Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Energen Corporation (NYSE:EGN)

Q1 2014 Results Earnings Conference Call

May 01, 2014, 11:00 am ET

Executives

Julie Ryland - Vice President of Investor Relations

James McManus - Chairman of the Board, President, Chief Executive Officer, Chairman and Chief Executive Officer of Alabama Gas Corp.

Chuck Porter - Vice President, Chief Financial Officer and Treasurer of the Company and Alabama Gas Corp.

John Richardson - President, Chief Operating Officer of Energen Resources Corporation

Analysts

Timm Schneider - ISI Group

Irene Haas - Wunderlich Securities

Tim Rezvan - Sterne, Agee

Ryan Oatman - SunTrust

Louis Baltimore - Macquarie

Gabriele Sorbara - Topeka Capital

Operator

Good morning, ladies and gentlemen, and thank you for waiting. Welcome to the Energen Corporation's first quarter earnings conference call. All lines have been placed on listen-only mode, and the floor will be open for your questions and comments following the presentation.

Without further adieu, it is my pleasure to turn the floor over to your host, Ms. Julie Ryland. Ms. Ryland, the floor is yours.

Julie Ryland

Thank you, Wes, and good morning. Today's conference call is being held in conjunction with Energen Corporation's announcement yesterday of our latest Wolfcamp results in the Permian Basin, increased drilling, capital and production guidance for 2014, financial and operating results for the three months ended March 31, 2013 and potential 2015 Permian Basin production growth. Locator maps showing our latest Wolfcamp wells can be found on Energen's homepage www.energen.com.

Today's conference call will include comments expressing expectations of future plans, objectives and performance. Such constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. All statements based on future expectations are forward-looking statements that are dependent on certain events, risks and uncertainties that may be outside the company's control and could cause actual results to differ from those anticipated. Please refer to our periodic reports filed with the SEC for a more complete discussion of the risks and uncertainties that could affect Energen's future results.

At this time I will turn the call over to Energen's Chairman and CEO, James McManus. James?

James McManus

Thanks, Julie. Good morning to you all. We have a lot of good news to share with you this morning. We will start with four excellent Wolfcamp results, two each in the Midland and Delaware Basins. We will also spend some time talking about drilling efficiencies we are achieving in the Midland Basin. These efficiencies are driving our decision to deploy additional capital in 2014 to further accelerate our current year drilling in the Midland Basin and, together, with above-budget performance from our Delaware Basin Wolfcamp wells in the first quarter, these efficiencies are largely responsible for an increase in our estimated production this year of 500,000 BOE. We believe the accelerated drilling we undertake in the fourth quarter will have a last significant positive impact on 2015 production as well. More on that later.

Let's start with the well results. We tested four new Wolfcamp wells in the Permian Basin, including our first in Martin County. The Jones Holton #1011H is the first of our 2014 exploratory wells. It has a completed lateral length of 6,675 feet and tested the A-bench. It generated a peak 24-hour IP of 1,171 BOE per day. The 3-phase product mix was 72% oil, 16% NGL and 12% natural gas. The Jones Holton also tested at a 30 day peak average rate of 843 BOE per day, 75% oil, 14% NGL and 11% gas. These are the best IP and 30 day average rates known to have been reported for a Martin County Wolfcamp A well. We are very pleased with first Wolfcamp well we drilled in the northern half of our Midland Basin acreage.

Our second Wolfcamp A well in Martin County is awaiting completion. Our first tests of the Wolfcamp A in Howard County is awaiting completion as well. In southern Glasscock County, the San Saba NS 37-48 #106H tested the Wolfcamp A. Once again, it is one of the last two wells on our 2013 drilling program and further underscore the consistency and predictability that have let us to move into the development of the A and B benches in that area. The well generated a 24 hour peak IP of 921 BOE per day that was comprised of 78% oil, 12% NGL and 10% gas. Its peak 30 day average rate was an impressive 876 BOE per day, 75% oil, 14% NGL and 11% gas.

The last well in our 2013 exploratory drilling program in the Midland Basin is awaiting completion, and four wells in our 2014 exploratory program are either awaiting completion or preparing to test.

In the Delaware basin, we tested two more excellent Wolfcamp wells in Reeves County. These are the final two wells that were part of our 2013 drilling program. The Langley 2-36 #1H tested the B-bench at a peak 24-hour IP of 2,009 BOE per day. The 3-phase product mix was 51% oil, 23% NGL, and 26% gas. This is our fourth Reeves County Wolfcamp well to top 2,000 BOE per day. Pretty impressive. We also have a peak 20 day average rate for the Langley well of 1,813 BOE per day that was 48% oil, 24% NGL, and 28% gas.

Located south of the Bodacious and Red Rock wells, the Matador 6-33 #1H tested the Wolfcamp A at a solid peak 24-hour IP of 1,338 BOE per day. The 3-stream rate was 72% oil, 14% NGL and 14% gas. The peak 30 day average rate was 1,057 BOE per day that was 71% oil, 15% NGL and 14% gas.

The first four wells in our 2014 exploratory program in the Delaware Basin currently are drilling or completed.

There are many more moving parts that comprise our guidance for any particular period. One of the biggest, of course, is production. As I mentioned earlier, we are raising our production from continuing operations guidance for 2014 by 500,000 BOE. Our prior guidance midpoint is now the low end of our estimated production range of 24.9 MMBOE to 25.9 MMBOE. That puts our new production midpoint at 25.4 MMBOE.

There are two major movements behind this increase. First are Delaware Basin production exceeded our expectations by about 200,000 BOE in the first three months of the year due to outperformance of our Wolfcamp wells there. And secondly, we have improved drilling efficiency in the Midland Basin such that we are moving more quickly to our original drilling schedule. This will allow some production coming online sooner.

We now estimate total Permian Basin production in 2014 based on the midpoint will increase more than 20% year-over-year. In addition, we have increased our estimated 2014 exit rate which we define as the December average at midpoint from approximately 73 MBOE per day to more than 75.5 MBOE per day.

Our enhanced drilling efficiency was also driving an increase in planned capital investment this year. We plan to spend an additional $250 million and drill 23 additional Wolfcamp and Cline wells, primarily in the Midland Basin. Capital investment in 2014 is now estimated to be $1.3 billion.

What do we mean by drilling efficiency? Basically we have decreased the drill cycle times for our four horizontal Wolfcamp development rigs through improved planning, accelerated permitting, accelerated location and water handling facilities construction, the use of spudder rigs to set intermediate pipe, and increased overall drilling efficiency. The results have been to lower drill cycle times for the horizontal development rigs by seven days from an original target of 28 days to a current 21 day cycle from rig up to rig up.

In short, this approach allows for an increased number of wells we drill with the same number of rigs at a lower cost per well. The additional 22 wells we plan to drill include 17 development wells in Southern Glasscock County, three exploratory Wolfcamp wells and one exploratory Cline well in the Midland basin and two Delaware Basin Wolfcamp wells. We have 100% working interest in these wells. So gross and nets are the same.

Other adjustments to capital include lower drill and complete costs for Wolfcamp development wells in Southern Glasscock County, higher drilling complete costs for exploratory wells in the Delaware Basin, increased facilities, some increased working interest and the addition of two gross non-operated Niobrara wells in the San Juan Basin. We have a 50% interest in these wells. So for the year, we are looking at total of four gross, two net non-operating wells testing the oil phase in the Niobrara. With respect to higher Wolfcamp cost in the Delaware Basin, I want to note that these are primarily related to increased infrastructure and facilities costs associated with drilling in remote locations as well as testing costs associated with drilling in new areas.

While we expect the current year acceleration in the Midland Basin to help drive increased production in 2014, the greater impact on production will be felt in 2015. This is preliminary but we are going to add a lot of investment comparable to the $1.3 billion we are looking at in 2014. Total Permian Basin growth in 2015 could exceed 30%. This is a tremendous growth rate of with an unrisked drilling inventory more than 5,500 horizontal wells in the Wolfcamp and Cline shales alone and now the financial capacity to accelerate our drilling to bring value forward our organic production growth is poised to be very, very strong of a number of years.

At this point, I am going to ask Chuck Porter, our Chief Financial Officer to run through the results of our first quarter and more importantly discuss our 2014 cash flow and earnings guidance for 2014 in light of the change I talked about and some others as well. Chuck?

Chuck Porter

Thank you, James. For the three months ended March 31, 2014, Energen's adjusted income from continuing operations totaled $77 million or $1.05 per diluted share. This compares with $80.7 million or $1.12 per diluted share in the same period last year. The year-over-year decline in adjusted earnings largely was due to recent changes to Alabama Gas Corporation's rate-setting mechanism. These changes included a reduction in the utility's allowed range of return on equity. Alagasco's net income totaled $43 million in the first quarter of this year and compared with earnings of $47.2 million in the same period last year.

Energen Resources' adjusted income from continuing operations in the first quarter of 2014 totaled $33.7 million and compared with $32.7 million in the same period last year. The benefit of a 23% increase in oil and NGL production and higher realized oil and natural gas prices were partially offset by higher DD&A expense, increased exploration expense largely associated with delay rentals, and higher price-driven production taxes.

Relative to our internal expectations, first quarter 2014 adjusted income from continuing operations fell short at both subsidiaries. Revenue reductions under Alagasco's Rate RSE were greater-than-anticipated largely due to weather-related increases in sales and recent changes to the rate-setting method. At Energen Resources, the net benefits of greater-than-expected production were more than offset by the timing of delay rental expenses, higher LOE and a lower-than-expected realized oil price due to above-budget sweet and sour oil to WTI Cushing differentials.

Adjusted EBITDAX from continuing operations totaled $290 million in the first quarter of 2014, up approximately 14% from $254 million in the same period last year. Energen Resources adjusted EBITDAX from continuing operations of $207 million in the first quarter of 2014 was up approximately 27% from the same period a year ago.

As we look to the remainder of 2014, I want to run through some changes of the other moving parts that James mentioned earlier. First I would expect Alagasco's earnings should be reflected as discontinued operations beginning with the quarter and year-to-date ended June 30, 2014. So from this point forward, our earnings guidance will reflect only our continuing E&P operations.

Energen's pro forma 2014 guidance range for after-tax cash flows is an estimated $848 million to $878 million. And then, in addition, we estimates that we will receive after-tax proceeds of approximately $1.1 billion from the sale of our utility. Pro forma 2014 earnings are estimated to range from $157 million to $187 million, or $2.15 to $2.55 per diluted share.

Positively impacting guidance is, of course, our increased production estimate of approximately 500,000 BOE. Negatively impacting guidance is the wider Midland to Cushing basis differential. To mitigate that exposure, we have hedged 600,000 barrels of our sour oil, that is the WTS Midland to WTI Cushing at an average price of $3.30 per barrel and those hedges are in place over the last six months of the year at 100,000 barrels per month.

We also have hedged 1.2 million barrels of our sweet oil production at an average price of $3.80 per barrel, that's WTI Midland to WTI Cushing. This hedges, too, are spread equally over the last six months of 2014.

Our guidance does reflect some adjustments in commodity price assumptions for unhedged production, but given that we are heavily hedged, these changes are not particularly impactful. More impactful, though, are the changes we have made in our assumptions for oil volumes that are exposed to the Midland accretion differential. We have increased the sweet oil basis assumption for the rest of the year to $4.22 per barrel and the sour oil basis to $4.40 per barrel. You could find additional detail on that in our news release and I would encourage you to review that information.

With that, I will turn the call back to James.

James McManus

Thank you, Chuck. Before we open the floor for your questions, let me piggy back on a couple of items discussed by Chuck. First, we have been adding to our 2015 hedge position. We now have 8.3 million barrels of 2015 oil production and 29 BCF of natural gas production hedged. We will continue to work to lay down additional hedges as we move through the year, not only for the commodities themselves but also for the various differentials in the various plays we are in.

The last thing I want to mentioned is Alagasco. We do expect the transaction to close in 2014 and have already taken the first step to get the process started on April 14, just a week after the deal was announced. The Laclede Group and Energen filed jointly an initial request for approval with the Alabama Public Service Commission. We will work the Commission and the staff to facilitate that process.

So with that said, let's open the lines for Q&A. For instructions, I will turn the phone line over to our facilitator, Wes. Wes?

Question-and-Answer Session

Operator

(Operator Instructions). First question comes from Timm Schneider from ISI Group. Tim, the floor is yours.

Timm Schneider - ISI Group

Hi, guys. How's it going? Quick question on 2015. I was wondering if you could give us some color, in terms of how many rigs you plan to be running with those numbers you threw out in the Delaware and the Midland Basin at this point?

James McManus

Yes. Well, Timm, right now, we are looking at a similar capital run. So it's actually a similar rig run rate to what we have got now. So that's kind of what we have got built in there.

Timm Schneider - ISI Group

Got it. Okay. One other question I had. Can you talk about the infrastructure constraints, if at all, in the Delaware Basin? We have heard some operators complain about that. Do you look at that as a constraining factor when you look at ramping there?

James McManus

Timm, infrastructure, we know that the Delaware Basin is rather immature but we are installing. As you know, some of our capital numbers are there to install that infrastructure. We have plans to be proactive there and the volumes that we projected take that into account.

Timm Schneider - ISI Group

Got it.

James McManus

Timm, coming back to that first question. We may actually have a little bit of a rig count boost in 2015 but the efficiency keeps the dollars at the same level. I don't want to mislead you. There is actually a building rig count in our projection.

Timm Schneider - ISI Group

Okay. Got it. That was it for me. Thank you.

James McManus

Thank you, Timm.

Operator

Next question is from Irene Haas from Wunderlich Securities. Irene, the floor is yours.

Irene Haas - Wunderlich Securities

Yes. Hi. I would like to focus on the really good wells you have been drilling. So the Langley well, it's a B well, which is interesting. Just wondering, how many horizons right now you think would be prospective in your Delaware Basin, Reeves County land? Then secondarily, maybe a little more color on the Martin County well? Aside from Wolfcamp A, would you be looking at B, C in other horizons? Those would be my two questions.

James McManus

So let me let Johnny comment on the horizons in Reeves County and Martin, also. I will follow back to it.

John Richardson

I mean, pretty much the same answer. We think we have got 1,200 feet of shale, basically, in Reeves County area. We tested basically one bench there. Whether it be A in some case, B in some case, but we are very optimistic about the whole section. Anyway, we are doing a pretty good job of identifying and derisking our acreage, but we still, in the future, will need to do that vertically and we are very excited about that opportunity. We are optimistic about those opportunities. I can't give specifics about what we will find in the A and the C, for instance, as we get into Western Reeves but from what other operators have said to the west of us and from the data we collected and where the shale looks, we are excited about those opportunities. But we will have to move our exploratory program in to finding the vertical horizons and those are one of the things will be doing ion the years to come, particularly in testing.

James McManus

In Martin County, there have been some good B wells drilled as we get five wells not two wells within the area. We are going to be testing the B and the Cline up in Martin County and we are very hopeful those results are going to be consistent with what others have seen.

Julie Ryland

Irene, this is Julie. We have got, when we roll in the additional wells that we are drilling, that we have now announced, you are looking at a total of nine exploratory wells in Martin County, three A, including the one that we have already disclosed, five B and a Cline.

Irene Haas - Wunderlich Securities

Great, and one more follow-up. I noticed that, be it the Langley well or the Matador or what-not and the Martin County well, these are fairly, at least on the Delaware side, fairly short laterals. Do you have any feeling as to when you guys might start drilling the longer laterals just for experimentation? Or are you not at that phase right now?

James McManus

Irene, we have got a longer lateral plan for this year in Reeves County, I think, of 7,500 foot lateral and I am not sure about the timing of that. Johnny may know more, but I know we have got one planned for this year.

John Richardson

James, I don't remember exactly when our rigs are scheduled to do it, but it will be this year.

James McManus

But we do have a longer one planned and we hope to test that concept.

Irene Haas - Wunderlich Securities

That's great. Thank you.

James McManus

I think, overall, Irene, just to tell you, we couldn't be more delighted with the results we are getting in both the Midland and the Delaware basin, the consistency of the results, the success rates. We are just really pleased with what we are continuing to delineate in both basins.

Irene Haas - Wunderlich Securities

That's great. Thank you.

Operator

Thank you. The next question comes from Tim Rezvan from Sterne Agee, Tim, the floor is yours.

James McManus

Hi, Tim.

Tim Rezvan - Sterne, Agee

Good morning, folks. I had a quick one I want to follow-up on the Delaware Basin results. When do think you might be able to provide some type curve or EUR information to the marketplace, because we have had these wells online for several months now?

James McManus

Tim, I think that's going to come, eventually. I can't give you the exact timeframe. There may be three curves in fact. We have got the East, Middle and West but we have been working internally and the good news is that the internal looks that we have done, our wells have been outperforming that. So from a cost perspective, we feel a little bit better about this being economic at a higher cost because we are outperforming the preliminary curves. I can't give you a specific timeframe but obviously that's something that we will be looking at and, hopefully, maybe by later this year we can put our arms around that a little bit better.

Tim Rezvan - Sterne, Agee

Okay. I think that's an important data to get out to the marketplace.

James McManus

But you know, a part of it is, had we put it out four months ago, it would have been much lower than what it actually is. So one of the things is obviously having enough time to be a little bit more sure of what you have got. But yes, I hear you.

Tim Rezvan - Sterne, Agee

Okay, and, then if you could maybe talk more broadly speaking. I know that the knock on the Delaware Basin Wolfcamp has been the lower oil cuts. I think the absolute number of oil is still impressive. How have oil cuts been holding in, as wells have been online for 90 days and longer?

John Richardson

They have been pretty consistent but we have not seen any real change in the character of those wells from what we have reported in the initial. I mean what we released to you initially.

James McManus

I think what Johnny is saying, Tim, is the IPs, the 30 day rates and the longer rates have been very similar.

Tim Rezvan - Sterne, Agee

Okay, and then just one last one. I want to piggyback on another question from earlier. How much of your acreage do you feel like, in the Delaware Basin, can you run a development program on concerning the infrastructure available? We know about the third Bone Spring infrastructure in Ward and Winkler, but as you migrate west?

John Richardson

Obviously, as we drill wells out to the West, we are putting infrastructure in, but would we be looking at that in 2015? I think we will wind up running the same number of rigs out here. You know we have got about five. We have got three in the third Bone Spring. I think those will move over to Delaware and whether there will be development versus exploratory will depend on overall lease situation. But I am sure in 2015, we will do some development drilling but we may still be doing a lot of lease holding as well.

Tim Rezvan - Sterne, Agee

Okay. That's helpful. Thank you.

Operator

Thank you. The next question comes from Ryan Oatman from SunTrust. Ryan, the floor is yours.

Ryan Oatman - SunTrust

Hi. Good morning.

James McManus

Hi, Ryan.

Ryan Oatman - SunTrust

Looking into 2015, what are the factors that we should think about for capital spending? Is that $1.3 billion, is that a de facto figure for us to think about moving forward? Or do we need to think about cash flow outspend or some other factors in how you guys set that guidance? Just trying to get a feel as to how much gospel truth we should put in that $1.3 billion?

John Richardson

Well, it's a preliminary number. I don't think its going to go down, and I think the question is, whether as we look it over whether we raise it or not? And so, we think it's a very good performance level in terms of growth for 2015, but as we look beyond, and we look at the results that we get the remainder of 2014 that's something that could be adjusted. I would not expect it to be adjusted down.

Ryan Oatman - SunTrust

Okay, great, and can you describe the environment for rigs and services right now a little bit more broadly? Any pressure you are seeing on cost side in either the Delaware or the Midland basins?

John Richardson

Right now, it's pretty calm. We just announced that we were going to increase a lot of that through efficiency, but also coming along with also coming along with the accelerated completions and we are not having any trouble filling those gaps. So supply of everything is pretty stable. We are not hearing of any cost pressures.

James McManus

Ryan, to add, this is an answer to a different question, but I don't know, it doesn't seem like it was recognized all that favorable, but we did about $300 million net better on the utility sale than we thought we were going to do and so we have got quite a bit of capability in terms of our ability to move things forward and accelerating.

Chuck Porter

This is Chuck, Ryan. Just to build on that. If you look at our projected debt after the utility sale, even with the increased capital for these 23 additional wells that we mentioned, our projected debt would be approximately $1.1 billion at the end of the year. So when you are that, and you look at what 2015 might be, you are still in the ballpark of a 1X debt to EBITDA range. So there is still a good bit of capacity there.

Ryan Oatman - SunTrust

That's great. That's helpful. I am sorry?

James McManus

No, go ahead. We didn't say anything.

Ryan Oatman - SunTrust

One final one for me. Looking at the two-well pairs in southern Glasscock, can you talk about how those wells compare to your individual wells from various standpoints, cost, budget, production times, et cetera?

John Richardson

Well, of course, we told you we are going to decrease our what those wells cost to lowering our capital projections on those and those are the payers, the walking rigs, drilling two wells from each pad, we will zipper frac these wells. Going to pad drilling allows us to use the spudder rig to do permitting early, get our damages settled early. It allows us to get that spudder rig out in front to drill an intermediate which is a much more efficient rig, to come in with the bigger rigs and do what they are designed to do. The learning curve when you are doing that kind of repetitive work is something that we would probably even have not accounted for yet. So we see a tremendous potential to keep driving down costs and driving up efficiency because you really don't have any down time when you get into full cycle between movement, bringing the frac crews in, being able to use the same frac pod, be able to reuse water. It opens up a tremendous economy for you and efficiency for you. So that's how we were driving so hard to get our exploratory guys out early and to get the development phase here.

James McManus

So Ryan, just to give you a little color on some numbers. We started the original budget at $8.5 million. We are targeting $8 million now pretty easily. We think we will get over that number over time. So we have seen some very rapid movement there. The first few, it might have cost a little more than that as we are running it now but we very quickly went below our $8.5 million. We are looking at $8 million, and I think we are going to get below that number and we are excited about the efficiencies that we are going to be able to gain. I think people don't need to underestimate what we are going to be able to do in the Delaware Basin, when we move into that mode.

Ryan Oatman - SunTrust

Very good. I will leave it at that. Thank you.

Operator

The next question comes from Louis Baltimore from Macquarie. Louis, the floor is yours.

Louis Baltimore - Macquarie

Yes. Thank you. With better-than-expected Delaware Basin Wolfcamp results driving a big portion of production guidance increase and the wells seeming more productive than those in the Midland Basin, can you just talk a little bit about your decision to increase activity in the Midland Basin despite this relative performance in the Delaware?

James McManus

Well, I think, overall, if you look at it with the costs and performance factored in, I think the Midland Basin is still low risk, high return at this point in time. So we are going to continue to up our activity there. At the same time, I think what's happened with the Delaware results being better and the consistency being better, we are not going to be concerned about having a pretty active program in the Delaware Basin at the same time we move forward in the Midland Basin. But I think, still, Louis, clarity wise, from a return perspective, I still think the Midland Basin is a little bit better. But again, it's in development phase. We will see how that all shakes out when we get them on a comparable basis.

Louis Baltimore - Macquarie

Okay. Great. Thank you. And then I guess, just one more. The CapEx increase, with $250 million, you talked about 23 wells. So that comes out to over $10 million a well. So is that infrastructure related driving the additional CapEx?

James McManus

Yes, there is infrastructure in there and there is going to be more cost associated with the Delaware Basin wells, particularly on infrastructure basis, but let me see if Julie has got anything to add.

Julie Ryland

No, I think there details of that in the release. I was just looking for what other moving parts in capital were but the whole $250 million is not explicitly for 23 wells.

Louis Baltimore - Macquarie

Right. Okay, I understand. That's all for me. Thanks.

Operator

Next question comes from Gabriele Sorbara from Topeka Capital. Gabriele, the floor is yours.

Gabriele Sorbara - Topeka Capital

Good morning, guys.

James McManus

Yes, hi. Good morning.

Gabriele Sorbara - Topeka Capital

Just maybe start with the well cost question here. How are your well costs in the Delaware Basin? How do they change from the Northwestern region down to the Southern region? Is there lower-cost, higher cost areas? Or are they pretty consistent?

James McManus

Let me do this, Gabriele. Let me take a little bit of a shot at that macro and let Johnny sort of add in. So on the Eastern side, the ground is a little bit harder that we were drilling through initially. So they could be, right now, probably a little bit up and we are a little deeper over there. So they are a little bit higher. As you move to the west, you get a little bit more shallow. So the cheaper well cost are going to be West to Middle right now, I think, with East being a little bit higher. Johnny?

John Richardson

Right. If you just talk about drilling complete cost, James is right, completely right. When we sort of look at this where the facilities and infrastructure we need to put in, there's not a lot of difference, Gabriele, between an Eastern well and a Western well, the way we look in to cost now. The components are different. We have got a lot more work to do on the Eastern side to get the drilling complete costs where we want those as we do on the Wes. But the Western side is shallower. It's a little bit easier drilling. But you do have the extra add for roads and infrastructure. Sometimes we are building a 15-mile road to get to some of those Western wells. So the cost shakes out about the same for different reasons.

Gabriele Sorbara - Topeka Capital

Understood. Thanks, and then maybe just what's the ASP on that long lateral? And what's your targeted well cost on the 4,000 foot laterals in the Delaware Basin?

James McManus

Well, I think where we like to give it on the Delaware Basin is, let's say, total cost somewhere around $9 million, $10 million. We are on a drilling complete. We got some that we have done under $10 million but when you throw the facilities in due to the remote, it's a little bit higher. So once we get soup to nuts with all facilities, we get it to $10 million, I think we are going to be pleased.

Gabriele Sorbara - Topeka Capital

Okay. Any sense on the cost of the long lateral, the 7,500 foot?

James McManus

No. I don't know.

Chuck Porter

I don't recall what the additional cost of that is, Gabriele. It's not tremendous, but I don't recall. I apologize.

Gabriele Sorbara - Topeka Capital

Okay. No worries, and then just thinking about, you have drilled three wells in the furthest southern portion of your block. You don't have much acreage down there. Just trying to get a sense of why you are drilling down there? Is it because there's infrastructure? Are there leasing issues? Or do you feel the economics are better with the wells being oily?

James McManus

No. It has all been leasing issues, frankly. We went down there for leasing issues and if we think the area is good, which most of what we have, we believe that way, we are going to drill the well to hold the acreage and a lot of what we have been doing in 2014 has been completely dictated by leasehold acreage holds and the nice thing has been, even though we have been all over the basin, we have had pretty good results everywhere.

Gabriele Sorbara - Topeka Capital

Great. Thank you much.

James McManus

We are derisking the basin for everybody, Gabriele.

Julie Ryland

Going back here just for a second. Louis, I didn't want to cut you off and I found what I was looking for that more specifically addresses your question. As James has mentioned, on a go forward basis, we have lowered our drilling complete cost for our Midland Basin Wolfcamp wells and the cost with the Delaware Wolfcamp has gone up slightly. And then, in addition to those things, you have two additional 50% non-operated working interest wells drilling in the San Juan Basin that we are working with WP Exxon as the operator. There are some additional facilities that are not well specific, that are more area specific that are part of that $250 million and we also have some additions to working interests that are embedded in there as well. So it's not explicitly the 23 wells alone.

James McManus

Yes, coming back for one second. I did mention in the press release. We will probably have some visibility on our first Niobrara wells next quarter. Those wells are currently beginning the flowback process. So we will have something for you next quarter on that.

Operator

This time there is no further questions.

James McManus

Okay. Great. Well, I appreciate everybody joining us today. Thanks very you much. Good bye.

Operator

Thank you. This concludes today's teleconference. We appreciate your patience. You may now disconnect your line at this time.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Energen's CEO Discusses Q1 2014 Results - Earnings Call Transcript
This Transcript
All Transcripts