SandRidge Energy Inc (SD) 2017 Q1 法說會逐字稿

Good morning. My name is Shelby, and I will be your conference operator. At this time, I would like to welcome everyone to the Q1 2017 SandRidge Energy Conference Call. (Operator Instructions) Thank you. Duane Grubert, you may begin your conference.

Thank you, operator, and welcome, everyone. Thanks for joining us on the conference call. This is Duane Grubert, EVP of IR and Strategy here at SandRidge.

With me today are James Bennett, our President and Chief Executive Officer; John Suter, EVP and Chief Operating Officer; and Julian Bott, EVP and Chief Financial Officer. James will make prepared remarks, and then the group will be available for Q&A.

We would like to remind you that in conjunction with our earnings release and conference call, we have posted slides on our website under the Investor Relations tab that we'll be referencing during the call. Keep in mind, today's call contains forward-looking statements and assumptions, which are subject to risk and uncertainty, and actual results may differ materially from those projected in these forward-looking statement.

Additionally, we will make reference to adjusted net income, adjusted EBITDA, adjusted G&A and other non-GAAP financial measures. A reconciliation of the discussion of those measures can be found on the website. You will also see us file our 10-K on our website.

Please note, the call is intended to discuss SandRidge Energy and not our public royalty trust.

Now let me turn the call over to CEO, James Bennett.

Welcome, everyone, and thank you for joining us. Today will be short in terms of prepared remarks, given we just had our year-end release over a couple months ago. I'll go through some updates and highlights that I'm excited about, including the expansion of our position in the Northwest STACK to 70,000 acres; very strong results of our Niobrara 2016 wells, including not just D bench, but also C bench production, in light of sight to resumed oil growth later in the year.

Starting on Page 2 of the slide deck we published this morning. Let me remind you of our strategy and tactics in 2017. We've been consistent for the last several quarters. With our strong balance sheet and 0 net debt, we are developing our Northwest STACK assets where we have increased our acreage position across 3 counties.

In the Niobrara Shale of North Park Basin, we have updated strong well results to share with you, and we'll resume development midyear of this high-oil-content asset. And the high-graded harvest of our large Mississippian-producing asset continues. In Q1, we completed another full section development multilateral well, and this asset continues to generate real free cash flow for the enterprise.

Everything we do supports resource value creation with a focus on moving to a more consistent repeatable and oilier portfolio. And with this program, our oil production will turn the corner and begin to grow in the back half of 2017.

Turning to Page 3, highlighting this quarter's results. We're off to a strong start and on track with our 2017 program. Production of 4 million barrels of oil equivalent and 28% oil is in line with our full year guidance. EBITDA was $56 million and CapEx was $41 million for the quarter, generating $15 million of real free cash flow. We have one rig running for most of Q1, so new well activity is light this period. We are maintaining our full year guidance CapEx midpoint of $215 million and no change to the other components of guidance.

On our free assets, we are enthusiastic with what we're seeing in the Northwest STACK in Oklahoma. Our last reported well there, the Medill in Major County, continues to outperform. The well has cumed 102,000 barrels of oil equivalent after 148 days, which is well in excess of our Meramec single lateral type curve and encourages follow-up drilling in this area.

On the heels of our results and other successful industry wells, we have increased our leasehold position in the Northwest STACK. During the quarter, we closed a 13,100-acre acquisition. And to organic leasing, we expanded our Northwest STACK position by 10,000 acres to 70,000 net acres.

Late in the first quarter, we added our second rig in the Northwest STACK, targeting the Meramec and have wells planned this year in all 3 of our Northwest STACK counties.

For our Niobrara oil asset in the North Park Basin of Colorado, first quarter daily production was just about flat with the fourth quarter despite bringing no new wells online, as our teams have optimized our artificial lift program and the 2016 wells continues to outperform our type curve.

Today, we'll highlight cumulative production from the entire 2016 program, our very successful first C bench well and our first extended lateral D bench well. These combined results have us excited to get a rig back in North Park at midyear.

In our traditional Mississippian asset, the results remain strong. During the first quarter, we completed another multilateral full section development well, the Hawk Haven. You can see the results here on Page 3. Importantly, this demonstrates our ability to harvest the Miss with strong rate of return projects.

While we don't have additional Miss wells on the drill schedule, we do have a solid inventory of high-return projects there that will be exploited in the future. And the Miss is an important source of cash and in the first quarter, generated actual free cash flow of $52 million before the benefit of any hedges.

Our balance sheet is one of the strongest amongst small-cap E&Ps. We have no debt. Cash is $137 million. Liquidity includes an undrawn $425 million revolver with no current plans to draw on the revolver in 2017.

Now into some details by area. On Slide 4, to reorient everyone on the Northwest STACK, which we define as portions of Woodward, Major, Garfield, Dewey and Blaine Counties. The Northwest STACK is an oily asset with multiple zones, primarily Meramec and Osage and within or adjacent to our existing Mississippian operating area. Here, we have 70,000 net acres. We count 20 rigs, including our 2 active in this area right now from 12 different operators.

Slide 5 outlines our Northwest STACK activity. In blue are the wells we drilled in 2016, 2 Meramec and 1 Osage well. In orange, you can see our current activity, including 1 well in Woodward and 1 in Southern Major Counties that are in early flowback or being completed. And our 2 rigs drilling, 1 in Major and 1 in Garfield County. With this level of activity, we will have more Meramec well results to share next quarter.

I mentioned the 20 industry rigs running in the Northwest STACK drilling a combination of Meramec and Osage wells. On Page 6, we show the Meramec results, including our 2 wells. These demonstrate the quality of this resource play, including its high oil content, averaging 40% to 60% and productivity, with IP rates in excess of 1,000 barrels of oil equivalent per day.

Similarly, on Page 7, we indicate the Osage results in this area. We drilled 3 Osage wells in Garfield County in '14 and '15, which we understimulated in hindsight. We often get the question why aren't you currently drilling in the Osage? We do like the Osage here and given its thickness, believe this will be developed as a stacked play with multiple targets. However, the ability to drill the Meramec with more cost-effective 2-mile laterals, coupled with its higher oil content, yields better rates of return. Also, we can drill a Meramec well to hold the unit and come back and drill the Osage later.

In 2017, we project to spend approximately $70 million of drilling-completing CapEx in the Northwest STACK. That will include 22 laterals, of which approximately 3/4 will be long laterals. We're also performing some additional science and geologic work. We recently acquired 330-square-mile 3D seismic data set in Woodward and Major counties, and we'll take a core in Major County this year to assist with reservoir characterization and oil-in-place calculations.

In terms of well cost in the Northwest STACK, we plan on just over $6 million for an extended lateral with an EUR of 800,000 to 1 million barrels of oil equivalent. This generates a 20% to 35% rate of return at recent prices.

Turning to the Niobrara in the North Park Basin. In 2016, we drilled 11 laterals and tested various stimulation concepts, spacing, alternate zones and long laterals. You can see the results of the entire 11-lateral program on Page 8. After analyzing these wells, which are now all over 160 days of production, we are even more encouraged by their very strong and consistent production results that are characteristic of an overpressured resource play.

Turning to Page 9. Recall that to date, the field has been developed both by us and the prior operators in the lowest bench of the Niobrara, the Niobrara D. Last year, we drilled our first well in the Niobrara C bench, which you can see just above the D and have plans this year for Niobrara B bench well.

On that, Page 10 is our first C bench well, the Hebron. The well has 170 producing days and has cumed 70,000 barrels of oil, which is outperforming our EUR 270,000 barrel of oil type curve by just over 30%.

Importantly, you can see the graph on the left, the production profile is flatter than originally projected. And even now, the well is making over 450 barrels of oil per day, triple the 150 barrels a day in the type curve.

Similarly, on Page 11 is our first extended lateral well, the Castle, with a 9,500-foot lateral. While this well didn't outperform the type curve initially, in the graph to left, you can see the production profile is flatter than our type curve and is starting to exceed the type curve on a cumulative basis. The well is currently making approximately 500 barrels of oil a day. In this case, twice the 230 barrel a day in the type curve.

On Page 12, we have the entire 2016 North Park program. I want to be transparent and show all of the wells in the 2016 program. All 11 laterals are on the left and, again, outperforming the type curve by just over 10%. After our learnings on cross-linked versus slickwater stimulations, going forward, we'll be utilizing cross-link stimulations in between 1,000 and 1,200 pounds of proppant per foot.

The graph on the right on Page 12, we show the 8 laterals using cross-link stimulation, and this well set is performing 20% above type curve.

On Page 13, in 2017, we are projecting approximately $25 million of drilling-complete CapEx to drill 6 laterals. These will be long laterals and will include our first C bench long lateral and our first well in the Niobrara B bench. We are excited about the B bench, given its thickness and analog to Niobrara productive zones in the DJ Basin. Target well cost here will be approximately $7 million for a long lateral, which at recent prices, generates a 27% the rate of return and PV10 of $2.9 million.

In terms of other initiatives, in 2017, we will drill a well to hold 24,000 acres in the Rabbit Ears Federal Unit, which will bring our held production or held by unit acreage in the basin to 95,000 net acres or 75% held. We will process our recently completed 3D seismic shoot in core 1 of our wells.

Also, on the midstream gas takeaway, we'll be testing infield liquids processing, gas to liquids and gas reinjection. All of these initiatives will help us position this asset for full development.

On a related midstream note, we extended our marketing and transportation agreements in the North Park Basin and have locked in a low $3.15 per barrel oil differential to WTI through the end of 2018.

You can see why we're excited about this asset. The wells are greatly outperforming our expectations with a flatter oil production profile and very consistent results. We have established production from 2 Niobrara benches, the D and the C, and drilling a third bench, the Niobrara B this year.

In summary, the strategy is consistent and our execution is solid. In the Northwest STACK, our Meramec wells and industry wells continue to perform and improve with high oil content and consistent IP rates. We have increased our acreage position to 70,000 net acres and our activity from 1 to 2 rigs. The Northwest STACK is an example of us expanding our resource base into a high-return, oily stacked play that is very complementary to our skill set and within our existing operating area.

In the Niobrara, the production data clearly shows that our wells are outperforming expectations with a flatter production profile and now production for multiple benches. The high-graded harvest of the Mississippi, it is working. We have a known location inventory that is over 75% HBP, and this asset continues to generate cash in 2017, providing an estimated $155 million of real free cash flow at the strip. With the Northwest STACK in North Park Basin focus, oil cut will increase from 28% now to over 30% by year-end, and oil production will turn the corner in the back half of 2017. We have 80% of crude hedged at over $52 per barrel this year, and our balance sheet is clean and provides a lot of financial flexibility. We have over $100 million of cash, no net debt and a $425 million undrawn revolver.

Everything we do is about resource value creation with a focus on creating a more consistent, repeatable and oilier portfolio long term.

With that, we'll turn the call back over to the operator for any questions.

(Operator Instructions) Your first question comes from the line of Tim Rezvan with Mizuho.

First, my first area focus on the unit expense results in the first quarter. Yes, there's a couple different items that we're going to see in 2017 with a declining production base. So you handled or exceeded full year guidance on unit expense, but should we expect things may increase a bit on the unit expense side given the decline in production expected this year?

Yes, this is John Suter. We really feel pretty good about the results in the first quarter. We feel comfortable with our guidance. We did a great job of delivering a production as anticipated and really did a nice job on the costs as well with the numbers that you saw. But it is a math thing, like you said, with declining production over the year, we would expect yearly operating cost to increase, but feel comfortable with our guidance at this point.

Okay. That's what I thought. If I could change topics. Moving on to Slide 8 where you show the 2016 Niobrara results. They were fairly tightly clustered, the wells there. I know there's the well to HBP, the 24,000-acre unit. How diverse is your drilling going to be in 2017? How much are you going to sort of step out across your footprint?

Sure. We mentioned we have the 6 laterals with 3 wells planned. We'll be drilling, if you're looking at Page 8 there, to the southwest, stepping out several miles there in that Rabbit Ears Federal Unit. We'll also be drilling some wells, if you look at the map again, kind of to the Northern part of that area and then a little bit to the east. So that area represents about 12 miles north to south. So not a small area if you can get 4 to 8 or more wells per section there. We are talking about a lot of wells. But we will be stepping out a bit this year and delineating the field. We do want to be mindful of our 3D seismic shoot that we just took and we're processing, so we'll be shooting underneath that. We're taking another 3D shoot this year to continue to advance our geologic understanding of the play.

Okay. And if I could sneak one more in, and then I'll hop back in the queue. You mentioned the 10,000 acres you were able to lease. Are you going to be -- are you actively looking to bolt on more? And can you give any parameters on the prices that you pay for those leases?

If you look at our guidance of about a $40 million land and seismic budget. I think, we spent about $15 million of that through the first quarter. So yes, I think we'll be adding more to this position, particularly in the areas that we like and in and around our good and existing wells. So yes, look for us to continue to add here. I don't want to disclose dollar per acres right now. Our folks are still out leasing actively, so I don't want to make their life any harder there. So give us a couple quarters before we disclose any dollars per acre. I will say that on a lot of our leases that were signed 2 and 3 years ago, we do have 2-year extensions on those, and the price per acre to extend those is $850 per acre. So that's one data point in terms of what we can spend to extend for 2 more years. It's about $850 an acre.

Your next question comes from the line of Mike Kelly with Seaport Global.

Following on to Tim's question there on the A&D front. Just hoping you could describe just the overall environment there just on the A&D leasing side. Have you seen things start to heat up, get more competitive there? What's really the opportunity set in your eyes, maybe county of focus and then just really desire to potentially take the acre position to a much bigger number from where you are now?

Sure. We have seen the activity increase over the last several quarters, and we've been active here, if you listen to our last call, since really 2015 in this area, leasing quietly and drilling some wells. But we've seen the activity pick up quite a bit the last several quarters. Lease rates have increased, pulling bonuses, which you can look those up, those have increased. Major Counties are very competitive so is Woodward and Garfield, Dewey and Blaine. So this area is getting a lot of attention. With 20 rigs running in this area from 12 different operators, you have a lot of leasing activity and a lot of drilling activity. In terms of additional acreage, we're trying to assemble the right size portfolio, but also at the right value. No sense in paying too higher price per acre here. We think we're getting these at very good values. But in the next couple quarters, I think, I suspect the leasing activity here will slow down and people will have their positions established and they'll go into more development mode.

Good. Appreciate that. And then Medill rate is, obviously, very impressive and just wanted to get your thoughts on is this attributable to you guys going after some of your best rock here maybe in the Southern portion of your basin and are you positioned? And just how repeatable are the drill-type results as you go further north or west, in your opinion?

Sure. This was our first well there in Major County. It was only a single-mile lateral. Going forward, us and you'll see a lot of operators drill 2-mile laterals. I think that's really key in the Meramec. You could put together a 1280-drilling unit and very efficiently drill a 2-mile lateral, which is just a little more challenging in the Osage. But look, our team and geologists, engineers liked this area. Picked it for the first well. Don't know if that's representative of the entire area. We have several Meramec wells and we have our eyes on so wouldn't say that this is the best area in the play. But again, it was only 2-mile lateral and stimulated with about which on 1,200 pounds per foot stimulation.

Yes, yes.

Do you've anything else to add to that?

No. I mean, I think we are really excited about Major County, the Medill is -- has been a fantastic well. But as James said, there's others that have made wells that have outperformed our type curve as well. We're excited about the upward pressure on that, but we continue to monitor that and have a well about a mile away that is extended lateral that we're really excited to see the results of in a week or 2.

Okay. Great. Well, sneak one more into. Tim did it. So if the Medill rates prove repeatable and you drill 22 wells this year, everything looks like seeing the type curve or go in that direction. James, how aggressive do you think you could be in terms of the activity level moving into 2018? What would you feel comfortable taking that 2-rig count to?

It's a reasonable question. The Medill is, if you look at the math, it's almost exactly 2x our type curve. So you can look at some returns in the type curve and do your math and that gets to very, very high rate of return. It's going to depend on a couple things which will drive that quite a bit. Obviously, you mentioned the well performance. But also commodity price is going to be a big one. We've got a oil in the 40s. That's going to be one answer versus something with a 5 in front of it. You are very well hedged this year with 80% of our crude hedged, but we like to look at these on a stand-alone basis and what kind of return can they generate. Service costs will be another thing we'll keep an eye on so it kind of depends on any service cost inflation. But look, if you were to keep a reasonable oil price and service costs where they are now, we could comfortably deploy a couple few more rigs here and keep up with that pace and have plenty to do in this area.

Your next question comes from the line of David Beard with Coker & Palmer.

Maybe talk a little bit about the competition for capital between the 2 basins. And I'm probably more interested in what are the levers that could change over time to cause you to steer money to -- of one to the other? Obviously, as these in -- as these basins develop, you could see things which could shift activity one way or the other.

Sure. On the -- really talking about the Northwest STACK and the Niobrara North Park Basin here. Don't have a lot of capital going to Mississippian right now, but we could always pick that back up at any time given it's largely held and we have over 200 locations there where we can drill. But really, between the Northwest STACK and the Niobrara, the Northwest STACK being in Oklahoma, 20 rigs active in the area. It's a very competitive area. There's forced pooling, so you have to be careful of, if so if you're not operating here you can lose operatorship. That's one thing that comes into consideration. Also, we're watching the results from the other wells. We've got about 117 wells in that data set that we keep an eye on and we have data on from either working interest owners in the wells or maybe it's a trading agreement. So we've got a large data set that we're watching there. In the Niobrara, the North Park Basin, it's really predominantly us drilling. We have the dominant position in that basin. We really like the results as you can see, they're way outperforming our initial estimates. But we're -- in there we're being -- making sure we have the right knowledge before we go too fast there. Yes, we're drilling some multiple benches. We're testing spacing. We're shooting some 3D. I'll expect to get more results from that this year with the 6 laterals we're drilling. So between the 2, it's going to be a balance of -- but first, it's going to be risk-adjusted rates of return; second, it's going to be what's the competitive environment and where do we need to deploy some more capital to protect and defend and delineate our position. And in the North Park, with this new federal unit, it's going to be 75% held by production or held by unit. And in our Northwest STACK, we're about 33% held by production. So that also tempers the pace at which you go in either one, which one's more HBP. I hope that -- I think that answers your question. Does it?

Yes, now that was helpful. And maybe just a follow on on that. It seems that and maybe this is too simplistic, but if you could solve that gas flaring issue or that the other takeaway issue in the North Park, that probably would take precedence in terms of capital just given the consistency and high oil cut. Is that relatively accurate over time? Or is it a little too simplistic?

That might be a little simplistic. I completely understand the comment. It's something -- it concerns something we talk about a lot. You could see we talked about it in the earnings release that I mentioned it. We do have other options that we're testing this year in terms of the gas takeaway, which should be some gas to liquids, some liquids extraction, even gas reinjection in the field. So gas takeaway right now is not the constraining factor. We do have options for the gas and we -- some of these things that we're pursuing can delay and maybe someday completely defer the need for a pipeline. We'll see. We're trucking the oil right now at a great differential of $3.15 per barrel differential to WTI. We have that agreement through the end of 2018. So getting the oil out is not a concern either. So look, longer term, we'll all address the takeaway capacity out of the basin. But some of the things we're doing now make that really not one of the top few constraints on going faster in this asset.

And James and just a reminder to everybody, this is a really relatively low GOR field or reservoir, so we don't generate a lot of gas for all the oil that we're able to output. I think we only make between 2 million and 3 million a day now. So something we can use functionally to our advantage was some of these projects we're considering.

(Operator Instructions) Your next question comes from Jeffrey Campbell with Tuohy Brothers.

I second the compliments on the illustrations today, very good color. I just want to make sure that I kind of pull this North Park thing together. It sounds like you're going to drill one well each in the B, C and the D. Is that correct? And assuming commodity prices cooperate, do you see North Park as being a continuous drilling program going into 2018? And my last North Park question is, is there well control to indicate that the IOA or maybe the Frontier would be a future target for exploration?

Yes. Good question. On the B, C and the D, yes, that's correct, we plan to drill one in each zone this year. And they'll all be extended laterals. On the full development, it could depend on, as we mentioned, commodity price, service costs here have been a lot more stable than they have been in the Mid-Continent, and so that's not as much of a concern. But we're going to drill these 3 other zones, continue to evaluate the wells we have now, which as I mentioned all have over 160 days of production. So by the time we get there, you'd be looking almost a year of production. So we'll make that determination at year-end. Between those initiatives and the flowback from the existing wells, some of this gas injection and processing tests that we're doing, we'll make the determination. Probably about the end of this year if we're ready to go into full development mode in that play. And again, it's going to be mostly dependent on commodity price.

Yes, I would say too to the rest of your question, the core we plan on taking later this year will check out all of the benches of the Niobrara. We certainly get through the A bench to get to the B, C and D. We've seen shows in it before, so we're excited about the potential of that. But we'll have more confirmation once we see the technical data. And again, the seismic that we're just now getting to look at and processing gives us encouragement about little more continuity in the field than we knew before. So we are excited about it.

That's fine. And my last question was, I was just wondering how your Permian acreage fits into the go-forward portfolio.

Permian is part of our Permian Royalty Trust. We have a couple of thousand wells out there that hold some shallow acreage on the Central Basin Platform. The Trust owns the wellbore in that zone and a halo around the wellbore. So the Permian generates nice flat oil production right now. We've looked at some other opportunities out there for infill drilling and other things. Doesn't really compete with some of our other projects for capital right now, but it's an asset of ours that we liked the flat production profile. But no plans to drill out there right now.

Okay. And just to make sure that I don't get confused on this point, you get the -- SandRidge actually has the ultimate say-so as to what investment is made into that? Or does the Trust have some sort of separate decision-making process as well?

It's really our decision. There's some protective rights that you would expect the Trust to have. We have to operate the wells using a proven operating standard. Again, there's a halo around the wells in terms of offset drilling, no? But it's completely our decision on how we develop that asset in and around the Trust.

Your next question comes from Tim Rezvan with Mizuho.

I just had one quick follow-up. On the G&A side and on the staffing side, the company is consolidated a bit from where it was a couple of years ago. How -- are you adequately staffed for the rig ramp potential that you talked about? Kind of curious kind of what organizationally -- what can you accommodate right now without having to increase headcount?

Yes, so we are staffed appropriately for this rig ramp that we have in the plan. We plan on that this year, plan on going from 1 to 3 rigs, so we are staffed appropriately. The technical teams and the operation teams can handle that level without adding any headcount here.

Okay. But anything in excess of that might be -- if you did do the kind of ramp you had talked about, it might be in the cards if we see a $55 oil price and you want to run and move to 5 rigs or something.

Yes. If we get beyond this level, there'll be some additional technical staff needed. It's not going to really change the G&A number materially going forward, but you would have some technical adds and some operational staffing as you would need if -- once you get past the low single-digit rig count.

There are no further questions at this time. I'll turn the call back over to the presenters.

Thanks, everyone, for joining us. We're really pleased with this quarter. And we laid out a plan on the fourth quarter call on how we intend to operate and execute 2017. I think we're doing exactly that, probably plus a little bit more. Very pleased with the cash flow we're getting off the Mississippian and the returns we can still generate there. The Northwest STACK continues to improve every quarter from our results and other industry operators, and the North Park Basin is doing better than our expectations, so really pleased with the way we're set up. Combine that with a very, very clean balance sheet, and we think we have a great story for this year and into 2018.

Thank you, operator.

This concludes this morning conference call. You may now disconnect.