SandRidge Energy, Inc. (SD) Q1 2017 Earnings Report, Transcript and Summary

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. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [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 statements. 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 we would be short in terms of prepared remarks given we just had our year-end release over a couple of months ago. I will go through some updates and highlights that I am 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 site 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 have been consistent for the last several quarters. With our strong balance sheet and zero net debt we are developing our Northwest STACK assets where we have increased our acreage position across three counties. In the Niobrara Shale of North Park Basin we have updated strong well results to share with you and we will 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 are 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 had 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 are seeing in the Northwest STACK in Oklahoma. Our last reported well there, the Medill in Major County continues to outperform. The well has cumed [ph] 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 into 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 three 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 continued to outperform our type curve. Today we will 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 mid-year. 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 among small cap EMPs. 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 detail 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 two 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, two Meramec and one Osage well. In orange you can see our current activity including one well in Woodward and one in southern major counties that are in early flow back or being completed and our two rigs drilling one in Major and one 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 two 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 1000 barrels of oil equivalent per day. Similarly on page 7, we indicate the Osage results in this area. We drilled three Osage wells in Garfield County in 2014 and 2015 which we under stimulated 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 two 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 three quarters will be long laterals. We're also performing some additional science and geologic work. We recently acquired a 330 square mile 3D. seismic data set in Woodward and Major counties and we will take a call 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 the very strong and consistent production results that are characteristic of an over pressured 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 [ph] 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, tripled 150 barrels a day in the type curve. Similarly on page 11 is our first extended lateral well the Castle with a 9500 foot lateral. Well this well didn't outperform the type curve initially. In the graph to the left you can see the production profile is flatter than our type curve and it's starting to exceed the type curve on a cumulative basis. The well is current making approximately 500 barrels of oil a day and in this case twice to 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-link versus slick water stimulations going forward we will be utilizing crossing stimulations in between 1000 and 1200 pounds of profit per foot. The graph on the right on page 12, we show the eight laterals using cross link stimulation and this well set is performing 20% above type curve. On page 13 in 2017 we're projecting approximately 25 million of drilling complete CAPEX to drill six 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 long lateral which at recent prices generates a 27% rate of return and PV 10 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 back production or held by unit acreage in the basin to 95,000 net acres or 75% held through a process or recently completed 3D seismic shoot in core one of our wells. Also on the midstream gas takeaway we will 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 315 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 the flatter oil production profile and very consistent results. We have established production from two 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 Northwest STACK, our Meramec wells, and industry wells continued 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 one to two rigs. The Northwest STACK is an example of us expanding our resource base into a high return oilier 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 from multiple benches. The high-graded harvest of the Mississippian 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 focused oil cut will increase to 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 hedge 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 to value creation with a focus on creating a more consistent repeatable and oilier portfolio long-term. With that we will 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. Your line is open.

Hey, good morning folks, thank you for taking my call. First, my first area of focus on the unit expense results in the first quarter. You added a couple different items that we are going to see in 2017 with a decline in production base, so you had 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 you expected this year?

Yeah, this is John Suter. You know 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 cost as well with the numbers that you saw. But it is a mass thing like you said with declining production over the year, we would expect unit operating cost to increase but feel comfortable with our guidance at this point.

Okay, thanks. This is what I thought. If I could change topics, moving on to slide 8 where you showed the 2016 Niobrara results, they were fairly tightly clustered the wells there. I know there is 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 mention we have six laterals with three wells planned. We'll be drilling if you're looking at page 8 there to the Southwest stepping out several miles there and that Rabbit Ears federal unit. We will also be drilling some wells if you look at the map again kind 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 four to eight or more wells per section there. We are talking about a lot of wells but we'll be stepping out a bit this year in delineating the field, would you want to be mindful of our 3D seismic shoot that we just took and we are processing so we'll be shooting underneath that. We take another 3D shoot this year to continue to advance our geologic understanding of the play.

Okay, thank you, and if I could sneak one more in and then I will hop back in the queue. You mentioned that 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 paid for those leases?

If you look at our guidance we have about $40 million land in seismic budget and we spent about 15 million of that through the first quarter. So yeah, I think we'll be adding more to this position particularly in 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 two and three years ago we do have two 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 two more years, it's about $850 an acre.

Okay, I’ll hop back in the queue. Thank you.

Thank You.

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

Hey guys, good morning, great update. 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 a County of focus and then just really desire to potentially take the acreage position to a much bigger number than where you are now? Thanks.

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. We’ve seen the activity pickup quite a bit the last several quarters, lease rates have increased pulling bonuses which you can look those up, those have increased. Major County is very competitive so is Woodward and Garfield, Dewey and Blaine. So these all areas 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. Since I'm paying too high a 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 have their positions established and they we'll go into more development mode.

Good, appreciate that. And then the Medill rate is obviously very impressive. I just wanted to get your thoughts on is this attributable to you guys going after some of your best rock here or maybe southern portion of your basin or your position and just how repeatable are the deal type results as you go further North or the West in your opinion? Thanks.

Sure, this was our first well there in Major County. It was only a single mile lateral going forward to us and then you'll see a lot other operators drill two mile laterals. I think that's really key in the Meramec that you can put together a 1280 drilling unit and very efficiently drill a two mile lateral which is just a little more challenging the Osage. But look our team and geologist engineers liked this area, picked up for the first well. I don't know if that's representative of the entire area. We have several Meramec wells, we have our eyes on, so wouldn't say that this is the best area in the play but again it was only two mile lateral and stimulated with about, what John 1200 pounds per foot in stimulation. You have anything else to add to that.

No, I think we are really excited about Major County, the Medill has been a fantastic well. But as James says 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 two.

Okay, great. Well, I will sneak one more in too, Tim did it. So, if the Medill rates prove repeatable to drill 22 wells this year everything would succeed in the type curve or are going that direction. James, how aggressive do you think you could be in terms of the activity level moving into 2018, would you feel comfortable taking that that two rig count? Thanks.

You're welcome, it's a reasonable question. The Medill is if you look at the math it's almost exactly two times our type curve so you can look at some returns in the type curve and do your math and that gives a very, very high rate of return. It is going to depend on a couple things which will drive that quite a bit. Obviously you missed the well performance but also commodity price is going to be a big one. We have got an oil in the 40's 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 hedge but we like to look at these on a standalone basis and what kind of return can they generate. Service cost so we will keep an eye on, something it depends on any service cost inflation. 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.

Great, thank you. Look forward to seeing you next week.

Thank you.

Your next question comes from the line of David Beard with Coker and Palmer. Your line is open.

Thank you gentlemen and good morning. Maybe talk a little bit about the competition for capital between the two basins and I'm probably more interested in what are the levers that could change overtime to cause you to see rate of one to the other obviously as these basins develop you could see things which could shift the activity one way or the other?

Sure, on the, you know, really talking about the Northwest STACK in the Niobrara and North Park Basin here don't have a lot of capital going to the Mississippian right now but we could always pick that back up at any time given it is largely held and we have over 200 locations that we can drill. But really between the Northwest STACK and the Niobrara, you know, the Northwest STACK being in Oklahoma 20 rigs active in the area, it is a very competitive area, there is forced pooling you have to be careful of. So if you are 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. So we've got about 117 wells in that data set that we keep an eye on that 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 and North Park Basin it's really predominately 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 -- and there we are being -- making sure we have the right knowledge before we go too fast there. We're drilling some multiple benches, we're testing spacing, we're shooting some 3D. I will expect to get more results from that this year with the six laterals we're drilling. So between the two it's going to be a balance of, the first is going to be risk adjusted rates of return, second it is going to be what 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 is going to be 75% held by production held by unit. And in our Northwest STACK we are about 33% held by production. So that also tempers the pace at which you go in either one which ones more HBP. I hope that -- I think that answers your question, does it.

Yeah, no that was helpful and maybe just a follow on that. It seems that maybe this is too simplistic but if you could solve the gas and 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 in high oil cuts, is that relatively accurate over time or is it too simplistic?

That might be of a little simplistic. I completely understand the comment and concern is something we talk about a lot. You can see we talked about it in the earnings release and 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 some of these things that we're pursuing can delay and maybe someday completely differ the need for a pipeline. We'll see, we're trucking the oil right now at a great differential of 315 per barrel differential, the WTI and we have that agreement through the end of 2018. So getting the oil out is not a concern either. So 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 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 with some of these projects we’re considering.

Great, that's very helpful and appreciate all the color.

You're welcome.

[Operator Instructions]. Your next question comes from Jeffrey Campbell with Tuohy Brothers. Your line is open.

Good morning and I second the compliments on the illustrations today. It's very good color. I just want to make sure that I have kind of pulled this North Park thing together. It sounds like you're going to drill one well each in the B, C, and 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 the well controlled to indicate that IOA or maybe the frontier would be a future target for exploration?

Yeah, good question on the B, C, and the D. That’s correct, we plan to drill one in each zone this year and they will all be extended laterals. On the full development it's going to depend on as we mentioned commodity price. Service costs here been a lot more stable than they have been in the mid continents so that's not as much of a concern. But we're going to drill these three other zones and 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're be looking almost a year of production. So we'll make that determination at year-end between those initiatives from the flow back from the existing wells some of these 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 plain again. It could be mostly dependent on commodity price.

I would say to the rest of your question the core we plan on taking. Later this year we'll check out all 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.

Okay, that's fine, thank you. 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 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 a 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 like 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 SandRidge actually has the ultimate say so as 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 are some protective rights you would expect the trust to have. We have to operate the wells using a proven operator standard. Again there's a halo around the wells in terms of offset drilling. But it is completely our decision on how we develop that asset in and around the trust.

Okay, great. Thanks, appreciate it.

Your next question comes from Tim Rezvan with Mizuho. Your line is open.

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

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

Okay, but anything is excess of that might -- if you did do the kind of ramp that you had talked about it might be in the cards if we see $55 oil price and you want to run -- move to fiber or something?

Yes, if we get beyond this level there will 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 ads and some operational staffing as you would need it once you get past the low single-digit rig count.

Okay, thanks.

You’re welcome.

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. We laid out a plan on the fourth quarter call on how we tend 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 in 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’s conference call. You may now disconnect.