SM Energy Co (SM) 2016 Q3 法說會逐字稿

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. (Operator Instructions). 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.

I now would like to welcome Mr. David Copeland, General Counsel. Please go ahead.

Thank you, Carmen. Good morning to all joining us by telephone and online for SM Energy's third quarter 2016 Earnings Conference Call and operations update. Before we start, I would 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 actual results to differ materially from the results expressed or implied on 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 in 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 will now turn the call over to Jay.

Well, thank you Dave and good morning, everyone. Thanks to all of you for joining us. I know we have 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 have completed. Before I turn the call over to Wade and Herb to cover the details of the quarter and our operations, I would 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 premiere operator of top-tier assets and generating differential returns for our shareholders. We are achieving significant tier one 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 capital spending to increase our capital efficiency and produce high margin growth. Our confidence in making these significant changes is based on our demonstrated competence in making better wells at lower costs in resource plays.

Our third quarter results are indicative of that competence, as shown on Slide four. We beat our guidance for production and came in lower on our all our guided costs. We have 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 assets. 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 have 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 six shows how dramatically our drilling focus has shifted as a result of all the actions we have 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 have 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?

Good morning, everyone. I'm going to over 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 thirdly, discuss the balance sheet impact on all of this. Before I get stared, I want to echo some of Jay's comments.

Last few months, we've announced over $5 billion of acquisitions, divestitures and capital market transactions. That takes a tremendous amount of work, so I want to personal thank all the folks and groups throughout the company for their very impressive efforts over the short period in executing these very important transactions.

So let's talk about performance first, on slide seven. In summary, I would say third quarter results were solid. Production at 14.2 million of barrel oils equivalent came in above the high end of our guidance range. As expected, the oil production increased sequentially, with increased activity in the Permian and the benefit of Willis ton 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 to 14.0 million BOE and ultimate volumes on 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 volorum, remained low at $3.50 per BOE, and as a result, we are 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 mid-point 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 partially due to the removal of certain from the DD&A base which we anticipate selling. That's the Raven/Bear Den assets as well as our interest in the non Eagle Ford asset.

Bottom line results include 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 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 in 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 eight, 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 these transactions are closed. We ended the third quarter with $0 drawn on our revolving credit facility and $981 million of cash plus $49 million of restricted cash.

October 4th 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 the definitive agreement to divest of $785 million of Williston's 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 and 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 in this presentation or in 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. Net to EBITDAX be in the high three times area. Of note, this is not a bank covenant for us. And as reminder our goal is to get this metric back down to the mid two 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 two times.

As we turn to Slide nine, I will remind you that we have begun marketing effort for the sale of our non-op Eagle Ford assets. The sales process is going well and we assume that a 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 cross 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 seven 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 remains priorities for us. We have taken sizable and aggressive steps to transition to the top-tier portfolio. In process, we have been very calculated in 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 metric and maintaining liquidity. We will be refining our operations plan in the coming months and look forward to sharing it with you.

I will l 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 will discuss 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 will touch briefly on recent results that we're seeing at Sweetie Peck, Rock Oil and QStar that all are really exciting us about the potential for better well, lower cost 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 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 the 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 Sprayberry and Wolf Camp B at Sweetie Peck. Based on our 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 DNC capital 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 lay out 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 continued 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 depth of the of the Wolfcamp A and B. These take a bit longer to drill than drilling to the shallower lower Sprayberry. We also used 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 close on the Rock Oil acquisition four weeks ago on October 4th. Our priority over the past couple months has to been plan for and seemingly 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 asset 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 he we acquired from Rock. Slide 12 shows the perform of the operated horizontal wells we acquired from Rock Oil and these continue to exceeds 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 and IP 30 of 1640 barrels equivalent per day. As you 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 stimulation on two more wells on one pad also previously drilled by RockOil and should be able to bring those on production next month. We have entered into new contracts for two rigs to operate on the RockOil acreage and both of those should be drilling ahead by the end of the month. By December, we will be right on our plan of running four rigs and two frac spreads on our Midland Basin assets split equally between Sweetie Peck and Rock Oil.

Similarly, we have been working closely with QStar to plan for 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 [Blathard] well which QStar just started pulling back about two weeks ago. This well with a 9,700-foot lateral, average production over 1830 BOE per day and over its first 14 days. And that's naturally flowing without running any artificial lift yet. Just over the past ten days, the well has averaged 1910 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 for 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 a 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 level. I'm now on Slide 14. If we were to drill a 5,000-foot lateral in the Wolfcamp A and Central Howard County with a typical industry sand loading of about 1370 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 NPV 10, 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 of 7,500 and continuous sands loading of 2,000-pound per foot would double a well NPV to $6 million per well. Finally, increasing the lateral length of 10,000 feet with sands loading at 2,000-pound per foot would 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 cost 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 design on non-contiguous acreage, you could see value of $4 million total in NPV 10. Alternatively you could drill one 10,000-foot lateral and enhance the completion design on contiguous acreage to get $9 million in NPV 10. Right there you've increased the value by two and one-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 have probably been wondering how well spacing, the distance between well laterals, and longer laterals and enhanced completions through higher sands loading factors into the value we can generate from our acreage, and specifically a spacing unit. Taking a look at Slide 15, which shows the net present value at a10% discount rate for several lateral lengths and sands 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 the 640-acre spacing unit, that's a square mile, the laterals would be 660 feet apart and the base completion design of 1370-pound per foot the NPV of that spacing unit would be about $18 million. If we drilled12 wells in that same interval, so that the laterals would be 440 feet apart in a planned view, the spacing unit 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 is that integrated in this value estimate. However, the additional wells enable an improvement in the overall recovery factor across the spacing units, and as I will 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 1280-acre spacing unit. As shown in the slide, that simply doubles the NPV to $36 million for the wider spacing and the $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 1280 acres, the NPV of the space 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-pound per foot at tighter spacing, we can gain over 20% incremental improvement from there.

Look, the bottom line here is that if we develop 1280 acres with 10,000-foot lateral space to 440 feet and enhance our completions to a sand loading level of 2,000 pounds per foot rather than develop with 5,000-foot laterals based at 660 feet and legacy sand-loading, the value of that spacing unit increases from $36 million to $90 million in NPV 10. In other words, the value of the 1280-acre spacing unit increases by 150%.Yes. That is about two and one-half fold.

Here you can see the enormous value that technology has brought us from first; drilling longer laterals; second, increasing sands loading and, third; enabling design of fracture stimulations that focus the stimulated 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, put two or three or four horizon advisory 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 economies of scale or lower costs to 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 of 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 heard from Jay that we are focusing our drilling dollars almost entirely on the Midland Basin. Our current plans ramp-up from four 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 drilling and completion operations. Once we have completed our budget process, we will 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 will be happy to take your questions.

Thank you. (Operator Instructions). 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 had 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 Sprayberry 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 lower development started in 1Q in the Eagle Ford. Can you talk a little bit about spacing there? Is that going to be on the 625 with end zone spacing you guys had talked about a couple months back?

So, Welles let me make sure I understand this. You're talking about Eagle Ford where we completed in 1Q or just throughout the year?

I'm sorry. When you restart in 1Q 2017 in upper lower development what -- what spacing you're going to use for the development plan?

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

It should be half of 625.

Yes.

312 and one-half.

Okay. Perfect. And it will be the same plan when you gets the rig working?

Yes. And the rig will be working in certain areas and we'll be doing that same sort of stagger pattern.

In general, as we go upper lower, we'll be at half of the old 625 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 adjoining 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're putting -- 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 now going to be identical to what you're drilling in Sweetie Peck, as far as the drilling and completions?

No. There's some difference 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 theirs 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 will jump back in queue, when do you expect to start drilling on QStar? Obviously you are still in the process of closing - but how long of a delay do you think that will 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 Sprayberry and WolfCamp Bs being drilled on the same pad? And then there anything in the hopper for down spacing tests in Howard in 2017?

Okay. Kyle, those are different paths for the lower Sprayberry from the Wolfcamp B where we down spaced 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 plans.

Okay. Great. And then a follow-up. Do you 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 Howard lateral length left?

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

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

That's -- yes. That's Sweetie Peck.

Okay. Great. And then.

And that's only because we are able to get those spacing units in place because of our contiguous acre position which is fantastic to have.

And that's great news. And then just one last one for 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-ons?

Well, I would just like to start by saying we have a great inventory at top-tier drilling inventories and right now we're really focused on integrating the acquisitions we have 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 not -- obviously not going to talk about what we pay for acreage in any specific area, but we are actively pursuing smaller acreage consolidation opportunities in our position.

Appreciate it. 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 put something in the press release about some of the completions being delayed because your -- 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 you anticipate those wells come online?

Yes. David, this is Herb. The -- we put -- 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 just putting 20 crews out there to do it all-in-one day, we're just kind of layering them all and bringing them all online. So they'll be coming on phased -- 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 could just go back to the big picture. You laid out a projected out spend -- 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 are you -- as far as cash flow share -- however you want to address it -- how should we think about that number up or down from here based on prices? Or how should we think about that?

Well, we have a program pretty well planned out. I think we -- through next year. We have identified we're going to run six rigs in the Permian and a rig in the Eagle Ford and that's what we think we need to run to generate the values that we estimated. So I think that that is pretty 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 you up and down a little bit. There's some -- there's probably a band around the numbers we have already -- we've showed. In terms of how we fund all that, I mean I think we're going our have non-op Eagle Ford proceeds in the first quarter.

Yes.

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

Okay. That's helpful. Thank you.

And our next question comes from the line ever Mike Scialla with Stifel. Please go ahead. Mike, Your line is now open.

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

Good morning, guys. Thanks for taking the question.

Sure.

If we look at slide 17 and your impressive growth through 2018, one thing that we have been thinking about is the ability for companies to either lock in and take-away capacity and/or differential protection out of the Midland basin because you're 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?

Yes, 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 existing capacity, which is quite a bit above current production for oil, and with anticipated known expansions, we're good through 2020 in terms of the take-away 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 infrastructures are 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. The big contiguous oily asset that flows 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.

(Operator Instructions). And our next question comes from the line of Mike Kelly with Global. Please go ahead, Mike.

Hey, guys. Good morning. Just following onto David's question there with respecting and appreciating 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 that may be 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're very happy with the inventory that we have built. We have a great inventory of top-tier drilling opportunities. As I said earlier, we'll always look at things that can enhance value. Most of our focus right now, though, is really on pursuing smaller acreage consolidation opportunities that would clearly enhance the position we have built.

Okay. Yes. 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 have seen historically out at Sweetie Peck?

Chris, this is Herb. Yes. So the spacing -- what we have assumed in the analysis that we showed you had and I mentioned that we do expect a little bit of degradation in 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 refresh your recollection in recovery, but we have 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 eight, you have more straws in the same pool. And so you would expect a slight degradation, but it's not significant -- from a value perspective.

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

So we have shown 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 and including the number of DUCs that you're going to be working down next year?

Yes. 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 -- the QStar 9,700-foot lateral was drilled?

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

Pretty close to the border -- one of the things that may be not be appreciated is how much -- there's quite a chunk of that QStar acreage that's in Martin county. That's a really exciting position -- part of the reason we were excited about the acreage is it's at a great position.

All right. Thanks. That's the only question from 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?

Yes. This is Herb. So the completion design is -- it's a completion design where a number of things have been tested. So at different parts of the lateral they use different stage spacings, different cluster spacings and the sand-loading level was pretty similar to what we have used for sand-loading, so in the 1900-pound 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 forwards to sharing our results with you as we move forward to execute on these great acquisitions we have 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.