Welcome to SM Energy’s First Quarter 2019 Financial and Operating Results Webcast. We have some pretty exciting well results to talk about today. But first, I will point to Slide 2 and remind you that we will be making forward-looking statements about our plans, expectations and assumptions regarding future performance.

These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

Please refer to the cautionary information about forward-looking statements in today’s earnings release, the related presentation posted to our website, and the Risk Factors section of our Form 10-K filed earlier this year and our Form 10-Q filed for this quarter.

The discussion of results for the quarter also includes 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 provided in our earnings release and related investor relations presentation. Speakers today are President and CEO, Jay Ottoson; EVP and CFO, Wade Pursell; and EVP of Operations, Herb Vogel.

With that, I will turn it over to Jay..

Well, thank you. Good afternoon and thanks to all of you for joining our first quarter 2019 review. We executed well in the field during the quarter, overcoming the impact of gas plant force majeure events on our Permian production to deliver production right at the center of our guidance range.

At this point, we are right where we expected to be on the path toward our 2019 priority objectives. Our top priority for this year is to continue growing while generating free cash flow in the second half of 2019.

As we turn that corner to generating free cash flow, our leverage metrics will begin to improve, which is our second priority, and we will have the opportunity to accelerate that process through debt reduction.

Our third priority is to continue to prove up and grow our economic drilling inventory on our existing acreage, and we made good progress on that front during the first quarter. Wade and Herb will review our quarter results and forward guidance for you in just a moment.

Before we do that, however, I wanted to say that we share investor disappointment about the recent underperformance of our stock. We are so close to growing within cash flow now that we can almost taste it.

We believe that reaching this important milestone in our transformation of the company, followed by demonstrated strengthening of our balance sheet, should reduce the apparent asymmetric impact on our valuation from industry volatility, and drive improvements in our valuation over coming quarters.

Now, let me turn the call over to Wade and Herb to give you the details on our performance and plan.

Wade?.

Thank you, Jay. The key message today is that we are right on track with our 2019 plan and on track to begin growing production while generating free cash flow in the second half of this year and continuing into 2020 and beyond. I will start on Slide 4.

Stepping back and looking at the first quarter, operational execution was right on track and on budget, even slightly better than expected, which Herb will elaborate on shortly. Capital came in at $316 million, which was below our guidance of $325 million to $350 million.

While we continue to drive cost saving measures, for purposes of modeling, I would assume the lower capital spend is related to timing and that we still expect to spend about 60% of our capital budget in the first half of the year.

Production was spot on guidance despite some additional third-party temporary issues in March, which continued through April, that affected both gas and oil sales volumes. We provided realized pricing a couple of weeks ago for the first quarter, which seemed to be the biggest variable.

Regional pricing in the Permian for both oil at Midland and natural gas at Waha is expected to be volatile into the fall of this year. First quarter realizations in the Permian were also affected by the force majeure events that effectively reduced our contract rates for the NGL uplift in Permian gas. Gas plants are now essentially back in service.

Otherwise, first quarter line items were generally in line noting G&A was a little higher in the first quarter due to timing of expenditures. Turning to hedging on Slide 5. All of the hedge detail is in the appendix to the slide deck by quarter.

However, I will point out that we have hedges in place for Permian gas at Waha for approximately 70% to 75% of Permian natural gas volumes, and more in the second and third quarters, and Midland to Cushing basis hedges in place for approximately 60% of Permian oil volumes through year end.

Turning to Slide 6, subsequent to quarter end, we amended our credit agreement to increase the borrowing base to $1.6 billion and the lender commitments to $1.2 billion. Pro forma to first quarter end cash and revolver balances, we have about $1.2 billion in liquidity. Turning to Slide 7. I will make a few comments about our second quarter guidance.

Production of 126,000 to 131,000 BOE per day that we project will be 43% to 44% oil. At the midpoint, this projects over 9% sequential growth and, given completion timing we will see growth from both of our core areas. Capital spend is expected to come in between $300 million and $310 million, aligned with our initial guidance.

Other line items are unchanged from the annual guidance As a reminder, our 2019 plan generates approximately 20% year-over-year production growth in the Permian, and in 2020, assuming a similar capital budget and capital allocation, we expect to generate Permian production growth in the mid-to-high-teens, further increasing the percentage of oil in the production mix and corresponding margins.

As I mentioned earlier, we are on track to begin generating free cash flow in the second half of this year, and then in 2020 and beyond. As Jay said earlier, our priorities include using this free cash flow for absolute debt reduction. Net debt-to-EBITDAX will remain around three times this year and should head towards two times in 2020.

So, in closing, for me, I hope that you agree that this is a very exciting time as we are extremely close to this very important inflection point of free cash flow generation and corresponding debt reduction. I’ll now turn the call over to Herb..

Thanks Wade. Let me start by simply stating that we are focused on execution. As I walk through today’s update on our Permian and South Texas operations, I plan to focus on three elements related to outstanding execution. I’m on Slide 8. First, well performance.

We are using a data-driven approach to optimize spacing, steer to the best landing zones and customize our completion designs while delivering on a clear target for financial returns. Second, capital efficiency.

Our well costs are among the lowest of our competitors on a like-for-like basis, and coupled with outstanding well performance, this translates directly to high returns. Third, value creation.

By testing new intervals in our stacked pay areas and continually improving well designs, each of which build inventory, we are continually driving to build value. Turning now to Slide 9 and our Permian operations. We are currently running six rigs and four completion crews.

We completed 27 net wells in the Permian in the first quarter and expect to complete 35 in the second quarter. This implies that just over 60% of our 2019 wells are brought on line in the first half. We are running slightly ahead of schedule given efficiency improvements in operations that I’ll cover in a moment.

Our biggest accomplishment in the first quarter was, of course, the seamless execution of the Merlin Maximus 25-well development which was on time and on budget. I’m pleased to say that all wells on production to date are performing at or better than expectations, and overall are ahead of expectations.

Let’s look at results to date in a little more detail on Slide 10. Here is a terrific example of continued top tier well performance. The chart on the left shows that the 24 wells producing to date on average are matching the average production profile of all of the operated Wolfcamp A wells completed to date in the RockStar area.

That is a great result as more than half of these Merlin Maximus completions are in the Wolfcamp B and Lower Spraberry. The chart on the right emphasizes an important point, that not all co-development projects are the same. Well spacing and completion design are critical.

Comparing our Merlin Maximus co-development to recently published peer co-developments shows a dramatic difference in well performance. I guess this simply illustrates what happens if you put too many straws in the milkshake, you’ll have spent more capital to only diminish production per well.

This is why it is so critical to be clear about what you are trying to achieve when deciding on appropriate spacing for co-developments. And I need to add that it is not just horizontal spacing that matters. Where there are few frac barriers, vertical spacing also matters.

Here’s where I will again emphasize the analytics behind our spacing decisions, which will differ across our acreage position and are customized to the specific geologic characteristics of an area.

Our philosophy is not to simply target maximizing NPV at a 10% discount rate but rather to target achieving a 25% return on the last dollar spent within a spacing unit, meaning, the return for the entire DSU will be notably higher. This enables us to optimize returns and deliver free cash flow faster.

As a result, the development plans and inventory range that we have communicated assumes a broad range of spacing within zone. Ours ranges from a smaller percentage of wells at 420 foot spacing and continues on up to 1,320 feet, all within a zone.

Slide 11 shows our usual quarterly chart that compares the most recent wells with a 30-day IP rate to the average of all wells to date in the RockStar area. Note that 16 of the 20 new wells are fully bounded, and strong performance has continued.

And, remember of course, that our RockStar wells start out producing at around 88% oil and, over time, this area has among the flattest trajectories of GOR growth in the Permian Basin. The second element of outstanding execution is capital efficiency. Turning to Slide 12, we just keep getting better.

Drilling rate during the first quarter improved 17% compared with 2017. We are completing faster with 64% more lateral feet stimulated per day compared with 2017. Sand costs are down 73%. And this quarter’s average lateral length of 10,700 feet ranks among the longest of peers.

The combination puts SM at a drill complete and equip cost of $765 per lateral foot, which we believe is top tier.

What does all this mean? Top tier well costs, combined with third-party analyst data that points to SM having the highest revenue generating wells in the Midland Basin, points to SM having among the highest returns and best capital efficiency in the basin.

I’ll briefly add, although it is too early to show dedicated slides, we are seeing some really encouraging results from testing new intervals in the Midland basin. This is the third element of outstanding execution, building value in inventory.

Our first Middle Spraberry test in the RockStar area, the McFly well has been producing for over five months now and reached a peak IP30 of about 1,000 BOE per day at 86% oil. Production from this well is looking very similar to a peer test about one mile away.

Middle Spraberry wells are expected to exhibit similar production profiles to the Lower Spraberry, meaning lower peak rates and shallower declines. So, keep your eye on this one. We’re excited about Middle Spraberry inventory potential as it was ascribed very nominal value at the time of acquisition.

Given the large section between the Lower and Middle Spraberry, we do not expect any interference. So, these intervals can be developed independent of each other to optimize returns.

In addition, we have preliminary results from our first Wolfcamp D test; the Sarah Connor well started production and in just over a week on-line, has achieved a 24-hour peak rate of over 1,900 BOE at 80% oil. We are very encouraged that this aptly named well is capable of this strong rate while naturally flowing up casing.

Helping this is the fact that the Wolfcamp D is over-pressured on our acreage. Similar to the Middle Spraberry, there is a very thick section between the Wolfcamp D and the shallower Wolfcamp B. So, these intervals can also be developed independent of each other to optimize returns.

This is an interval that we did not ascribe any value to at the time of acquisition. So, this is all upside inventory and value. And, following detailed geologic work, more good news, we brought our first Dean well online last week. The well is highly productive with a low water cut.

Very early days, but this well has already produced a 24-hour peak rate of over 2,000 BOE at 92% oil. This is an interval that we will integrate into our co-development plans. Given the early indication of high productivity, we would expect high returns. More to follow as we see longer-term production behavior.

Now, let’s turn to Slide 13 and South Texas, where we have ramped up to running two rigs and two completion crews, after only bringing two wells on-line in the first quarter. This quarter, we expect to bring 14 net wells on-line. This means almost 90% of our South Texas net completions activity is in the first half of the year.

The second half focuses on the joint venture area, funded fully by our partners, where we are testing wells on wider spacing with our latest completion designs. Here, we expect substantially higher returns than we achieved with earlier pilot tests, and that is backed up by performance of early wells and some wells of offset operators.

The third element of our execution strategy, building the value of our inventory, is a key focus in South Texas. We are executing on value enhancements by testing new intervals and implementing wider spacing and completion designs that deliver higher returns.

Turning to Slide 14, where we are showing early results from our second Austin Chalk well – the Watson State 167H. To date, we are very encouraged. This 12,875 foot lateral well is currently producing more than 3,500 BOE per day on a three-stream basis. The liquids content, similar to our first test, is more than 55%.

The high liquids content leads to higher revenues per lateral foot and lower transportation costs per BOE than an offset Eagle Ford well. To date, we are seeing a step-up in performance and returns from this second Austin Chalk well given it has a 60% longer lateral and the Austin Chalk formation is 22% thicker in this location.

You’ll also note from the gun-barrel view shown in the lower right portion of the slide that this new well is located between two Eagle Ford PDP wells that have been producing for quite some time, and also shares a pad with a new Lower Eagle Ford well that commenced production at the same time.

We have not seen any interference between these wells to date. As a result of these recent tests, we now plan to drill and complete a third Austin Chalk test later this year. This is in addition to the three Austin Chalk wells that we discussed previously that will be drilled late this year and completed in early 2020.

We are obviously very excited about the value and inventory potential of this liquids rich play. Turning to Slide 15. More broadly in the Eagle Ford we continue our phased implementation of wider spacing, improved landing zone selection, and enhanced completion designs that we have talked about over the past several quarters.

We have made real progress and continue to add data that supports our belief that we are on the right track to achieve higher returns with our revised development plans. I know that all of us are eager to see the benefits of this revamp of our Eagle Ford plans that we announced early last year.

Since that time, we completed several DUCs, continued drilling permitted wells, met our leasehold requirements, and phased in our new approach throughout last year as quickly as we could.

As the arrow indicates, we are now part of the way on the journey towards these higher returns that are consistent with our most recent inventory count, but we aren’t all the way there yet.

We’ve already achieved a 30% uplift in performance from some increase in well spacing and improved completion design, and are well on our way to our targeted 100% uplift.

The point of the figures in this slide is to show you on the left side how our wells have improved per lateral foot, and on the right, what we are targeting when we also increase lateral lengths. To elaborate on this, at the lower left we are showing cumulative production per 1,000 lateral feet versus time. The 2017 wells are the orange line.

These 2017 wells were spaced at 562 feet in plan view, had an average lateral length of 7,800 feet and were completed with an average of 1,874 pounds per lateral foot of proppant. 70% were completed in the Lower Eagle Ford and the remainder in the Upper Eagle Ford. Moving up, we see the bright blue line.

This quarter, we have results from six wells that we call moderately spaced at an average 807 foot spacing in plan view. The moderately spaced wells included three existing DUCs. To date, these wells are generating a 30% average increase in production over the 2017 wells with lower drill and complete costs per lateral foot.

Higher production coupled with lower cost clearly results in higher returns. So, we’ve confirmed progress halfway up the arrow in the slide. Next, look at the purple line across the top. This shows the production from two wells completed in the first quarter of 2018 at 1,250 foot spacing. These wells are huge; however, they are unbounded within zone.

Testing these unbounded wells and seeing the outstanding results, provides us critical information about both reservoir quality and well potential as we work to optimize spacing and assess viable returns at current commodity price levels.

The figure on the lower right side shows what happens when you combine the better productivity per foot with longer laterals.

Here, we are comparing the actual production of the 2017 wells as they were developed with the 562 foot spacing and 7,800 foot laterals to a fourth quarter 2018 well scaled up to a 12,500 foot lateral length at the same production per lateral foot that we showed on the left.

You can see from this why we have confidence that we can achieve the 100% uplift target that we show in the arrow on the slide. We are now taking another step towards what we term the optimized well design. The first two wells of this type will be brought on-line this quarter.

These wells are spaced at 1,250 feet, have 11,400 foot laterals and 2,000 pounds per foot of proppant. In terms of next steps and as part of phase 2 of our JV in the Eagle Ford North area, we plan to complete 12 wells at wider spacing this year.

In these wells, we will apply new completion designs that have been derived from what we learned from the fiber optics installation last year and several other design tests late last year. We will look toward year-end and early next year for more information from these new JV phase 2 wells, which will be fully optimized.

Let me add that when we provided our estimated years of economic inventory during the year-end investor call, we had already factored in the wider spacing and longer laterals that I have been talking about today. Now, we are simply executing toward that inventory level, while assessing new intervals like the Austin Chalk.

Turning to Slide 16, just as in the Permian, we just keep getting better on capital efficiency in the Eagle Ford. Drilling rate during the first quarter improved 23% compared with 2017. We are completing faster with 36% more lateral feet stimulated per day compared with 2017.

We expect our average lateral length this year to increase by 49% over the 2017 average. The combination puts SM at a drill, complete and equip cost of $650 per lateral foot in the Eagle Ford, which we believe is top tier. I will wrap up by simply reaffirming that we are focused on execution.

This will deliver top tier well performance, drive improved capital efficiency, and create value through expanded economic inventory from new intervals and optimized development plans. We are extremely excited about the progress we have made on all these fronts. I’ll now turn the call back to Jay.

Jay?.

Thanks, Herb. As we have all said multiple times during this discussion, we’re on track to deliver on our 2019 plan. Our well performance has been outstanding and we continue to execute with excellence. We’re generating high returns and we’ll shortly be growing while generating free cash flow.

Given our current market valuation, we believe that SM shares at this point are an outstanding opportunity for investors. Thank you all for your interest in our company and we’ll be happy to take your questions on our call tomorrow morning..

Good morning, everyone, and thank you for joining us. I thought I’ll kick off our Q&A session this morning with a question for you all. In Herb’s prepared remarks he references straws in the milkshake. What movie is that from? It’s a busy morning.

I need to quickly remind you all that we may discuss forward-looking statements about our plans, expectations and assumptions regarding future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

Please refer to the cautionary information about forward-looking statements in today’s release, the first quarter IR presentation and the Risk Factors section of our Form 10-K filed in February and our Form 10-Q filed this morning, all of which are posted to our website.

Our discussion today may include discussion of non-GAAP financial measures that we believe are useful in understanding and evaluating our performance. Reconciliation of those measures to most directly comparable GAAP measures and other information about these non-GAAP metrics are provided in our earnings release and IR presentation.

Here to answer your questions this morning, our President and CEO Jay Ottoson; EVP and CFO, Wade Pursell; and EVP of Operations, Herb Vogel. I will now turn it back to Chris to take our first question..

[Operator Instructions] Your first question comes from Gabe Daoud of Cowen & Company. Your line is open..

Hey, good morning everyone. I appreciate the comments last night, nice Sarah Connor well name there, but could you maybe just talk a little bit about the Dean and the Wolfcamp D.

And what you learned, how you think about these zones over the next couple of years? And what this could potentially mean for inventory?.

Okay. This is Herb, Gabe. Thanks for questions. So, in the yesterday’s remarks, we talked about how the Wolfcamp D is separated and the Middle Spraberry are separated from the Wolfcamp A, B and Lower Spraberry. So those are two separate intervals, and they’re relatively thick in the – just in the Rock Ridge area.

The Middle Spraberry is about 250 feet thick and the Wolfcamp D is about 330 feet thick, and there is an entire Wolfcamp C section in between those. So – what we really see – like about it is that they can be independently developed. The Dean is quite productive and at the 200-foot thick interval in the Rock Ridge area.

So when you look at those, there is quite a bit of oil in place, and that’s really what we like. And then over time, we’ll be delineating out along with quite a few other parties who are operating near us. So we feel quite good about those intervals and the ultimate potential for inventory and reserves..

Great, great. Thanks for that. And just a follow-up obviously, it looks like you’re on track for second half free cash flow generation and you’ve been pretty clear about usage of free cash flow.

Just curious about how you think about like the A&D environment or the M&A environment, if there is any interest in looking to continue to bulk up the Permian position. Or are you satisfied for now? And thanks everyone, I’ll leave it there. Thank you..

Yes. This is Jay and I’ll take that one. While we’re open to ideas that would clearly accelerate meaningful value realizations, we are not going to consider doing anything that would not be both an obvious step in the same direction as our current planned priorities and accretive to our shareholders. At this point, we don’t need to buy inventory.

And as I said, we wouldn’t do anything for the sake of scale that wouldn’t be clear with our priorities and accretive to our shareholders..

Thanks, Jay..

Your next question comes from Mike Scialla of Stifel. Your line is open..

Yes. Good morning. I think to answer Jennifer’s question, and There Will Be Blood if I remember my movie script..

Not at all..

There’s going to be a prize for that..

I’ll collect that later. Just want to follow up first on Gabe’s question on the Dean and Wolfcamp D. Pretty encouraging results there.

Any chance of testing those further this year? Or is that a 2020 event?.

This is Herb, Mike and we will be looking at how these are performing, very early days. I mean, we just had these on a week and a couple of weeks. And so we’ll be – plan out seeing how they perform and then we’ll be integrating them into our development plans for 2020 and beyond. So no, we’re not going to be doing anymore on those this year..

Got it. Okay. Also looks like pretty encouraging results out of the second Austin Chalk well. Wondering if you’re looking at that zone any differently now on your acreage on other parts of the plate, I think I’ve asked you in the past, if you see it as more of a resource play or more of a conventional type play.

Any updated thoughts there?.

Hey, it’s Herb again, Mike. The Austin Chalk, we’re really excited about it, because it overlies pretty much all of our acreage, gets thicker to the West, a little bit thinner to the East. And it’s quite a good interval. I’d view it as an unconventional play. We’re putting pretty big fracs on it.

And we really like the liquids content relative to the intervals below. We can extend our high liquids content to the South quite a bit compared to the Eagle Ford. And obviously, the revenues from the NGLs and the condensate are – really help the economics.

So we’re encouraged with it, and you can see we’re putting one more well in that, and that’s really just shifting some completion dollars around from another Eagle Ford well, so it’s not incremental to our capital program. Excited with what we got there, and we’ll integrate it with the lower Eagle Ford and upper Eagle Ford development..

Very good. Thank you..

Your next question comes from Oliver Huang of Tudor, Pickering, Holt & Co. Your line is open..

Good morning and thanks for taking my questions.

On the Merlin Maximus pads that came online, I was wondering if you can provide some color around what some of the key learnings throughout the project were that can be carried forward? And how we should be thinking about optimal pad and project sizing going forward?.

Hey, Oliver, there’s a lot to that Merlin Maximus pad. So I’ll just summarize by saying we drilled it with four rigs starting in April last year. We started completing and we used three frac spreads and we moved from East to West as we were completing the wells and kind of hopped the first frac spread over the fourth location – fourth slice of well.

So the key thing we were also doing some spacing testing in there, and we were working to improve Wolfcamp B performance, so the sequence wasn’t necessary always top to bottom. We were trying some things to see how we could enhance Wolfcamp B performance and contain Lower Spraberry fracs.

So the main learning we’ll see as the production proceeds over the next year or so. And that’s when we’ll see how it performs, particularly given the different tests that we’ve got integrated and what we’ve done.

Does that helps?.

Yes, that’s helpful. And as a follow up, you had a slide on the Permian showing, I guess, co- development projects versus some of your peers.

Just wondering if there is any incremental color to the prepared remarks on what SM is doing differently to drive that outperformance?.

Yes. I think it’s really in just what you’re trying to achieve. And I think I mentioned that in there, as clear as I could. We target that 25% return on the last well.

So we have a pretty – a very, very good correlation with all the data we have on what impacts are as we space tighter and tighter and what happens as you get tighter and tighter vertically also. And so the key thing is we’re really striving to get that 25% return on the first – last well. So that means overall the returns will be higher.

So that’s why the milkshake analogy. If you put too many straws in there, you’re not going to get as good a performance per well, and so you really have to understand that in designing these co-developments. That’s really the point of the whole slide there..

Okay, perfect. Thank you very much..

Your next question comes from Paul Grigel of Macquarie. Your line open..

Hi, good morning. I was wondering if you guys could maybe elaborate on the Lower and Middle Spraberry initial peak rates and the subsequent lower declines as compared to maybe the upper Wolfcamp wells and try to put some numbers or some directional color to just how big the difference may be there..

Yes. So there’s not a single answer to that one, Paul. It depends where it’s located. So for example, on the 2018 program, our Lower Spraberry wells actually performed stronger than Wolfcamp A from an overall standpoint.

But if you look over time, you’ll see that even when you shift to where the Lower Spraberry has come on a little bit slower, they ultimately have a lower decline. So the economics in 2018 were actually slightly better for the Lower Spraberry and in 2019, we expect them to be slightly lower.

And it’s simply where it’s located, the thickness of the section and the spacing we are using. And what we’re doing is targeting a certain rate of return by putting all those factors together, the spacing horizontally, the spacing vertically to get that 25% return on the last well, so that the overall DSU has a much higher return.

We have a lot of control, it’s not like it just happens. We have the ability to influence the returns we get on these wells. I think that’s really the point we want to make on all these..

No. Understood. Great color there. And I guess, maybe turning to the CapEx budget. You guys have noted before today and then again today the kind of front-end loaded of 2019 and lower CapEx in the back half of 2019. I realize it’s early, but how should we think about cadence in 2020.

Is this a seasonal aspect that could be front-end loaded and that may be the situation? Is it based on just when large pads like Merlin Maximus come on? How should we think about just from how you operate the business kind of beyond 2019 as you move towards free cash flow?.

Paul, it’s Wade. Some of all of that. I mean, as we approach 2020, we’ll give a lot more color on cadence and specifics with respect to those questions, but I’ll just reiterate that 202, we do – our plan does show us generating free cash flow and reducing debt during that year – during the year.

So again, as we get closer, we’ll give you more detail on the cadence..

Okay. Thanks..

I would now like to return the call to Jay Ottoson, President and CEO. Please go ahead, sir..

Well, thank you. I guess, I’ll take the minimal number of questions today as a sign that our materials were clear and comprehensive. Obviously, we’re thrilled about our new well results and Jennifer will be happy to address any subsequent questions you have. Thank you for your interest this morning, and we’ll let you go. Thanks..

This concludes today’s conference call. You may now disconnect..