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Energen Corporation (NYSE:EGN)

Q4 2012 Earnings Call

January 24, 2013 11:00 AM ET

Executives

Julie Ryland – VP, IR

James McManus – Chairman and CEO

Chuck Porter – VP, CFO and Treasurer

John Richardson – President and COO

Analysts

Mario Barraza – Tuohy Brothers

Holly Stewart – Howard Weil

Moe Dohane

Joe Magner – Macquarie

Mike Matus – Citibank

Operator

Good morning, ladies and gentlemen, and thank you for waiting. Welcome to the Energen Corporation 2012 Financial Results Conference Call. All lines have been placed on listen-only mode and the floor will be open for your questions following the presentation.

Without further ado, it is my pleasure to turn the floor over to your host, Ms. Julie Ryland, Vice President of Investor Relations. Ms. Ryland, the floor is yours.

Julie Ryland

Thank you, Erin, and good morning. Today’s conference call is being held in conjunction with Energen Corporation’s announcement yesterday of the results of operations of the three months and 12 months ended December 31, 2012.

Our comments today will include statements expressing expectations of future plans, objectives and performance that constitute forward-looking statements made pursuant to the Safe Harbor provision act – I’m sorry – the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. All statements based on future expectations are forward-looking statements. These are dependent on certain events, risks and uncertainties that may be outside the company’s control and could cause actual results to differ materially from those anticipated. Please refer to the company’s periodic reports filed with the SEC for a more complete discussion of the risks and uncertainties that could affect the future results of Energen and its subsidiaries.

At this time, I will turn the call over to Energen’s Chairman and Chief Executive Officer, James McManus. James?

James McManus

Thanks, Julie. Good morning to you all. 2012 was a busy and exciting year for Energen that sets us up in 2013 to generate strong growth in liquids production from existing plays while exploring several emerging opportunities in the Permian Basin.

Our record level of drilling activity in the Permian Basin resulted in an 18% increase in production, including a 40% increase in oil volumes. Total production in 2012 was a company record 24.1 million BOE.

The performance of our 3rd Bone Spring and Wolfberry wells was strong. In 2012, we drilled 40 net 3rd Bone Spring wells. The average initial stabilized rate of 35 net wells tested was more than 1000 barrels of oil equivalents a day and was 68% oil. Over the course of the year, we drilled 167 net Wolfberry wells. We actually tested 172 net wells and they had an average initialized, stabilized rate of 90 BOE per day and were 75% oil.

We see the continued development of these two plays driving strong double-digit production growth in the Permian Basin in 2013. We also quantified our 1,880 net potential Wolfcamp and Cline locations in the Midland Basin and Eastern shelf in 2012 and look forward to beginning our operated exploration of the Upper Wolfcamp and Glasscock County in the second quarter of 2013.

In the latter half of 2012, we began to take a closer look at the Wolfcamp potential on our Delaware Basin acreage east to the Pecos River with the drilling of five operated wells, primarily in various Wolfcamp targets. We reported the results of the first of those wells last quarter and the other four are in various stages of completion and testing.

Earlier this month, we spudded the first well on our 2013 operated program in the Upper Wolfcamp, and BHP is currently completing a Wolfcamp well in which we have a 50% non-operated interest in Reeves County, near our state C-1915 well or their 1915 well. The bottom line is that the success of even one of these emerging horizontal plays obviously offers significant opportunities for active drilling in the Permian Basin in the coming years.

2012 was not problem-free, of course. For example, in the Permian Basin, we and other operators dealt with issues such as transportation and infrastructure constraints and basis blowout, issues that we expect to improve as 2013 progresses. Significantly lower natural gas prices resulted in a write-down of some of our East Texas properties and led to a significant downward revision of our 3P gas reserves.

Perhaps the most important thing about 2012 is that we learned more every day about the new generation of plays, both in development and emerging, that we are giving new life to the Permian Basin; that holds a substantial value for Energen.

At this time, I’d like to ask Chuck Porter, our Chief Financial Officer, to review the key financial results of the fourth quarter and calendar year of 2012. After that, I’ll talk a little bit more about our year-end proved, probable, and possible reserves, and our outlook for 2013, then open the door for questions. Chuck?

Chuck Porter

Thank you, James. Excluding the non-cash mark-to-market gain on certain hedging contracts, Energen’s adjusted net income in the fourth quarter totaled $47.2 million or $0.65 per diluted share. In the same period last year, adjusted net income totaled $71 million or $0.98 per diluted share. Production increased 14% over the same period last year to 6.2 million BOE and realized oil prices were up 3%. Our realized NGL and gas prices were down 21% and 25%, respectively.

Depreciation expense was higher in dollars and on a per-unit basis. This primarily is the result of continuing to grow our oil production, which inherently has higher associated development costs than does natural gas. And another contributing factor, although to a much lesser extent, was the price-related loss of some of our year-end proved reserves. Lease operating expense was high in the fourth quarter of 2012 as well, largely due to high water disposal cost, workovers, ad valorem taxes, and equipment rental. As some of these increases were offset by lower O&M expense, which was primarily associated with San Juan basin compression.

Energen did not incur any dry-hole expense in the fourth quarter of 2012. We did, however, write-off $5.3 million of Delaware Basin leaseholds set to expire in the first half of 2013. On an after-tax basis, this charge impacted net income by $3.4 million or $0.05 per diluted share. The bulk of these 4,380 acres was located west of the Pecos River in Reeves County, Texas.

In looking at the full calendar year, net income adjusted for non-cash items totaled $229.7 million or $3.18 per diluted share. Adjusted 2011 earnings were $283 million or $3.91 per diluted share. 2012 production of 24.1 million BOE was up 18% from the prior year and the average realized sales price of oil increased 5%.

The decrease in net income relative to 2011 was driven primarily by realized NGL gas prices that were lower by 18% and 30%, respectively. And as with the fourth quarter, DD&A and LOE were higher. Net income at Energen’s utility unit increased $2.8 million to $49.4 million as it earns on a higher level of equity.

And with that, I’ll turn the call back to James.

James McManus

Thank you, Chuck. Our proved reserves at the end of the year were essentially unchanged at 346 million BOE, but that included a significantly lower gas commodity price that resulted in a huge downward revision of our gas reserves. Primarily, the total revision was 43 million barrel of oil equivalents. Had it not been for that, we would have had a pretty good growth rate in our proved reserves, but they did stay essentially unchanged even with that downward revision.

We also produced 24.1 million BOE during the year. These items effectively offset the addition of approximately 58 million barrels of oil equivalents of reserves, primarily due to proving up previously unproved reserves. We also added some 12 million barrel of oil equivalent of mainly Wolfberry reserves through acquisitions of proved properties and leasehold.

Obviously, when gas prices do rebound, we’ll be getting those reserves back. The gas price used to calculate year-end reserves fell from $4.12 per MCF last year to $2.76 in 2012. The natural gas liquids price dropped from $1.23 per gallon to $0.88 per gallon, and oil prices fell as well, from $96.19 per barrel to $94.71 per barrel. In the unproved categories, probable reserves totaled 114.2 million BOE at year end, and possible reserves totaled 292.4 million BOE, for a total of 407 million BOE. This, of course, is down from the 598 million BOE at the end of 2011.

Again, the same theme, the substantially lower gas and natural gas liquids prices resulted in the loss of approximately 137 million barrel of oil equivalents of unproved San Juan reserves. In the Delaware Basin, 3rd Bone Spring reserves west side of the Pecos River were revised down by some 64 million barrel of oil equivalent. Approximately 54 million barrel of oil equivalent of prior year unproved reserves, primarily in the Delaware and Midland basins, were proved up.

Net reserves primarily reflect 36 million BOE of 100 net Upper Wolfcamp locations that we added in Glasscock County in the Midland Basin and 18 million BOE of acquisition-related Wolfberry reserves. The 100 net Upper Wolfcamp reserves were based on gross EURs of 460,000 BOE per well, assuming a 160-acre spacing and 4400-foot laterals. Not yet reflected in Energen’s probable and possible reserves are Wolfberry down-spacing, horizontal Cline potential in the Midland Basin, horizontal Wolfcamp in the Delaware Basin, and horizontal Avalon Shale in the Delaware Basin. Energen also has identified 685 net horizontal Wolfcamp locations that are currently not included in the company’s unproved reserves.

We had a total of 785 and as I mentioned earlier, 100 of those net Upper Wolfcamp’s moved into the 3P reserves. Our total 3P reserves of 753 million barrel of oil equivalent at year end 2012, more than 55% are oil and natural gas liquids, and over half reside in the Permian Basin.

Yesterday, we reaffirmed our various guidance items for 2013. We plan to invest $875 million to explore and develop our Permian Basin assets, including drilling 299 wells. We plan to invest only $25 million in our traditional gas basins, and this will be primarily recompletions in the San Juan basin that have really good economics, even at low gas prices. We estimate that production will increase to 26.1 million BOE in 2013, and we estimate that consolidated after-tax cash flows will range between $917 million and $946 million.

An important part of our financial picture in 2013 will again be an excellent hedge position. Approximately 70% of our total estimated production is hedged, including 84% of our estimated oil at over $90 a barrel, 31% of our estimated NGL production at more than $1 a gallon and 69% of our estimated natural gas at more than $4.60 per MCF. In addition, we also have hedges in place that limit our exposure to the volatility in the WTI Midlands to WTI Cushing differential. In fact, that differential has been hedged on approximately 60% of our 2013 oil production.

With that, I’m now going to move into Q&A, and I would turn the phone line over to our facilitator. Erin, if you could start that process, please?

Question-and-Answer Session

Operator

Certainly, the floor is now open for questions. (Operator Instructions) The first question we have is from Mario Barraza. Mario?

Mario Barraza – Tuohy Brothers

Good morning, guys.

James McManus

Good morning.

Mario Barraza – Tuohy Brothers

How’s everything going?

James McManus

Fine.

Mario Barraza – Tuohy Brothers

That’s good. Hey, just wanted to get some more color around your horizontal Wolfcamp type curve. Can you just talk about how you came up with the 460,000 barrels of equivalent?

James McManus

Yes, Mario, I’m going to kick that one to Johnny.

John Richardson

Yes. Well, that’s based on a 4400-foot lateral, 6000 – I’m sorry, a 160-acre spacing well. And there is a body of data out there. Two things, one is you always want to look at volume metrics on the Upper Wolfcamp, which is what we’re referring to here. Looking at recoveries and in traditional shale-type plays, what is your recovery of resource, and the 460 fits very nicely there from a recovery standpoint. Also, the data we have with a lot of other operators have done in that area in analyzing the data that we’ve seen from them and the public data, and indicates that’s the right landing spot from what we know right now on the current completion methods for that potential resource

Mario Barraza – Tuohy Brothers

Okay, so when you talk about – when you say Upper Wolfcamp, are you meaning more – I mean some operators have been targeting more of the B zone. Is this a mix of A and B, or would this be more...

James McManus

It’s not, Mario. When – there’s two nomenclatures out there to confuse the world. There’s A, B, and C bench, which is basically, under our terminology, is upper, middle, lower. What we have booked on is upper right now, which would be equivalent to the A bench.

Mario Barraza – Tuohy Brothers

Okay.

John Richardson

And where we are, that’s where most of the completions have been made – in the particular area where we’re looking at these 100 locations.

James McManus

And you know, we had an interest in one well – just to add a little more color – I’m sure you remember the Yellow Rose that Laredo drilled that we had an interest in. That was a 4400-foot lateral.

Mario Barraza – Tuohy Brothers

Yes.

James McManus

That was in Upper Wolfcamp, that performed very well.

Mario Barraza – Tuohy Brothers

Yes, Okay. So basically that’s what you are going after...

James McManus

And basically, as you know, these aren’t proved. We’ve booked these as – I think these are – are these possibles?

John Richardson

Yes.

James McManus

These are booked as possibles...

John Richardson

Possibles probables. There will be some combination.

James McManus

A combination.

John Richardson

The Yellow Rose is on the property.

James McManus

Okay, well, combination of probable and possible, and we won’t drill our first one out here, as I mentioned, until sometime in the second quarter.

Mario Barraza – Tuohy Brothers

Okay. And with these test wells, what would you need to see in order to accelerate the activity on the horizontal front here?

James McManus

Well, as we’ve talked about consistently, I think we’re planning on running a rig out there starting in the second quarter. We’ve also mentioned that we’re in discussions with some operators about partnering with them on some wells. So I think this is a year of seeing what we have out here. I don’t think this is the year we are going to press the accelerator, but I do think this is a year that we’re going to start to identify what we’ve got and based on those results, obviously then we would decide when we really wanted to ramp up from a perspective of horizontal rig count, which could occur as early as 2014 if we have good results in 2013.

Mario Barraza – Tuohy Brothers

Okay. And then if I can jump over to the Delaware Basin, just one more question. I noticed you guys have started listing the vertical Wolfbone, in addition to the horizontal Wolfcamp.

James McManus

We have.

Mario Barraza – Tuohy Brothers

Are you at all planning to test for that this year?

James McManus

We are.

Mario Barraza – Tuohy Brothers

How many of you – I’m sorry, if you’ve said this before, how many wells are you looking to test?

James McManus

We’ve got three that we’re looking to test this year. There’s been some encouragement. The Wolfbone play was primarily south of where our acreage position was on the western side, but there’s been some work done that leads us to believe that that may have some promise on the western side, and even in some areas on the eastern side that are close to the river. So the idea here, when we say Wolfbone, because there’s a lot of water in the 3rd Bone Spring on the western side, we’re thinking more some of the sands up-hole from the 3rd Bone, 2nd – 1st, 2nd, maybe even some of the shales in between.

Johnny, do you want to add some color?

John Richardson

Yes. Of course, yes, we want to look at the Wolfcamp in that area, which is largely untested. It’s a good way to test that. It’s also a good way to isolate and look at different formations as we are completing them, which you can’t do in a horizontal arrangement.

And we are quite encouraged by the results that others have had. As James pointed out, that play has grown up out of Pecos County into more of the areas where we are and continues to grow sort of north and west. And we think that there’s a lot of good data and good production, hopefully, to be gained from that application.

James McManus

I don’t want to get us ahead of ourselves here, Mario, but one of the things about the western side is our focus on the Wolfcamp has been – horizontally, has been east.

BHP and some others have done some stuff on the west. One of the things that it could afford you if the Wolfbone play worked on the west, is it would give you a vertical way to hold that acreage while you were thinking about what you might want to do horizontally in the Wolfcamp.

So that’s another plus of looking at it that way. So I don’t know that we’re going to do that yet. But if it worked over there, that would certainly be a way to hold that acreage.

Mario Barraza – Tuohy Brothers

Okay. Could you remind me how much acreage you have west of the Pecos, again?

James McManus

My last count – and I’m looking around the table here – was it was pretty evenly split, 55,000 on each side. Was it 53?

John Richardson

That’s close.

James McManus

Okay. 53 on the west.

John Richardson

And then we broke off.

Mario Barraza – Tuohy Brothers

And then when you – where is this – the Delaware Basin acreage going to expire? So would this go to high 40s after you left the acreage?

James McManus

No. We took some off, as Chuck mentioned. What was the acreage amount there?

Chuck Porter

We’re 4,300.

James McManus

4,300. Okay.

John Richardson

50 – 55 down to about 50 now.

Chuck Porter

Yes.

John Richardson

Call it 50.

James McManus

So let’s call it 50 west. And then in the latter half of 2013, if we didn’t either renew or hold, what is that acreage number?

John Richardson

We may have to get back to you on that.

Chuck Porter

A little over 9,000.

John Richardson

I think it’s...

James McManus

All right. A little over 9,000.

Chuck Porter

In the last half of 2013, there is 9,652 acres that would be expiring in the last half of 2013 and approximately $13 million on a pre-tax basis. But we consider most all of that to be still very highly prospective for the horizontal Wolfcamp and the Wolfbone that James was just discussing.

James McManus

Yes. Now, bear in mind there are ways to extend some of those leases as well. So it’s not like it just would all go away if we don’t drill on it. But that’s the – that’s what we – if we let it all expire, which at this point we don’t have that intention, you’d be talking about another 9,000, roughly, acres.

Mario Barraza – Tuohy Brothers

Okay. All right. Thank you very much for the questions.

James McManus

Thank you.

Operator

Your next question comes from Holly Stewart. Holly?

Holly Stewart – Howard Weil

Good morning, gentlemen and Julie.

James McManus

Good morning, Holly.

John Richardson

Hey, Holly.

Holly Stewart – Howard Weil

James, first, you talked about some infrastructure constraints you’re seeing in the Permian. Can you just give us a little color around what’s going on out there and then maybe a timeframe in terms of when things might be resolved?

James McManus

Well, we’ve got a marketing person who works on that fulltime. And just to kind of get down to the bottom line, we have built some of that into our first half of the year numbers as we’re working our way through this. But the bottom line is that, by mid-2013, we think there’s going to be adequate capacity, adequate NGL frac and take-away capacity. So we see, with all the pipelines under construction and all the work being done, that hopefully by mid 2013, we’re through this. Doesn’t mean it can’t happen again, but there’s at least going to be a point of relief, I think, starting in the middle of 2013. Have you got any – anybody got anything else they want to add to that?

John Richardson

I think that’s both intra-field kind of movement and inter, more globally moving product out of the basin. So we look for a lot of relief midyear.

Holly Stewart – Howard Weil

So I’m assuming, Johnny, you’ve got quite a bit behind pipe right now?

John Richardson

Well, you can term it that. We have still got constraints of moving product in some of our areas because of line pressures and so forth. So we see that relieving plus the total global situation of liquids being able to move – both liquids and oil being able to move out of the basin, because we’re basically impacted on both those products, gas, liquids, and oil. Transportation, it’s a very full system out there right now. We do see that relief coming midyear from what we...

James McManus

Yes. And Holly, we’re not – just to add on to what Johnny says, we’re not the only one seeing that. If you look at the Midland to Cushing spread, you’ll notice in June it drops back to $1. And so the market is anticipating that things are going to be okay, particularly from an oil perspective, because that differential comes back down. Now, are we all right? Who knows, but at least the market also says that as well.

Holly Stewart – Howard Weil

Okay, perfect. And then just the NGL environment out there, I know your volumes have been a little bit lighter than initially you had expected. Just kind of what’s going on in terms of ethane rejection, et cetera?

John Richardson

Ethane rejection in the second half of 2012 was more severe than we had planned. Of course, we do our budgets and we look at things in August and September. So in August and September of 2011 we thought we had the right approach, given what our marketing and processors were telling us. It turns out the last half of the year was more severe than we had anticipated. We have let that flow into 2013 from what we saw the last half of the year.

We’ve made judgments again on what people are telling us, how much relief we should give our self as the year goes along. And we’re basically, we’re back to very little rejection by the summer; or, by the second half of 2013, we anticipate seeing very little rejection. But in the first half, we have continued that – the kinds of rejection we saw at the end of 2012 into 2013.

James McManus

Holly, I might get Johnny to mention, to, we’ve got a pretty good uplift in NGL production in 2013, and Johnny, why don’t you talk a little bit about – I know you didn’t ask the question, but I’m going to use this as an opportunity to get him to talk about the factors surrounding our NGL increase, one being that obviously you’re eliminating a lot of ethane rejection in the second half of the year. But the other is our wells in the Delaware Basin.

John Richardson

Our Delaware Basin, as we’ve talked in the past, we were delayed getting the gathering system in there. That did come on in the fourth quarter last year, about midway through. And it continued to grow to the end of the year. But we haven’t seen the ethane rejection in the Delaware that we’ve seen in the Midland Basin. So two things; one is, a lot of gas came on, and that gas is – ethane rejection is not bad on that. There’s some mild, but that – we’re seeing more like 130 barrels per million yield there, where we were seeing in the 90s over in the Midland Basin, yield-wise. So we did see a good bit of ethane growth in the last quarter. It’s due to those two factors. More gas with less rejection in the Delaware Basin.

Holly Stewart – Howard Weil

Okay, well, that’s perfect. That helps bridge the gap, kind of, to the guidance. So that was actually my next question.

James McManus

Well, I can read your mind.

Holly Stewart – Howard Weil

There you go, perfect. Finally, James, you’ve kind of been quiet here on M&A side the last few quarters. I know you’re typically out there in the market, so can you kind of just give us a little bit of color on what you’re seeing, and maybe some thoughts around the go forward?

James McManus

Yes. I think there continue to be things out there, Holly, and on a very selective basis, I think we’re looking more at small additive increments, both in the Delaware and the Midland Basin. I don’t see us doing anything major or big unless the – it was just a dream deal, which never – you can’t ever draw up the dream deal. You can talk it about you’d do it if you saw it. But for the most part, I think we’re going to be looking at pretty small stuff over this year as we see how our exploratory plays develop, because if they develop, the type of capital that they could command would be substantial and we’d hate to get our balance sheet over-extended on acquisitions when we’ve got some potentially very high rate of return projects.

At least to just kind of address that a little bit. I’ve talked about this with most of the people who were on the call here before. But just to reemphasize, obviously the Midland Basin is further along in terms of innings of a baseball game. It’s clearly in the third or fourth inning. There’s been a lot of work done by a lot of operators, and our external auditors felt comfortable enough to give us some P2, P3s in the Upper Wolfcamp, particularly in the area in Glasscock County where a lot of this success has occurred.

In the Delaware Basin, obviously we’re in the early stages of that and we probably are doing more wells than anybody else other than BHP, who’s drilled a lot on the western side. But either one of those two, would they prove to be pretty successful, would give Energen a lot of running room. Both of them are successful, it’s a tremendous amount of running room. And so I think, until we see some clarity on that kind of growth, which could be very high rate of return growth, we’re only going to be looking at acquisitions where we feel like we’re getting a lot of upside in addition to the proved reserves that we don’t have to pay for. Those are hard to find, large ones like that. But on a smaller scale, we do occasionally find those opportunities.

Holly Stewart – Howard Weil

Great, that’s all I had. Thanks, guys.

James McManus

Thanks.

Operator

The next question comes from Moe Dohane. Moe?

Moe Dohane

Yes, good morning, guys.

James McManus

Hey, Mo.

Moe Dohane

Hey, got two questions. Just – the first question is on the reserve report you guys have. The revisions in the Permian Basin and San Juan, was that mainly due to weaker prices in gas – natural gas liquids?

James McManus

Yes.

Moe Dohane

Or was it some reservoir issues as well?

James McManus

Yes, let me split that out. So San Juan is pretty much price related, okay, gas prices being lower. But as you go to the Permian side of things, a very small section of that is price related. We did have some revisions in one area on the Wolfberry. And let me just kind of describe that in an area that we call Five Stones, which is in the southern area, we have about 9 million barrel of oil equivalents revision there. Now, most of that – can you hear me clearly? We’re getting some static on this side.

Moe Dohane

Yes.

James McManus

Okay. So of the 9, about 6 million of that was related to PUDs and about 3 million to proved developed, producing. What we found in that particular field of the Wolfberry is that using cross-linked gel, while the initial rates were performing fine, that these wells started to fall off.

As we started to study that, we’ve now looked at slick-water frac being the proper antidote to solve that problem, and we’ve been very encouraged. We’ve done, now, how many, Johnny, in slick-water frac? 7 to 10, something in that neighborhood?

John Richardson

At least that many...

James McManus

At least that many, and they have come on and held up well. So we think we’ve got that problem solved. And in fact, when we go back in to drill these PUDs, if we get the same sort of success we’ve got with the slick-water frac, we’re going to get those reserves back. And of course, that’s no additional cost because it’s just the cost to drill and complete like we normally would.

And then, on the other side of that, the other 3 million, we could do some recompletions. So we’re studying that, of course, that would be additional costs. So, yes, we did have a little bit of a reservoir performance in the Wolfberry area, particularly as you got sort of the 30, 60-day rate in one particular area. And again, we think we’ve got an adequate solution for that. And so let me stop there and see if you have any follow-up.

Moe Dohane

Switching to the drilling program for 2013, any color on the six Wolfcamp that you plan to – Wolfcamp Cline shale you plan to drill in the Midland Basin? Any color on the counties, how many Cline wells will you do or Wolfcamp?

James McManus

Yes, I can tell you what our intention is. We might change your mind, obviously. But right now, we’re going to start in Glasscock County near where the successful wells have been. That would be our intention. And as I mentioned, we have a rig moving in there and we’re going to drill Upper Wolfcamp probably first. I’m not sure yet whether we’re going to do a Cline.

The Cline reservoir looks attractive, don’t get me wrong, but the Upper Wolfcamp in terms of in-place oil, resource potential, looks to be better. Doesn’t mean that you wouldn’t eventually get to the Cline, it just means that for our money right now, we’d rather concentrate on the Upper Wolfcamp.

Now, in addition to that, doing our own thing with our own rig, we’ve also been in discussions with folks out there about maybe doing something jointly in order to also get some longer laterals in than the 4,400 laterals that we probably plan to do initially, which are similar to the Yellow Rose. And so don’t be surprised if we do even a few more wells with somebody else.

Moe Dohane

Okay, thank you so much, that’s it for me.

James McManus

Thank you, Moe.

Operator

The next question comes from Joe Magner, Joe?

James McManus

Hey, Joe.

Joe Magner – Macquarie

Good morning, thanks.

James McManus

Yes.

Joe Magner – Macquarie

I might have missed it, but on the San Juan, 2P/3P revisions, was that all tied to price, or were there any performance-related revisions there?

James McManus

It’s virtually all price. Everything we’re feeling on the gas side is price related, and we would fully expect that those reserves are going to come back when prices rebound. It’s really kind of a shame. We had a great year for proving up reserves, had over 50 million barrels of oil equivalents. And had we not had the substantial gas price, we would have had really good growth in the company.

Joe Magner – Macquarie

Great, and any update on any Niobrara well performance, either...

James McManus

I can only tell you what you may have also seen. Encana obviously released some data. Obviously, we’re not planning on drilling anything, we’ve been watching since all of ours is held by production. They basically said it was a mixed bag and they needed to drill some more wells, kind of mixed results. And then as I understand it, Bill Barrett has delayed drilling their wells for permitting reasons, and they have planned a couple.

So we continue to be watchful. We hope they’re successful because we’ve got an awful lot of acreage out there that would have that potential. But we’re not planning on doing anything there ourselves because, again, we don’t need to – no lease is expiring. We’ll let somebody else do the exploratory work for us.

Joe Magner – Macquarie

Okay, great. And then on the horizontal test you have planned this year, what sort of, I guess data will you all be looking for or will you be planning to share with the market that might suggest an expansion of that program? I know you mentioned you might bring in some outside help to expand it. But just more broadly, what you are looking for to just have more confidence in?

James McManus

Yes. Let me ask a clarifying question. Are you talking about the Midland Basin, the Delaware Basin, or both?

Joe Magner – Macquarie

I guess we could start with the Midland Basin, in that Glasscock County area, but then broadly just across both.

James McManus

Sure. Well, I think if we – obviously, one well, we know, doesn’t tell you a lot. So if we can get six wells down and our performance is consistent within a range of economic wells, and then we partner with somebody else and we continue to have good results, then I think you take an approach of ramping up. You say, hey, we may want to run a lot more than one rig in 2014.

And you continue to do that, just like we did on the 3rd Bone Spring. I guess I would use that as a really good example of what we did there. For a long time we were quiet there because the focus was not on our 3rd Bone Spring program. But we went from one rig and we eventually escalated that up to seven rigs once we had a level of confidence that the formation was solid and that we were moving to the development stage.

So I think the way to think about this is over a period of time, and it might be two years, we might go from one rig if we’re very successful here up to five, seven rigs running horizontally in the Midland Basin. That’s one way to think about it.

Joe Magner – Macquarie

Okay.

James McManus

I think, just thinking about the Delaware Basin at the same time. We need to see how consistent the results are over a broad area, and then you start thinking about moving up. Now, I’ll tell you, I think the Midland Basin right now is scalable faster than the Delaware, just simply because there’s more penetrations, there’s more data, there’s more information, you are further along in the game.

So it’s more likely that we would scale up there quicker. Now, it could change if we got great results everywhere in the Delaware Basin. But my bet is it’s more likely we go scale up in the Midland Basin just because it’s further along first.

Joe Magner – Macquarie

Okay, great.

James McManus

Okay. Yes.

Joe Magner – Macquarie

And then on the 2P/3P reserves that were put in the release, on the 2P side, do you plan to actually include those in your 10-K filing this year or not?

James McManus

No, we never put them in the 10-K filing. They’re just disclosed. But they’re audited by our outside reserve auditors, but we don’t want to put them in.

Joe Magner – Macquarie

Okay. I just want to make sure there wasn’t a change there. And then, on the Bone Spring results in the fourth quarter, it looked like the wells that were completed in the fourth quarter were a little bit gassier than what you had drilled on average throughout the year. Any shift in the area where you’re drilling or anything else that might...?

James McManus

Yes, there was. We had some really strong wells that came on that had a high percentage of gas. But we believe, over the course of the remaining inventory that the type curve we put out there is still accurate, which is a little oilier type curve than what we had in the fourth quarter. Go ahead, John.

John Richardson

Let me say this. Actually, in 2012, we achieved a goal of basically getting our Bone Spring only locations or our area delineated. So we basically have a well on each lease now, all that is held. We have facilities on each lease. So in 2013, we’re going back through and basically going with second and third wells on each lease. So we have seen the program pretty much, and as we did go – the further west we went, we got a little gassier. That was just a product of where we were drilling at the end of the year. We will now go back through and start to develop those leases with more density. So we’ve basically seen the program. We’re in the development phase there in the Bone Spring. We anticipate continued of what we’ve seen, and maybe a little bit less stress on getting facilities and pipelines and so forth in, in that area.

Joe Magner – Macquarie

Okay, great, thank you.

James McManus

Well, thank you.

Operator

(Operator instructions) And we do have a question on the line from Mike Matus. Mike?

Mike Matus – Citibank

Hi, yes, I’m from Citibank. I was just calling to follow up on how to realize the value in the Wolfcamp and the Cline. I know you had talked about drilling some wells and potentially bringing in a partner. But I saw, a few months ago, that you changed some of the – change of controls, and I know you have a gas utility where some of the recent transactions have been 11-12 times EBITDA, and what your plans with the utility were, if that was another way of just kind of generating cash to go it alone?

James McManus

Yes, let me say this. Any changes we made to change of control was housekeeping items. Not any significant changes were made. So that has no correlation to any plans to do anything, first off. Secondly, at this point in time, we don’t have any plans to dispose of the utility for cash. Now, we’ve always said that we obviously have assets that we could monetize if we needed to. But we don’t have any plans to do that right now. When I was addressing – the question that I was addressing really was talking about us ramping up on our own. Now, a good question is, where would we get the cash to do that?

Mike Matus – Citibank

Right.

James McManus

And we could do a good bit of that internally with our balance sheet. And then at what point would you consider other alternatives? And anything can be on the table, but right now we don’t have any plans to dispose of any of the current assets that we have.

Mike Matus – Citibank

Okay, thank you.

James McManus

Sure.

Operator

(Operator instructions) Joe Magner. Joe?

James McManus

Hey, Joe.

Joe Magner – Macquarie

Hi. Just a couple other follow-up questions. With respect to the pipelines and other infrastructure projects in place, have you all committed to any of those with respect to longer-term transportation arrangements or...

James McManus

Joe, we work through marketers. We don’t really contract for our own capacity, and that’s kind of how we’ve handled that. And we try to tell them what our needs are going to be, and so then they would contract for the capacity and move the volumes for us. So it’s handled that way by us. We are not directly contracting for capacity.

Joe Magner – Macquarie

Okay.

James McManus

We use the larger people in order to be sure that we’re going to have good access, atlas, planes, et cetera.

Joe Magner – Macquarie

Okay, and then, I guess, along those lines, any – and then the pipelines and the expansions being planned there are pretty visible, pretty well understood. But are there any rail projects that are being done that you might have access to or get benefits...

James McManus

I don’t know of any, but I may not be as far down in the details of that. Does anybody...

John Richardson

No, I don’t know. I know it has been quite successful in the Bakken area, but we haven’t heard of any significant rail in the Permian area.

Joe Magner – Macquarie

Okay. And then just one last one, any, I guess, initial thoughts on what the format of the outside partnership that you’re thinking about would take? Would that be a JV or would that be just a traditional farm-out of some sort?

James McManus

It would be more in terms of just combining some acreage in a little small joint venture.

Joe Magner – Macquarie

Okay, that’s all I’ve got. Thanks.

James McManus

Thank you.

Operator

There are no questions in the queue at this time.

James McManus

Okay. Well, thank you, Erin. Given our substantial drilling inventory for 2013, it’s going to be an important, exciting year for us. Looking forward to testing these plays. As I mentioned earlier, we’ll frame our future development. We’re going to continue, obviously, with a successful Wolfberry and 3rd Bone Spring program, and we expect these two plays to once again drive substantial double-digit growth in oil and natural gas liquids. Thank you for joining us today. Have a great day. Thanks, Erin.

Operator

Thank you. This does conclude today’s teleconference. You may now disconnect.

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