SM Energy Company
Q4 2015 Earnings Call Transcript

Published: 24 Feb 2016

[Operator:]

Good day, ladies and gentlemen, and welcome to the SM Energy Fourth Quarter and Full Year 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. As a reminder, this conference call is being recorded. I would now like to turn the conference over to Jennifer Samuels, Director of Investor Relations. Please go ahead.

[Jennifer Martin Samuels:]

Thank you, Abigail. Good morning, everyone, and thank you for joining us. A few housekeeping items before we get started, first, I need to remind everyone that we will be making forward-looking statements during this call about our plans, expectations, and assumptions regarding our future performance, including discussing full year guidance. 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 to our website for this call, and the Risk Factors section of our Form 10-K that we filed, oh, I guess about an hour ago, that is posted to our website. 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 also described in our earnings release from yesterday. Following the call today, we will head up to Vail for the Credit Suisse conference, where we hope to see many of you. We will also attend the Simmons and Raymond James conferences in the coming weeks and again hope to see many of you there. Speaking this morning will be

[Javan D. Ottoson:]

Well, thank you, Jennifer. Good morning. Thank you to everyone for calling in today. Well, I'm going to address just right upfront what seems to be a key issue for people following our release last night. We do expect our production volumes to be down sharply this quarter and down year-over-year, because in both our operated and non-operated Eagle Ford programs, discretionary capital was cut starting late last year. We are transitioning to spending more in the Permian because at current product prices, our program in the Permian generates better cash-on-cash returns and higher operating margins than our Eagle Ford programs. Our Eagle Ford volumes, however, are large and they decline rapidly when you first cut activity. And it takes awhile for the Permian volumes to kick in. So overall, you get a steep drop in production and then rate flattens out. Our overall operating margin per barrel should improve significantly as our black oil percentage of production rises, which will have a positive impact on cash flows and on our debt leverage. Look, I know the optics of this initially aren't great. But it's the right thing to do in order to optimize cash flow. And cash flow is the lifeblood of our business. Now, there is no question that the macro is tough right now. However, we came into this downturn in a better position than most of our peers, from a leverage and balance sheet standpoint, and we believe we can maintain that advantage. Our strategic priorities are, first, to preserve liquidity. Secondly, we're going to persevere through this downturn without shareholder dilution. And thirdly, we believe we can continue to make progress in improving our well results and our project portfolio, even here at the bottom of the cycle. We strongly believe that we have both the capacity and the discipline to perform differentially for shareholders as prices begin to recover. I'm now going to turn the call over to Wade and Herb, so they can fill you in on the details of our 2016 financial and operating plan. Wade?

[A. Wade Pursell:]

Thanks, Jay. Well, good morning, everyone. Well, as Jay said, these are certainly very difficult times for us and I know for everyone on the phone this morning. However, I will say the fact that our stock is less than half of where it began this year and our bonds are trading below 50% seems to be implying something that I believe is simply not going to happen. We continue to be steadfast in our plan to keep our debt metrics and liquidity in good standing, while our Operations team continues to drive value, regardless of commodity prices. So let's start with the balance sheet and capitalization structure on Slide 5. I'm going to make four very important points this morning; first and foremost, liquidity. Nothing is more important in this environment. We currently have a revolver with a $2 billion borrowing base and $1.5 billion commitment level. Only $200 million is drawn on the facility and our long-term plan keeps spending less than EBITDAX generated. I'll make a quick comment on the upcoming spring redetermination. We all expect borrowing bases to fall significantly as banks lower their price decks. With respect to SM, I can tell you that I think ours could fall below the $1.5 billion commitment level, but not too far below that level. So we will still have significant liquidity available to us. Second point, maturities; you can see from the slide that the earliest maturity on any of our bonds is 2021. Even our revolver does not mature until 2019, so we are in very good shape there. Third point, coverage levels; those of you that have been following this for awhile know that we were disciplined in not levering the balance sheet during the high-commodity price years, like a lot of our peers did. Because of that, our debt-to-EBITDAX is currently only 2.3 times, which compares very favorably with the peer average. We currently have a covenant with the banks to maintain a level below four times. I can tell you that our 2016 business plan, which I'll walk through momentarily, run at current strip pricing stays within this level. And looking ahead to 2017, we have a plan that stays below four times as well, assuming oil prices average $45 and natural gas $2.75. These prices approximated a recent strip. Now, while we believe prices will be at or above these levels in 2017, we obviously will not bet the balance sheet on it. Accordingly, we've already had discussions with our banks about changing this covenant to something we would be much more comfortable with, should prices not recover. We're hoping to get this done in connection with the spring borrowing base redetermination. So my fourth and final point on the balance sheet relates to the significant discount on the bonds and whether we would try to capture some of that by repurchasing them. We obviously do the math and are very tempted by it. The first thing I will repeat is there's nothing more important than liquidity right now. Extreme caution should be employed when using liquidity to retire very attractive long-term unsecured debt. Now, you might ask, why drill any wells right now. Why not just buy back bonds? First of all, you'll note in our business plan discussion that we continue to reduce activity significantly. And, as you know, investing some level of capital into drilling wells does support our long-term business and financing capacity. Continued drilling ensures that we meet our commitments to our lessors, allows us to retain our substantial drilling inventory, and better positions us for significant upside leverage to a price recovery. With all that said, I can tell you that we are exploring ways to take advantage of this opportunity, but we're not interested in hampering our liquidity or diluting shareholders particularly at these depressed levels. So let's now move on to the 2016 business plan. So I'm on Slide 6. Capital expenditures are planned to be around $705 million, which is aligned with projected EBITDAX for this period. This was a recent strip with averaged $37.50 for oil and $2.30 for natural gas. This level of spending is down more than 45% from 2015. As a result of low natural gas and NGL prices, we plan to redirect capital from the natural gas condensate development in the Eagle Ford, which we actually began slowing in the fourth quarter, as Jay mentioned, to our oil-focused programs in the Permian and Williston Basins that have favorable recycle ratios and returns at current commodity prices and service costs. We will be completing a number of wells in our DUC inventory. You can see these projected levels on Slide 7 as well as the rig count in each area throughout the year. Of note, we plan to pick up a second rig in the Permian beginning in the second quarter. Our Permian position is the core of the core. We believe our position there has tremendous upside value as we prove-up additional zones and continue to refine our already best-in-class well performance. The results of this activity is a CapEx split

[Herbert S. Vogel:]

Thank you, Wade, and good morning, everyone. Behind the metrics of the 2016 plan that Wade just discussed, we're doing a number of things operationally that are driving performance, building drilling inventory and, ultimately, value. Simply stated, we are continually delivering better wells at lower cost, which are imperative in the current price environment. During 2015, our regional Operations teams executed drilling and completion tests in each of our core areas that improved well performance and, importantly, significantly increased our view of viable inventory at five-year strip pricing. This, in turn, is shaping our 2016 plan to optimize returns from our capital program. I will speak to overall inventory growth in a few minutes, but let me first touch on some of these 2015 accomplishments and what we learned and speak to how they feed the 2016 plan. I'm at Slide 10. There's some headlines there about the Eagle Ford, but, in the interest of time, I'm going to jump right to Slide 11 and talk about our Eagle Ford Pilot Test, where we made substantial progress in 2015 executing on our pilot. Across the five pilots that have commenced production to-date, we have reached several general and, in some cases, preliminary conclusions that will drive our future plans. First, increasing sand loading to the 1,700 to 2,200 pound per lateral foot range substantially enhances well economics across the vast majority of our acreage. The only exception to-date is at the eastern end of our acreage position in Galvan, where the Lower Eagle Ford is somewhat thinner and our older, lower sand loading levels are appropriate and optimal. Second, the Upper Eagle Ford is productive across our acreage position. We see very similar early production profiles in the Upper and Lower Eagle Ford in lower yield areas. In higher yield areas, we see room to optimize our completion design and land spacing (14

[Javan D. Ottoson:]

Thanks, Herb. So in summary, although the current operating environment is very difficult, we're very pleased about our ability to take advantage of the oily optionality in our portfolio. We believe we can achieve good returns on wells we're drilling in our focus areas, while preserving valuable acreage and value for the future. Liquidity, as we've said multiple times, is our first priority right now. But our longer-term objective is always to generate top quartile, debt-adjusted, per share metrics over multiple-year time periods. Shareholder-friendly balance sheet management and operational execution are both critical to achieving that goal. I'm extremely proud of the way our people worked in 2015 to capture cost savings, and improve our well results, and I know they will do the same in 2016. With that, we'll turn the call over for questions. Thank you.

[Operator:]

Thank you. Our first question comes from the line of Pearce Hammond with Simmons & Company. Your line is open.

[Pearce Wheless Hammond:]

Yes. Good morning. I was intrigued with your commentary about liquidity and the importance thereof, but also the opportunities to buy back some of the distressed debt. How do year bridge that gap, where you can maintain that liquidity that's important to you but take advantage of the opportunity that the debt market is offering you?

[A. Wade Pursell:]

Hey, Pearce. This is Wade. I don't want to get too detailed on things we might be looking at, but you said it very well. We're not going to simply just use liquidity. It would be other sources of capital, whether that's other financing alternatives or from some asset divestitures, things like that.

[Pearce Wheless Hammond:]

Now, would that be above and beyond the $100 million of asset divestitures that you targeted in the release last evening?

[A. Wade Pursell:]

Possibly. Possibly. I would lean more toward the other financing sources, but, yeah, that's something we'd be looking at also.

[Pearce Wheless Hammond:]

Great. And then my follow-up, Wade, would be on the credit agreement covenants. Are you looking to get some relief on that front through a renegotiation?

[A. Wade Pursell:]

That's what I said. I don't want to get too detailed. I'm obviously not going to speak for the banks, but we are intending to get some relief, as you call it, or amendments to our covenants as we go into the spring borrowing base.

[Pearce Wheless Hammond:]

Okay. Thank you very much.

[A. Wade Pursell:]

Thanks.

[Operator:]

Thank you. Our next question comes from the line of David Tameron with Wells Fargo. Your line is open.

[David R. Tameron:]

Good morning.

[Javan D. Ottoson:]

Morning.

[David R. Tameron:]

Page 23 that you referenced, I kind of missed the number. You said at current strip, it was 1.1 billion barrels. Is that what I heard you say, Herb?

[Herbert S. Vogel:]

Yeah. This is Herb. Yeah, that's correct. It's 1.1 billion barrels with the assumptions we have for year-end 2015.

[David R. Tameron:]

Okay. Okay. And then, just not to get into too much detail, but is the reduction there from that 1.8 billion barrels, do I think about that as mostly Eagle Ford and a little Bakken, how should I think about that?

[Herbert S. Vogel:]

Oh, yeah. You know, the Eagle Ford dominates our inventory, so it's mostly Eagle Ford.

[David R. Tameron:]

Okay. That was a simple answer. And then, Jay, if I just think about big picture, I don't know, if you go back a year, year and a half, you guys had 20 rigs running. You take it down to your current of four, how does the organization right-size for that? Meaning, I assume there's been layoffs through attrition, et cetera, but how do you think about when you come out of this on the other side, assuming we do get some higher oil prices and you start to ramp back up? How do you envision that?

[Javan D. Ottoson:]

Well, I think if you look back right now, David, and I think it's a great question and certainly my organization is asking that question, too. And I'm not going to say anything today that I haven't said to them. If you look back at the peak, we were at about 903 or 904 people. Today, we're at about 780. That's a consequence of us closing our Tulsa office last year and exiting the Mid-Continent, attrition. And then, some small reductions we've taken just recently as a part of downsizing our exploration program. So we're down 12%, 13% in terms of total head count and you can see that already in our G&A reductions. We're obviously managing every G&A line item, every cost item, as closely as we can. I think when you look into the future, clearly, activity is way down. And we really believe that this first six months of 2016 is going to be very ugly from a price standpoint and then you'll start to see some improvement. And that's certainly what most people believe, too. I mean, it's a hopelessly conventional perspective, I guess, but we're trying not to knee-jerk on head count because we really believe that we'll need a lot of our people eventually. Now, my people, our people know this. If we get to the point in this cycle or at any part in this where we look out a number of years and say, look, our activity levels are going to be low for a long time, then clearly, we will need to make additional adjustments in cost structure. And those are baked in to our longer-term projections when we run low-price cases. We certainly hope we don't have to get to that point. We don't want to lose technical talent, but certainly, in any case when you look at really low price cases, cost structure is something we simply have to look at, along with everybody else in the industry. I will say and I think it's important that we say this, if you look at where we are relative to our peers, when we start talking about things like cost reduction and leverage and all these other things, we're much better off than most of our peers. And sometimes, I feel like people aren't listening to us or just don't look at the numbers, frankly, on this. So we probably have a little more runway than most people before we have to make those difficult decisions. But if we get to the point where we have to make them, we will make them.

[David R. Tameron:]

Okay. No, that's good answer. And then just final question, service costs, since even December, it sounds like a number of producers are seeing additional service cost reductions. You kind of alluded to that. Is that what you're seeing on your end as well?

[Herbert S. Vogel:]

Yeah. David, this is Herb. Yes, we are both on the rig side and the completion side. I would say we didn't see as big a reduction as last year in the Bakken. And in December, January, we did see further declines there. So, yes, we do see runway for lower service costs, given price levels where they are.

[A. Wade Pursell:]

And then that's baked into the guidance. I think we've assumed 5% to 10% reduction. In 2016, we're already seeing 5%-ish, right?

[Javan D. Ottoson:]

Yep.

[David R. Tameron:]

Okay. I appreciate the Q&A. Thanks.

[Operator:]

Thank you. Our next question comes from the line of Kevin Smith with Raymond James. Your line is open.

[Kevin C. Smith:]

Good morning. Appreciate all the prepared remarks, especially the roadmap you laid out for the next few years as far as debt levels. And you hit on some of this in your prepared remarks, but would you mind discussing your Bakken completion activity, specifically maybe the change in completion activity in the Bakken you were contemplating three versus six months ago versus today's budget?

[Herbert S. Vogel:]

Okay. I think I understand your question, Kevin. This is Herb. So our program, we completed 11 Divide Bakken wells in 2015. Previously, it was all Three Forks. Because of the results there being positive, we plan to complete 22 Divide Bakken wells in 2016, and we've gone from the swell-packer sliding sleeve design to the plug-and-perf. Is that your question? Sand loadings are similar to what they were before.

[Kevin C. Smith:]

Yeah, right. I was trying to get to I think before. Last quarter, you were talking about getting very aggressive with the completion activity, and now it seems like you're slowing some of it down. And so I was trying to figure out what you were thinking about for the DUC inventory?

[Herbert S. Vogel:]

No. I see where you're going. So we are draining our DUC count fairly significantly in the Bakken. And this is just from memory, it's around 50 DUCs at the end of the year and we're dropping down to about 20. So we are completing quite a few wells in the Bakken/Three Forks that have already been drilled.

[Kevin C. Smith:]

Gotcha. And then one more question and I'll jump off. On your targeted divestitures, did I hear correctly you're targeting selling 4,000 barrels a day, and that's been fully removed from all 2016 guidance?

[A. Wade Pursell:]

That was 400,000 barrels of oil equivalent in the fourth quarter of 2016, is what's been removed. That's what been removed from the guidance.

[Kevin C. Smith:]

Okay. Perfect. Thanks for clarifying that. Thank you.

[Operator:]

Thank you. Our next question comes from the line of Matt Portillo with TPH. Your line is open.

[Matthew Merrel Portillo:]

Good morning.

[Javan D. Ottoson:]

Morning, Matt.

[Matthew Merrel Portillo:]

Just wanted to circle around on the preservation of liquidity and just, I guess, ask a philosophical question on spending at an EBITDAX level versus spending at a cash flow level. So, obviously, as we include interest expense in the line items, there's some incremental debt being added this year. Just wanted to understand how you guys think about that philosophically? And what would be the triggers to potentially reduce your capital budget further if we progress through this year?

[Javan D. Ottoson:]

You know, Matt, it's a question that we really put an enormous amount of thought into, and it really comes down to preserving acreage. If you look at our Eagle Ford position, and even to our Bakken position, to some extent, we have to drill a certain number of wells. We have to maintain a certain level of activity to hold all our acreage. And the way we look at the future, that's very valuable acreage for the future value of the company. When this thing turns around, as I assume everybody on this call thinks it's going to, or we wouldn't even be on the call anymore, that acreage is going to have real value to us. And we don't want to give it up. And so in order to keep, like, for example, acreage in the Eagle Ford, where, frankly, our margins aren't that great right now, and still have significant cash flows by generating higher cash margins in the Permian, we have to mount a larger capital program than cash flow. That's just the way the numbers work out. Now, if things get really awful at some point, and you're convinced this is a lower than longer thing, gas prices are going to be low for a long, long time, then clearly that assumption has to be revisited. Losing acreage somewhere where you'll never drill it, obviously, is not a loss in value. But at this point, given where we are in the cycle, given where we are from a balance sheet standpoint, given how we see the world, it makes sense to us to hold that acreage. And that really drives our capital spending over cash flow. That's the simple answer to the question.

[Matthew Merrel Portillo:]

Great. That's helpful. And then, I just wanted to circle back on I think a previous comment from a previous conference call. You guys provided some color around your expectations from a PDP decline, or base decline perspective, but wanted to just get your updated thoughts around your base decline at the corporate level, and then I guess specifically, as you guys have shut down your Eagle Ford completions from November till now, how your Eagle Ford base declines are trending, or how we should think about that on an annualized basis.

[Javan D. Ottoson:]

Well, what we've said before, and is accurate now, is that our base declines for the overall company, if you just stop drilling, it's high 30s, high 30% range, over 35%. And I will say that if you look at what we've done in Eagle Ford, Eagle Ford dominates our production. I think total Eagle Ford production's almost 75% of our total production. If you look at the fact that we don't intend to complete any wells from November all the way to the end of March, and you look at the production drop between fourth quarter and first quarter and just do the math on that, that's almost exactly how it works out. You take more than half your production at, say, 37%, 38% decline, over that period of time, you get almost exactly to the math we're showing for our first quarter result. Of course, as we pick up our activity in the Permian, and we just completed our first two wells there starting into our program, then the production starts to – it flattens out. And your oil percent, your black oil percentage particularly starts to come up. And I want to remark on that because people need to understand a lot of our oil that we produce, that we report as oil, is actually condensate that comes from our Eagle Ford production. And a lot of that is on the non-op side. Most of you are aware that Anadarko has slowed way, way down on the Anadarko side. So in fact, our condensate production is falling quite a bit because our activity layer is coming down. So a lot of what we're adding here is high-margin black oil. And that is really the big benefit of going to black oil, that optionality is the ability to drive higher operating margins at a time when we really need cash. So that's what's driving the decision-making there.

[Matthew Merrel Portillo:]

That's helpful. Thank you very much.

[Operator:]

Thank you. Our next question comes from the line of Brad Carpenter with Cantor Fitzgerald. Your line is open.

[Brad Carpenter:]

Hey, morning, everyone. Thanks for fielding my questions. In the 8-K you put out this week regarding the gas gathering agreement with Regency, and sorry if I missed this in the prepared remarks, but I was hoping you could provide some additional details on that. Did you have to make any payments to Regency to cancel the contract? And I guess secondly, what gathering agreements or commitments do you now have in place in the Eagle Ford?

[Herbert S. Vogel:]

Okay, Brad, I can cover this. This is Herb. So you're probably aware early in 2015, we entered into a contract to expand the gas gathering capacity in the Eagle Ford from 580 million cubic feet a day to 980 million cubic feet a day. That was not actually to be at that level until mid-2017. So Regency had really not commenced the work yet, so it was not a difficult negotiation. I think both parties got together and we are having some expansions done that are more around efficiency across the gathering system that will give us some nominal increases, but it significantly reduced our commitment. You're probably aware our downstream takeaway commitments feather down over the next couple of years. So we've worked it out to extend some of that with ETC on our long-haul transport, but not with a ship-or-pay commitment. So I would say we're quite robust on the takeaway side, long distance and on gathering, and we don't see any ship-or-pay risk in the next two years.

[Javan D. Ottoson:]

Yeah, thanks, Herb. And I'll say just in general, we're working in every area we can to minimize the number of commitments we have in areas that, frankly, from a discretionary standpoint, we'd prefer not to drill. So every area like that, we're working on ways to reduce commitment levels, reduce our required spend to be able to get to lower levels.

[Brad Carpenter:]

Okay, great. I appreciate that. And then, I guess, staying in the Eagle Ford, I think previously, you've said you needed two rigs running down there to hold all your acreage, but with the new 2016 plan, looks like you're dropping to zero by the end of the year. How should we think about that? Are you able to hold it just by drawing-down on the – I think you show 76 DUCs down there in the Eagle Ford? And if so, what do you expect to exit 2016 as far as your DUC inventory in the Eagle Ford?

[Herbert S. Vogel:]

Okay, Brad. This is Herb again. I'll address that one. So on the acreage commitments, the way our arrangements are, we're real fortunate, first of all, that we're with these big ranches and have consolidated drilling arrangements. So we were able to bank previous drilled wells that in a given year, you can draw-down that bank on wells that you've already completed. So that defers the day where you have to have activity higher. So that is basically during 2016 and into 2017; one ranch, we're staying above the minimum, and then the other ranch, we're drawing down those commitments. And we have the ability to also do cash payout if necessary. Obviously, we're working with our lessors closely. They understand the environment. They're sophisticated landowners and we'll be working that down. Does that answer your question, Brad?

[Brad Carpenter:]

It does. Yeah. I appreciate that. And have you discussed a kind of year-end DUC number for your Eagle Ford that you're planning on hitting?

[Herbert S. Vogel:]

Yeah. We drained the DUC count in the Eagle Ford also. I don't recall exactly where it is, but it's got to be in the 20s or 30s, the number of DUCs at the end of the year versus probably around 50 at the end of the year.

[Brad Carpenter:]

Okay. Got you.

[Javan D. Ottoson:]

I think it'd be fair to say that given – we assume we're going to have to do some drilling in the Eagle Ford in 2017.

[Herbert S. Vogel:]

Yeah.

[Javan D. Ottoson:]

In any plan that we've built.

[Herbert S. Vogel:]

Yeah.

[Javan D. Ottoson:]

But it's not a lot. And we've been able to reduce those commitments quite a bit. And we're still working on reducing them further.

[Herbert S. Vogel:]

Yeah. In 2016, we drill 17 wells in the Eagle Ford in the budget, and then we complete 40.

[Brad Carpenter:]

Okay, great. All right. Thank you. That's helpful.

[Operator:]

Thank you. Our next question comes from the line of Mike Kelly with Seaport Global. Your line is open.

[Michael Kelly:]

Hey, guys. Good morning. Wade gave an expected oil cut I think of 34% for Q4 2016. Was just hoping you could give us an annual figure for 2016 and then maybe just talk in ballpark terms for how you expect this percentage to really trend in 2017 as you put on more Permian wells? Thanks.

[A. Wade Pursell:]

Thanks, Mike. This is Wade. You know, for 2016, I did mention we'd go from 30% currently to around 34% by the end of the year. I think if you just assumed adding a percent per quarter, you'd get to that level by the fourth quarter. I think that gets you pretty close. As far as 2017, we're being very high level with respect to 2017, and not really giving specific guidance, but maintaining that level I think would be something you could assume. Now, you would have to replace some oily divestitures in the fourth quarter of 2016, but, as we said, that's about 400,000 barrels for the fourth quarter.

[Michael Kelly:]

Got it. And are you assuming those divestitures all happen in the fourth quarter of 2016? I just want to make sure I understand that.

[A. Wade Pursell:]

We are.

[Michael Kelly:]

Okay. Got it.

[A. Wade Pursell:]

Yeah, exactly.

[Michael Kelly:]

Okay. And then second question for me, on the PV-10 number, that $1.8 billion, I was I guess a little surprised at the magnitude of the drop year-over-year and I just wanted to get your comments on this. And really, do you think that $1.8 billion value is a fair representation of the total value there of your proved reserves at a $50 oil, $2.60 gas number? Or is there something that isn't really being accounted for, whether it's further cost declines, efficiency gains, et cetera, that you think that that could be biased higher? Thanks.

[Javan D. Ottoson:]

Well, Mike, obviously, we understand these are SEC numbers. They're run at current costs essentially. And so obviously, costs can come down further. Let me make a couple comments about that, though. You quote the $1.8 billion number. You're leaving out our hedges, which are a very important number. It's a big number and when you look at borrowing base and other assets, you really have to include that. All the hedges get counted in our borrowing base. Second, you're ignoring the fact that, and we've said this in the release, that we pushed out a number of proven cases into the future because of five-year rule. And those cases are still technically proven. They still have the same value. They just are occurring in another category now, because our budget program doesn't get them drilled within five years. They're still there. They still have the same value.

[Michael Kelly:]

Right.

[Javan D. Ottoson:]

So those need to be added back on. And I saw one comment where people were comparing that number to our debt numbers, and that's not a reasonable comparison at all. I mean, first of all, you've got to discount the debt. The debt's not due until after 2021. So, you know, I think people...

[A. Wade Pursell:]

And it's unsecured.

[Javan D. Ottoson:]

And it's unsecured. Okay. And we've got plenty of interest coverage. So I think the relevant question, and I think Wade answered it well, is what's going to happen to our borrowing base. And we answered that. We think it is likely to come in under our current commitment, which is the $1.5 billion number, but not a lot under. And then the real issue with liquidity, of course, is as you go forward in time, is what happens to the borrowing base in the fall and next year. And I will come back to the point – if you're worried about that with us, there are a whole lot of people you should be a lot more worried about first. And I don't think we get credit for that, frankly. And I don't mean to sound irritated about it, but it seems to me like we're getting a sort of throwing the baby out with the bath water on some of this stuff.

[Michael Kelly:]

No, that's fair. Thanks for answering that.

[Operator:]

Thank you. Our next question comes from the line of Welles Fitzpatrick with Johnson Rice. Your line is open.

[Welles W. Fitzpatrick:]

Hey, good morning.

[Javan D. Ottoson:]

Hi, Welles.

[A. Wade Pursell:]

Hey, Welles.

[Welles W. Fitzpatrick:]

So I think you're perfectly allowed to sound irritated, by the way. It is striking how well-positioned your balance sheet is, given the pullback. But I suppose that's neither here nor there. Can we get an update on the GORs off the Upper versus the Lower Eagle Ford offsets in the north and south? And then, it looks like you added 17,000 acres in the Eagle Ford since the last presentation. Any color on that would be helpful.

[Herbert S. Vogel:]

Yeah. This is Herb. I'll address that. So the interesting thing, and we've learned a lot with the Lower Eagle Ford and Upper Eagle Ford, and if you look down to the far south, let's say Pilot #4 and then southeast of there, the Upper Eagle Ford wells have a higher yield than the Lower Eagle Ford. So it would be like in some of these 70 barrels per million versus 30 barrels per million. So we were expecting them all to be the same. So in that case, the Upper winds up better. If you go up to the north, that's inverted. It's the other way around on the yield. And then in terms of productivity, the productivity of the Upper and Lower are very similar when you go to the southeast, whereas there's lower productivity in the Upper as you move to the very northwest. So that's the yield level. And you can just invert that if you want to convert it to GOR. Your other question, Welles?

[Javan D. Ottoson:]

Acreage. Why the acreage number changed?

[Herbert S. Vogel:]

Oh, the acreage. So the total net acreage we have on all the leases in the Eagle Ford is 161,000. Previously, we had a polygon around the area that we were developing. That was 144,000 acres. So all it is, is we wanted to be consistent on when we represented the 10-K what our net acreage position is. That's the 161,000. When you look at where we're developing or potentially developing, that's 144,000. That's the difference.

[Welles W. Fitzpatrick:]

Okay. That's perfect. Thank you.

[Operator:]

Thank you. Our next question comes from the line of Subash Chandra with Guggenheim. Your line is open.

[Subash Chandra:]

Yeah, hey, Jay. Good morning. What is your comfort with having bank debt outstanding? There's big liquidity numbers out there. Some folks like it at zero. Other folks don't mind carrying a little bit on it. What are your thoughts heading into 2017?

[A. Wade Pursell:]

This is Wade. I'll give you my thoughts first. Look, it'd be great to have zero secured debt. We have a very sizeable borrowing base, though, and we just talked about what we think that's going to go down to. So there's substantial liquidity between our outstanding and that number. I'll just tell you internally, we don't mind carrying a little secured debt. It's very low cost. It seems prudent, but to a degree. Those of you that know us well know we have an internal policy that we would never draw more than half of our borrowing base at any time. That's an internal governor we put on ourself, but we look out in the future and try to predict what might happen with our borrowing base, and we act accordingly. You see us term-out secured debt a lot. That's why we have a good layered ladder of very long-term unsecured tranches of high yield debt, but that's essentially my thoughts on how we manage the level of secured debt.

[Javan D. Ottoson:]

I want to tell a little story. When we first started talking to the banks about the covenant, the initial reaction we got was, first of all, why? And second, well, we got a lot of other people we're dealing with right now. We'd really like to deal with you later. So we have a super relationship with the banks. We are at very good credit. We have probably the lowest cost revolver out there in terms of what rates we pay at. So we don't have a problem carrying a little bit of a balance here and certainly our bankers don't have a problem with it either.

[Subash Chandra:]

Okay. Second question is so as these hedges roll off this year and you prepare for that in 2017, I think I heard you say you would spend below EBITDAX maybe a different phrasing than the 2016 spending at EBITDAX and I don't know if I heard that correctly, but are there any other ways here of preparing for those hedges to roll off?

[Javan D. Ottoson:]

Well, I'll make one comment. I'll turn it to Wade. First of all, we're going to be below EBITDAX a little bit this year, too, but certainly the plan is to be more below EBITDAX in 2017. Go ahead, Wade.

[A. Wade Pursell:]

No, that's the plan. And we have some hedges in 2017 as well, which will be rolling off, as you say, but we've made some assumptions with respect to what we're going to be drilling. And I've given you the commodity prices that we assume in 2017. And I've also declared that we think if we don't see the recovery by 2017, that we think costs will continue to fall. So that's baked in as well. I think I said 5% or 10%. And we would likely be, Jay said earlier, looking at every line of costs. And if we see recovery is not going to happen any time soon, then we'll be making some adjustments to the cost structure. And we would reflect those in future forecasts. The outputs speak for themselves, which I shared with you earlier.

[Subash Chandra:]

Yeah. I guess I was getting at if there are plans for further asset sales, if there would be anything meaningful remaining in the non-core portfolio after the 4Q sale this year, if you have any intentions in 2017.

[Javan D. Ottoson:]

Our current 2017 plan doesn't have a lot of asset sales in it. I think if you really get in that lower for longer scenario, there's always some things. You'd have to look at operating margins and make some really hard decisions about is there a time when you sell this stuff. And I think the first decision you would make would be to stop holding acreage in those areas and cut your capital program in those areas first. And then, there's always these really difficult decisions about, okay, if I sell this now, I'm going to get X value for it. If I get any price recovery at all, I get much higher price for it. You got to make that decision. At some point, I think as an industry, people are going to capitulate and start selling assets. And I think you're going to start seeing some of that here in the second half. But we'll see. Those are tough choices you have to make. The first choice you would make would be to cut your capital program in areas where you'd start to lose acreage, and that's probably the first thing we would do.

[Subash Chandra:]

Okay. And a final real quick one, there was a reference to how many Sweetie Peck horizontals were producing. I missed it; if you could repeat that number.

[Herbert S. Vogel:]

Yeah. It's something over 20. We just added a couple, so it's 20-plus.

[Javan D. Ottoson:]

And we've just brought on two so far this year.

[Subash Chandra:]

Okay, terrific. Thank you.

[Operator:]

Thank you. That does conclude today's Q&A session. I'd like to turn the call back to management for closing remarks.

[Javan D. Ottoson:]

Well, thank you for those who you stuck with us through this whole process. And we really feel strongly that we're going to be positioned well to perform well for shareholders as we go forward. We're continually focusing on how to be a top quartile debt-adjusted per share metrics company. And we're going to continue to focus on that and on our liquidity and making better wells, so better wells, lower costs. Thank you for your time today.

[Operator:]

Ladies and gentlemen, thank you for your participation. That does conclude the program. You may all disconnect. Everyone, have a great day.