SM Energy Co (SM) 2014 Q4 法說會逐字稿

Good day ladies and gentlemen and welcome to the SM Energy Company's 2015 Outlook and fourth-quarter earnings call.

(Operator Instructions)

As a reminder is conference is being recorded.

I would now like to introduce your host for today's conference, Brent Collins, Senior Director of Planning and Investor Relations.

Sir, you may begin.

Thank you, Amanda.

Good morning, all joining us by phone and online for SM Energy Company's 2015 Outlook and fourth-quarter and year-end 2014 earnings conference call and operations update.

Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations, pending divestitures and assumptions regarding our future performance.

These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted to our website for this call and the risk factors section of our Form 10-K that was filed earlier this morning.

We'll also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance.

Reconciliation of those measures, and the most directly comparable GAAP measures, and other information about these non-GAAP metrics, are described in our earnings press release from yesterday.

Company officials on the call this morning are Jay Ottoson, President and Chief Executive Officer, and Wade Pursell, Executive Vice President and Chief Financial Officer.

I will now turn the call over to Jay.

Thanks, Brent.

Good morning, everyone, thanks so much for your interest in the Company.

We did have very strong fourth quarter and full-year 2014 results.

We recognize, however, that most of the interest we really have from investors today is about how we are responding to the current down cycle in oil prices.

We have a number of slides in our deck this morning with useful information on them, but we're not going to run through all of them in order to stay focused on what we think really matters to you the most right now.

We will try to be clear, though, about what side we are on as we go through.

I'm going to turn now to slide 3. Although it's unclear to us what the eventual mid-cycle price of oil will be, we believe SM is well positioned to make a successful transition to the new normal with a strong balance sheet, significant liquidity and core development assets with at least a billion barrels of oil equivalent of economic drilling inventory, about 20 years of our production at current levels.

As a management team, we have been through a number of commodity price cycles before.

During the high price part of this cycle we were both prudent and temperate in the way we managed our business.

Along with limiting debt, we maintained a great deal of flexibility in our commitments.

Now we're going to take advantage of that flexibility and position ourselves to generate high returns as costs adjust and business conditions improve.

We believe that our resulting performance will lead to differential value creation for our shareholders and that is our objective.

This morning we're going to cover three major topics.

First, I'd like to point out some important 2014 year-end metrics that I think investors should be thinking about as they consider our current valuation, especially in comparison to our peers.

Then Wade will discuss the assumptions we made in preparing our 2015 plan, the plan itself and the resulting guidance.

Lastly, I'd like to mention some key points on our core asset development plans for the year.

Moving to slide five, I'd like to point out our year-end 2014 reserve figures.

I've read some commentary in which some analysts imply that year-end reserve numbers are less meaningful for 2014 because SEC pricing for oil was much higher than where the commodity has been trading in recent months.

I really do understand that sentiment with respect to SEC PV-10 numbers, but not for the level of reserves in million barrels of oil equivalent.

I can't speak for everybody else in our industry, but as part of our process for booking reserves we confirm for both ourselves and our auditors that our PUDs were economic at year-end strip pricing and expected costs and would be drilled within five years.

We had another great reserves year in 2014 with drilling reserve replacement up 261%.

Our proved reserves now stand at 548 million barrels of oil equivalent, up 28% year-over-year.

Our reported production in 2014 rose 14% over 2013, so our proved Developed Reserves to Production ratio, or R over P, increased by more than 20% and our total proved R over P is now about 10 years.

This significant improvement in our proved reserve life is a reflection of the improvements we are seeing in our core development areas.

I mentioned our economic inventory numbers earlier.

A lot of that inventory was added just this last year as a result of deliberate and thorough testing of new completion designs, work that we will continue on in 2015.

The other metric I want to point out is on slide 6. Our year-end total debt to trailing twelve-month EBITDAX was about 1.5.

We don't know everybody else's year-end numbers yet, so on slide 6 we're comparing ourselves to the peer group as of the end of the third quarter of 2014.

Slide 7 shows that our balance sheet is not only strong, it's also simple, and we have no pressing maturities.

Along with our revolver, which has a borrowing base of $2.4 billion and $166 million drawn at year-end, we have five tranches of unsecured long-term secure debt, the earliest maturity of which is in 2019.

In summary, we believe we're in better shape than most of our peers from a balance sheet standpoint.

With that, I'm going to turn the call over to Wade so he can run through our 2015 plan.

Thank you, Jay.

I'll start on slide 8.

Obviously the larger theme for 2015 is uncertainty, and where will commodity prices bottom, and by how much will they recover.

We're certainly not calling a bottom.

Our general theme for 2015 is to come out the other side well-positioned to continue top quartile debt adjusted per share growth.

For us specifically that means, number one, protect the balance sheet.

You just heard Jay talking about it, and we believe it is critical in this business.

Number two, slow down activity and allow the cost environment to correct.

We are already seeing this correction taking place.

And number three, focus on improving operational efficiencies and support functions.

Our goal is always to be the efficient low-cost resource producer.

We know especially in this environment that will define who is successful.

Moving to slide 9, as I just said, we're slowing activity to allow cost to correct.

We're blessed with lots of flexibility with respect to duration of contracts, take away commitments, set amount of acreage held by production.

We plan to start the year with 17 rigs running and reduce that count throughout the year, such that by year end we will be down to seven rigs, four in the Eagle Ford, two in the Bakken/Three Forks, and one in the Powder River Basin.

We're assuming for now that commodity prices do not improve from current levels.

If they do, we can be very quick to respond.

Picking up rigs is a much quicker activity than laying them down.

Slide 10 shows how we will be building our inventory of wells waiting on completion throughout the year.

This will allow us to take advantage of completion cost deflation when we enter 2016.

We will also be able to accelerate quickly if we see an improvement in commodity prices.

Turning to slide 11, I'll discuss the CapEx dollars resulting from this program.

But first a word on cost assumptions: while each basin has its own dynamics, we are generally assuming about a 15% reduction in costs off of year-end 2014 levels, growing to nearly 20% by year end.

So the combination of reduced activity and falling cost results in a CapEx of about $1.2 billion, which is about 43% less than the spend in 2014.

That's excluding acquisitions.

You should not be surprised that over 80% of the drilling and completion CapEx in the Eagle Ford and Bakken/Three Forks.

Now let's take a look at production and cash flow generated by this program.

You can see on slide 12 that despite the significant reduction in CapEx, reduction still grows 12% year-over-year.

The product mix is essentially unchanged, with over half our production being liquids.

On a quarterly basis, the first quarter should be flash with 4Q 2014 levels, and then decline about 1% per quarter due to the decline in activity.

Turning to slide 13.

First thing to note here is that, assuming current commodity prices beginning in third quarter, we should see EBITDAX in excess of CapEx.

For the full year, CapEx should exceed EBITDAX by only $150 million.

I should point out we expect to close the Mid-Con divestiture around mid-year, with proceeds well in excess of this amount, but if not, included in forecasted amounts to be conservative with respect to balance sheet metrics.

So debt to EBITDAX at the end of 2015 should be about two and half times, again that's without counting Mid-Con sale proceeds.

Therefore, we will enter 2016 with a strong balance sheet and EBITDAX exceeding CapEx.

And by the way, our forecast for 2016 shows, assuming current strip and forecasted cost, our debt to EBITDAX metric would exit that year at a similar level.

So in summary, we believe the plan manages this downturn without sacrificing future growth or the strength of our balance sheet.

And as I said at the beginning of my remarks, our general theme for 2015 is to come out the other side well-positioned to continue top quartile growth.

This plan achieves that, with SM exiting 2015 with EBITDAX exceeding CapEx, total debt to EBITDAX around two and a half times with significant liquidity and assets generating returns above our hurdles.

That last point is a good segue back to Jay as he has a few comments on continued strengthening of our assets.

Jay?

Thanks, Wade.

I will give a few highlights on our plans in our core developing areas for the year.

Slides 14-20 give updated information about our operated Eagle Ford in North Dakota positions, which will count, as Wade indicated, for the lion's share of our 2015 capital.

We plan to compete about 75 wells in our operated Eagle Ford program this year.

I should note that we are already ahead of where we thought we would be on well cost reductions in that program.

We continue to see good results from our increased sand loading completions.

A number of people have asked about our results on our recently completed 10,000 foot lateral well, which is located west of our previously discussed high sand loading frac job wells in the North area.

After some delays due to offset frac work by other operators, this well is now achieving the same production per lateral foot as our earlier good wells there to the East.

This result is supportive of our earlier statement that we believed wells to the west on our acreage would be good producers if properly completed.

I want to remind everybody that we have some of the thickest Eagle Ford pay on the trend on our acreage.

During 2015 we will be continuing our efforts to test various landing zones within that thick section.

Approximately half of the completions we will make this year will be in landing zones above or below our previous standard landing zone target.

While we don't have definitive results on a big pilot area yet, we're excited about the potential to prove up several times as many locations on our acreage as we currently have included in our estimates of economic inventory.

Were going to make meaningful progress on this front this year even with a reduced capital program.

In North Dakota we'll be slowing our drilling activity as our rigs come off contract, deferring completions and pushing really hard on the cost front.

If prices stay low, we expect to be drilling and completing wells in our Gooseneck, Divide County/Three Forks area sweet spot for around $4 million by year-end.

We're routinely drilling these wells now in less than two weeks, and have drilled several in 10 days to 11 days, so we can put up a pretty high completion count, or drilled well count, pretty quickly there.

About a third of our Divide County activity this year will be on Bakken wells, following up on some successful wells we announced in early December.

We're currently don't have any Bakken locations on this large acreage position in our economic inventory numbers, so this is another big add opportunity we will be moving forward on in 2015.

Turning now to slide 21, I'd just like to reiterate in closing that our management team has been through cycles before.

We know that now is the time to be patient and have fortitude.

We're well-positioned to do both with a strong balance sheet, significant liquidity and good economic inventory to drill.

We will be patient and make good present-value decisions.

We remain optimistic about our Business.

Our plan for 2015 includes continuing with our inventory improvement efforts, and we think those efforts will generate good results.

I think it should be encouraging to investors that we have low-cost opportunities to generate new inventory even in a downturn.

From a big picture standpoint, demand for our products is still growing and costs are falling even faster than we budgeted.

Slowing US activity will have a big impact on supply sooner than many people might expect and people around the world are slowing down activity on projects that are harder to ramp back up than ours.

We think we have a good plan in place for 2015 and we're confident that we will emerge from this transition year as a strong competitor.

I will be happy to take any questions you might have.

(Operator Instructions)

Mike Kelly, Global Hunter Securities

Thanks, good morning.

Jay-- (multiple speakers)

The well results in the Eagle Ford, in the east and north, real impressive on a thousand lateral foot basis.

Just seeing when you guys will have enough confidence to maybe take tight curves up in that region?

Mike, I don't know exactly when we will push them up.

A few more wells, I think.

Obviously we're outperforming the tight curve in most of those areas.

And that's certainly the position we want to be in the position for tight curves.

When we show you economics, we want to be conservative about those.

Great.

As it pertains to maybe having multiple laterals possible in the Eagle Ford here, can you expand upon that?

You have got the 300 locations in the East, 500 in the North.

What could that ultimately go to, in your eyes, if you're successful in this front?

We have almost 300 feet of pay in some big sections of our acreage there.

And so, if you start to think about how many stacks stagger, and that's the way we refer to it as stack and stagger type program, there is areas there we could potentially triple our well count over time.

And that's certainly our target, is to aim at that.

We will be running some large pilot area programs where we're going to drill things that closer spacing and stack and stagger them in this year so that we can see how they perform when they are producing next to each other.

We have some data that indicates that wells in other landing zones will perform okay but we don't have enough data yet to be able to say that we can really push them together in that stack/stagger thing.

That's a 2015 objective.

Great, I'm going to sneak one more in.

Wade, you made the comment that debt to EBITDA by the end of 2016 shouldn't look too much too dissimilar to what you're going to have end of 2015.

Imagine you can only get there by having some sort of assumption of what production growth will look like in 2016.

Any color from you guys on 2016's program as it stands today I think it would be a well received, too.

Thanks Mike, that's a good question.

I don't think we're prepared to get a lot of color or lot of details with respect to what were planning for 2016.

I just thought it would be useful to know that, obviously we're running several scenarios, and one of the biggest things of the 2015 business plan was to see what the impact on 2016 was.

So it was comforting to me that under various scenarios we could end up with leverage metrics very similar at the end of 2016, at the end of 2015.

That's very similar program, slightly higher program, nothing materially different and really nothing specific we can say more than that right now.

All right, fair enough.

Thanks a lot guys, great quarter.

Jeb Bachmann, Howard Wiel

Good morning guys.

Hey, good morning Jeb.

Just some few questions Jay on the completion backlogs.

Looking at the 45 to 50 you had at year-end 2014, and looking you're going to add another 45 or so throughout this year, kind of where that breakdown is between Eagle Ford and Bakken and maybe some in the PRB.

Most of that backlog we are building is going to be in the Bakken.

And a lot of that is because we're ramping down activity, we still had five rigs running coming into January, and as I said, we're drilling these wells in less than two weeks.

So you can pile up quite a few opportunities for completion pretty quickly.

We are drilling a number of wells there and basically putting them in the bin to be completed later.

That's the majority of the build.

We'll complete most of our Eagle Ford wells within a few months of drilling.

Really on the Powder side, not building a big backlog there.

Okay great.

And then, just kind of looking at the bigger picture with the crude price, at what level do you guys need to see they get back to where you start burning off some of that backlog?

That's an interesting -- we haven't really come up with a number like that yet.

Our view is that when we get into 2016 we're going to be back to growing our business.

We'll have a number of opportunities to complete wells at lower costs.

I would say around here we don't talk a lot about needing price to recover.

What we're really focused on is getting cost down.

When we get cost to where they need to be, we can make good returns, and we can grow this Company, and that's what we're all about.

Okay great, thanks Jay.

Welles Fitzpatrick, Johnson Rice

Hey, good morning.

You guys talked about being able to hold together the PRB position with the other budget.

Can you talk a little bit about how we should think about your all's East Texas or Permian acreage as we go through the year and how much you might lose there or how much you'd have to spend to save it?

Let me start with the Powder and just say that our guide-- the reason we can hold all that acreage is because we formed three big federal units and we can hold a lot of acreage now there with very little drilling.

I give tons of credit to our land staff up in the Rockies for doing that, a lot of great work to get it done.

In East Texas right now, we are really doing some long-term production tests on wells.

We got our pipelines in place and we are producing the wells.

Our look at that is that with the drilling we've done we will be able to hold the acreage that we really think has value for quite some time without drilling, without spending a lot more money.

And in the Permian, the acreage we have that we've really got, that we see as significantly economic right now is essentially all HBP.

And it just doesn't make sense to drill HBP acreage in the Permian with costs falling as fast as they are.

Okay, perfect-- Thanks for the updates on the well cost in the Bakken and Eagle Ford.

In the PRB, still looking in that $15 million range?

No, we're below that.

We're well below that at this point.

But we have more things to do.

Really what we're focus on there is completion design.

How are we optimizing?

We pumped some white sand completions up there which are significantly less expensive.

Frankly, we just made the best Shannon well ever drilled in that basin and really excited about that.

So there's significant opportunity there.

We are slowing down.

Relative to our other areas it doesn't quite meet the standard we need to make to keep drilling it in this environment.

But we're going to hold that acreage.

It's going to be a valuable position over time.

That's perfect, thanks so much.

Michael Hall, Heikkinen Energy Advisors

Thanks, good morning and congrats on a nice update.

One thing I was wanted to get a little more color around is the implied efficiency improvements within the 2015 program versus the 2014 program.

If we look at how much you all spent to add production last year versus this year is a pretty dramatic improvement implied in the 2015 program.

Understand, obviously costs are coming down.

But just kind of curious on what other additional type of efficiency improvements you guys are pushing through the system and whatever sort of color you can provide around that?

We are ramping our exploration program down substantially.

As you might expect we typically risk volumes associated with exploration much more highly than we do volumes associated with development.

So the improvements you're seeing, A, we're ramping on exploration.

B, we are reducing cost and we're seeing costs come down faster than we expected almost everywhere across the whole portfolio.

And certainly we are drilling the best parts of our portfolio.

When you look at those type curves, and we talked about this earlier, we are clearly going to be portions of the area where we think we can do above tight curve wells.

And all those things combined then just generate higher capital efficiencies.

Yes, okay, that is helpful.

That make sense.

On the divide versus McKenzie County well cost; can you just remind me what the major differences are there?

There is a big difference in depth.

Lot shallower wells up in Divide County and that's why those wells are literally half the cost now of-- Well maybe not quite half now, but they will be in that $4 million range we think by year-end.

I think the total debt is about 8500 feet in Divide County.

So considerably shallower than the others.

And I think it's a great point because I think this is what people have missed about Divide County.

People consistently underestimate these wells.

Part of that is because a lot of our competitors show maps showing all of Divide County as being kind of the same and kind of tier 3. Just not true.

Our portion of Divide County has significant shale thickness, has significant maturity, and we're making great wells.

And we make them for little more than half of the cost of a typical McKenzie Council, Bakken or Three Forks well.

And so the economics here are strong.

We probably were a little reluctant to talk about that too early on because we were actively buying acreage in the area.

But this is a great development.

We have a ton of acreage with a lot of upside in it.

Okay.

That's helpful, thanks.

I guess last on my end, just coming back to the backlog a little bit, maybe just any additional insight you can provide into how you guys plan to pull that down?

I guess, number 1, is there some sort of baseline typical backlog per rig that we ought to keep in mind as we think about modeling that, getting drawn down in 2016?

And should we bias our thinking towards drawing that down first as opposed to ramping rigs back up?

Just whatever additional color you can provide there would be great.

Clearly what we're doing is we are setting ourselves up here to be able to do some-- to take advantage of completion cost reductions.

As soon as we see those costs at a point where we can look forward and say-- hey fabulous returns on these.

Then we will pick back up.

I think generally we would start completing wells before we'd necessarily start picking up rig count again.

Part of what this gives us and a lot of this is in the Bakken again because again we drill these wells really quickly.

What it really gives us is a ton of flexibility as we look at how things play out into 2016.

I think it's a really positive thing that we're basically able to keep production pretty flattish this year and still build a backlog.

I think that speaks to the strength of our underlying inventory that-- the wells that we are completing.

And sorry, just one more I'll sneak in.

How long does it take, roughly on average, to drill the Eagle Ford wells these days?

Oh boy, you know, 10 days?

I don't want to oversimplify it because the depths are a little different from one side to the next.

We drilled some of these wells in as low as 9.6 days, and most of them in the southern areas are probably more like 15 to 16 day wells.

The longer laterals obviously take a little longer than that.

Typically our lateral lengths are going to average between 6,000 feet and 8,000 feet during this next year.

Great.

That's all very helpful and, congrats.

Thanks guys.

Thank you.

Thanks.

David Tameron, Wells Fargo.

Good morning.

I would echo, congrats on the nice update.

I am trying to think about 2016.

A lot of people, or a lot of your competitors, I guess, seem to be developing a capital budget for 2015 that allows them to ramp going into 2016.

You guys are showing growth this year where a lot of those players aren't.

Can you just talk about how you think about-- should I think about the completion backlog being the toggle in assuming everything that happens happens, and we are down 20%, that that will provide that ramp going into 2016?

Or how should I think about that?

I'm thinking about that 16 to 6 rigs and then ramping back up.

I know it's easier to add then take off but I was trying to think about how you toggle that on the backend.

All those things come into play.

We are building a backlog so we have an opportunity to go in and just start completing wells, really whenever the time comes, and we can be very flexible about when that starts.

I think it is important that when you think about everybody's 2015 plans, and certainly ours.

This is really just a snapshot in time of how we see this playing out and we can be very flexible in the back half of 2015.

Give you a specific example, so we show dropping Bakken rigs all year long.

As things pick up in the back half, we don't have to drop those rigs.

We can keep right on driving through that and just start completing wells.

There's a lot of opportunity here for flexibility and getting back to a steeper growth ramp.

Wade mentioned this, really important: our focus is on debt adjusted per-share growth.

What we want to get back to as quickly as we possibly can is growing EBITDAX faster than we are growing debt and that is exactly what we are targeting in 2016.

We're going to build a program that gets us to debt adjusted per-share growth in all the key metrics.

I think one of the quickest ways to do that, obviously, is to complete that backlog of wells and then start picking up rig count as the opportunities present themselves.

Okay.

No, that's helpful.

How do you guys think about potential acquisitions?

I mean, obviously you have the balance sheet.

Should we look for you to-- obviously everybody wants you to bolt onto the right price, but how do you think about that-- or how should we think about over the next three months to six months.

Typically we are interested in assets that complement our existing footprint and that we think have unrecognized value or inventory in them.

We are seeing-- we see a lot of deals.

Right now you don't see a lot that don't have some kind of hair on them.

It actually is a really high bar for an acquisition to get into our portfolio.

The best opportunity we have right now I think and it's probably the easiest way to answer is-- you look at the inventory in our existing assets.

These are things we already own that are low-cost opportunities for us and we're extremely focused on them.

Okay.

And then last question.

Jay, what's your take on what does the recovery look like?

I know that's the million dollar question but, does 65 become the new normal type price?

Can you just talk about how you think, maybe not SM's view, but, and you guys gave your plan this morning, but just think about how you're thinking about the back half of 2015 and into 2016 what the landscape looks like as far as the pricing environment?

You know David, I think we mentioned earlier, I don't know what the price is going to be.

What I can tell you is that we have been outperforming our peers on a lot of key metrics over the last couple of years because our assets are high-quality and they're getting better all the time.

As costs fall we're going to be extremely competitive.

And that's the focus.

We're not sitting around here thinking about what we do when prices go up.

What we're doing is focusing on driving costs and outperforming our peers on those kind of competitive metrics.

Price is going to go where he goes.

We're going to continue to focus on having the kind of assets that can outperform our peers.

Okay.

I have a hard time answering that question, too, so I appreciate the other color.

Thanks.

Scott Hanold, RBC Capital Markets.

Thanks, good morning.

Good morning.

Good morning, Scott.

Jay, on the stack potential on the Eagle Ford, can you give us a sense for some of those more financing oriented guys, more of a layman's term, in terms of the geology in the upper and lower part of the Eagle Ford compared to what you were drilling before, how it kind of compares and what you all expect at this point?

I know it's really early, but what are your expectations.

Sure.-- I want to go back just a second and you'll forgive me for giving a somewhat long answer here.

I think what we and many other people have found in a lot of these shale plays is there's a lot more vertical heterogeneity in these reservoirs than we originally thought.

In fact, there's a number of different facies within the Eagle Ford shale, especially in this thick section, that we did not really account for in our early work.

We thought, we will put a completion sort of in the middle of this thing or below the middle, and we will get it all.

And what we found through both core work and modeling is that that does not necessarily work that way.

These fracs-- you may frac up into the upper Eagle Ford but you may not keep it open.

And in fact, there is other facies in which you can make good completions.

So the areas you are draining vertically are smaller than we thought, which probably tells you you're getting higher recoveries than you actually thought in the facies that you were actually completed in.

So what it opens up for all of us, and you're seeing it is not only from us, but from others, is this opportunity then to complete wells across the vertical section of these reservoirs and potentially push them considerably closer together because they may not communicate in a vertical sense.

That is where the real opportunity is at.

We don't just see this in the Eagle Ford, we've seen it in these thick sections in the Permian as well.

We have done some specific modeling there where we had some core work and learn a lot across our whole portfolio on this issue.

I think it just speaks to the fact that the Eagle Ford, in particular, is an enormous resource.

The benefits of that should accrue more to people with thicker pay and we have some of the very thickest pay in the trend on our acreage.

That certainly is helpful, and maybe if I could again push a little bit more there.

Like when you look at the upper and lower sections, and you did say it does look a little bit more consistent you thought, is there any kind of variation between the upper and lower section from a geological perspective.

You know there's, I believe, nine different facies we have identified across that Eagle Ford, like that 300 foot section.

And there are portions of that in the uppers and lowers that look very similar.

Typically, we used to think that the upper was not source and the bottom was and the upper was maybe storage.

There's some good looking faces in the upper to be completed in.

It was just our assumption early on that we were probably completing that whole thing when we completed a frac well in there.

What we found is that we do not believe that to be the case and we're not the only people who think that.

I think there's a number of different facies that we can look at in which we can put wells that potentially don't talk to each other at closer spacing than we originally thought.

That is the test we need to run to really be definitive, is to run a significant pilot, which we are building, we will be building in 2015, where we really stack and stagger some wells and complete all of them at the same time so we can see how they talk to each other.

Until we get that data it's not going to be a definitive test.

We are really encouraged about what we've seen so far in terms of landing wells in kind of different facies.

Okay.

Which part of your Eagle Ford acreage are you going to do this pilot in and when would you expect to have results?

Should we expect some time by the end of the year or is that still too soon?

We're really focused on that western area of like the North area where we have a lot of thickness.

We're doing one of the-- a pretty good size pilot there in 2015.

And then we're also testing some uppers in the eastern section, obviously, because it's a terrific area for us.

I think we were relatively conservative about the way we initially spaced those wells so we have that opportunity to put in some uppers there.

There's test will be this year.

I don't expect-- I don't want to be negative.

We could have results fairly early in 2015 I think on some wells, some one-off kind of wells that we put in various facies.

But we won't have significant pilot results probably until year-end or so.

Understood.

Thanks a lot, guys.

Subash Chandra, Guggenheim

Yes, thanks.

I was hoping you can help me think about a number from the K that I really have not looked at before.

It's part of, and when you talk about the number of wells discussion, I guess what's in there is about 130 net wells, that as of the February date were still in the completion process or about to be completed.

Which is considerably more than I guess the prior year's 10-K.

When I think about I guess that number being above a trend line or a year ago and that gets worked through so you may not get the benefit of that heading into 2016.

But then you do get the benefit of the deferred completions as you talk about throughout the course of the year.

I guess a net some of that is what I'm trying to think of is do we end up in the same place that where you have more deferrals but less momentum from the 2015 carryovers versus the current period where you got a big momentum from the 2014 carryovers but fewer ducts?

That's quite a question.

(laughter) Sorry about that.

And I understand it's a modeling question.

Let me make one comment, I think maybe it's helpful.

I think everybody knows that we underperformed a little of our expectations in the third quarter last year because we had a lot of wells shut in, waiting on completion or associated with SimOps.

In the fourth quarter a lot of those wells came on and we had very little simultaneous operations downtime in the fourth quarter, so we performed really well in the fourth quarter, which carries us well into 2015 with some really outstanding performance.

I think we show in our data there how many wells we think we are carrying in and how many wells we think we are carrying out.

Our model is based on that.

I guess for more detailed modeling questions I will ask you to follow up with Brent and James later on because I'm not sure I can completely follow the question.

Yes, I will Jay.

I think it goes back to Dave's question earlier on thinking about 2016 as being a function of maybe a number of things; based completion, ducts, but also possibly a carryover momentum from the prior-year.

That piece of it is something among operators I was trying to figure out.

And then, as far as the northern Eagle Ford, in your best guess right now you still think, I guess, the entirety of your new completion techniques will apply.

But practically speaking, what portion of it do you think is-- would be effectively economic at a 65-- 350 dec that you've run.

Let me go back to your question on carrying momentum.

I think, no question, when we think about 2016 what we're thinking is that we'll come into 2016 because how we've ramped down and we will be ramping throughout 2016, so the back half of 2016 we're growing, we think we can be growing, and I think that relates somewhat to your momentum question.

I will talk specifically about the North area and the Eagle Ford.

We think this acreage is going to drill out.

We have a type curve there that's an average for the whole area, you start to look at getting our cost down and the strip and where pricing will go over the next few years and we think a lot of this is economic.

We've already spud a 12 well pilot there to test the stack and stagger idea.

I think there is enormous amount of potential in the North area for a lot of oily wells.

We are not discounting any of it at this point.

I think the type curve we present is a very reasonable type curve and all the evidence we have so far is that the western portions of this acreage are good.

Okay, and a final one for me.

I apologize if I missed it in the release but do you have a commodity mix for 2015 production guidance?

Yes we do and it is essentially the same as 2014.

It is not in the release it is in the deck.

It is slide 12 (multiple speakers) shows you the mix and it is essentially the same.

I think oil is exactly the same percentage of production.

Right.

The other comment I will make on your question on the ducts, as you call them.

Slide 10 is pretty clear that we're showing an increase from year-end 2014 of 45 to 95 by the end of year-end 2015.

As Jay said, give Brent and James a call and we will help you reconcile the numbers to the numbers you are looking at in 10-K.

Sure, absolutely.

And a final one.

The non-op Eagle Ford I suspect maybe the number is usually in there, if I missed it I apologize again, or maybe it was because Anadarko provides it after they update next week.

Or do you have a sense on timing when you might have the number?

We put a capital number in there based on our best guess of what their activity level is going to be.

And we have gotten some feedback from them later last year that they were going to be shifting some of their activity to areas in which we have somewhat lower working interest as well.

So what we did is we assumed that they are going to cut their activity about in half and that we are going to lower working interest areas.

So we have a budget in there for it.

They will be releasing here in a few weeks and certainly we are as anxious as anybody to see what they actually say about their activity level.

Okay, and your fourth quarter production?

This is Brent.

It grew 23% in the fourth quarter.

APC's production, so, it's about right under three million barrels equivalent.

Great.

Thank you all very much.

Pearce Hammond, Simmons & Company.

Good morning and thanks for taking my questions.

You bet.

Jay, I would love to get your big picture thoughts on the Permian and SM in the Permian.

The reason I ask is because I know you have got some good acreage there at Sweetie Peck.

I know it's small but-- seems like you generate some very good rates of return there.

The rig count based on slide number 9 looks like you dropped that Permian rig in May.

So just kind of a big picture thoughts, how it fits in your overall portfolio and that acreage they are at Sweetie Peck.

I think scale in the Permian really needs to be measured by well count not by acreage.

We have a very large economic well count there essentially all of which at this point is held by production.

When well costs are dropping this fast on HBPed acreage, it just does not make sense to us to continue a program and we need to wait.

We are going to wait there, we can afford to do that, we can hold all the acreage held.

And we will way til our costs come down and our returns improve.

That is just a good present value approach to your business.

In terms of the long term in the Permian, I'm not sure it's even worth having a conversation about right now.

We are not going to sell HBPed oil the assets in this market and I do not see an opportunity to do that anytime soon anyway.

So maybe that's a little longer-term discussion we can have when things return to a more normal cost environment associated with price.

Thank you for that Jay.

Then my follow-up, on slide 10 you detail the deferred completions that you'll be building those wells waiting on completion this year.

What oil price would make you maybe change your mind a little bit and start completing some of those wells that you currently intend to defer.

Well Pearce, as we said several times earlier, this is not about price.

This is about cost.

We're not making guesses and not floating numbers about, hey if oil price was $70 we would ramp back up.

That's not what we're about.

I understand why people do it.

What we're after is cost.

Our wells will make substantially better economics at lower cost.

And when cost get to where we think they need to be and where we think they're bottoming, we will start completing wells.

That could be later this year, it could be into 2016.

Perfect.

Thanks for the color Jay.

Matt Portillo TPH.

Good morning guys.

Good morning.

You mentioned the increased activity in the middle Bakken in Divide County potentially rolling through in 2015 and I was wondering if you could talk about relative well performance you've seen to date versus your Three Forks type curve and that portion of the play.

Yes, thanks for asking that.

Actually we showed data on that in our December presentation.

We drilled a number-- I think it was three or four Bakken wells on the North side of our acreage and they actually are outperforming our Three Forks type curve.

Admittedly, those wells are on the North end and we need to get some more wells on the South, we will be drilling some of those this year.

But very, very encouraging early results and wells drilled, I think we drilled those wells for right around-- a little more than $5 million.

If you put a 400,000 barrel type curve on that at $5 million, this is very economic drilling.

If we can get our cost down there even lower that is going to be terrific.

We need to show-- Again, we don't include any of those Bakken completions as part of our current inventory.

This is a huge upside on a very large acreage position.

Great, and then just a follow-up question.

I know that you're testing enhanced completions across a large portion of your portfolio.

I was wondering if you could provide an update on your thoughts around enhanced completions in the Bakken?

And as you think about the 2015 mix, how that could change versus some of the completion techniques you are testing at the back end of 2014?

In the Bakken specifically, we have moved to plug-perf on almost everything at this point.

We would agree with everybody else out there that plug-perf is the way to go.

We are cementing a number of our liners now, something we did not used to do.

I think all those things that we are seeing significant sustained improvement from that across the entire Bakken interval.

We are testing some higher sand loading completions, they are not to the extent we do in the Eagle Ford or Permian but certainly higher.

I do think in the Bakken, because we are essentially building inventory and delaying completions quite a bit, it will be-- We obviously won't make a lot of completions in the first six months of this year in the Bakken.

So it will delay our opportunity to see some results there.

I think you will continue to see really good results coming out of our Eagle Ford program with higher sand loadings.

And we will be watching, we're doing higher sand loading, zipper frac jobs on completions in the Permian on the wells we just recently completed, and we will be watching those as well.

So continued information flowing to us on things that I think drive our completion program into the future.

Thank you very much.

Paul Grigel, Macquarie

Hi, good morning.

Just focusing on the rig plan going forward here, how much was that influenced outside of the Powder River?

You guys touched on lease expiration, but in other plays on lease expiration or on midstream commitments throughout the year?

Our plan meets all our midstream commitments and, really, if you look at it, I think the question I would ask when I look at this is why didn't we slow down faster in some of these areas.

And the real reason is we had rig commitments.

We did not want to have to pay big penalties to lay down rigs earlier.

So our approach, rather than do that, was to go ahead and drill those rigs where we are drilling very efficiently, like we are in the Bakken.

And that just backlog the completions.

That was the approach we chose to take.

Okay.

Just on the M&A, I realize it's an ongoing process, but could you give any color on what the earlier response has been on the Midtown sale?

Really an enormous amount of interest in the package.

I want to say one thing about this.

The Mid-Con sale is about two things, really.

One it's about getting us out of what we consider to be not necessarily strategic assets going forward.

And we're not going to sell these assets in a fire sale, we're going to get what we think they're worth or we're not going to sell them.

I will tell you, I was in the field looking at these assets just two weeks ago, they are fabulous assets.

I saw the teaser: if we did not own them, I would be interesting in buying them.

These are great assets and will be a perfect package for somebody who's trying to build a company in that area of the world.

They are very well-managed, look great, we will get a lot of bids on this package.

But the second thing about this, and it's really maybe even more important to the Company, is that this was really about moving the people who are working on those assets to places in our Company where they could have more of an impact for us.

And I will tell you, people from our Tulsa regional office, it's where we're closing associated with the sale.

We're going to close it whether we sell the assets or not.

We have people from those offices who are already in South Texas, already moving to Permian, and they are already having an impact, a very positive impact on our developments there.

We had some terrific people in Tulsa, we just needed to put them in places where they could have more of an impact for the Company.

And I'm very, very proud of them, for the attitude they've showed and the impact they are going to have.

That was really what this was about, it was really about a strategic decision to put our people where they could make the most difference for us.

Thanks for that color.

One last one on the non-drilling in new ventures spending of $185 million, how much of that is actually related to new ventures spending in exploration?

It is really a very small part.

Most of that spend is really ramping down our Powder River Basin program.

That is where a lot of that spend comes from.

We came in the year running four rigs in the Powder and we're going to one.

So a lot of that spend is in the Powder.

That's it for me, thank you.

Hold on just a second -- let me say, the other was 185 and I think $44 million of that, right around $45 million, is actually new venture spend.

Joe Allman, JPMorgan

Thanks operator, hi everybody.

Hey Joe.

Jay, a couple of questions on your the D&C cost.

In your slides, when I look at the tight curves in this new presentation versus the presentation in December, it appears that your D&C costs for both Eagle Ford and the Bakken are down 12% to 13%.

Have you realized those actual D&C costs that you're putting with those tight curves?

There is a difference.

When we look at forward inventory, of course we're using a 25% number when you look at those slides in the back of the deck.

We are way ahead of where we expected to be already on cost reduction.

We've seen 25% type of cost reductions on completions already, pretty much across the board in all areas at this point.

I will give you a specific comment, we rebid a job recently in one of our areas and the frac job came in 67% below the original bid.

There's some enormous discounting going out there for people to stay busy.

I feel sorry for the service company folks who are having to do that, but that is just the nature of our business in this time.

We are well ahead of where expected to be.

Now in our budget, when we build the 2015 budget, I think we were really pretty conservative about what we saw cost being at your end.

It was 15% to 20% type assumptions by year-end.

I think there's upside actually in that.

We can either have more activity than we expected or potentially come in below what we project on CapEx.

I still think we've made some fairly conservative assumptions about cost.

If you look back, we did some work looking back at the 2008 and 2009 correction.

In the Permian, for example, there our costs were down 35%.

I think there's opportunity here to drive cost even lower than what we have showed here.

I can deal with this off-line but when I look at-- One thing I want to figure out is what is the base?

When you say in your slides that you are assuming a 25% reduction in completed well cost, that seemed to be related to the IRR.

But when I actually do the math on what you had in your December slides versus these slides the actual reduction, area by area, without fail is 12%, 13%.

So when you talk about reduction, what is the base?

Is it the average for 2014?

Is it sort of the--

Joe, this is Brent.

When you look at the December slides, those included a 15% discount off of-- that we were anticipating.

Right, based on 2014 cost.

We were already seeing costs coming down even in December when we put those numbers in.

Right.

Okay.

Those are forward inventory numbers.

We were looking forward a year and saying-- hey, we think we'll be down 15%.

Now we think we'll be down even more than that.

25%

--And then just a question on inventory.

You're doing various tests this year, so you're doing enhanced completions, even more enhanced completions, you're doing some down spacing, than you're doing the stagger/stack-- Could you give us just a timing of when you're going to give us some somewhat definitive results from those?

And which of those can really be the most impactful to your inventory?

I think there is two big tests that really drive inventory for us.

The stack/stagger is a huge impact because it could literally double or triple our inventory in certain areas of Eagle Ford.

The problem with these tests-- we've spud the wells, but it takes a long time before you actually have them completed online because you have got to drill a number of wells in one area and then essentially complete them all at the same time or within a very close proximity to one other.

If you look at that particular's example, that 12 well pilot we have in the North, we're spudding the wells now, we don't complete them until almost September.

It takes quite a long time, and then after that you'll have to have production results to see how they talk to each other.

It takes a while to do this.

It is a big project.

It will take a while for us to get the answers.

We will have some insights, I think, into just how wells are performing in different landing zones, things that we completed last year or early this year.

A little earlier than that, it might help us get people a little general direction about how we think it's going to go.

But we won't have specific results on that til certainly year-end I would think.

The other big impact is the Bakken up in Gooseneck.

And I will say there, again, because we are drilling and stacking a bunch of wells to be completed later, it's going to be a near year-end thing before we'll have a lot more Bakken completions to really talk about.

The exciting thing, I think, is that we're not stopping our process of building inventory here.

We built an enormous amount of inventory last year.

We are in a very strong inventory position.

What we can do now, we can go literally to the same assets that we've been working in without spending any additional land money or having to do acquisitions to get it and we can develop inventory even in this down year in those assets.

I think it just points to the opportunity set that we have.

It's a very strong opportunity set and fairly low-cost entry for us in the ability to add new inventory.

I think investors should be encouraged by that.

Jay, is the down spacing in the Eagle Ford East to 900 foot interlateral spacing-- That's separate from the stack/stagger program you're doing, right?

You mentioned that.

We have completed those wells at 900 to 1000 feet initially.

What we're hoping and what we think we can probably do is squeeze wells in the upper-- those wells were generally completed below the upper-lower interface.

What we're hoping to be able to do is put another row of wells essentially in the upper and change that spacing to get tighter.

And that's an opportunity potentially to double on that Eastern area if it's successful.

Big upside in areas that we know have substantial economics and where the infrastructure is already in place.

All right, very helpful, thank you.

Mike Scialla, Stifel

Good morning everybody.

Apologize if these have already been asked, I missed a portion of your prepared remarks.

I think you just answered, Jay, my first question or at least part of it.

You talked about building inventory with the opportunities you see within your existing asset base.

Any of those opportunities also include potential acquisitions?

I know you are asked about that to some extent in the $185 million that you allocated for non-drilling.

I'm just wondering if any of that is planned to target any sort of potential bolt-ons?

Mike, we don't budget acquisitions.

So that $185 million doesn't include anything other than some minor land acreage just in places where we need to renew a few things.

As I mentioned earlier, acquisitions-- and we see these deals, people bring us things all the time, companies, properties, whatever.

It's just hard for us to find acquisitions that will really-- they're as good or better than what we have internally as opportunities.

We look at a lot of things but we don't take a lot of interest in a lot of them.

Really it has got to be core area to us, we really want to stay within our footprint.

And we really want things that are as good or better than what we own.

In this environment, in particular, I think to do a major acquisition we would have to have some real thought process on how we manage the balance sheet associated with that.

When you go back to that $185 million-- I want to be really clear about what that $185 million is.

$65 million of that is overhead, it's exploration overhead, it's our people that gets capitalized.

$45 million of that is new ventures.

The rest is land and G&G.

And facilities.

And facilities cost.

And some of that is finishing up the pipelines that we were building in East Texas.

Now powder--

Powder shows up in other.

--is in other D&C, yes.

Okay, thanks.

Thanks for that.

Just wondering where you did in acquisition, if you have you been able to get any results on the new acreage that you acquired in Divide County in terms of new drilling results there and how those compare to what you've seen on your legacy acreage?

It's interesting, some of the very last wells that the previous operators had drilled up there, which were completed plug-and-perf, have turned out to be really good wells.

Even in our estimates of how those wells would perform, we think we got a real good deal on that.

We will be drilling a number of wells on that acquired acreage in the next year to hold acreage.

So we will see a lot of good results, I think.

We are encouraged by it.

Does that change your thinking at all, the results on those wells in terms of how you've been drilling and completing wells there?

I think in general we were probably one of the last companies to move strongly to plug-perf and cemented liners and we had really good results particularly in this area with uncemented non-plug perf wells.

Typically we are seeing better results and that's the direction we are going to be moving on almost all our completions.

And on your last call you talked about testing the southern acreage in Gooseneck.

Just wondering if there's any results there?

I don't have any to show yet, there.

That is something we will be doing in 2015.

Okay and last one for me.

I was kind of surprised the southern Eagle Ford economics you show actually look pretty decent.

Any plans to drill that or any requirements to drill anything down there?

Well we have one well clawing back now.

The real thing we had to do before we could get more testing done down there and really start poking some holes is we had to get some infrastructure issues lined out.

We needed to able to take those wells to a dry gas pipeline, significantly improves our net backs.

And actually if you look at the net backs on that dry gas stud it's really not bad compared to the gas business around the country.

You're talking about Houston Ship less $0.30 or $0.50, it's not a bad gas market relative to a lot of other places.

We are looking at it, certainly will drill some wells this year but not the huge focus of the program down there.

We talked a lot about building inventory and certainly the oily parts of the play is where we're going to focus a lot of our attention.

Great, thanks Jay.

You bet.

Thanks for the question.

Thank you, this concludes our Q&A session.

I would like to hand the call back to Jay Ottoson, President and CEO, for closing remarks.

Well thank you very much for your time and attention today.

We know it's an incredibly busy day and we really do appreciate your time.

I just want to say, again, this is as a Company with a strong balance sheet, significant liquidity and a lot of inventory that make sense to drill.

We're going to come out of this transition year a strong Company, and we're going to be beating people, and that's what we're all about here.

Thank you.

Ladies and gentlemen, thank you for your participating in today's conference.

This does conclude the program, you may all disconnect.

Everyone have a great day.