Brent Collins - Senior Director of Planning and Investor Relations Javan D. Ottoson - President, Chief Executive Officer & Director A. Wade Pursell - Chief Financial Officer & Executive Vice President.

Michael Dugan Kelly - Global Hunter Securities LLC Joseph E. Bachmann - Scotia Howard Weil Welles W. Fitzpatrick - Johnson Rice & Co. LLC Michael Anthony Hall - Heikkinen Energy Advisors David R. Tameron - Wells Fargo Securities LLC Scott Hanold - RBC Capital Markets LLC Subash Chandra - Guggenheim Securities LLC Pearce W. Hammond - Simmons & Co.

International Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc. Paul Grigel - Macquarie Capital (USA), Inc. Joe D. Allman - JPMorgan Michael S. Scialla - Stifel, Nicolaus & Co., Inc..

Good day, ladies and gentlemen, and welcome to the SM Energy Company's 2015 Outlook and Fourth Quarter Earnings Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. As a reminder, today's 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 to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday.

The 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'll 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've recognized, however, that most of the interest we really have from Investors Day is about how we're 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 focus on what we think really matters to you the most right now. We'll try to be clear, though, about what's slide we're on as we go through. I'm going to turn now to slide three.

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 1 billion barrels of oil equivalent of economic drilling inventory, about 20 years of our production at current levels.

As a management team, we've 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 of the 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've 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 of 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/P increased by more than 20%, and our total proved R/P is now about 10 years.

This significant improvement in our proved reserve life is a reflection of the improvements we're 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 six. Our year-end total debt to trailing 12-month EBITDAX was about 1.5 times.

We don't know everybody else's year-end numbers yet, so on slide six, we are comparing ourselves to the peer group as of the end of the third quarter of 2014. Slide seven 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 a $166 million drawn at year-end. We have five tranches of unsecured long-term 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 eight, obviously the largest 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, we believe it is critical in this business. Number two, slowdown activity, allow the cost environment to correct. We're 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 nine, as I just said, we're slowing activity to allow cost to correct.

We're blessed with a lot of flexibility with respect to duration of contracts, takeaway commitments, and 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'll 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'll also be able to accelerate quickly if we see an improvement in the commodity prices. Turning to slide 11, I'll discuss the CapEx dollars resulting from this program. The first word on cost assumptions.

While each basin has its own dynamics, we're 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 is in the Eagle Ford and the 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 a significant reduction in CapEx, production still grows 12% year-over-year.

The product mix is essentially unchanged with over half of our production being liquids. On a quarterly basis, the first quarter should be flattish with 4Q 2014 levels, and then decline about a 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 a $150 million, and I should point out, we expect to close the Mid-Con divestiture around mid-year with proceeds well in excess of this amount, but it's 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 2.5 times, again that's without counting the Mid-Con sales 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 with 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 2.5 times with significant liquidity and assets generating returns above our hurdles.

The 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 and our core development areas for the year. Slide 14 through 20, give updated information about our operated Eagle Ford in North Dakota positions, which will account as Wade indicated for the lion's share of our 2015 capital.

We plan to complete about 75 wells in our operated Eagle Ford program this year. I should note that we're already ahead of where we thought we'd 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 believe 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'll 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. We're going to make meaningful progress on this front this year, even with the 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 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'll 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 U.S activity will have a big impact on supplies 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 had a good plan in place for 2015 and we're confident that we will emerge from this transition year as a strong competitor. And we'll be happy to take any questions you might have..

Thank you. Our first question comes from Mike Kelly with Global Hunter Securities. Your line is open..

Thanks. Good morning. Jay,....

Hi, Mike..

Hi, Mike..

Hey, guys. So, the well results in the Eagle Ford and the Eastern North, real impressive on the 1,000 lateral foot basis.

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

Well, Mike, I don't know exactly when we'll push them up, and a few more wells I think. Obviously we're outperforming the type curve in most of those areas and that's certainly the position we want to be in for the type curves. When we show you economics, we want to be conservative about those..

Okay. Great.

And as it pertains to maybe having multiple laterals possible in the Eagle Ford here, maybe can you expand upon that, I mean, you got the 300 locations in the East, 500 in the North, what could that ultimately go to in your eyes if you're successful on 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's areas there we could potentially triple our well count over time and that's certainly our target, is to aim at that.

We'll be running some large pilot area programs where we're going to drill things at closer spacing and stack and stagger them in this year, so that we can see how they perform when they're 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, so 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.

I imagine you can only get there by having some sort of assumption of what production growth will look like in 2016, and any color from you guys on 2016's program, as it stands today, I think would be well received too..

Yeah. Thanks, Mike. That's a good question. I don't think we're prepared to give a lot of color or a lot of details with respect to what we're 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's 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, and that's a very similar program, slightly higher program, but nothing materially different and really nothing specific we can say more than that right now..

All right, fair enough. Best of luck, guys. Great quarter..

Thanks..

Thanks, Mike..

Our next question comes from Jeb Bachmann with Howard Weil. Your line is open..

Good morning, guys..

Hey, good morning, Jeb..

Just some few questions, Jay, on the completion backlog, looking at the 45% to 50% you had at year end 2014 and then kind of 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're building is going to be in the Bakken, and a lot of that is because we're ramping down activity. We 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.

So, we're 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 – 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. So, 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 costs down. And when we get costs 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..

Our next question comes from Welles Fitzpatrick with Johnson Rice. Your line is open..

Hey, good morning..

Hi, Welles..

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 East Texas or Permian acreage as we go through the year and how much you might lose there, how much you have to spend to save it?.

Yeah. Let me start with the Powder, and just say that our guide, the reason we can hold all that acreage is because we form three big federal units, and we can hold a lot of acreage now there with very little drilling. So I give tons of credit to our land staff up in the Rockies for doing that and a lot of great work to get it done.

In East Texas, right now, we're really doing some long-term production test on wells. We got our pipelines in place, and we're producing the wells. Our look at that is that, with the drilling we've done, we'll 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 then in the Permian, the acreage we have, that we've really got that we see is significantly economic right now, essentially all HBP. And it just doesn't make sense to drill HBP to acreage in the Permian right now with cost falling as fast as they are..

Okay, perfect.

And then, thanks for the updates on the well costs in the Bakken and Eagle Ford, and the PRB is still looking in that kind of $15 million range?.

No. We're below that. We're well below that at this point. But we have more things to do and really what we're focused on there is completion design. How are we optimizing. We've pumped some white sand, completions up there, which are significantly less expensive.

And frankly, we just made, I think the best Shannon well ever drilled in that basin, and really excited about that. So there is significant opportunity there.

We are slowing down relative to our other areas, it isn't – 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..

Our next question comes from Michael Hall with Heikkinen Energy Advisors. Your line is open..

Thanks. Good morning and congrats on the nice update..

Good morning..

I guess, one thing I just wanted to get a little more color around, is the implied efficiency improvement within the 2015 program versus the 2014 program. If we kind of look at how much you've spent to add production last year versus this year is a pretty dramatic improvement implied in the 2015 program.

I 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.

Any type of – ?.

Well, certainly we're ramping our exploration program down substantially..

Sure..

And as you might expect we typically risk volumes associated with exploration much more highly than we do volumes associated with developments.

So the improvements you're seeing, A, we're ramping on exploration, B, we're cutting – we're reducing costs and we're seeing costs come down faster than we expected almost everywhere across the whole portfolio.

And certainly we're drilling the best parts of our portfolio when you look at those type curves and we talked about this earlier, we're clearly going to the portions of the area where we think we can do above type curve wells and all those things combined in just generate higher capital efficiencies..

Yeah, okay. And that's helpful. That makes sense. And then, on the Divide versus McKenzie County well costs.

Can you just remind me what the major differences are there?.

Well, there's a big difference in depth. And a lot shallower wells up in Divide County. And that's why those wells are half literally half the cost now well maybe not quite half now, but they will be in that $4 million range we think by year end. I think the total depth is about 8,500 feet in Divide County. So you know.

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 competitor show map, showing Divide County is being – all of Divide County is being kind of the same and kind of Tier 3, just not true, okay.

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 County, Bakken/Three Forks well.

And so the economics here are strong and we probably – we're 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 and we have a ton of acreage with a lot of upside in it..

Okay that's helpful. Thanks and then 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 are you guys planning to pull that down, I guess number one, 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 it should be biased, our thinking towards drawing that down first as opposed to ramping rigs back up, just there were additional color you can provide that will be great?.

Well, clearly, what we're doing is we're setting ourselves up here to be able to do some to take advantage of completion cost reductions and as soon as we see those cost at a point where we can look forward to say, hey fabulous returns on these and we'll pick back up, so I think generally we would start completing wells before we'd necessarily start picking up rig count again..

Okay..

Part of what this gives us and lot of this is in the Bakken again, because again we drilled these wells really quickly. What it really gives us is a ton of flexibility as we look at how things play out into 2016.

And so, I think it's a really positive thing that we're basically able to keep production pretty flattish this year and still build the backlog. I think that speaks to the strength of our underlying inventory that we're – the wells that we are completing..

And sorry, just one last, if I can.

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

Ah, boy. 10 days..

Okay..

I don't want to oversimplify it, because the depths are a little different from one side to the next, but we've drilled some of these wells as low as 9.6 days, and most of them in the southern areas are probably more like 15-day to 16-day wells, and 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 very helpful, and congrats. Thanks, guys..

Thank you..

Thanks..

Our next question comes from David Tameron with Wells Fargo. Your line is open..

Hey, good morning. I would echo, congrats on the nice update..

Thank you..

And I'm just starting to think about 2016.

A lot of people, a lot of your competitors I guess seem to be developing a capital budget for 2015 that allows them to ramp going into 2016, and I know you guys have shown growth this year where a lot of those players aren't, but can you just talk about how you think about – I mean, so I think about the completion backlog being the toggle and assuming everything in that happens, happens and we're down 20% and that will provide that ramp going into 2016 or how should I think about, I'm just thinking about the 16 rigs to 6 rigs and then ramping back up? I know it was easier to add than takeoff, but I was trying to think about how you toggle that in backend?.

Yeah. David, all those things are come into play, right. We're building the backlogs, 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 doing the starts.

I think it's important 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 in drop in Bakken rigs all year long.

Well, if things pickup 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. So there's a lot of opportunity here for flexibility and getting back to a steeper growth ramp. We've mentioned it as really important. Our focus in on debt adjusted per share growth.

Well, we want to get back to as quickly as we possibly can is growing EBITDAX faster than we're growing debt and that is exactly what we're targeting in 2016. We're going to build a program that gets us to debt adjusted per share growth in all the key metrics.

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

Okay. Now, that's helpful.

How do you guys think about potential acquisitions, I mean, obviously you have the balance sheet? I mean, should we look for you to, I mean, obviously everybody wants to do bolt-on to the right price, but how do you think about that over the next – or how should we think about that over the next three months to six months?.

Typically, we're interested in assets that complement our existing footprint in that, we think have unrecognized value or inventory in them. We're seeing – we see a lot of deals, but right now, you don't see a lot that don't have some kind of hair on them, but 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 probably the easiest way to answer is that, if you look at the inventory in our existing assets, these are things we already own. There are low cost opportunities for us and that we're extremely focused on..

Okay.

And then last question, what – Jay, what kind of – what's your take on – what does the recovery look like, I know it's a 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 for 2015 and into 2016, what the landscape looks like as far as the pricing environment?.

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've 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. So, price is going to go where it goes and we're going to continue to focus on having the kind of assets they can outperform our peers..

Okay. I have already kind of answered my question, so I appreciate the other color. Thanks..

Our next question comes from Scott Hanold with RBC Capital Markets. Your line is open..

Thanks. Good morning..

Good morning..

Good morning, Scott..

Hey. Jay, on the stack potential in the Eagle Ford, can you give us a sense for some more finance or into the guidance more of a layman's terms. In terms of the geology in the upper and lower part of the Eagle Ford compared to what you were drilling before. How – what 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 forgive me for giving a somewhat long answer here. But I think what we and many other people have found in a lot of these shale plays is that there is a lot more vertical heterogeneity in these reservoirs than we originally thought.

And in fact, there is a number of different facies within the Eagle Ford shale especially in this thick section that we didn't really account for in our early work. We kind of thought well we'll put a completion sort of in the middle of this thing or below the middle and we'll get it all.

And what we found through both core work and modeling is that, that doesn't necessarily work that way. These fracs may – you may frac up into the Upper Eagle Ford, but you may not keep it open. And then the fact there is other facies that in which you can make good completions.

So that the areas you're 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've seen is not only from us and 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. So that's where the real opportunity's at.

And I will tell you, we don't just see this in the Eagle Ford. We've seen it in these thick sections in the Permian as well. We've done some specific modeling there where we had some core work and learning 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..

Okay. I mean, that certainly is helpful. And maybe if I can push a little bit more, is 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?.

There is I believe nine different facies, we've 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. I mean typically, we used to think that the upper was not sourced and the bottom was and the upper was maybe storage.

There is some good facies, good-looking facies 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. And what we found is that we don't believe that to be the case and we're not the only people who think that.

So I think there is 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're building, we'll 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, but we're really encouraged about what we've seen so far just in terms of landing wells in kind of different – in different facies..

Okay.

And so, 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?.

Well, we're really focused on that western area, where – the western area, like the north area, where we had a lot of thickness and we're doing one of – we'll be doing 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. So those tests will be this year. I don't expect – well, 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 till year end or so..

Understood. Thanks a lot, guys..

Our next question comes from Subash Chandra with Guggenheim. Your line is open..

Yeah. Thanks. So I was hoping you can help me think about a number from the K, that I really have not looked at before. But 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 I think the Feb date, were still in the completion process or about to be completed.

So – which is considerably more I guess than the prior year's 10-K. So when I think about I guess that number being above a trend line or a year ago, and that gets worked through.

So you get – so you may not get the benefit of that heading into 2016, but then you do get the benefit of the completions, the deferred completions as you talk about throughout the course of the year.

So, I guess a net sum 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?.

Well, that's quite a question....

Sorry about that..

Yeah. 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 were – 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 outperformed 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're carrying in and how many wells we think we're carrying out. So that's – our model's based on that.

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

Yeah. No, I will Jay, and I think it goes back to Dave's question earlier on, I'm thinking about 2016 as being a function of maybe a number of things – base depletion, ducts, but also possibly a carryover momentum from the prior year. So 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 deck that you've run?.

Well, let me go back to your question on carrying momentum. And I think no question, when we think about 2016, what we're thinking is that we'll come into 2016, because that we've ramped down and we'll be ramping throughout 2016. So, the back half of 2016, we're growing. We think we can be growing.

And that's – I think that relates to somewhat to your momentum question. On the – I'll talk specifically about the north area in the Eagle Ford, and we think a lot of this acreage is going drill out. We have a type curve there, that's an average for the whole area.

It's very – you start to look at, getting our costs down and the strip and where price is going to go over the next few years. And we think a lot of this is economic. We've already spud a 12 well pilot there in the North District to test the stack and stagger idea.

So, I think there is an enormous amount of potential in that North area for a lot of oily wells. And we're 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 the final one from me, and I apologize if I missed it in the release, but do you have a commodity mix for 2015 production guidance?.

Yes, we do, and essentially the same as 2014..

It's not in the release, it's in the deck..

It's in the deck..

Slide 12..

Slide 12..

Subash, shows you the mix and it's essentially the same..

Yeah, I think..

Okay..

Oil is exactly the same percentage of production..

Right. And Subash, just wait, the other comment I'll make on the – on your question on the ducts as you call them, I mean slide 10 is pretty clear that we're showing an increase from year-end 2014, a 45% to 95% by the year-end 2015.

And as Jay said, give Brent and James a call, and they'll help you reconcile those numbers – to the numbers you're looking at in the 10-K..

Sure. Absolutely. And a final one.

The non-op Eagle Ford, my suspect, maybe that numbers usually in there, if I missed that, I apologize again or maybe it was because, Anadarko provides that after they update next week or do you have a sense on timing of when you might have the number?.

Well, 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.

And so, what we did is, we assumed that they're going to cut their activity about in half, and that we're going to be 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're as anxious as anybody to see what they actually say about their activity level..

Okay.

And your fourth quarter production from Anadarko?.

This is Brent. It grew 23% in the fourth quarter..

Okay..

APCs (42:17) production, so it's about right under 3 million barrels equivalent..

Great. Thank you all very much..

Yep..

Our next question comes from Pearce Hammond with Simmons & Company. Your line is open..

Good morning, and thanks for taking my questions..

You bet..

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

The reason I ask you is, I know you've got some good acreage there at Sweetie Peck, I know it's small, but seems like you generated some very good rates of return there, and the well count based on slide number nine, to me the rig count based on slide number nine, it looks like you drop that Permian rig in May.

So, just kind of big picture thoughts, how it fits within your overall portfolio and that acreage there at Sweetie Peck?.

Well, 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, most of – essentially all of which at this point is held by production.

And when well costs are dropping this fast on HBP acreage, it just doesn't make sense to us to continue a program and we need to wait, and we're going to wait there, we can afford to do that, we can hold all the acreage, we've got acreage held and we'll wait till our costs come down and our returns improve.

That's just good present value – a good present value approach to your business. In terms of the long-term in the Permian, no, I'm not sure it's even worth having a conversation about right now.

We're not going to sell HBP to all (43:56) the assets in this market, and I don't see an opportunity to do that any time 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. And then my follow-up on slide 10, you detailed the deferred completions that you will 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 well, that you currently intend to defer?.

Well, Pearce as we said several times earlier, this isn't about price, okay. This is about cost. We're not making guesses and not floating numbers about, hey, if oil price was $70, we'd ramp backup, that's not what we're about. I understand why people do it. What we're after is cost.

Our wells will make substantial – substantially better economics at lower costs, and when costs get to where we think they need to be and where we think they're bottoming, we'll start completing wells, and that could be later this year, it could be into 2016..

Perfect. Thanks for the color, Jay..

Our next question comes from Matt Portillo with TPH [Tudor, Pickering, Holt]. Your line is open..

Good morning, guys..

Good morning..

You mentioned the increased activity in the Middle Bakken and 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 in that portion of the play?.

Yeah. Thanks for asking that. Actually we showed data on that in our December presentation. We drilled a number of – 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 and we need to get some more wells on the south.

We'll be drilling some of those this year, but very, very encouraging early results, and wells drilled like – I think we drilled those wells right around $5 million – a little more than $5 million. So, if you put a 400,000 barrel type curve on that at $5 million, this is very economic drilling.

If we can get our costs down there even lower that's going to be terrific. We need to show – again, we don't include any of those Bakken completions as part of our current inventory. So 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 the 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 kind of the 2015 mix, how that could change versus some of the completion techniques you're testing at the back end of 2014?.

Well, in the Bakken specifically, we've moved the plug-and-perf on almost everything at this point. We would agree with everybody else out there that plug purposed the way to go and we're cementing a number of our aligners now something we didn't use to do.

I think all those things that we're seeing some 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'll be – we obviously, won't make a lot of completions in the first six months of this year in the Bakken. So, it'll 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'll be watching, and we're doing higher sand loadings, zipper frac jobs on the completions in the Permian on the wells we've just recently completed and we'll 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..

Our next question comes from Paul Grigel with Macquarie. Your line is open..

Hi. Good morning..

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 exploration, but in other plays on lease exploration or in midstream commitments throughout the year?.

Well, our plan meets all our midstream commitments. And really, if you look at I think the question, 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 have rig commitments, we didn't 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 on the Bakken and then just backlog the completions. And that was the approach we chose to take..

Okay. Thanks.

And then just on the M&A realize, it's an ongoing process, but could you give any color on what the early response has been on the Mid-Con sale?.

Really, an enormous amount of interest in the package. I want to say one thing about this. The Mid-Cont sale is about two things really. One, it's about, getting us out of what we considered to be not necessarily strategic assets for us going forward.

And we're not going to sell these assets in a prior sale, we're going to get what we think they are worth, or we're not going to sell them. I will tell you – I was in the field, looking these assets just two weeks ago, they're fabulous assets. I saw the teaser – man, if we didn't own them, I'd be interested in buying them.

These are great assets, and it'll be a perfect package for somebody who is trying to build the company in that area of the world and that very well managed, look great. We'll get a lot of bids on this package.

But, the second thing about this is, 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, which we are closing associate with 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 place, where they could have more of an impact for the company. And I'm very, very proud of them for their attitude they showed, and the impact they're going to have. And that was really what this was about.

It was really about a strategic decision to put our people where they could make most difference for us..

Thanks for that color. And then, one last one on the non-drilling in new ventures, spending about $185 million.

How much of that is actually related to new venture spending in exploration?.

It's really a very small part. Most of that spend is really ramping down our Powder rig program, and that's where a lot of that spend comes from. We came in the year around four rigs in the Powder and we're going to one. So that – a lot of that spend is in the Powder..

Okay. That's it from me, thank you..

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

Our next question comes from Joe Allman with JPMorgan. Your line is open..

Thanks operator. Hi, everybody..

Hey Joe..

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

So in your slides, when I look at the type curves in this new presentation versus the presentation in December, it appears that your D&C cost for about Eagle Ford and the Bakken are down 12% to 13%, so have you realized those actual D&C costs that you're putting with those type curves?.

Well, there is a difference, when we look at forward inventory as – of course we're using that, I think a 25% number, when you look at those slides in the back of the deck. I will tell you, we're way ahead of where we expected to be already on cost reduction.

We've seen a 25% type cost reductions on completions already pretty much across the board in all areas at this point. I'll give you a specific just comment, we rebid a job recently in one of our areas, the frac job came in 67% below the original bid and there is some enormous discounting going on out there for people to stay busy.

I feel sorry for the service company folks who were having to do that, but that's just the nature of our business in this time. So we are well ahead of where we expected to be. Now in our budget, when we built the 2015 budget, I think we were really pretty conservative about what we saw cost being at year-end.

So it was 15% to 20% type assumptions by year-end, so I think there is upside actually in that we can either have more activity than we expected or potentially come in below what we project on CapEx. So I still think – I think we've made some fairly conservative assumptions about cost.

If you look back, we did some work, looking back at the 2000, 2008 and 2009 correction. In the Permian for example there, I mean our costs were down 35%. So, I think there is opportunity here to drive cost even lower than what we have showed here..

Got you. And I can do it offline but when I look at, I guess one thing I want to figure out is what's the base.

So when you say in your slides that, you are assuming a 25% reduction in completed well costs, that seems 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, I mean without fail is 12%, 13%.

So, when you talk about a reduction, like what is the basis, the average for 2014 is at sort of a peak?.

So, this is Brent. So when you look at the December slides, those included a 15% discount off of – that we're anticipating..

Right, based on 2014 costs..

Right..

Yeah. And we were already seeing cost coming down even in December, when we put those numbers..

Okay..

Again those are forward inventory numbers, so when – we were looking forward a year, and saying, hey we think we'd be down 15%. Now, we think we'd be down more than that..

Okay, okay. That's helpful. Okay. And then just – just a question on inventory, you're doing various tests this year, so you are doing enhanced completions – even more enhanced completions, you're doing some down spacing, then you are doing this, the stagger stack.

Could you give us just the timing on when you're going to give us some somewhat definitive results from those? And which of those can really be most impactful to your inventory?.

Well, 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 the Eagle Ford.

The problem with these tests, it takes a long – we spud the wells, but it takes a long time before you actually have it completed online, because you've 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. So if you look at that particular example.

that 12 well pilot we have in the north, we're spudding the wells now. We don't complete them till almost September. So it takes a quite a long time, and then after that, you'll have to have production results to see how they talk to each other. So it takes a while to do this, and it's a big project. So 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 earlier this year, a little earlier than that, and it might help us give people a little general direction about how we think it's going to go, but we won't have specific results on that till certainly year-end, I would think.

Now the other big impact is the Bakken in the – 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.

So, 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're in a very strong inventory position.

But 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.

So I think it just points to the opportunity set that we have, it's a very strong opportunity set and a fairly low cost entry for us in the ability to add new inventory. So I think investors should be encouraged by that..

And Jay, is the down spacing in the Eagle Ford East to 900 foot inter-lateral spacing, that's separate from the stack stagger program you're doing, right?.

That's what we – you mentioned that, we completed those wells at 900 feet to 1,000 feet initially. What we are hoping and what we think we can probably do is squeeze wells in in the upper, those wells are 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 tight – to get tighter. And that's an opportunity, potentially to double on that Eastern area, if it's successful. So big upside in areas that we know have substantial economics, and where the infrastructure is already in place..

All right. Very helpful. Thank you..

Our next question comes from Mike Scialla with Stifel. Your line is now open..

Yeah. Good morning, everybody. I apologize if these have already been asked. I've missed a portion of your prepared remarks. But, I think you just answered, Jay, my first question or at least part of it, you talked about building inventory with opportunities you see within your existing asset base.

Any of those opportunities also include potential acquisitions? I know you were asked about that to some extent, and the $185 million that you've 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 – 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 – that are as good or better than what we have internally as opportunities. And so, we look at a lot of things, but we don't take a lot of interest in a lot of them.

Really, it's 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. And 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.

So when you go back to that $185 million, just to be – 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, okay. $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..

Powder shows up in other..

Is in other D&C, yeah, okay..

Okay. Thanks. Thanks for that.

And then, just wondering where you did an acquisition, if you've 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?.

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

We're – we will be drilling a number of wells on that acquired acreage in this next year to hold acreage and – so we'll see a lot of good results, I think, we're encouraged by it..

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

Well, I think in general, we were probably one of the last companies to really move strongly to plug perf and cemented liners, and we had really good results, particularly in this area with uncemented non-plug perf wells, but typically we're seeing better results, and that's the direction we're going to be moving in almost all our completions..

Okay.

And then, on your last call, you talked about testing the southern acreage in Gooseneck, just wondering if there is any results there?.

No. I don't have any to show yet there. I mean, that's something we'll be doing in 2015..

Okay. And then, last one from me. Just kind of surprise the southern Eagle Ford economics you show actually look pretty decent.

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

Well, we have one well flowing back right now. The real thing we had to do before we could get more testing get done down there, and is really start focus some holes is we had to get some infrastructure issues lined out. We needed to be able to take those wells to a dry gas pipeline, significantly improves our netbacks.

And actually if you look at the netbacks on the dry gas, it's really not bad compared to the gas business around the country. I mean, 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.

So, we are looking at it, certainly we'll 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 plays 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'd 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 the company with a strong balance sheet, significant liquidity and a lot of inventory that makes sense to drill.

And 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 participating in today's conference. This does conclude the program. You may all disconnect. Everyone have a great day..