Jennifer Martin Samuels - Senior Director, Investor Relations Javan D. Ottoson - President, Chief Executive Officer & Director A. Wade Pursell - Chief Financial Officer & Executive Vice President Herbert S. Vogel - Executive Vice President-Operations.

Pearce Wheless Hammond - Simmons & Company International David R. Tameron - Wells Fargo Securities LLC Kevin C. Smith - Raymond James & Associates, Inc. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc. Brad Carpenter - Cantor Fitzgerald Securities Michael Kelly - Seaport Global Securities LLC Welles W.

Fitzpatrick - Johnson Rice & Co. LLC Subash Chandra - Guggenheim Securities LLC.

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..

Jay Ottoson, President and Chief Operating (sic) [Executive] (1:49) Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; and I am very pleased to introduce Herb Vogel, our EVP of Operations, who will cover certain operational accomplishments in 2015 and how what we learned in 2015 shapes our 2016 plans, as well as reserves in economic inventory.

Herb is covering a lot of good information today, so get out your notepads. After the prepared remarks, we may be time-limited for Q&A, so in order to stay within an hour, I ask you to limit your questions to one or two. And with that, I will turn the call over to Jay..

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?.

30%, Permian; about 30% Divide County, Williston; and about 30% Eagle Ford, predominantly in the east. We expect this plan to generate production of 51 million to 55 million barrels of oil equivalent for 2016, with an increasing oil mix. The oil percentage of fourth quarter 2015 production was about 30%.

We expect this to increase to about 34% by the fourth quarter of 2016. I mentioned earlier that we began to slow activity in the Eagle Ford during the fourth quarter. Again, this is an intentional shift to the oilier assets, driven by economics and liquidity preservation.

The result is a pretty steep decline in our forecast production for the first quarter of this year, especially natural gas and NGLs. Of note, we have not connected any new wells in the Eagle Ford to sales since November 2015.

Therefore, we're projecting first quarter 2016 production of around 13.1 million to 13.5 million barrels of oil equivalent, with production then remaining relatively flat the remainder of the year. For 2017, we have assumed a similar level of drilling activity, generating relatively flat production and keeping CapEx under projected EBITDAX.

We believe if prices do not materially recover by then, costs will continue to fall another 5% or 10%, in our estimation. And we will likely make some further changes to our cost structure. With respect to portfolio activity, we plan to continue to core-up by divesting of various non-core acreage throughout the company.

Just based on PDP value, we anticipate at least $100 million of proceeds from these divestitures by the fourth quarter of this year. With respect to our 2016 production guidance, we removed about 400,000 barrels of oil equivalent – and that was about 70% oil – from the fourth quarter related to these divestitures.

Finally, as a reminder, on Slide 8, we have substantial hedges in place at very favorable prices that help support our cash flows and liquidity position. Details of these are included in the Appendix of this presentation and the 10-K, which was filed this morning.

So in the interest of time, I'm not going to walk through the fourth quarter results, which are summarized on Slide 9. Much of this was reported last month. There are a lot of detailed schedules in the release and the IR materials, with further detail in the 10-K. We're happy to answer any questions regarding this material directly by phone.

So with that, I'm going to turn the call over to Herb Vogel to discuss our year-end reserves and economic inventory and also to provide a little more color on the operations detail in the 2016 plan.

Herb?.

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 (14:10) target in the Upper Eagle Ford.

Third, tighter well spacing is viable, with optimal spacing dependent on the pay thickness, the configuration of wells across the Upper and Lower Eagle Ford, and the condensate yields. Co-development at tighter spacing achieves stronger economic returns than later in-fill development.

Given that we have some of the thickest rock across the entire Eagle Ford play, we see potential for "W", or stacked-staggered configurations, but need more production history from recent pilots to reach firm conclusions.

Pilot #3, in particular, gives us quite a bit of encouragement, where we see the staggered, or "W" configuration between both the Upper Eagle Ford and the Lower Eagle Ford on 312-foot spacing resulting in wells as productive as our older Lower Eagle Ford wells spaced at 625-plus feet.

Clearly, we are very excited about the potential inventory additions from what we've seen to-date. Fourth, drilling well bores with a high percentage of the lateral in the optimal targeted facies matters much more than we previously recognized and became a key area of focus in 2015.

We are now approaching 90% of our lateral lengths being completed in the optimal target facies interval, and this helps us develop the complex fracture networks that we seek to maximize the reservoir area contacted by our fracture stimulation.

Fifth, we evaluated many other completion optimization techniques, such tighter stage spacing, use of diverters, use of lower fluid volumes, tighter cluster spacing and different perforation clusters, and will be incorporating what we have learned in future completion designs. Now, let me touch on Pilot #5 for a couple minutes.

The 11 wells in this pilot were all drilled with 8,000-foot laterals at the north end of our Briscoe Ranch acreage. We targeted Facies 3 in the Lower Eagle Ford and Facies 5 and 7 in the Upper Eagle Ford in a stacked-staggered configuration in some of the thickest Eagle Ford section in the entire play, a gross thickness of almost 350 feet.

We aggressively and appropriately targeted drilling the wells at 525 feet laterally between wells in the same facies, which would look like 262 feet between wells in a planned view. The uppermost Upper Eagle Ford Facies 7 wells were targeted to be drilled directly above the Lower Eagle Ford Facies 3 well, or roughly 200 to 250 feet apart vertically.

If successful and applicable broadly, this pilot would more than triple our perceived inventory in the area, so we were clearly shooting for a big inventory impact with this pilot.

Now, we've been flowing hydrocarbons from all 11 wells since mid-November, so we have about three months of production data, all naturally flowing, with no artificial lift installed yet. Production to-date from the four Lower Eagle Ford wells have averaged right at our expected type curve for the area on a per thousand foot lateral basis.

To-date, we haven't seen any interference here with the offset Upper Eagle Ford wells. Early yields range from 200 barrels per million cubic feet to 380 barrels per million cubic feet, with gas rates between 1.5 million cubic feet and 2 million cubic feet per day.

The good news is that these wells, on 525-foot spacing, fit a floor at one times our inventory expectations for the area. The wells drilled in the Upper Eagle Ford, Facies 5 and 7, are not performing as well as the wells in the Lower Eagle Ford. Some of these wells were drilled a bit closer to each other than planned.

And from the tracer surveys that we have run, we can see that there has been cross-flow between wells and that the stimulated rock volumes may have overlapped. However, looking at other places that we have completed in Facie 5, we have now determined that Facies 7 is a better target than Facies 5 in the Upper Eagle Ford.

Early days, but given the performance so far, we see that there is potential of down spikes further in the Lower Eagle Ford in this area, and perhaps a staggered Facies 3 and 7 configuration may be better up here in the north, where condensate yields are higher.

Looking across all the pilots, we see the Upper Eagle Ford working about equal to the Lower Eagle Ford in the vast majority of our acreage to the south and east, where tested. At the north end of Briscoe, the Lower Eagle Ford outperforms the Upper Eagle Ford.

We should be able to work from here to customize and optimize our completion design in the Upper Eagle Ford in the north and see whether we can do better on wells up there.

In short, our extensive Eagle Ford tests have given us the confidence to significantly increase our drilling inventory relative to a year ago, by over 50% in the Eagle Ford alone, under identical five-year strip assumptions as last year.

This is a great asset with a lot of hydrocarbon in place, well over 6 billion barrels equivalent on our 161,000 operated acres and many years of growth potential from a large inventory of future drilling location.

Finally, we have reduced the drill and complete cost of wells by over 40% from over $1,200 per lateral foot in mid-2014 to around $700 per lateral foot during fourth quarter 2015 from a combination of service sector deflation and many efficiency improvements, such as faster drilling and zipper fracking, as shown in Slide 12.

We are clearly achieving better wells at lower costs in the Eagle Ford today. During 2016, we can meet our acreage commitments with less than one rig and one completions crew. We have renegotiated our gas gathering and processing commitments, and production can be maintained well above commitment levels at this drill and complete activity level.

Given the high gas percentage of our Eagle Ford production and the current commodity price environment, economics of new wells here are less attractive than the oily parts of our portfolio in the Williston and Permian Basin.

Recognizing balance sheet priorities and the current economics of drilling gassier plays, less capital will be allocated to Eagle Ford in our 2016 plan than previous years.

As a result, we will complete and evaluate pilot tests that have been drilled to-date at a slower pace and use the added time available to evaluate and further optimize completion design.

Turning now to the Williston Basin in Slide 13, in 2015, we focused on incremental completion design improvements and testing and optimizing well performance across the significant acreage acquisitions that we closed in Divide County during 2014. I'll just touch on a few notable advancements here.

First, cemented plug-and-perforated completions have performed well, delivering superior economics and higher EURs of the same sand loading levels as our previous swell-packer sliding sleeve design and have become our standard design, as shown in Slide 14.

Second, tests of the Bakken in Divide County, where we had previously focused solely on the Three Forks, have yielded similar economics and EURs as the Three Forks in the locations we have tested to-date.

This is another area where we have significantly increased our view of viable inventory at five-year strip pricing, doubling our inventory by adding the Bakken where we previously only accounted the Three Forks. Stacked pay also enables attractive economies of scale.

With two productive intervals, there's more developable oil in place per section, doubling up our ability to utilize infrastructures such as roads, pads, and sump (21:33) facilities, thereby improving returns from wells drilled at both intervals.

And third, we've been able to drive cost down to the $4.5 million level for a 10,000 foot lateral in Divide County from a combination of efficiency gains and service cost reductions. In Slide 15, you can see that we have made progress improving returns in the current commodity price environment and expect to see further improvement.

For example, we just negotiated new lower cost rig and completion contracts in December, which will benefit the economics. I'd like to point out one thing that's frequently overlooked about our position in Divide County in comparison to Bakken plays to the south in Williams and McKenzie Counties.

And that is that the Bakken and Three Forks are at shallower depths in Divide County. This results in lower cost wells for the same lateral length in a target interval. While the initial production rates are lower, the decline rates are shallower.

This combination, better wells, by a shallower declines and lower costs, leads to very competitive economics. For 2016, in the Williston, we can retain our prospective acreage with one rig and we have a substantial inventory of DUCs that we will be completing and bringing on production.

We plan to run a slightly reduced program in 2016 relative to 2015, as cash payouts in the Permian Basin are somewhat faster. Turning now to the Permian Basin in Slide 16, you're likely aware that our acreage in Sweetie Peck is held by production, or HBP.

As a result, we were able to dial back activity in 2015 without losing acreage, which enabled us to deploy capital to other regions where we had commitments and good returns.

This enabled us to focus on understanding production performance and completion design influence on the 20 plus new horizontal wells we completed at Sweetie Peck through February of 2015.

As peers began to report more of their well results in the Midland Basin, we quickly realized that Sweetie Peck horizontal well production performance was truly extraordinary and among the best in the basin, as shown in Slide 17. The IPs of our Sweetie Peck Wolfcamp B wells really stand out.

This trend continued and became even more evident after about a year of production history, as shown on Slide 18, which confirmed that Wolfcamp B wells in our acreage are some of the best in the basin, as compared to results reported by other major operators in the basin.

In the slide, we show actual Sweetie Peck well production performance normalized to a 7,500-foot lateral length and compare the results published by other operators. From the legend, you can see some of the range of completion techniques we tested at Sweetie Peck.

Our testing program at Sweetie Peck led us to conclude that longer laterals completed with a cemented plug-and-perf design, a slick water fluid system, higher sand loading, zipper fracking, and tighter cluster spacing all contributed to improved well performance or improved efficiencies.

While most of our horizontal wells targeted the Wolfcamp B zone, our Lower Spraberry wells are showing some promise that returns in this shallower zone will be equal to or better than Wolfcamp B zone as a result of lower well costs, coupled with shallower decline rate.

We started drilling and completion activity at Sweetie Peck again at the start of the year and have achieved drilling and completion costs over 40% lower than mid-2014.

The completion design improvements which led to better wells, coupled with the lower costs from efficiency gains and service sector deflation, have materially improved the economics of wells at Sweetie Peck.

We are now able to achieve nearly 20% IRRs at flat $40 per barrel oil prices with a 7,500-foot lateral, as shown with the Lower Spraberry example on Slide 19.

Sweetie Peck economics are the best in our portfolio and, as a result, our plan for 2016 includes CapEx for redeploying an Eagle Ford rig to Sweetie Peck during April, in addition to the rig which started operations there at the start of the year. Overall, we view Sweetie Peck as a true Tier 1 asset in the Midland Basin.

We have a contiguous acreage footprint, with ownership of water and surface rights that enable particularly efficient and low-cost operations that yield outstanding margins. Our roughly 15,000 net acre position is comparable in size to Diamondback's Spanish Trail asset and has potential in five horizons, and we've only tested two to-date.

Our 2016 program will target the Wolfcamp B and the Lower Spraberry in order to deliver the best proven returns on capital. Given the track record of our wells to-date, we have no doubt that our Sweetie Peck program will deliver industry-leading returns in the Midland Basin. I'll now move on to reserves and economic inventory. I'm on Slide 20.

There's several tables in the press release, presentation, and, of course, 10-K providing backup data for our year-end proved reserves. We ended the year with 471 million barrels equivalent, which is down 9.8% from year-end 2014, adjusted for the assets we sold during the year.

While price and five-year rule revisions slightly more than offset the positives, the performance revisions and reserve additions through drilling are a testament to a successful 2015 program, despite the decline in commodity prices.

I will reiterate that production replacement from reserve additions and performance revisions was 324% and point to a few other highlights in Slide 21. And in Slide 22, you can see our solid track record of building our proved reserves, with a compound annual growth rate in proved reserves of 23% over the past six years.

Turning now to drilling inventory in Slide 23, we started 2015 with a number of pilot tests in the Eagle Ford and Bakken/Three Forks with a goal of doubling our economic inventory over the next few years.

At year-end 2014, we had a drilling inventory of about 1 billion barrels, from 1,300 net drilling locations in our operated Eagle Ford and Bakken/Three Forks programs. This assessment assumed five-year average strip pricing as of year-end 2014, or $65 barrel oil, $3.50 gas, $26 per barrel NGLs, and a 20% IRR hurdle rate.

We believe that for evaluating multi-year inventory levels, it is important to assess with a longer-term view; hence, the use of the five-year strip average.

Applying these same prices and hurdle as used to calculate our drilling inventory at year end 2014, the company's drilling inventory at the end of 2015 increased by more than 75% to 1,776 million barrels equivalent, or 1.8 billion barrels, and nearly 2,500 net drilling locations, demonstrating the success of our tests to-date in all regions.

Of course, prices have fallen since last year, so we also looked at our inventory assuming year-end 2015 five-year average strip pricing and a 20% IRR, and that case still left us with economic inventory of about 1.1 billion barrels, or roughly 20 years of inventory at our current production level.

In a nutshell, our operations teams delivered better wells at lower costs in all our core plays through continued innovation in completion design and efficiency improvements. This enabled better returns and significant increases in our drilling inventory, which should put us in an excellent position at the other side of the cycle. Now, back to Jay.

Jay?.

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..

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

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?.

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..

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

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

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?.

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..

Okay. Thank you very much..

Thanks..

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

Good morning..

Morning..

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?.

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

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?.

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

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?.

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..

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?.

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..

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?.

Yep..

Okay. I appreciate the Q&A. Thanks..

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

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?.

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..

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?.

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..

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?.

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..

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

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

Good morning..

Morning, Matt..

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?.

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..

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..

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..

That's helpful. Thank you very much..

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

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?.

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..

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..

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?.

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?.

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?.

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..

Okay. Got you..

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..

Yeah..

In any plan that we've built..

Yeah..

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..

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

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

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

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..

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..

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..

We are..

Okay. Got it..

Yeah, exactly..

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..

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..

Right..

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....

And it's unsecured..

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..

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

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

Hey, good morning..

Hi, Welles..

Hey, Welles..

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..

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?.

Acreage.

Why the acreage number changed?.

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..

Okay. That's perfect. Thank you..

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

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?.

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..

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..

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?.

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..

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..

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..

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..

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..

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

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

Okay, terrific. Thank you..

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

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..

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