up so much today, but I am going to make a contribution to Ted Cruz tonight..

I will start out with our strategy and go quickly through this, but the point that this is -- this is the strategy we essentially set for ourselves about two years ago. We have now accomplished these things.

In 2010, we decided we wanted to be oiler and not gassier, and we have now finished that process partly by selling off some assets, I will talk about that in a minute, but we've grown our oil production in the Eagle Ford and the Niobrara to now where we are going to have more than 50% of our production oil, 50% of our reserves oil, and more than 80% of our revenue oil.

We've been able to do this by keeping our financial resources under control, working on our balance sheet, getting our debt-to-EBITDA down from over 4 three years ago to now we are down to 2.5, and after we sell our Barnett Shale at the end of this month, we will be down to 2.

And that leads into prudently managed asset portfolio. In order to raise capital and reduce debt and ship oil, we sold off the Barnett in three blocks of a third each. We have also done some joint ventures with different Asian companies that basically sold equity in the ground in gas and oil plays, so that we could bring in new capital to not have to sell our stock.

We have a natural gas option, not as much as one as we used to which is fine with me, but we still feel like we need some exposure to gas upside, probably in 2016 and 2017, mostly in the Marcellus, in the C Counties, and in West Virginia, which needs higher prices than today to be competitive with the Eagle Ford.

We have drilled our first Utica well in Guernsey County. We will start fracking that Monday, it has an 8,000 feet lateral, it's in an area surrounded by PDC and Antero wells that have made a 1,000 barrels of condensate per day. So we’re not going to be real surprised by how this well does. We will rest the well two months and bring it on probably around the beginning of December. And then we’ve been able to deliver predictable results, I’ll show you that in a minute, we’ve had 11 quarters of oil production growth, revenue growth, and I’ll show you what that looks like.

This is what our second quarter looked like, 50% growth year-over-year in total production, oil production, EBITDA and revenue. We kept our drilling and completion CapEx flat, actually little under budget, which we’re very proud of. We’ve been trying to convince the market that we have financial discipline. While we did all that, we’re still able to add about 1,500 net acres in the Eagle Ford, which was a little more than what we drilled. So we’ve been able to preserve our 10-year inventory of Eagle Ford drilling at our current pace.

We had such good results in Eagle Ford that matched our new type curves that we’ve been able to bump our oil production guidance from 28% year-over-year to 45% from 2012 to 2013.

We increased our borrowing base. We should have a new number on the borrowing base at the end of this week, we don’t see anything changing there. And again, we reduced our debt-to-EBITDA down to 2.5, and with the Barnett sale it will be 2, which is well under the average for our peer group.

This is where we operate. We will be selling the Barnett, which is right there. We started in that in 2003, we kind of peaked in 2008, really built the company on the back of the Barnett, used that knowledge, moved into the Marcellus again focusing on dry gas, up until about 2010 when the futures prices on gas dropped, and we decided to get oily, bought into the Eagle Ford, mostly LaSalle County and also in the Niobrara in the Northeast extension, Northeast of the DJ Basin. Lately, in the last couple of years, we’ve been trying to buy the oily parts of the Utica, and I’ll show you how we’ve done at that.

This shows oil production growth, the top of the bar is oil production -- barrels of oil per day. You can see back in 2010, we were at about 770 barrels of oil per day net, now we’re over 12,000 barrels of oil per day net in about three years. The green bars are margins, so you can see our margins' grown consistently; we’re at $32 a BOE in margin. The Barnett itself is at $78 BOPD of margin.

This shows how our revenue has grown over 11 quarters, and the green is how much of the revenue is from oil, this little wedge is NGLs, and the rest is dry gas. In the fourth quarter, that will -- the red will drop even more as we sell off the Barnett. The total won't jump as much as it has in the past because of that sale, but we still think we’ll have quarter-on-quarter growth.

And in EBITDA growth, not always an increase over the previous quarter, because we’ve done asset sales and JVs, but we think still that was the right thing to do, and as we grew the EBITDA and cut our debt, and we got the debt-to-EBITDA down.

This is what our reserve picture looks like over in this chart. The lime green is the proved reserves, the dark green is the probable reserves. As you know, in a lot of these resources plays, the probable reserves are – essentially, they'll all become proved as wells just get drilled further and further into where you have undeveloped acreage.

If we have acreage that’s in between our wells and Chesapeake wells, it might not qualify as proved, but you’re only about two wells away from it and suddenly all being proved.

You can see we have a lot of acreage in the Barnett -- or reserves in the Barnett, but that was a pretty small part of our PV10 just because of the low value that dry natural gas had. The more impressive column is over here, that’s our PV10. When we sell off the Barnett that will drop by about $150 million but still $4.8 billion of PV10 of NAV. I’ll show you how we calculate that. With 40 million shares outstanding, it would be about $120 per share. We have less than $20 a share of debt. So we should be able to someday prove that we’re worth a $100 a share at PV10.

This is what the 2013 plan looks like and what it will develop. Three rigs running in the Eagle Ford. We’re testing down spacing from 750 foot between wells to 500 feet between wells right now. In the Niobrara, we have two rigs running. There we’re testing, we’re going from 80 acre spacing to 60 acre spacing, and those wells are being drilled now.

We say we utilize managed frac programs, basically that means we don’t have enough capital to frac all the wells we drill, so we drill all year but then we only frac about two thirds of every quarter. And so for instance, we just brought our frac crew back into the Eagle Ford. They will frac for about six weeks to two months. We haven't fracked a well in Marcellus for probably two months.

We probably have another two months before we start fracking there. Again, we just feel like we are already growing at a top 10% of our industry group, and we don’t want to add the debt as we think we are not going to get rewarded for the growth any more than we are going to get punished for the debt.

Some of the benefits here I mentioned, oil production growth to 45%. We can still keep our drilling and completing CapEx between $530 million to $540 million, grow EBITDA every quarter, keep the debt-to-EBITDA down, and we’ve been able to hedge about 80% of our oil production this year. I think we are at about 65% next year. We’ve been holding our hedging 2015 because it’s so backward dated, but I think we have about 30% hedged.

Gas will be very hedged now if we sell the Barnett and keep the Marcellus and keep all the hedges.

This is what the CapEx budget looks like this year; down from 2013 on purpose. In 2012, we had to run extra rigs to hold leases. We are almost finished with doing that now, so we’ve been able to drop some drilling rigs by not fracking as much. We still frac inventory so we have some nice options next year if prices stay high or EBITDA is high enough that we can get just frac wells and bring on production.

What this pie chart shows is that the split, most of the money goes into the Eagle Ford, $380 million of drilling and complete versus $70 million in the Marcellus, $60 million in Niobrara, and $25 million in Utica. Next year, the Marcellus would be just about finished. So, a lot of that capital will move into the Utica, at the -- spending in in Appalachia will stay about the same, but it will now be mostly Utica and oiled focused rather than Marcellus and gas focused.

We spent a lot of capital this year on land. We had an option with our private equity partner in Utica where they were putting up 90% of the capital to buy the land. We had an 18-month option to pay them back to see if we liked the way the Utica turned out. Well, we did, so in January, we paid them back about $70 million, so that $70 million of that $140 million went away in January.

I hope we have $140 million worth of opportunities next year, but we are seeing the opportunities dry up in the Eagle Ford and the Utica, or at least what we are willing to pay for.

This is what CapEx per quarter looks like, drilling complete, you can see we dropped down in 2013. We’ve been able to stay at a pretty levelled pace. We’ve been promising the market on that, and I think we delivered.

This is our NAV slide. We challenge anybody to find some holes in it. We start with our acreage counts and we discount that by everything we know about it in terms of 3D Seismic lease geometry, resistivity in the Niobrara, uneconomic or non-competitive gas prices in the Marcellus, and we end up with a net acreage count, then we do all of our PDP’s and PUDs, we end up with total undrilled wells; for instance in the Eagle Ford we have 417 locations. We can show you on a map. We know the length of every one of them. Those are all at 750 feet spacing.

We know what the reserves are going to be for all that, crank all that through and you end up with the NAV of PV10, using the strip, and that’s the backwardated strip. We still have $3.1 billion of NAV in the Eagle ford, which is about almost $80 a share.

This is at 750 feet spacing in the Eagle Ford and basically 80 acres spacing in the Niobrara. Both of those are being tested right now to down space. Both of those with, what we think is going to happen, would bump those numbers up by about a third in both undrilled wells and in NAV.

This is our Eagle Ford position in LaSalle and McMullen County. If you are familiar with the Eagle Ford, if you are too far up dip and shallow, you get basically dead oil, very hard to get it out, not enough gas. If you are too far down dip, where the play was discovered, you get dry gas or at best deep uneconomic wet gas. So, the play has migrated straight into this volatile oil window and condensate window which is where all of our acreage is except those blocks that were probably never drilled.

All the stars indicate drilling pads we’ve already drilled on. We’ve been drilling three well pads since the get go here. We have Ryder Scott type curves on every one of these different areas. So, we know exactly what the economics, GOR, the well length, the number of fracs is going to be on every one of these wells. We can show in great detail what this is going to turn out to be.

We’re in an area where our competitors here are EOG here, Chesapeake here, and El Paso here, which means great comps and great competitors, people that are pretty easy to do deals with in terms of joint drilling, but nobody’s giving up any acreage. So it’s very hard to get any acreage here.

The acreage we’ve been buying has just been except for one block we were able to buy here from a company that wasn’t able to drill in time before the leases were about to expire, most of it's just bolt-on acreage up here. We have been able to buy enough acreage to exceed our drilling rate. So, we still have about a 10-year inventory.

The other thing we have here is pretty high priced oil. This is our type curve; let me talk about that first. Last year, we were using this red type curve, that’s production versus time, and this is cum versus time. At the end of the year, after Ryder Scott did their analysis, at this point we had about 90 wells for them to analyse. They gave us these higher curves.

We didn’t believe it until about midway through this year, and now we’re basically tracking this curve, and that green curve, and that’s why we’ve been able to increase our guidance periodically because we’ve basically been using pretty conservative type curves, but want to see more data to prove it.

And then this shows our economics, and this is what I was talking about. 96% of our revenue comes from oil and of that oil, 87% of that is API gravity of 45 or lower. We’re basically getting the premium for that crude. The crude, we get deduct for 50 gravity or higher is only 3% of our mix. So we’re in the right spot, we’re getting LLS pricing for this. We’re getting around $107 today. That lets us have economics like this, 98% rate of return at $100 NYMEX. Our average well we will have this year will have 23.3 stages, and be 5,600 feet long, recover 495 MBOE, and we’ve got this nailed.

This is our Niobrara position. We started buying acreage here in 2010, Northeast of Wattenberg and then Northeast extension, which at that point was basically an EOG discovery. Wattenberg is down here at the Southwest in Denver. The Jake well was up here, we started buying across here and further up into the areas that are now called East Pony, which is this area and Red Tail which is the Whiting area. So we have Noble as a partner here, Whiting as a partner here.

We have two rigs running here, two extreme rigs in Canada. We can drill these wells in about nine to ten days, average well cost is about $4 million. This is what the economics look like here; great economics, but not as good as the Eagle Ford. So this is kind of our tier 2 project right now. We sold some of this down last year to partners. We’re still trying to figure out exactly what the spacing is.

The other thing we’ve done is only drilled Niobrara B Bench wells because it is uniform across our acreage. There are A pods and C pods that need to be tested. And I think especially Noble right here has about a 28 well pilot plan that we will be a very small partner in but we get still a lot of data on exactly what the right spacing is and whether the A, B and C all be drained effectively.

This is our Utica position, this is the Southern Utica, this is Guernsey County right here, Harrison County is up here, Northern Noble is right here and that’s where we have focused. We have about 16,000 net acres in the play, 12,000 is in these blocks that we call this basically our Northern Guernsey Gulfport block, our Southern Guernsey PDC block and our Northern Noble Antero Block.

So we’re mixed in with all those three companies in all those areas. The red outline basically is the outline of all the 1,000 barrel a day condensate wells that have been announced in the play. So that’s been our focus, try to stay in that area.

We want the certainty of the condensate, we’re still little bit nervous about ethane and what we are going to do with ethane now at this play in the future. We drilled our first well here, the Rector well, an 8,000 foot lateral. We start fracing that Monday. It will probably take a couple of weeks to frac. We should have results on that in December. We are planning to rest that well two months. We could shorten that a little bit but we are basically just going to watch everybody around and see if anybody changes from that, the results on wells that are been rested less than that lately haven’t been that stellar so we are kind of still thinking 60 days is the right amount.

We are still trying to buy acreage inside that window. We’ve been beaten by an ex-Chesapeake employee on three different deals in this area. Our partner Vista is actively trying to sell their acreage right now. We are waiting to see what kind of offers they get and see if we can come in at the last minute and may be pick off some of the acreage, the best acreage that we like the most in areas where we can pay what we think is a market price depending on what this ex-Chesapeake employee does.

This is the last of our Marcellus acreage that we are drilling in Northeast PA. This is Northern Susquehanna County, this is Wyoming County. Cabot is everything between us and Chesapeake is up the left side of this. As you know these are some of the most prolific dry gas wells in the country, probably the best economics of any dry gas wells in the country.

This low 10,000 acre position we will be making about 300 million a day gross next summer when we have finished drilling and fracking about the last 30 wells that we have left here. When we finish drilling here at the end of this year except for testing the upper Marcellus and down spacing which will happen in the spring but we’ll have everything fracked in the spring of next year selling gas mostly right now to Millennium up here with some long term contracts to [Ramapo].

This is Tennessee, right now we were not putting any new gas on Tennessee because the prices are so low. But on Wyoming we can take gas down to Transco. Transco’s prices have bumped up in the last week to an acceptable level so we are pretty happy with that. This is been a great project for us it was just hard to get acreage here and that was we were all able to put all together.

This is what the economics of this play look like and I assume some of the dry gas Utica will be the same at $4 NYMEX we are still very healthy prices and actually some of the wells we drilled Wyoming County are better than this they are going to be close to 10 BCF wells so that will jack these economics even more and the dry gas Utica could also be in the same boat.

So to summarize we’ve made the shift to oil. We are basically done with the hard work of selling assets buying big blocks of acreage in oil plays, doing JV’s to raise money that’s all behind is now it’s just about execution and where we can pick up more acreage in our key areas, we’ll be doing that.

We’ve been able to sustainably grow production and meet our numbers and also fix our balance sheet, get our debt-to-EBITDA down to two which is below the average of our group at 2.6.

The capital program is very flexible, we’ll have everything held as far as drilling at the end of this year in the Marcellus and the Eagle Ford and the Niobrara. So drilling could fall away and we’d still have a big inventory of wells to get fracked next year to bring production on or we have an inventory that we’ll get a sell rate if we have the capital to do that. So we could get through some sort of a crisis if we had to with our production that’s already basically behind pipe in hedges.

And we think we are doing a right thing in the Utica. We might have been slower to drill in the Utica. We thought like was a better use of capital to put that money in the land and let very confident companies drill wells around us because the infrastructure is still not there and until the infrastructure is there, there is not a whole lot of point in us bringing on production.

So with that I will finish, showing in Eagle Ford location and go to breakout.

Question-and-Answer Session

[No formal Q&A for this event]

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