Energen Corporation (NYSE:EGN)
2012 Barclays CEO Energy/Power Conference
September 6, 2012 1:45 PM EST
James McManus – Chairman and Chief Executive Officer
Next, we have Energen Corporation, a company who has successfully transitioned itself into a Permian E&P player. It’s currently focused on exploring and producing wells in Wolfberry, Wolfcamp, 3rd Bone Springs and Cline. Here to present is James McManus, Chairman and CEO.
Thanks, Christine. It’s a pleasure to be here. I’d like to talk to you today really about some excellent results we are getting in the Permian, as well as an ever increasing inventory of things to do out there. We’ll making forward-looking statements so I‘d ask you to consult our SEC filings for more thorough discussion of uncertainties and risks. And with that, we’ll kick it off with Energen, a top 25 independent producer based on U.S. reserves, 3P reserves of 941 million barrel of oil equivalence. Since 2009 we really stepped it up in the Permian basin, a place we’ve been since the 1990’s but we invested another $900 million there and a company that has actively used hedging to protect cash flows.
If you look at our footprint you can the Permian basin now comprises 54% of our total reserves. We are the 12th largest producer in Texas of oil, with the 6 most active driller in the Permian basin currently with about 19 to 20 rigs running. Still have a lot of size and scale in the San Juan basin, it’s more gas prone as most of you know but there are also some oil plays being pursued there now. 38% of our reserves were the fourth largest producer in that particular basin.
If you look at our capital expenditures for 2012, it’s right about $1 billion for drilling and development. We did a $75 million acquisition that’s record capital for us. In 2011 we invested about $810 million, virtually all of that 96% plus is going into the Permian basin, we basically scaled back our gas related drilling at the end of July in the San Juan basin. You can see very active in the Wolfberry play. Total capital there of $450 million, 8 to 10 rigs, estimated production of little under $4 million barrel of oil equivalence. 3rd Bone Spring in the Delaware basin, another place we are very active with 5 to 7 rigs running, 43 in that well, an estimated annual production of 3 million barrel of oil equivalence and then our traditional properties in the central basin platform which is primarily been water floods that we’ve actively down spacing.
If we look then at our production growth particularly in 2012 you can see that the primary area of growth is the Wolfberry and the 3rd Bone Spring and that our other production, our other 5 million barrels of annual production in the Permian and the central basin is basically flat coming from our water floods and then you can see the rest of our production is basically flat in the San Juan and elsewhere.
So if we look at liquids really being the driver for us and when we talk liquids we really mean oil. You can see that in 2010, really in early in ’11 when we came out with what we might be able to do with liquids production particularly ramping up in the Permian, you can see that in 2010 in the orange and the green that we had about 7 million barrel of oil equivalence production at that time and we were talking about really scaling up in the Permian and almost doubling that liquids production in 2013. Now, the 2013 estimate is an old number that we came out with 11. We still believe we’ll be in that range when we put our 2013 budget together and announce it at the end of October. You can also see the three year growth rates in oil and gas and we basically taken the company from what was predominantly a natural gas producer to one that in 2013 will have more production from oil and liquids than it had from natural gas.
Then take a look at our reserves. Obviously the growth has really been on the oil side, we are now 54% oil and liquids improved reserves at 343 million barrels of oil equivalence. Problem possible on the right-hand of the slide amounts to about 598 BOE. I will point it out to you that we still have a lot of problem possible on the gas side when prices do rebound that we would be able to go after. I would also point out fees had not included in our P2, P3 numbers is in Wolfberry down spacing to twenties, no Wolfcamp or horizontal Cline in the Midland basin and the Wolfcamp and Avalon shale in the Delaware basin. So there’s a good bit of upside in seeing these numbers move as soon as we start to incorporate those formations in our P2, P3’s.
If you then just kind of look at our overall footprint here in the Permian basin. Again, we’ve been active here since the late 1990’s; we’ve got 275,000 acres roughly. As I mentioned earlier we beefed investing some $900 million in acquisitions of both leasehold and some prude properties since mid-2009. We got multiple opportunities out here which I am going to run through in great detail with you. We believe we got a decade or more forth for drilling out here now.
So if we then focus in on the Midland basin. You can see we have total acreage in the vertical Wolfberry play of 58,000, 32,000 net undeveloped which represents about 800 locations on 40 acre spacing. Now we are currently with our rig program of 8 to 10 rigs, drilling about 170 a year. So if you can add our 20 acre locations of 665, that leaves us with about 1,400 locations nearly 8 years’ worth of inventory in the vertical Wolfberry. Early predictable we are getting the kind of results that we expected out there. We can see our initial stabilized rate and 30 day rates.
If you take a look for a second at the producing zones, what we are trying to show you here is if you look at Martin County and move to Glasscock County which you’ll notice is that the Wolfcamp dramatically thickens as you move down into Glasscock County which will be relevant when I talk about the number of horizontal Wolfcamp locations that we have. In the Sprayberry we are doing pretty much what everybody else does, we go all the way to the Strawn, excuse me, we are doing a 6 to 8 stage frac at 3,035 hundred foot interval.
If you look at our IP curve, very similar to others EUR of 155, NRI of 75%, 2.3 million drilling complete a 33% pretax rate of return at $104. The gas really doesn’t matter because it’s mainly oil and some liquids. We’ll show you our sensitivity later on with oil prices moving down to $80 a barrel and what that does to returns. You can see the mix, again 61% oil, 23% liquids, very little dry gas.
We then take a look at look at our Wolfcamp potential; we’ve now added to this slide an outline of the Wolfcamp in blue. You will note on the slide in the box that we have participated with Laredo as a 21% owner of the Yellow Rose well which looks to be very economic, IP at 700 barrel of oil equivalent per day. You can also see that just to the South of us, there had been some 8 wells drilled through the last one I think was 6,000 through Lateral and IP did 900 barrels of oil equivalence. So we certainly think that the 25,000 acres we’ve got in Glasscock is in a great location. We also believe this other acreage we have is prospective bringing our total to 64,000 net acres of 785 potential locations on 160s, not on 80s but on 160s. You will also note that Pioneer, black dot on left hand side is drilled too pretty good looking, horizontal Wolfcamp wells as well.
We then move to our Cline potential in the Midland basin. You’ll see that we have an outline in red; the Cline potential is pretty close to Devon’s outline. We’ve done our own work and have adjusted it somewhat. You’ll also see that just to the North of us Laredo has drilled some 29 Cline wells with average IPs of 600 barrels of oil equivalence. And so again we feel like our acreage lies in a very good location. I think Devon talked today about drilling 15 Cline wells in 2012. I don’t know how many of those are round our Mitchell County acreage but we know they are going to be active up there as well, that would not have Wolfcamp potential also but obviously where you are within the blue boundary and the red boundary, you’ve got both Wolfcamp and Cline potential. We’ve got 80,000 acres in the Cline with 495 locations.
Now, if you look at how that stacks up, one of the important slides that show you was how the Wolfcamp thickens as you move from Martin’s to Glasscock and there are multiple benches. Now, the Yellow Rose, the well that we participated with Loredo and the Wolfcamps that they’ve drilled so far have all been uppers approach which is further South in the basin has tested the middle and lower benches a little bit. And I think is encouraged by what they see but we’ve quantified the number of locations that we have within each bench. Even if you put some heavy risking on this you wind up with 8 to 10 years plus inventory if we have some success and as I mentioned we are right in the heart of the play particularly right there in Glasscock County surrounded on both sides by Loredo.
We then shift gears to Delaware basin. This is an area where the company has had tremendous success particularly in the 3rd Bone Spring. You could see our results on there. Our initial stabilized rates have been over 1,100 barrels. Our 30 day rate very impressive close to 800 BOE per day, a high percentage of oil Energen has the distinction of having drilled the two best wells in the 3rd Bone Spring. The Black Mamba came on at 2,256 barrels of oil per day, 69% oil. That’s on a 1664 inch shock with 3,900 pounds of pressure on the well that could have flowed at much more than that had we decided to open it up. We’ve also drilled the second best well in the basin which was the Cadenhead well which came on at 727 barrels per day.
If you look at the Eastern side which is where we’ve concentrated in our core area, we’ve got about 80 3rd Bone Spring locations left over there. We feel like they are very predictable, very solid. We are actually outperforming our curve right now on the wells that we’ve drilled this year. We do plan to drill and are currently drilling three test wells in the Wolfcamp horizontally on the Eastern side of the basin. Hopefully we’ll have some results by October and you can see in the two white boxes on your screen that DHP is going to be drilling two offsets to two wells that they paid for to have drilled for by us that we will have a 50% ownership interest in. So the 3rd Bone Spring base of lie is 82,000 acres. Now, obviously 3rd Bone Springs that we drilled on the western side had a little bit more water. There’s not anything we’re going to take any action on right now. The focus seems to be on the Wolfcamp on both sides of the basis and the 3rd Bone Spring particularly on the eastern side of the basin. And then on course Avalon shale is up hole to the formation here. It’s more gassy. It typically is 50% to 60% natural gas and that’s why you’ve seen people sort of back away from it right now, saving it for a later day.
If you look at the strat graph here, you can see first and second our primary targets into Mexico. Where we are in Texas it’s mainly 3rd Bone Spring and then you’ve got 3 Wolfcamp lobes. Most people believe the lower is not that prospective in the Delaware basin, but the upper clearly is and the middle has yet to be tested. Obviously you hold to the deepest formation that you drill.
This is kind of our best return at the company right now and again we’re outperforming this curve so far year-to-date. 475,000 barrel EUR, 75% NRI drilling complete close to $7 million. You can see the product mix, 72% before tax return on 4400 laterals. I might mention that in the midland basin the laterals that obviously have a greater return are the 7500 foot laterals. A little bit of difference between the two basins, the midland basin is under pressured. The Delaware basin is over pressured and so people have not gone with the longer laterals out here as readily.
If you take a look now at our rates of return as they are, price sensitivities you’ll see that even all the way down to $80 and I’ll show you in a minute they were largely hedged at 90. The returns are pretty good and the gas number really doesn’t have a lot of bearing on it since there’s very little gas production even though we got that built at $4.
One of the things we’ve got in our portfolio is a very strong gas position. For years the company had double digit growth in the San Juan basin on the gas side. We are rate of return focused and we actually do what we say. So if gas prices drop we scale back gas drilling, even though we have some opportunities that could make a decent rate of return like our horizontal Frindland coal we’ve just chosen since it’s all held by production mostly to save that opportunity for a later day. What I’m showing you here is simply a time slice of the Mancos or Niobrara shale. Now, Encana is active here. They have recently talked about drilling horizontal wells in the Gallup field, not the Gallup formation but the Gallup field and they’re drilling it in whatever you want to call it. The Niobrara or the Mancos shale horizontally.
You can see we’ve posted one of their 30 day rates up there. I believe their slide has reserves they hope to eventually have at 550,000 and 4.2 million. We’re obviously very poised in this particular basin should oil take off with 81,000 acres held up by production in the oil space and then in the gas phase about another 59,000 acres up here where Williams has drilled a couple of wells and got decent EURs off the well. The gas prices simply weren’t there with the drilling cost to make that economic. I will also point out that Bill Barrett recently entered into a joint venture with Marion kind of right in this particular area for 25,000 acres. So with everything over here held by production we’ve got good upside on both the oil and gas side once gas prices turn around or once one of these other operators has some success here on the oil side.
If you then take a look at the company’s cash flows and balance sheet, that solid after tax cash flows of $794 million to 824 million. Energen Resources comprises about $700 million to $725 million of that. The utility operation is $100 million. The utilities basically cash flow break even once it funds its CapEx and pays out a portion of its earnings in dividends, usually about 65%. You can see our key assumptions on the left hand slide. I’m not going to run through all of those in detail, but you can see them per BOE or at least operating expense et cetera.
In 2012 we’ve got an out spend of capital about $250 million to $300 million by design. Three or four years ago we were very under levered company approaching almost 100% equity. One of the decisions we made at that point is we thought shale gas might drive gas prices down. We had no idea how right that assumption was going to be or how deep gas prices were going to go and so we chose to take our balance sheet and invest in oil at a time when oil was about $55 a barrel and so far it’s been a very good decision for us.
If you look at our cost to break even and our cash flow numbers, they’re also on there for 2013. One of the things that has set us apart since we’ve really been in the EMP business since the mid 1990s in a pretty significant way has been hedging and you can see that we’ve got a pretty deep hedge position and a fairly long hedge position as compared to most other operators in the business. The biggest risk we felt like we were facing when we moved into oil. We scaled up the number of rigs we contracted for the services that the only thing that could really dramatically go wrong was commodity price. We think $90 is a very attractive price where we can make very good returns. Some of the reason that the price is on here a little bit below $90 is we hedged some of those acquisitions in the $50s and those have not completely rolled off yet. But you can see our gas hedges is well or pretty strong. You can’t find those prices on the strip and several years ago we had some gas at right around five and we’ve added to that position.
So we’ve got the ability here to stomach some downward price in oil and not have to really change our program and that’s continuing philosophy that we’ll follow out into ’15, particularly if we can find oil prices in the $90 range there as well.
Now we do own a very small utility, very small part of the overall operations. It’s about 15% of the overall company. It’s got probably one of the best regulatory environments in the country and that after tax return you see on the slide equates to about a 21% pretax rate of return that’s not got a lot of risk associated with it. So the earnings of the company have been very good. It’s got all the regulatory whistles and bells that you could want. Temperature adjustment forward looking test year and you can see that the performance of the company has been very good in terms of its earning very close to its allowed rate of return.
Talk about dividends. The utility company does fund our dividend. We’ve had 30 years of dividend growth. The utility has about a 3% to 4% net income growth factor built into it by virtue of the way the regulatory process works and we pay out most of the earnings that fund the dividend from the utility.
So that’s pretty much the Energen story. We have shifted the company from gas to liquids and when I say liquids I mean primarily oil. We are now a major Permian driller as I mentioned. I think we’re now tied for fifth actually with Devin as the most active driller. We’ve got a very extensive inventory when you consider that horizontal Wolfcamp both in the Delaware and the midland basin are not really quantified into our reserves and we don’t think quantified a lot into our evaluation and the cline is also not built in there in any significant way and yet we’ve had excellent results in the 3rd Bone Spring in the Delaware basin and also in the Wolfberry. Our goal would be to continue to grow particularly our liquids at a double digit rate. We are not concerned about growing the gas side. In fact if we don’t spend any capital on gas since it’s mostly long line it will decline at about a 10% rate since we’re rate of return oriented and we’re not going to get real worried about what happens to that particular side of the commodity. Our focus is on the return side.
So with that, Christine that about sums up my presentation and I’ll be happy to turn it back over to you. Oh, be happy to take any questions that anyone might have.
Looks like I have done an outstanding job, Christine and we have any questions? Christine is going to break the ice.
You did a JV well with Laredo and you’re assessing results and sharing data and you have a whole bunch of acreage in that neighborhood that would be prospective for Wolfcamp or horizontal Wolfcamp. I guess what are your plans going forward? Are you going to continue to swap information with them? Or are you thinking about developing your acreage on a JV basis? Can you just give us some more color on that?
Yeah and actually the well we ran was not really a JV. It just so happened that they proposed well that we had a 21% working interest. So there’s no real JV with Laredo. But obviously we’re in touch with them. Our acreage lies contiguous to theirs and we’re certainly open to opportunities where we can find ways to be sure that we get the longer laterals. One of the issues you have is if you don’t have your land together to go over two sections then you need to cooperate in order to get those longer laterals and the other issue would be you can’t force pool in Texas so you’ve got to work with your landowners to the extent that you have uncommon ownership over that 7500 acre. So yeah, we’re absolutely open to cooperating and I think we’ll be swapping data with folks in the midland basin to the extent they want to just like we’ve done in the Delaware basin in both the Wolfcamp and the 3rd Bone Spring and a lot of these areas the acreage grab is over and so the competition is not that intense from an acreage perspective and people are more interested in everybody trying to be capital efficient and figuring out the best way to do it.
Any other questions? Okay, where is our breakout room Christine? Liberty 3 breakout room. Thank you.
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