David W. Copeland - SM Energy Co. Javan D. Ottoson - SM Energy Co. A. Wade Pursell - SM Energy Co. Herbert S. Vogel - SM Energy Co..

Welles W. Fitzpatrick - Johnson Rice & Co. LLC Kevin C. Smith - Raymond James & Associates, Inc. Kyle Rhodes - RBC Capital Markets LLC David R. Tameron - Wells Fargo Securities LLC David Martin Heikkinen - Heikkinen Energy Advisors LLC Michael Dugan Kelly - Seaport Global Securities LLC Chris S. Stevens - KeyBanc Capital Markets, Inc. Robert B.

Alpaugh - Piper Jaffray & Co. Michael A. Glick - JPMorgan Securities LLC.

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the SM Energy Third Quarter 2016 Earnings Conference. At this time, all participants are in a listen-only mode to prevent background noise. We will have a question-and-answer session later and the instructions will follow at that time.

As a reminder, this conference is being recorded. Now, I would like to welcome, and turn the call to Mr. David Copeland, General Counsel. Please go ahead..

Thank you, Carmen. Good morning to all joining us by telephone and online for SM Energy Company's third quarter 2016 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 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, presentation posted to our website for this call, and the Risk Factors section of our Form 10-K that was filed earlier this year and our Form 10-Q filed earlier this morning.

We will 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 release from yesterday.

Other company officials on the call this morning 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 of Investor Relations. I'll now turn the call over to Jay..

Well, thank you, Dave, and good morning everyone. Thank you to all of you for joining us. I know we've had a number of phone conversations this last quarter. As I look back over the last quarter, we performed very well in a period of significant change for the company. And I am very proud of our people and the work they've completed.

Before I turn the call over to Wade and Herb to cover the details of the quarter and our operations, I'd like to make just a couple of general remarks. I'm now moving to slide 3. During this last quarter, we made major progress toward being a premier operator of top-tier assets and generating differential returns for our shareholders.

We are achieving significant Tier 1 inventory growth through the two major acquisitions we announced in the Midland Basin. Our concurrent sales of other assets are funding these purchases and will allow us to redirect half of our spending to increase our capital efficiency and produce high margin growth.

Our confidence in making these significant changes is based on our demonstrated confidence in making better wells at lower costs in resource plays. Our third quarter results are indicative of that confidence, as shown on slide four. We beat our guidance for production and came in lower on all our guided costs.

We've rapidly transitioned into our operations role, following the closing of the Rock Oil transaction and are positioning ourselves to do the same on the QStar asset. We're already seeing better well results in Howard County than we assumed in our acquisition evaluations and expect that to continue as we fine-tune completions.

As you can see on slide 5, we've now achieved scale in the Midland Basin equal to or greater than our highly valued pure play peers. Our acreage position lends itself especially well to drilling long lateral wells, which Herb will address in more detail later.

Slide 6 shows how dramatically our drilling focus has shifted as a result of all the actions we've taken. This slide compares our rig activity in 2014 to what we now expect in 2017. I think it's fair to say that we've accomplished a significant transformation of the company's portfolio and our growth prospects.

The remainder of our prepared remarks today are divided into three parts. First, Wade will share with you more details on our third quarter results, and talk about our financial position. Then Herb will fill you in on our thinking about how we will create value in the Midland Basin.

Lastly, although we're not going to give final 2017 guidance today, because we don't have an approved budget, we will provide you with some general sense of our plans going forward.

Wade?.

Thank you, Jay. Good morning, everyone. I'm going to cover three areas this morning. The first area will be performance, and that will cover the third quarter plus any changes to guidance. Secondly, I'll summarize our recent transactions, and then thirdly, discuss the balance sheet impact on all of this.

Before I get started, I want to echo some of Jay's comments. The last few months, we've announced over $5 billion of acquisitions, divestitures, and capital markets transactions.

That takes a tremendous amount of work, so I want to personally thank all of the folks in my groups and throughout the company for their very impressive efforts over this short period in executing these very important transactions. So let's talk about performance first on slide 7. In summary, I would say, third quarter results were solid.

Production of 14.2 million barrels of oil equivalent came in above the high end of our guidance range. As expected, oil production increased sequentially with increased activity in the Permian and the benefit of Williston Basin well completions that came online late in the second quarter.

Natural gas production declined sequentially, although less than forecast, as Eagle Ford completions were in the higher oil/lower gas volume portion of the field. Fourth quarter production guidance of $13.3 million to $14.0 million BOE and ultimate volumes and commodity mix will depend upon timing of the closing of the Raven/Bear Den divestiture.

We're assuming the QStar acquisition closes near the end of the fourth quarter. LOE including ad valorem remained low at $3.50 per BOE, and as a result, we have reduced full-year guidance to $3.60 to $3.65 per BOE. That's down from $3.90 to $4.30 per BOE, which is down 12% at the midpoint and down 16% from our original February guidance.

G&A was just under $33 million and included about $3 million of charges related to our Billings office closure and internal reorganization. Fourth quarter should mimic this with another $3 million in reorganization charges expected. Given the one-time charges, we have narrowed full-year guidance to $128 million to $130 million.

DD&A guidance for the year has been reduced nicely to $14.50 to $14.80 per BOE, down from $15 to $16.50. This is partly due to the removal of certain assets from the DD&A base, which we anticipate selling as the Raven/Bear Den assets, as well as our interest in the non-op Eagle Ford asset.

Bottom-line results included adjusted EBITDAX and adjusted EPS, which well exceeded consensus estimates. Adjusted EBITDAX came in at $205 million and adjusted EPS was a loss of $0.37. Capital spend before acquisitions was $145 million, reflecting continued cost savings in drilling and completion activities.

We're revising full-year capital guidance down to $700 million. Final point to make here, which I think is a very important one, is through the end of the third quarter this year, adjusted EBITDAX exceeded capital expenditures by $86 million.

So turning to transactions update, in the financial position and liquidity section of the earnings release, we list the numerous transactions entered into during the last three months, which summarized were – $2.6 billion in acquisitions closed or under definitive agreement; $980 million in asset sales closed or under definitive agreement; $1.05 billion in equity funding, or 31.8 million shares, including shares issued in conjunction with the Rock Oil acquisition and shares expected to be issued to the sellers in the QStar transaction; and finally, $672 million in new unsecured senior notes.

That's more than $5 billion in transactions. The balance sheet at the end of the third quarter includes some, but not all, of these transactions.

Therefore, flipping to slide 8, I think it would be helpful to look at what we think the balance sheet will look like, at a very high level, at the end of this year after all of these transactions are closed. We ended the third quarter with zero drawn on our revolving credit facility and $981 million of cash plus $49 million of restricted cash.

October 4, we applied the cash balances to close the Rock Oil acquisition. Subsequently, we announced the definitive agreement to purchase QStar's Midland Basin assets for $1.1 billion cash plus $500 million in equity to the seller.

We announced this simultaneously with a definitive agreement to divest of $785 million of Williston assets, leaving only $315 million to be funded by the revolver, which has a borrowing base of $1.35 billion and commitments of $1.25 billion.

I should also mention that we added some oil, natural gas and NGL hedges a few weeks ago, thankfully at higher prices than they are today. You can see all of our up-to-date positions in the appendix of this presentation, or the 10-Q, which was filed this morning.

So at the end of 2016, before any adjustments for cash flow versus capital spend in the fourth quarter, we expect the following approximate debt metrics. Debt to EBITDAX to be in the high 3 times area. Of note, this is not a bank covenant for us.

And as a reminder, our goal is to get this metric back down to the mid-2 times area, which we believe will occur in 2018. Senior secured debt to trailing 12-month EBITDAX of around 0.4 times, well below the maximum ratio allowed of 2.75 times. And trailing 12-month EBITDAX to interest at around 5.7 times, well above the minimum of 2 times.

As we turn to slide 9, I will remind you that we have begun marketing efforts for the sale of our non-op Eagle Ford assets. The sales process is going well, and we assume that the transaction will take place in early 2017.

Our non-op Eagle Ford position includes a 17.5% working interest in the PDP, an average of around 15% working interest in the total acreage, as the working interests vary across the position, and a 12.5% interest in the midstream assets.

Proceeds from the sale of our non-op Eagle Ford assets should more than cover outspend associated with our general plans to run 7 rigs in 2017 and 14 rigs in 2018, which is a great segue in turning the call over to Herb. But before I do that, I want to emphasize, liquidity and cash flow coverage remain priorities for us.

We've taken sizeable and aggressive steps to transition to a top-tier portfolio. In the process, we've been very calculated on our funding of the acquisitions and in the timing of our divestitures and capital markets transactions.

Our plans to drive value creation from the Permian will be well-thought-out in terms of balancing aggressive cash flow growth with reducing our debt metrics and maintaining liquidity. We'll be refining our operations plan in the coming months and look forward to sharing it with you. I'll now turn the call over to Herb Vogel.

Herb?.

Thanks, Wade, and good morning, everyone. I'm going to cover three areas related to our assets in the Midland Basin. First, I will update you briefly about our continued progress and success at Sweetie Peck.

Second, I will summarize how we are doing in terms of integrating operations from the Rock Oil acquisition and planning for QStar and next year's operations. Third, I'll discuss the value we are creating from a single well perspective and then extend that to broader value generation at a spacing unit level.

Throughout this discussion, I'll touch briefly on recent results that we're seeing at Sweetie Peck, Rock Oil and QStar that all are really excited about the potential for better wells, lower costs and great returns in the Midland Basin. Finally, I'll close with a few comments about our forward operational plans for 2017 across the company.

Turning to slide 10. Here on the left, you can see our anticipated Midland Basin acreage position after close of the QStar acquisition. As Jay previously mentioned, we expect to be able to generate top-tier returns throughout much of this acreage from the stacked pay in multiple horizons.

On the right, you can see that once again, we have upped our expectations for production growth at Sweetie Peck this year. The completion improvements that we have implemented continue to yield production in excess of our pre-drill expectations.

I should point out that the production ramp-up shown in the slide includes early production from the six wells that we drilled and completed to test spacing down to an average of 400 feet between wells in both the Lower Spraberry and Wolfcamp B at Sweetie Peck.

Based on the early production performance from these wells, we believe that we can achieve excellent returns at these spacing levels with 7,500-foot laterals, even using an earlier generation completion design.

On top of that, we know that we can achieve even better returns when we drill 10,000-foot rather than 7,500-foot laterals, because the D&C capital cost per lateral foot is decreased, while productivity per lateral foot is about the same, improving capital efficiency by drilling 10,000-foot laterals where possible.

Now, speaking of lateral lengths, over the past few months, we have put in place sufficient land deals at Sweetie Peck to increase the number of 10,000-foot laterals in our inventory there. At year-end 2015, given the layout of our acreage, we assumed that only 42% of our laterals drilled there could be greater than 5,000 feet in length.

Now, we believe that 95% of our Sweetie Peck inventory could be made up of laterals greater than 5,000 feet in length. As I will show in more detail later, the combination of tighter spacing and longer laterals adds enormous value to our asset at Sweetie Peck and by extension to the rest of our growing Midland Basin position.

On slide 11, you can see that we continue to drill our wells at a fast pace, delivering best-in-class cost levels, even when we are drilling wells as we did this past quarter to the greater depths of the Wolfcamp A and Wolfcamp B. These take a bit longer to drill than drilling to the shallower Lower Spraberry.

We also use higher sand loading than many peers, which costs us a bit more but helps us achieve best-in-basin production performance. Now, turning to the second area that I'm planning to cover, as many of you know, we closed on the Rock Oil acquisition four weeks ago on October 4.

Our priority over the past couple of months has been to plan for and seamlessly integrate the Rock Oil assets into our Midland Basin operations. Handover of operations has moved right on plan and much of the success to date can be attributed to very effective and thorough planning and great cooperation from Rock Oil.

We were able to staff up to manage these assets by transferring a few of our people from Sweetie Peck and from assets that we divested over the past two months. In terms of activity, we are now managing the 140 producing wells that we acquired from Rock.

Slide 12 shows the performance of the operated horizontal wells we acquired from Rock Oil, and these continue to exceed our expectations despite most of these wells using an earlier generation completion design. Last quarter, we highlighted the first few days of production from the Ogre well, an IP30 of 1,640 barrels equivalent per day.

As you we can see, that continues to be a very strong well and utilizes some of the completion enhancements like higher sand loading that we have talked about previously, but it has a lateral length of only 7,700 feet rather than 10,000 feet.

Continuing with our activity on Rock Oil acreage, we just completed fracture stimulations on three of the wells that Rock Oil had drilled on one pad and are about to drill out the plugs and bring those wells on production over the next two weeks.

Just this week, we are starting up fracture stimulations on two more wells on one pad, also previously drilled by Rock Oil and should be able to bring those on production next month. We have entered into new contracts for two rigs to operate on the Rock Oil acreage, and both of those should be drilling ahead by the end of the month.

By December, we will be right on our plan, running four rigs and two frac spreads on our Midland Basin assets, split equally between Sweetie Peck and Rock Oil.

Similarly, we've been working closely with QStar to plan for a seamless handover of operations of the 180 wells we are acquiring from them, and to ensure drilling and completion operations continue at pace.

We expect that transaction to close in late December and are currently in discussions to sign contracts for two rigs to start operating on that acreage shortly after the start of the year.

On the QStar acquisition acreage, we were very pleased to see excellent early production from the BLISSARD well, which QStar just started flowing back about two weeks ago. This well, with a 9,700-foot lateral, averaged production of over 1,830 BOE per day over its first 14 days and that's naturally flowing without running any artificial lift yet.

Just over the past 10 days, the well has averaged 1,910 BOE per day at over 90% oil with 39.8 API gravity oil. Early days, yes, but this level of performance certainly exceeds our pre-acquisition expectations.

Given our expanding operations in the Midland Basin, we are seeing the potential for improved service costs from economies of scale and will be looking to work with high quality service providers throughout our operations there.

Turning now to slide 13, and the third area that I plan to cover today, and that is value creation from our expanded Midland Basin position.

We are now moving into execution mode and are laser-focused on delivering high returns through first, better wells from longer laterals and enhanced completions; and second, building on our upside inventory by drilling wells at tighter spacing and delineating additional intervals.

Finally, we will be delivering lower costs through well-planned development programs and economies of scale. Let me now elaborate on a couple of these points.

During the investor call that we held a few hours after we announced the QStar acquisition, I showed how we are able to build value through lateral length and completion design using single well examples.

I realize that many of you may have seen this before; however, let me repeat what I covered then, before building up to value at the spacing unit level. I'm now on slide 14.

If we were to drill a 5,000-foot lateral in the Wolfcamp A in central Howard County with a typical industry sand loading of about 1,370 pounds per foot, sort of the recent historical average, you could expect each well to generate a little bit over $2 million in net present value with a 10% discount rate, or NPV10, at recent strip pricing.

Increasing the sand loading to 2,000 pounds per foot would increase that NPV by almost 50% to $3 million per well. Increasing the lateral length to 7,500 feet and continuing with sand loading of 2,000 pounds per foot would double the well NPV to $6 million per well.

Finally, increasing the lateral length to 10,000 feet with sand loading at 2,000 pounds per foot will increase the value by another 50% to $9 million per well. This is consistent with performance improvements that we and other operators have experienced throughout the basin.

Rate is enhanced from the longer lateral length and higher sand loading, while costs are reduced since a higher percentage of the well's drilling costs is focused on the productive part of the wellbore.

As an example, let's say, you drilled two 5,000-foot laterals with old completion designs on non-contiguous acreage, you could see value of $4 million total in NPV10. Alternatively, you could drill one 10,000-foot lateral and enhance the completion design on contiguous acreage to get $9 million in NPV10.

Right there, you've increased the value by two-and-a-half-fold, not even mentioning the efficiencies in terms of surface facilities and pipeline infrastructure derived from one well with higher productivity versus two with lower productivity.

From this simple single-well example, I hope that it's clear how contiguous acreage offers us intrinsic value from longer lateral lengths and how completion design does make a difference.

Now, you probably have been wondering how well spacing, the distance between well laterals, and longer laterals and enhanced completions through higher sand loading factors into the value we can generate from our acreage and specifically at spacing units.

Taking a look at slide 15, which shows the net present value at a 10% discount rate for several lateral lengths and sand loading levels in two different size spacing units for a specific Wolfcamp A development in Howard County.

Starting at the left, if we plan on eight wells with 5,000-foot laterals in a 640-acre spacing unit – that's a square mile – the laterals would be 660 feet apart and with a base completion design of 1,370 pounds per foot, the NPV of that spacing unit would be about $18 million.

If we drill 12 wells in that same interval, so those laterals would be 440 feet apart in a plan-view, the spacing unit's net present value would be increased by a modest 17% to about $21 million.

When we tighten the spacing, we expect similar initial well production rates, but a reduction in each well's ultimate recovery, and that is integrated in this value assessment. However, the additional wells enable an improvement in the overall recovery factor across the spacing units, and, as I'll show you, the value.

For purposes of comparison to longer laterals, let's double the number of wells of 5,000-foot laterals to develop two 640-acre spacing units, that's equivalent to a 1,280-acre spacing unit. As shown in the slide, that simply doubles the NPV to $36 million for the wider spacing and to $42 million for the tighter spacing.

Now, shifting further right, if we replace the 5,000-foot laterals with half the number of 10,000-foot laterals in that same 1,280 acres, the NPV of the spacing unit increases by 60% from $36 million to $58 million at 660-foot spacing and a healthy 74% from $42 million to $73 million at 440-foot spacing.

Finally, if we enhance the completions to sand loading of 2,000 pounds per foot at tighter spacing, we can gain over 20% incremental improvement from there.

Look, the bottom-line here is that if we develop 1,280 acres with 10,000-foot laterals spaced at 440 feet and enhance our completions to a sand loading level of 2,000 pounds per foot, rather than develop it with 5,000-foot laterals spaced at 660 feet and legacy sand loading, the value of that spacing unit increases from $36 million to $90 million in NPV10.

In other words, the value of the 1,280-acre spacing unit increases by 150%; yes, that is about two-and-a-half-fold.

Here you can see the enormous value that technology has brought us from first, drilling longer laterals; second, increasing sand loading; and third, enabling design of fracture stimulations that focus the stimulator rock volume near the wellbore to enable tighter well spacing, i.e., laterals closer to each other.

Ultimately, that increases the value and recovery factor on each acre that we own. The example that I showed you only addresses one interval of a certain thickness. With stacked pay, we can repeat the same sort of logic to each pay interval subject to adequate pay thickness and reservoir properties.

With two or three or four horizons each, with a large amount of original oil in place, it is easy to see why investors and the industry value the Midland Basin so highly. Pulling all this together, I'm now on slide 16, which summarizes our Midland Basin position.

Through the announced acquisitions over the past quarter, we have expanded our potential drilling inventory in the Midland Basin by over five-fold to approximately 4,200 potential well locations. Our acreage position is largely contiguous, which enables drilling of better wells and those would be high value, longer laterals.

The expansion of our position in the Basin also brings the economies of scale, or lower costs, for our future development program, and that in the end delivers stronger returns on capital.

Turning now to slide 17, focusing our capital towards the top-tier opportunities that we now have in the Midland Basin, we anticipate growth with higher returns; a four-fold increase in oily Midland Basin production from 2016 to 2018 under current planning assumptions. Now, let me turn to 2017.

Although we are just now in the process of preparing our plans for 2017, you've heard from Jay that we are focusing our drilling dollars almost entirely on the Midland Basin. Our current plans ramp up from four rigs to six rigs in the Midland Basin by the end of the first quarter and dedicate one rig to the Eagle Ford throughout the year.

We will also continue to draw down our DUC inventory by completing wells in all regions and funding non-operated drillings and completion operations. Once we have completed our budget process, we'll be sharing full guidance. With that, let me turn the call back over to Jay.

Jay?.

Well, thank you, Herb. In closing, I think it should be really obvious to anybody why we're excited about SM Energy and our story right now. It's a very simple story of success in capturing high-value inventory, improving capital efficiency and driving high-margin growth through operational excellence and focus.

We're entirely driven by our vision to be a premier operator of top-tier assets and our desire to generate differential returns for our shareholders. At this point, we'd be happy to take your questions..

Thank you. And our first question is from the line of Welles Fitzpatrick with Johnson Rice. Please go ahead..

Hey. Good morning. And congrats on the big bump in inventory. It's great to see. I have one question.

And I apologize if I missed it, but that long lateral QStar well, did you guys say if that was in the Lower Spraberry or Wolfcamp?.

Well, that's – this is Herb. That's in the Wolfcamp A..

Okay. Perfect. Thank you.

And just one follow-up on the Upper and Lower development starting in 1Q in the Eagle Ford, can you talk a little bit about spacing there, is that going to be on the 625 feet within zone spacing you guys had talked about a couple months back?.

Eagle Ford..

So, well, let me make sure I understand – this is Herb.

So, you're talking about Eagle Ford, where we've completed in 1Q or just throughout the year?.

I'm sorry, when you restart in 1Q 2017 in the Upper and Lower development, what spacings you're going to use for the development plan?.

Okay. So, we have a number of DUCs that we're completing and those are generally in the – where there is just one Upper, one Lower, there's – not stacked, they're just simply staggered in that area. And I believe those are on a plan-view basis, those are around 300 feet or 400 feet of spacing..

Should be half of 625 feet, right?.

Yeah..

312.5 feet or something..

Okay. Perfect.

And it will be the same plan when you get the rig working?.

Yeah. And the rig will be working in certain areas and we will be doing that same sort of stagger pattern rather than the stacked stagger pattern..

Yeah. In general, once as we go Upper/Lower, we'll be at half of the old 625 feet spacing. So it should be 312.5-foot spacing essentially..

Okay. Perfect. Thanks so much..

And our next question is from the line of Kevin Smith with Raymond James. Please go ahead, Kevin..

Hi. Good morning.

Appreciate your discussion on the value of drilling longer laterals in Midland, but I was wondering, do you have a sense of the average lateral length you're targeting initially in Martin County?.

So, Kevin, this is Herb, again. We are planning on 10,000-foot laterals wherever we're able to permit them and get the spacing units configured properly to do that. So, definitely our average is over 7,500-foot laterals in that area and we'll go for 10,000 where we can..

Okay. That's helpful.

And then, is there anything that you're going to be doing differently or are these wells pretty much are now going to be identical to what you're drilling in Sweetie Peck as far as the drilling and completions?.

No, there are some differences in the completion. We start from a Sweetie Peck design and then we improve from there. So we're constantly working improvements in where we see them possible. I will say QStar did some real innovative things in there for testing that will give us data, that will help us identify even better what to do in Howard County..

Okay.

And lastly and I'll jump back in queue, when do you expect to be able to start drilling on QStar; obviously you're still in the process of closing, but how long of a delay do you think that would be?.

So if we assume end of December, it's just a matter of entering the rig contracts and getting them geared up to drill. So we'll do it as soon in the first quarter as we can..

Thank you..

And our next question comes from the line of Kyle Rhodes with RBC. Please go ahead, Kyle..

Hey, good morning.

On the down-spacing pilot, are those Lower Spraberry and Wolfcamp Bs being drilled on the same pad? And then I guess, is there anything in the hopper for down-spacing tests in Howard in 2017?.

Okay. Kyle, those are different pads for the Lower Spraberry from the Wolfcamp B where we down-space. So, they're not directly over each other. There are some legacy wells in the other intervals nearby, but those specific tests, those six are in different pads.

For Howard County, yes, we anticipate some of those being at lower spacing than the 660-foot legacy in our plan..

Okay. Great. And then a follow-up. Do have an average lateral length on the remaining Sweetie Peck inventory? I think, you said 95% was now drillable at over 5,000 feet.

Is there an average you can give us on average lateral length left?.

Yeah. I would say the average is over 9,000 feet..

And that's on Sweetie Peck, over 9,000 feet?.

Yes, that's Sweetie Peck..

Okay. Great. And then, just one... (32:02).

...we are able to get those spacing units in place, because of our contiguous acreage position, which is fantastic to have..

Yeah, that's great news. And then just one last one from me.

Any specifics you can give us on the bolt-on acreage you guys got in Howard County just in terms of price and location there and then the scale of the opportunity set for future bolt-on?.

Well, I'd just like to start by saying we have a great inventory, top-tier drilling inventories, and right now we're really focused on integrating the acquisitions we've made and demonstrating that value through great execution.

We did acquire a couple of ongoing entities who had leasing programs going on and we're always going to look at things that will enhance value. We're obviously not going to talk about what we paid for acreage in any specific area. But we are actively pursuing smaller acreage consolidation opportunities in our position..

Appreciate it, guys. I'll hop back in queue..

And our next question comes from the line of David Tameron with Wells Fargo. Please go ahead..

Good morning. Just jumping out of the Permian to the Bakken, can you talk about – you mentioned something in the press release about some of the completions being delayed, because I think you said you're installing pumps.

Can you talk a little bit about where that's at today, and as far as when do you anticipate those wells to come online?.

Yeah, David, this is Herb. Yeah, we completed quite a few wells in the Bakken and we were just going through a program of putting the pumping units on. So, it just staggers out rather than all 20-some completions coming on one day.

They're just on a program of installing – it's the efficient way to do this rather than put 20 crews out there to do it all in one day. We're just kind of layering them all in and bringing them online. So, they'll be coming on in a phased manner through basically the end of the quarter and now.

So, they'll just be offsetting base decline and then potentially showing a little bit of growth from there..

Okay. That's helpful.

And then there's been a lot asked about the Permian, but if I can just go back to the big picture, you kind of laid out like a projected outspend, I know it's not a lot, especially given the balance sheet, but how should we think about the toggle of that level? I mean, as far as cash flow share, however you want to address that, how should we think about that number up or down from here based on prices or how we should think about that?.

Well, we have the program pretty well planned out. I think through next year we've identified we're going to run six rigs in the Permian and a rig in Eagle Ford and that's what we think we need to run to generate the values that we've estimated. So, I think that the Permian's fairly well set.

We still have some debate on how many completions we do with respect to coming to a final budget. I think those numbers should be fairly close, obviously prices are up and down a little bit. There is probably a band around the numbers we've showed.

In terms of how we fund all of that, I mean, I think we're going to have non-op Eagle Ford proceeds in the first quarter..

Yeah..

That data room is well attended with a lot of what we believe is really genuine interest in that and that's how we'll be funding our outspend..

Okay. No, that's helpful. Thank you..

And our next question comes from the line of Mike Scialla with Stifel. Please go ahead. Mike, your line is open..

Mike's disappeared..

Okay. And our next question comes from the line of David Heikkinen with Heikkinen Energy Advisors. Please go ahead, David..

Good morning, guys. Thanks for taking the question..

Sure..

As we've looked at slide 17 and your impressive growth through 2018, one thing that we've been thinking about is the ability for companies to either lock in and takeaway capacity and/or differential protection out of the Midland Basin; because your growth continues obviously beyond 2018, it shouldn't slow much.

So how do you think about that? Can you talk about that a little bit?.

Yeah, David, this is Herb. We looked at that real closely, so obviously when we went into Howard County, we were real pleased to see its location with respect to all the long-haul pipelines away from the Midland Basin.

And it's pretty clear to us that, between the existing capacity, which is quite a bit above current production for oil, and with anticipated or known expansions, we're good through 2020, in terms of takeaway capacity, even assuming fairly aggressive growth from other operators. On the gas and NGL side, there's plenty of capacity there.

So, yes, we are focused on that and we realize that others are also growing and we think the infrastructure is planned or there to do that..

Okay. And then, just long-term fit in the portfolio for Divide County and how you think about capital allocation there..

Well, our Divide County assets are a great asset, a big contiguous oily asset that throws off a lot of cash flow. It's great to have options like that in our portfolio. And as we move forward and start looking forward into 2018, certainly we'll take actions there that are consistent with maximizing its value to our shareholders..

Okay. That's helpful. That was it; thanks, guys..

And our next question comes from the line of Mike Kelly with Seaport Global. Please go ahead Mike..

Hey, guys. Good morning.

Just following on to David's question there and respecting and appreciating you've just done an epic amount of portfolio high grading here, I'm just curious, Jay, if you're largely done on this front or are you still hungry for potentially to be involved in some of these bigger Permian deals that might still be out there, maybe trim the Eagle Ford operated acreage position a little bit.

How are you thinking about where the portfolio sits now? Thanks..

Well, I think we are very happy with the inventory that we've built. We have a great inventory of top-tier drilling opportunities. As I said earlier, we'll always look at things that could enhance value.

Most of our focus right now though is really on pursuing smaller acreage consolidation opportunities that would clearly enhance the position we've built..

Okay. Yeah. Fair enough. Thank you..

And our next question comes from the line of Chris Stevens with KeyBanc. Please go ahead, Chris..

Hey. Good morning, guys. Thanks for taking my question here.

I was just kind of curious on the Permian down-spacing on the wells where you have 400-foot spacing, how much production history do you think you need before declaring victory there, and are you expecting any degradation to the well performance compared to what you've seen historically out of Sweetie Peck?.

Chris, this is Herb. Yeah, so the spacing, what we've assumed in announcements we showed you and I mentioned that we do expect a little bit of degradation in the ultimate recovery; however, the value from these wells is really attributed to the first few years of production from the wells.

From a value perspective, down-spacing really generates quite a bit. We would expect longer term for some reduction in recovery, but we've baked that into those numbers that you see there..

Okay.

So, it sounds like most of the degradation might be further out on the life of the well?.

Right. If you put 12 wells into a spacing unit versus the 8, you have more straws in the same pool. And so you would expect a slight degradation, but it's not that significant from a value perspective..

Right. Okay.

And what's the expected increase to your inventory relative to what you're showing now in your presentation slide?.

So, we've shown kind of that base known inventory and then we show upside inventory. So, quite a bit of that is in the upside inventory there..

Okay. Got it.

I guess just one on 2017, if I can, is there a rough estimate of the number of completions you might have in the Eagle Ford relative to the Permian, including the number of DUCs that you're going to be working down next year?.

Yeah, now we're probably getting into more detail than we can talk about without an approved budget at this point. So I don't think we have that estimate for you today..

Got it. Thanks a lot, guys..

And our next question is from the line of Robert Alpaugh with Simmons Piper Jaffray. Please go ahead, Robert..

Hi, guys, thanks for taking my question.

Just a short one; I was wondering, which county or where in location the QStar 9,700-foot lateral was drilled?.

Robert, this is Herb. It is in Martin County, southeastern part..

It's pretty close to the border. One other things that probably may not be appreciated is how much – there is quite a chunk of that QStar acreage is in Martin County, it's really a exciting position. Part of the reason we were excited about the acreage is it's a great position..

All right. Thanks. That's the only question for me..

And our next question is from Michael Glick with JPMorgan. Please go ahead, Michael..

Just another one on the QStar well, could you maybe speak to the completion design on that well specifically?.

Yeah. This is Herb. So the completion design is a completion design where a number of things have been tested.

So it's different parts of the lateral, they used different stage spacings, different cluster spacing and the sand loading level was pretty similar to what we'd use for sand loading, so in the 1,900 pounds per foot range; and that's a 9,700-foot lateral.

The stage spacing is relatively tight, but it's more or less at a latest generation completion design..

Got it. Thank you very much. That's it for me..

And ladies and gentlemen, this concludes our Q&A session for today. I will turn the call back to Jay Ottoson for final remarks..

Well, thank you again for being on the call today and we look forward to sharing our results with you as we move forward to execute on these great acquisitions we've made. Thanks again..

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program and you may all disconnect. Have a wonderful day, everyone..