SM Energy Co (SM) 2017 Q2 法說會逐字稿

Good morning, and welcome to the SM Energy Second Quarter 2017 Q&A Discussion.

(Operator Instructions) Please note, this event is being recorded.

I would now like to turn the conference over to David Copeland, General Counsel.

Please go ahead.

Thank you, Austin.

Good morning to all joining us by telephone and online for SM Energy Company's Second Quarter 2017 Earnings Call.

Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations 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, the presentation posted on our website for this call, the Risk Factors section of our Form 10-K that was filed earlier this year and our Form 10-Q filed for this quarter.

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

Reconciliation of these measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release for this quarter.

Other company officials on the call are Jay Ottoson, President and Chief Executive Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Herb Vogel, Executive Vice President, Operations; and Jennifer Samuels, Senior Director, Investor Relations.

I'll now turn the call over to Jay.

Thanks, David.

Good morning, everyone.

Thank you for joining us.

Well, I really hope you had a chance to listen to our prerecorded commentary, it's kind of a new thing for us for the quarter, and that you were able to review the associated presentation materials that we released last night.

We're going to take nothing but questions this morning.

But before doing that, I would like to make 3 quick points.

The first point I want to make is that with the end of the second quarter, we're now through the part of our planned strength to grow transformation in which oil production declined as we sold noncore assets and geared up our Permian drilling program.

We did beat our production guidance in the second quarter.

Much of that beat was due to the front end weighted pace of completions and simply great well performance in our relatively gassy Eagle Ford asset area.

I would note that our Eagle Ford program makes very high investment returns, similar to our oilier Midland Basin well program returns.

And obviously, it contributed to our very solid financial performance for the quarter.

Now with this quarter's release, we are again raising our production guidance for the year with no increase in our capital spending forecast, reflecting our high capital efficiency and our increasing confidence in well performance in both our Midland Basin and Eagle Ford development areas.

Within that increase in guidance, our oil production and oil percentage of production, after adjusting for the retention of our Divide County assets, have been adjusted upward to reflect the outperformance of our Permian wells as we've reported in our IR materials year-to-date.

We expect to see significant growth in oil production and associated increases in our operating margin in the second half of 2017 as our back end weighted, very oily Howard County completion program really kicks in.

In fact, our oil production and percentage of production are already up strongly in July.

This should be clear to everyone that we're on track to deliver better performance than we originally projected for full year 2017, and that we're driving higher value for the company.

Now my next 2 points have to do with some specific Permian-related issues discussed in other earnings calls this week, after we had already recorded our prepared remarks.

With regard to the issue of drilling through abnormally pressured or depleted zones associated with shallow produced water injection or older producing intervals in the Midland Basin, you should know that we diligently assess those risks and we plan our business accordingly.

At our Sweetie Peck asset, there are no shallow injectors.

In fact, all our water disposal there is off lease.

And in our RockStar area, we know where all the shallow injectors are and how much water they've injected, and we're very careful in choosing our surface locations.

Future water disposal in that area will be predominately in intervals below all our planned producing horizons.

To be clear, we have not encountered and don't anticipate encountering significant issues associated with abnormally pressured shallow zones, and we don't expect any related negative impacts to our drilling program for our economics.

The third point I'll make, and lastly, I'm sure that many of you understand that in reservoirs like the ones we're exploiting in the Midland Basin, that producing gas oil ratios vary by depth, reservoir pressure and producing interval.

But in general, all producing wells will increase in gas oil ratio as reservoir pressure declines with depletion.

The change in producing GOR or gas oil ratio for a well can be forecast using fluid composition data, and we incorporate that type of information into our reserve calculations and production forecasts.

One of the big attractions to us of our recently acquired RockStar acreage position is that in that area, producing GORs are low relative to other areas.

If you just look at our reported well results, you'll see that our wells in Howard County, for example, average around 90% oil initially, and our forecasts indicate that our GORs in that area will always be relatively low.

That's a significant benefit to our economics and it's a big part of the reason that as one analyst recently pointed out, our producing revenues per well are significantly higher than most Midland Basin producers.

With that, we'll be happy to take your questions.

(Operator Instructions) And our first question comes from Brad Heffern with RBC Capital Markets.

In the prepared comments, you talked about this 385-foot testing in Sweetie Peck.

Can you give a little more color on that test?

What were the benches?

And what the sort of geometry looked like there?

Brad, yes, this is Herb.

The Sweetie Peck test involved really 17 wells, altogether.

We had 6 existing wells there, and then we infill drilled between those 6 wells with multiple Lower Spraberry, Wolfcamp A and Wolfcamp B wells.

So when you look at the way that area performed, it was pretty much as we expected.

It's really the 6 out of those wells were existing wells.

Six wells were new wells that were surrounded by other wells, and then there were 2 that were directly offsetting 2 of the older wells.

And when we looked at it, the 2 that were offsetting the older wells didn't perform quite as well, but the other 6 performed right at expectations.

In fact, the 24-hour IPs on those new 6 wells that were isolated were at 90% of the 6 original wells that were there.

So we were real pleased with what we saw, and the key thing was we see the importance of doing codevelopment right from the get-go.

And I think, if you listen to those remarks, you'll understand the -- make a conclusion there.

Okay.

And then on the PRB, a couple of -- or one additional result and some longer history on the other result, they continue to look pretty strong.

What do you need to see in that area for it to start to compete for capital?

Or for you to maybe go to loan there?

Well, I think actually, those well results do compete if you -- you do have to look at them and say, look, right now we're -- this is Javan, by the way.

We're drilling standalone individual wells.

And so the well costs, pad costs and the cost associated with drilling single wells out there is pretty high.

When you start to project in, okay, we're drilling multiple wells on a pad or a larger program, you can get to significantly lower well costs.

And when you project that forward, those wells do start to compete for capital and make some sense to us.

So I mean, really super pleased by the performance of our JV partner there, significant improvement in well performance largely due to bigger fracs, better completions.

But we've also made some big strides in reducing the number of days to depth on the drilling side and other areas.

So we're making great progress and adding a lot of value to the asset.

So is that a like a 2019 event or something that you would foresee it getting a larger share of capital than it does now?

Well, what -- we clearly see this as where we can go once we have -- once we're basically back to our cash flows.

And that's kind of how we see that going, yes.

And so we're going to have to make some decisions as we go forward.

Do we continue to hold this asset or do we drill it out ourselves?

That's really just going to depend on what kind of returns we can achieve.

Our next question comes from Jeb Bachmann with Scotia Howard Weil.

Jay, just looking up in Howard on the Lower Spraberry.

Just wondering what this Papagiorgio well that, I guess, it's flowing back now.

Were you guys testing lower proppant in that well to kind of achieve higher flowback or higher peak rates faster?

Jeb, this is Herb.

So what we've been doing is we've been using standard completion designs of 167-foot stage spacing and around 1,800, 1,900 pounds per foot.

What we've been doing is in place that we have 3 pads -- 3 wells and an interval and a pad, we've been testing some more enhanced completions.

So what you'll see is a combination of completion design as we are customizing to the different locations.

So in the case that Papagiorgio or Lower Spraberry, it's pretty much a standard completion design for us.

Okay.

And just remind us what the lateral length is on that well, if you could?

Both are right around 10,000-foot.

10,000, okay.

And I guess, just quickly on the PRB.

Are the -- is the permitting still a lengthy process up in that area?

Yes, I'm glad -- yes, I get this question a lot and it does take time to get permits up there, but we have a lot of permits in hand and really have not a lot of permitting issues.

If you get yourself well organized and you have a plan and you have some alternatives to that plan, we haven't had any real issues in getting permits.

And I hear that from people occasionally that that's a big issue.

It does take more time, it's federal acreage.

But in general, we're well stocked with permits and haven't had trouble getting them when we need them.

You just need to be -- have a good planning process for that.

Okay.

I guess, can you just remind us what kind of time frame that is, like -- with the length to plan ahead?

We've got right now 75 to 80 permits in hand.

And so really, what you do is you have them, they're valid for a certain period of time depending on whether it's state or a federal.

And we actually just renew them, and I think we do that pretty much on an annual basis.

So we're pretty well stocked up to prosecute a big program, if it was justified.

I think -- and this is a Jay.

And I think, if you were starting from ground 0, you need to assume 200 days or something to get a permit on federal acreage.

That's probably not at all unreasonable.

But essentially, once you get a program set up and you're submitting multiple permits, you just need to get ahead of it in your planning process.

And I guess, just lastly, I mean, if you guys were to sell -- decide to sell that asset, do those permits transfer over to any potential buyer?

Sure.

Yes.

Our next question is from Michael Hall with Heikkinen Energy Advisors.

I guess, while on the PRB, can you kind of maybe talk about specifically on well cost kind of where they're at today?

And where you think you could potentially get them in the development case?

Okay.

Michael, this is Herb.

So the most recent wells, we've done quite a bit of science, data gathering is part of the JV so we could understand it better and then optimize the completion designs.

So Shannon wells are cheaper than Frontier wells.

Niobrara wells would be at a different cost also, but they're going to be in a full development mode by $2 million to $3 million less than our current well costs, and current well costs are going to be between $9.5 million and $11 million depending on how much data gathering we put in there.

But we do see the reduction of pad drilling dropping cost significantly.

So I think, at the end of the day, you can get these down to kind of Permian-type $8 million rough number kind of well costs.

Obviously, we're seeing some pretty outstanding well performance in some of these wells here recently.

So there's a reason to believe that you can get to the point where these wells can compete, certainly.

And that -- just to be clear, that number, the $9.5 million to $11 million, was that for the Shannon?

Or is that kind of across the Shannon and Frontier, that range?

Across Shannon and Frontier.

The $11 million had more data in it.

That actually had a core -- that had a core in it.

Okay, that's helpful.

And then, I guess, on the prerecorded call, you guys did have a comment around your oil hedge percentage on '18, sort of more than 40%.

I'm just wondering if you could potentially narrow that range down a little bit for us if you're comfortable doing that at this point?

This is Wade.

Probably not comfortable giving any more specificity there, given that we haven't really officially guided 2018 production.

But yes, we -- the point there was, I think before it was in the low- to mid-30s and we've been adding some more hedges on it, so -- recently.

So we've gone beyond 40%.

I think that's the gist of the comment.

Okay, it's worth a shot.

And then I guess, last on my end -- we did notice a quarter-on-quarter decline in Permian oil mix.

I'm just wondering, is that just a factor of or a function of well timing and a little bit of a roll in completions in the quarter, quarter-on-quarter?

Or kind of where your completions were?

I guess, what was the primary drivers of that from your perspective?

Well, clearly, the GOR that you see from us depends on where we bring the wells on.

So if we bring on more HoCo wells, they're going to be lower GOR.

If we bring on more Sweetie Peck, they're going to be a little bit higher GOR.

During the quarter, we put on 5 Sweetie Peck, 4 HoCo.

And then if you look at the back end of the year as we bring on -- 2/3 of the completion in the back end of the year.

1/3 was in the front end of the year, so you'll see the GOR vary a little bit based on that.

And then as Jay mentioned right in the opening remarks, there's a gradual increase in GOR relatively slow, just under the normal depletion of all the reservoirs.

And we're going to be really clear.

I mean, the reason we got a gassy quarter is because our Eagle Ford wells performed so incredibly well.

It is almost -- there is very, very little change really in the GORs of our Permian wells during the quarter.

Okay, fair enough.

And was there -- as we think about, like, you've already brought on, what, 12 wells in July, I think I'm getting the number right?

Right.

It's correct.

Versus, I think, 9 over the course of the whole second quarter.

So like is that -- I mean, I'm just wondering, like in terms of lumpiness throughout the course of the third quarter and into the fourth quarter, is there any kind of variability in completion timing that we ought to just keep in mind?

Any large pads that are going to influence that over the rest of the year?

Just to add a little granularity on the mining front?

Right.

Now, this is Herb.

So we've got 3 frac spreads running in the Permian.

And in July, for example, we had the 6-well Iceman pad come online, which is 420-foot spacing.

And obviously, that takes time to complete.

Most of the pads we have are between 3 and 6 wells per pad.

In Sweetie Peck, we actually had pads right next to each other, so that was a number of wells shut in while we were fracking them and then brought on 8 wells pretty much at the same time.

So yes, it's lumpy, but it's -- we're not going to do many single-well pads.

There's like Sundown where there's 2 wells, but most of them are going to be 3- to 6-well pads.

Our next question is from Chris Stevens with KeyBanc.

At this point, it does seem like a lot of your acreage in Howard County has been derisked for the A bench.

But do you have an update on, I guess, how much has been derisked for the Lower Spraberry and B bench at this point?

And I mean, I know you guys do have a lot of completions in the back half of this year, so is there an estimate of maybe how much of your acreage will have been tested and potentially derisked for the Lower Spraberry and B bench by the end of this year?

Yes, Chris, this is Herb.

So I'm going to just point either those maps we showed in January with the sweet spots and then say that, while we're derisking the Lower Spraberry and Wolfcamp B, we also have a lot of offset operators who are also derisking around us.

So you kind of combine those in there.

And we had clearly -- where we had to mark kind of the end of sweet spots in the Lower Spraberry or Wolfcamp B, and we're just pushing the boundaries where it makes sense.

In a lot of cases, we're doing pads where we do a Lower Spraberry, Wolfcamp A and a Wolfcamp B wells.

And what we're doing is just in a logical way, we're running through our program, which takes into account acreage holding, what other operators are doing and our data gathering plans.

So for example, we get core in a location.

That tells us something before we go drill another Lower Spraberry and Wolfcamp B well, so we know the specific target interval to focus on, the specific footage from the logs.

So it's an integrated approach, and we're doing it to really maximize returns long run and inventory.

So that's really how it's set up.

And I hope that makes sense.

Yes, yes, that makes sense.

Maybe I can just ask a question on the Iceman 6-well downspacing pilot.

The 420-feet between wells, is that in each zone, so it's 420 between the wells in the Wolfcamp A and the Lower Spraberry?

And then if that is successful, what does that, I guess, imply for upside to your inventory?

Okay.

So the 420 those -- that configuration is 3 Lower Spraberry wells directly over 3 Wolfcamp A wells and they're each 420-feet apart.

So imagine the Lower Spraberry and the Wolfcamp A, they're about 400-feet of pipe vertically and then they're each 420-feet laterally.

So that's the configuration.

In terms of inventory, really, that's pushing basically a little over 12 wells per section, which is an uplift over the normal 8 wells per section.

So it's more or less a 50% increase in what we call our normal inventory.

That said, in that specific area, we probably don't have that much inventory depending on where it was on those sweet spot maps we showed in January.

Okay, got it.

And then is there a -- I mean, we -- I guess this quarter saw some other operators talk about a little bit of degradation in the well performance from some of the downspacing pilots.

Is there an expectation on what we should expect on some of these wells?

Yes, there's 2 parts on that, and I think we're -- our results are quite consistent with other operators when we look at Sweetie Peck.

For example, those 385-foot spaced wells that we saw a reduction in the IP24 of 10%.

If we just look at a correlation based on -- and these are not very good correlations because there's lot of noise in the data.

But you can see a 15%, 16% reduction in the IP30s for going from 660-foot spacing to 330-foot spacing.

We have data sharing programs with other operators, so we can see what they're getting versus what we're getting.

So yes, you see -- expect degradation.

Key thing though is, how does it look for the first year, and so it takes some time before you can say, okay, this is what the change in the return is going to be from downspacing versus inventory.

And we're trying to maximize the NPV per section.

So that's how we're looking at it.

But I would say you can't make a call on the first 24 hours.

You can't make the call on the first 30 days.

You need to look at least for a year and really see where those declines come in.

And I'll just contribute here that, you asked the question earlier about delineation of the Lower Spraberry and Wolfcamp B. And I understand that everybody wants to see us go drill every interval in all our acreage, improve it all really fast.

But our priority is to set ourselves up to be able to drill pad spacing with significant density, pad drill stuff in 2018.

And in order to do that, we have to do a lot of this other testing.

Frankly, that's more important to the overall value of the program.

We have to do that this year.

So there is a compromise that we're making between full delineation of the acreage and getting the spacing testing and important data that we need to get, and we're leaning toward what we think is the higher-value side of that, which is to build a foundation for our future development by doing these downspaced testing right now.

So that kind of explains why we do what we do.

Yes.

And I want to make sure, when I said 12 wells per section, that's per interval.

So it's not -- so when we're talking about Lower Spraberry and Wolfcamp A, so that's per interval.

I just want to make sure that's clear.

Yes.

Our initial -- the economic inventory we put out earlier this year was 8 wells per interval per section, right?

In the Niobrara.

Wherever we felt, we had a test.

Our next question is from Paul Grigel with Macquarie.

Just jumping back to the Powder River Basin, a quick follow up there.

How much water are you guys seeing come off those wells?

And is that something that's manageable within the process and does it add a lot of cost?

Yes, Paul, this is Herb.

Yes, it's quite -- we're quite pleased with that.

The water cuts are quite low in the Frontier in particular.

Obviously, it's early days, we've only had those wells on for a couple of months now, but they are -- the water cut is definitely -- in the Frontier, it's going to be more like 1/3 for water cut.

In the Shannon, it's too early to tell, but it's probably dropping below 1 for 1 right now.

Okay, that's helpful.

And then as you guys kind of look to the '18 program, obviously, you've added some more hedges.

Can you provide an update on where you stand in the Permian on the HBP side?

And then just how you think about reacting both in a higher or lower scenario?

And maybe a little bit more focus on the lower side?

Is that based on outspend, leverage?

Just trying to understand what the governors are to the program as you've gotten more efficient, I think, in the prerecorded comments too on maybe not having to have as many rigs to do the program as previously thought?

Okay, Paul.

On the HBP, what I'll say here is that we have in our development plans, we have an execution plan that basically preserves all the acreage that we want to keep.

In some cases, that's triggering some extensions that are already integrated in there.

We -- I think we published at one point what the HBP percentage was already, because there's a lot of existing vertical wells.

But the program is really to maintain our acreage either by drilling or extending leases where that makes sense.

And Paul, this is Wade.

Regarding the '18 plan, I think, I commented in the remarks that we'd be seeking a balance between cash flow growth and debt metrics.

It should be pretty obvious that we'll be looking to get more visibility on cost and what commodity prices are looking like and baking in the better wells.

As we mentioned, we'll be factoring that in, but we'll be looking at debt metrics.

Liquidity is always a top priority of mine, so that will factor in when we're looking at potential outspend.

We've got a lot of liquidity right now with the cash and the revolver.

The undrawn revolver has a borrowing base of $925 million.

It shouldn't be unreasonable to assume that, that number excludes the nonop Eagle Ford, which we divested already.

So with the better well results we're seeing, you can assume a commodity price anywhere in the ballpark on where we are, you should reasonably assume that, that borrowing base could be growing.

So all of that will be factored in as we put the plan together.

It'll be a balance, though.

Okay.

And then maybe, Herb, one last one just on the operations side in the Permian on the downspacing.

Is there any thoughts with the slightly lower IP24 and IP30s as you guys get more data?

Would you go back and test wells with either lower proppant, lower fluid and kind of back off the completion side?

Any color you have on if there's potential solutions to some of that interference on the downspacing?

Well, Paul, what we're really striving towards is really near wellbore complexity in the fracture system.

And so where we're really driven that is to tighter stage spacing and more clusters and then trying to get that cluster efficiency up.

So there's things like use of diverters that we haven't started using in the Permian yet that will drive more of that sand near to wellbore.

And the more effective we can be that way, the tighter we can space wells.

So that's really what we're driving towards.

So we -- I don't think the solution is going to be lower sand loading and -- or lower fluid volumes.

The solution can be more driven by how do we get more sand near the wellbore and really get high recovery factors near the wellbore.

And we've had success moving in that direction.

We think there's a long way to go.

Our next question is from Cindy Treska with Goldman Sachs.

On Divide County, I know you took that asset off the market recently.

Could you just give us your thoughts on the potential for that to go back on the market?

And just in general, thoughts on additional asset sales?

Sure.

Yes, we did pull that after we didn't receive bids that we thought were sufficient.

Now if you think about asset sales for us in a general sense, when we're selling assets, we need to get a -- essentially a multiple of cash flow for that asset that's in excess of our leverage in order for that to be a deleveraging event for the company.

Otherwise, we're just selling cash flow and we're not here just to shrink the company.

So I think the -- our purpose would be to try to generate values for assets that we sell that are well in excess of the value of the PDP.

And in the case of that asset, what we got ourselves into was a following tape in terms of the strip and the upside associated with that was not being valued and we essentially got PDP-only type bids.

So we won't be going back to try to sell that asset again, until that situation changes in one of two ways: Either we can do enough work to show people that there is value in the upside at the current strip or we're going to look for a higher oil price in order to sell that.

In the meantime, we're harvesting the cash flows from that and benefiting from that by reducing our total outspend.

And I would say that principal is the same for any asset we would sell.

And what you're seeing us do, and I hope you noticed this, in the Permian or in the Powder, for example, is innovatively finding ways to create value to identify upside and to get to those kinds of multiples of cash flow for value that could be deleveraging to the company in a potential sale.

That's helpful.

And just lastly, on your balance sheet, you talked a little about your focus on liquidity heading into 2018.

You have to spend quite a bit of capital to develop the new Permian assets.

Are you looking to reduce absolute debt?

And if so, what are some of the options you're considering?

Well, I think the -- I think Jay just did a great job of talking to you about potential divestitures.

I mean, that -- those are obvious ways to reduce the outright debt balances and any debt metrics as well.

We previously announced what the outspend we thought would be in '17 and '18, and we prefunded that essentially with the nonop Eagle Ford divestiture.

So sitting here today, we have over $0.5 billion of cash and the undrawn revolver, as I mentioned earlier.

So as we move to next year, I said we'll be watching liquidity close and we will.

If we need to use a percentage of the capacity in the revolver, that's what we'll do.

Certainly, seeing no need to consider any capital markets activity in the future if that's what you're asking as well.

But those are kind of the -- we have a lot of flexibility and a lot of knobs that we can utilize over the -- this year and next year to manage leverage, including substantial growth of cash flows, which should be coming with the higher-margin production from the Permian growing into the credit metrics.

Our last question will be from David Tameron with Wells Fargo.

A couple of questions here just to run through.

And you talked -- I think, Herb, you talked a little bit about Sweetie Peck versus being a little bit more gassier than perhaps some of the other wells in the program.

How should we think about -- like what's that difference?

And then if we think about second half of this year and into '18, any -- can you guys give us a mix of kind of what you would expect that -- the way rigs to be allocated and I guess, back half of this year and into '18?

Yes, David, this is Herb.

So here, just for the GORs, just if you think about Sweetie Peck, the deepest interval in Wolfcamp B, they start off around 1,000 GOR and they'll climb by 3 years to be about a 4,000 GOR.

Wolfcamp A and Lower Spraberry are going to be a bit less.

The Howard County roughly, they start around 700 GOR depending on which interval, and they might get up to 1,400 after 3 years, so significantly lower.

When you think about our rig program, we have right now 7 rigs running out there, 2 over in the Sweetie Peck area and 5 in Howard County.

So you're going to see we're going to be weighted more, as we complete those wells, more towards the Howard County, lower GOR level.

Did that answer the question?

Yes, that gives me the detail.

Back to the Powder, Jay, or Herb or whomever.

You mentioned in the slide deck you have a Niobrara -- potential Niobrara test in '18.

Can you talk about, I don't know if others have talked about, can you talk about the way you see the Niobrara versus the Shannon or the Sussex or the Frontier?

Or however you want to address it.

Yes, I'll leave it at that.

David, let me just take the Niobrara right away.

What -- we see our acreage as being quite good for the Niobrara.

We had 2 wells with early completions back in 2011, short laterals, very low sand loading.

We see some of the offset operators just to the Northeast with significantly larger sand loadings, I mean, like kind of 12 to 14x what we did per -- pounds per foot.

So we see potential for a lot of inventory.

But the way -- only way we're going to answer that is by putting a big frac on the Niobrara well there and we -- we're -- we've got the maps.

We've got offset data, so we're working on the ideal way to test that Niobrara in a couple of wells.

I'll just add.

Geologically, they obviously are very different.

Shannon and the Frontier are essentially sandstone reservoirs and not really source rock, they are carrier beds and the Niobrara is a chalk, it's a source rock and very different -- two very different things.

Actually, very encouraged though by some of the results we're seeing in areas of the Powder where people have made successful Niobrara wells outside of what I would view as structure or highly structured areas.

We typically think of the Niobrara as being very successful in the Wattenberg, for example, where it's on structure.

What you're starting to see in the Powder is people making some pretty good wells in areas that aren't necessarily -- don't necessarily have that big structural component.

And I think that's a big -- that's a game changer for the Niobrara and the Powder River Basin if we can make good wealth off without that necessary structural component.

So really excited about the opportunity, tough locations on our acreage if we can make that work.

With that said, even just the Frontier and the Shannon looked really good.

We have a lot of locations there and I think in general, we have added a tremendous amount of value to our company and to the Powder River Basin over the last year with our activities in the Powder.

Okay.

And Jay, so I would assume that being the source rock, you need a bigger frac than what you're putting on in the Shannon and the Sussex?

Is that accurate?

Well, we're using pretty big fracs in the Shannon and Sussex, too.

But in general, yes, you're going to put a bigger frac on these wells and drill long lateral and all the things that you're doing in other source rock places.

Okay.

And then Jay, just one.

I just want to just give you a chance to step back.

And you laid out the 3-year plan in February and I know we talked a little bit about this in June.

But how do you see the 3-year plan today versus what you thought in February?

Obviously, prices moved a little bit on you.

But can you just talk about stepping back big picture where you think you're at and what that looks like over the next couple of years?

Sure, yes.

Honestly, I don't think our plan has changed.

Our view is that we're on a big oil growth ramp, cash flow is growing.

I know the strip has moved, but frankly, by the time we get to 2018, prices may be exactly the same as we projected back in February.

There has been -- it's moved a lot, it's going to move again.

The things that have changed that are all positive for us, very much better well performance than we expected.

Our costs are right -- essentially right where we expected them to be as you weigh in the efficiencies we've gained, so a really kind of a trade off there.

Our field operations are going extremely well and we're getting stuff done, we're drilling faster.

We're going to be able to do this stuff with less equipment in the field than we thought.

So when I look at it, we're ahead of the pace we expected to be, and we raised production guidance multiple times this year and we just raised it again.

We're going to get much, much oilier in the second half and you're going to start to see this big ramp in oil production and cash flows that we've expected.

So if anything, I think the future looks brighter for us than it did 6 months ago.

I understand all the uncertainty and stuff about the macro and I get that, but if you just look at facts on the ground as opposed to look at our program versus what we said the program was going to be, everything has been moving in our favor.

And so, I guess, from that standpoint -- and we feel very confident about where we're at right now.

Well, that's the end of the questions for today.

We'd love to get your feedback about the recorded message we did this quarter.

We're -- and a longer little -- maybe a little more extended Q&A session.

We did that because we thought it would help you get more information earlier and then that might help you in the preparation of your materials.

We know these are really busy times for you, so we're hoping that helps.

But anyway, we just want to thank you for your participation this morning, and we really look forward to talking with you again next quarter.

Thanks.

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