SandRidge Energy Inc (SD) 2017 Q2 法說會逐字稿

Good morning. My name is Andrew, and I will be your conference operator today. At this time, I would like to welcome everyone to the Q2 2017 SandRidge Energy Conference Call. (Operator Instructions) Thank you. Justin Lewellen, Director of Investor Relations, you may begin your conference.

Thank you, operator, and welcome, everyone, to our second quarter 2017 conference call. This is Justin Lewellen, Director of Investor Relations 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 is going to make some 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.

We will also make reference to adjusted EBITDA and other non-GAAP financial measures, a reconciliation of which can be found on our website. Finally, you will see us file our 10-Q this coming Monday.

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

Thanks for joining us on the call this morning. We'll walk you through the quarter, highlight some of our momentum building events, such as a very positive drilling agreement in the Northwest STACK, well performance in our 2 main plays, resulting in an increase in production guidance and an improvement on our type curve, a 15% reduction on our lease operating expenses for the year, and finally, review our capital plans and guidance for the remainder of 2017.

Starting on Page 2 of the presentation. Our strategy has remained consistent. We first published this slide in October in 2016, and the strategy and tactics have been durable since then. While protecting our liquidity and unlevered balance sheet and with material cash flow from our Mississippian assets, we are prudently developing our Northwest STACK and North Park Basin assets and growing our resource value. As a result, our percent oil will increase and oil production will turn the corner in the fourth quarter of 2017.

Page 3 summarizes a few of the items from this quarter. We had a moderate level of activity, averaging just under 3 rigs: 2 in the Northwest STACK and in June, picked up 1 rig in the North Park Basin.

In the Northwest STACK, we closed a very impactful $200 million drilling participation agreement, with $100 million initial tranche. We have another strong Meramec extended reach lateral well, the Campbell, with a 30-day IP of over 900 BOE per day and 80% oil. We have 2 other Meramec wells that went to sale as outlined in the earnings release.

Our teams are doing a great job on lease operating expenses. Through reduced chemical and electrical costs, along with some other savings, we realized $8.5 million of actual year-to-date cost savings. We're also reducing full year LOE guidance by 15%, saving $16 million for the full year.

In the Niobrara in North Park Basin, Colorado, we resumed drilling here in June. We've drilled 2 extended reach lateral wells that are undergoing completion, and we'll have well results from those wells in the third quarter.

In the second quarter, the North Park production averaged just under 1,900 barrels of oil per day. That's less than a 2% decline from the Q1 production, with no new wells brought online. We are seeing a flatter early production profile in our Niobrara wells. This yields an improved and higher return type curve that I'll walk through. Also in North Park, we extended our very favorable $3.15 oil differential through all of 2018.

Our liquidity remains very strong, with $145 million of cash and an undrawn $425 million revolver and no net leverage. We have been and will remain very careful with our liquidity, particularly in these volatile markets.

Turning to our assets, and starting with the Northwest STACK on Page 4. This is our Meramec and Osage play in Major, Garfield and Woodward counties of Oklahoma. Here, we have a 70,000 net acre position, and this is within and adjacent to our legacy Mississippian Lime development, where we have drilled over 1,600 horizontal wells.

We started drilling the Osage here in late 2014, with a thesis of lower water content and higher oil cut. On that success, we expanded, then tested the Meramec, and starting in late 2016, initiated a focused Meramec development effort. We like operating in this Northwest STACK due to being well-positioned within a vast, oily, hydrocarbon-rich area of the Anadarko Basin. This is an unconventional play where hydrocarbons are found in multiple zones across a large geographic area. The play has sufficient takeaway capacity, with more under construction. And Meramec drills efficiently and allows for extended laterals to improve development economics.

On Page 5, you can see the continued industry presence. There are currently 20 rigs in these 4 counties from 12 different operators. We have data on about 140 wells here: 100 in the Osage and 40 Meramec wells, and seeing results consistently averaging 700 to 800 BOE per day IP ranges, with oil content around 60% of the Meramec and 40% in the Osage.

In terms of our plans for 2017, we'll spend just over $60 million in drilling completion capital here. We're targeting the Meramec initially. We like the Osage, but we'll drill the Meramec to hold the unit and come back and drill the Osage later. We'll drill the majority of extended reach lateral wells this year and continue to develop and delineate the play. Our XRL well costs are right around $6.6 million, which yields a 23% rate of return and $2.5 million of PV10 at the current strip.

In terms of drilling activity, we are increasing our number of laterals by just over 50% to 34% from 22%. However, due to the structure of the drilling participation agreement, we are decreasing our Mid-Con D&C CapEx by just under 10%, which is a good segue to the drilling agreement outlined on Page 6.

This is an exceptional transaction, and I'm very proud of our team for putting this together.

This sizable investment by a sophisticated investor highlights the value of our acreage and of the Northwest STACK play. This is a $200 million total agreement with $100 million in initial funding. I personally have a lot of experience in these types of capital raises, and this structure is very favorable when you have a large acreage position, like the Northwest STACK, that needs to be delineated and proven through increased drilling. However, I want to manage any outspend while I increase activity in drilling. This allows us to accelerate development of the play and create material resource value, book proved reserves, optimize well designs completions, and advance our learning and holds acreage.

We will invest 10% alongside our investor and receive a 20% working interest. So effectively, 100% carry on our capital. This agreement covers 30 sections, and we'll drill approximately 30 wells in the program. This is a highly flexible structure, and we are the operator and the investor is receiving a working interest in the wellbore only. This is important because SandRidge retains future undrilled PUDs in probable locations.

As we noted in the earnings release, we signed and closed the agreement in late July. And prior to declaring the transaction effective, we sought preclearance from the SEC of certain accounting matters related to the transaction.

Now turning to the Niobrara. I'm on Page 7. Here, we have 125,000 contiguous acre position in the North Park Basin in Jackson County, Colorado. We are targeting the Niobrara at depths between 5,800 feet and 7,500 feet. This is a high-quality asset due to its greater than 80% crude content, a hydrocarbon-rich basin with a thick 480-foot Niobrara and analogous to the DJ Basin to the east. This is a resource play where we have production proven now from 2 benches of the Niobrara, and 2 additional benches look highly prospective. And our 125,000 contiguous acreage block is projected to be 85% held by year-end 2017. We have about 1,300 2P locations. And importantly, well results are exceeding our initial type curve and exhibiting flatter production.

Let's look at our 2016 program that's outlined on Page 8. In 2016, we drilled 11 laterals from February to August, then paused to study results and evaluate our completion methods. We also shot and evaluated 61 miles of 3D seismic. This approach has proven very effective as we zeroed in on the most effective completion technique in targeting. Our last 2 wells in the play are among our best. With our first long lateral, the Castle, and our first C bench test, the Hebron 4-18.

On Page 9 are the results from the 8 of the 11 laterals using our optimized completions. We are ahead of type curve, both on a daily and accumulative basis. The wells are showing a flatter early decline than our initial estimates. In fact, the cum oil production of this program has exceeded the initial type curve by just over 20%, as you can see on the graph on the right.

As a result, we have adjusted the shape of our North Park Basin type curve, which you can see on Page 10. The green line is our current type curve with a flatter decline compared to the gray initial curve. We have the same 760 barrel of oil per day, 90-day IP rate, but flattened the slope of the initial decline. This better matches actual production data.

Note that we didn't change the 513 MBo EUR as we want more production history first. This change in the slope of the curve improved our IRR at the strip by 1,000 basis points and added $1 million in PV10 per well. This improved production and newly approved federal units were among the catalysts for us to increase our activity in the Niobrara.

In terms of our planned 2017 activity, seen on Page 11. We made tremendous progress towards developing and improving our Niobrara asset this year. We'll spend just over $60 million to drill 11 long laterals in 2017. Due to this improved well performance, our first C bench well, that is the best well drilled yet to date in the field, our first very successful extended reach lateral, we're increasing our extended reach laterals drilled by 8 from the 3 planned originally, with well costs of just over $7 million for an XRL. At the strip, this is an IRR of 32% and PV10 of $3.3 million per well. I'm very pleased with our team's progress in advancing this emerging asset of ours.

Turning to our capital allocation and full year guidance on Page 12. With this program, we're accelerating delineation, developing real NAV and positioning us for full field development. We entered 2017 and budgeted cautiously, planning to drill only in the first 9 months of the year in order to pause and evaluate the results before making additional capital decisions. This is similar to our approach in 2016 when we drilled 11 North Park Basin laterals and then took a break to review those results.

In light of some very recent and positive events, we're going to continue drilling through the end of the year. I want to stress that we are very diligent to any change, particularly an increase in our capital program and worked extensively not to increase our outspend.

There's some very impactful near-term items that have improved the landscape of our opportunities. First, in the North Park Basin, we received approval in June from the BLM to form 2 new federal units. These 2 units will hold another 13,000 acres once the initial wells are drilled. Additionally, these 2 wells are step-outs to the East and West of our existing development.

Earlier, I walked you through the performance of the North Park Basin and how that asset is exceeding our initial type curve. Therefore, instead of halting the drilling after the third quarter, we plan to continue to drill extended reach lateral Niobrara wells through the end of 2017. Drilling through year-end will add an additional 8 long laterals to the program and allow us to continue to test other Niobrara benches and spacing.

To support these 2 federal units and 2018 development, we're increasing our infrastructure spend by $11 million. Of this $11 million, just over half is pre-spent for the 2018 program. Here, winter weather and wildlife stipulations dictate that construction needs to occur in the back half of the calendar year. This will consist of central tank batteries, pads and facilities.

I'm still on Page 12. In the Northwest STACK, we are increasing our gross laterals drilled to 34, up from 22. Due to the very beneficial impact of our drilling agreement, with this 55% increase in laterals, we're also reducing our D&C CapEx about $10 million, which you can see in the table.

We're being very dynamic and diligent with our capital allocation. We are further delineating the play, adding real NAV-improved reserves and accelerating our learnings, while at the same time, reducing the capital allocated here.

For workovers, we are decreasing CapEx by $7 million. Our technical teams have done an outstanding job of extending the run time of our artificial lift, and we have been able to further reduce our non-D&C capital. We are adding seismic to the 3D seismic category. This is a 3D chute that we licensed in the Northwest STACK, covering parts of 3 counties there, and will aid in our reservoir understanding and targeting.

On Page 13 is our updated production guidance for the full year. Due to the flatter North Park Basin production profile, we are raising production guidance by 20,000 MBoe, with oil making up half of that increase or 100,000 MBo.

It's worth noting that the additional wells we are adding are largely in the fourth quarter and will be completed into next year. So first production from these wells will fall into early 2018.

All of these opportunities, approval of federal units, improved well performance, performing science through seismic, have led us to the decision to continue our drilling program through the entirety of 2017, ensuring a seamless transition into 2018 as we move to growing oil production and increasing resource value.

One of the most important points of this capital expenditure program, and I hit on it in the earnings release, is that we will not result in a greater level of outspend. With higher EBITDA from rising production guidance and lowering lifting guidance, along with $15 million of noncore asset sales occurring in the first 6 months of 2017, we will maintain the same level of outspend under this revised plan, as in our original guidance.

In closing, we have 2 high-quality plays that we continue to develop, improve and increase their value, the Northwest STACK and North Park Basin, with strong well results, improved type curve, additional zones and further cost reductions. These are both examples of our successful expansion into high-return stacked pay oil assets that are complementary to our skill sets.

Our Mississippian asset continues to generate real cash flow to reinvest in the business. And with over $100 million of cash on our balance sheet, an undrawn revolver and no net leverage, our balance sheet is one of the strongest in the industry. Also, 80% of our oil and natural gas volumes are hedged for the remainder of the year.

The drilling agreement is a validation of our assets in the Northwest STACK and an excellent form of capital as it allows us to accelerate delineation, development and learnings while preserving our financial flexibility. Importantly, this agreement, combined with our financial flexibility, allowed dynamic portfolio allocation and the ability to move capital to the North Park Basin and develop both assets concurrently.

We said in the Q4 2016 call that oil production will grow in the back half of 2017. Oil troughs in the third quarter and then grows in the fourth quarter and into 2018.

Finally, on CapEx. In light of these new opportunities outlined on this call and in our release, we are capitalizing on the higher cash flow and noncore asset sale proceed to increase our budget by $40 million while maintaining the same level of outspend. These tactics exactly follow our stated strategy that I covered on Page 2: preserve the balance sheet while developing our assets in a very prudent manner. Everything we do is about creating resource value for our shareholders, with a focus on creating more [consistent], repeatable and oilier portfolio long term.

Finally, I want to welcome our new Head of Accounting, Mike Johnson, who'll be joining us later this month. We 8-K-ed his arrival yesterday, I believe.

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

(Operator Instructions) Your first question comes from the line of John Aschenbeck with Seaport Global.

I wanted to get your thoughts on just your production trajectory as you exit '17. And James, you've kind of talked about this in the press release and in your prepared remarks. But before last night, if I recall correctly, Q4 '17 was kind of thought to be this point of inflection in terms of getting oil back to growth. It seems like with all the updates from last night, that's even more so the case now. So I was wondering, when you guys look at it internally, if you just simply assume you hold activity approximately steady from where you are right now, what that could mean for oil growth as you look into next year.

Sure. The oil production this quarter was just over 1 million barrels, and we said oil troughs in the third quarter and then turns the corner. So next quarter, you'll see oil down slightly from this 1 million barrels and then turn the corner and grow into the fourth quarter. In terms of 2018, right now we estimate ending the year or averaging the fourth quarter, really, with 2 rigs in the Mid-Continent drilling in Northwest STACK, and 1 rig in the North Park Basin drilling Niobrara. That's where we'll end the year. I'm not sure what 2018 has in store for us. We'll work on that towards the end of the year with our board and come out with 2018 guidance later this year. But right now, we're looking at, for the fourth quarter, 2 rigs in the STACK and 1 in North Park Basin.

Okay. Fair enough. Helpful. And then, I guess, just to kind of turn to the Northwest STACK result. I was maybe hoping you could help us think about how to compare the results, just to the type curve you've laid out there, particularly the Campbell and the Jack Samuel, and really, again, how it just compares to the 800,000 to 1 million barrel EUR type curve that you have laid out there for extended reach laterals.

Yes, this is John Suter. I think the Campbell has started out looking really nice with that 900 Boe per day start. It looks like it should easily be a type curve for an extended lateral. Jack Samuel come on with a little bit lower oil percent on that eastern side of the play, but it also has a little bit flatter characteristic. So we've seen that increase slightly in recent days, but again, don't have as much long-term data there in that area to figure that one out. But we're still encouraged by its flatter oil production upfront, even though the IP was a little bit lower. So we continue to watch that.

Okay, great. That's really helpful. And then in terms of the Adams well that was released in June, I believe. I was just curious to get your thoughts, higher level, really, on those results, particularly as it pertains to the various hydrocarbon phase windows, and that those are kind of evolving as the play gets delineated. And then maybe just -- kind of generally, maybe some lessons learned from that well or any type of information you could share there.

Yes. I think the Adams was -- looked like a pretty strong gas well as it stands right now. We continue to have some completion plans to do some further testing on it, did make a little H2S with it, so we're monitoring that. But we have a large acreage position over there that may cover more than 1 phase window. So we want to see some longer-term results there. We also are very interested in things going around in that area with EOG's DrillCo in some shallower horizons. So we continue to monitor that as well for upside on -- potential upside on that acreage. But we're kind of going to test what we have and sit back and evaluate that area as well. There's other operators in that position.

Your next question comes from the line of Tim Rezvan with Mizuho.

Let's start in Colorado quickly. You talk about target drill and complete costs of about $3.6 million in the play, and back of the envelope math here, around $5.5 million right now. Given the improvement in the type curves, you'll be active here. How aspirational is that $3.6 million? And how do you get there, because that will be an important kicker on well level economics?

Yes, and it's easy to get confused between per lateral and per well and extended reach lateral wells. And what we're really saying is that, it's $3.6 million per lateral, so a little over $7 million for an XRL. So we really think about that $7 million or $7.2 million as the well cost for a Niobrara well. And that yields, at the strip, about a 32% rate of return. That make sense?

Yes, yes, but you talked about $60 million this year for 11 extended reach laterals?

Yes, and some of those will be completed into 2018, as we talked about at the call. A lot of these wells we're adding, we add them in the fourth quarter, so the drilling cost -- sorry, the completion costs will really roll into 2018.

Okay, okay. That's helpful there. And then now that you've gotten this, I guess, partnership in place in the Northwest STACK, does that change your thought on possibly getting a partner into Colorado?

No, it doesn't change our thought. We look at opportunities, whether it's partnerships or capital or funding ourselves all the time, and we'll take advantage of whatever's the best cost of capital and risk adjusted return for us. But no plans to get a partner in Colorado right now. I think we've got plenty to do there for the next year. We're really happy about the deal we got done in the Northwest STACK.

Okay, okay. And then when you did give some color on the infrastructure spend, $18 million, I guess you're building out pads, given that's your window to do so. It doesn't look like there's anything in there on gas processing. You talked a little bit about that last quarter. Are there any updated thoughts on kind of how you would handle gas given the incremental activity?

Yes. I'll let John take this. I think we've got a good update on that.

Yes. So in our midstream, we really view that in a short-, mid- and long-term strategy. James mentioned already that on oil, we've extended that arrangement there to lock that in for 2018. On the gas side, we have executed a contract with a third party to install the mechanical refrigeration unit, to process gas and NGLs. Permitting is underway, and it should be installed in our largest central tank battery, the Big Horn facility, near the end of the first quarter 2018. But just as you know, we also have -- we're currently drilling a utility well where we'll do a gas injection test before ultimately converting it to a disposal well. That well just reached TD this week.

And so we see potential gas injectivity as a parallel path that we can work while we're also seeing the benefits of the MRU that we'll be installing. In the midterm, we can, on a modular basis, add more processing units at central tank batteries as we see the effectiveness of that. We can also drill more injection wells if that's the preferred midterm way to kind of keep up with our development activity while we take a look at the longer-term view of constructing gas pipeline.

We are spending CapEx in 2017 on right of way acquisition, architectural surveys and wetland delineation to be able to get pipe up to Cowdrey, Colorado to start with before ultimately looking at the I-80 corridor. And we're already having some high-level conversations with midstream providers to consider letting a third party take this segment of our development. So hope that gives you a view of how we look at that at short- and long-term perspectives.

And I'll just add that with this single rig or even if you were to add a rig here, that level of activity, you've actually got quite a bit of time and measured in years before you really need to build out any material midstream pipeline infrastructure.

Sure, yes. That makes sense. That's a very comprehensive answer. Just to clarify, you said the permitting is underway for the, I guess, the refreeze unit at your largest battery. Do you feel 1Q '18 is the target?

Yes, I think it's right at the end of the first quarter is when that's scheduled to be operational.

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

Just a question about the pace of drilling with the drilling agreement, sort of a bit macro and micro. Any color you can give on how this should be paced because you have plenty of money to do that? And then micro, I do see in one of your slides here, I think it shows 3 rigs, I know you mentioned going to 2. It would seem that you could sort of drill more with that amount of money, and that's why I'm just trying to get some color on the pace of drilling.

Sure. We spiked up to 3 rigs just for a short period of time as we had just a little overlap here, but really, just by keeping 2 rigs through the end of the year. With the drilling agreement, around 30 wells, the ultimate number will depend on working interest, how many of those are long or short laterals, so the number might move around a little bit. But think of it as 30 wells over kind of 18 to 20 months, and that will take a rig, a rig and a half or so, to drill that. So yes, we could pick up the level of activity more, but we're real cognizant of the outspend. And keep in mind, our contribution here is 10%, so we're exposing $10 million of capital for that DrillCo, and we get 100% carry on that. So I think that -- hope that answered your question.

No, no, that's helpful. And then just sort of a follow-up to some of the other questions in the North Park Niobrara. Just relative to takeaway or gas flaring, is gas flaring, either volumes or permits, is that a constraining factor which would push you to need pipelines earlier? Or could you flare for 18 months to 2 years given what you know now relative to permits?

We can flare for some longer period of time as long as we have the permits in place and a long term -- longer-term development plan. You can't have a plan to just flare or combust indefinitely. But we do have longer-term plans. We're buying options on right of way. We're looking at these MRU units, testing gas injection, all the things that John went through. So we're advancing that. But no, the combusting permits aren't going to impede us in the near term. Now if we wanted to go to 6 rigs next quarter just to pick a book end on it, that might be a constraint, but at this level of activity, it's not a constraint.

(Operator Instructions) Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers.

The press release mentioned the Niobrara B bench test, second half of '17. I was -- just want to confirm, that's also going to be an XRL well? Or is that going to be a shorter length?

Yes, that will be an extended lateral, sure will.

Okay. You also mentioned in the press release some efficiencies and practice changes that significantly reduced your LOE. I was just wondering if you could expand on what's been the most material thing in bringing the LOE down.

You bet. Really, the -- we've had some tremendous success with some electrical initiatives. Also, in the realm of chemicals and from chemical management methodology in the Mid-Con and Permian, been able to reduce rentals, everything from generators to switch to purchase power in the North Park asset to be able to -- as well as being able to reduce our artificial lift compressors as we've switched them from gas lift to rod pump. I think we've already reduced 24 units this year. Also been able to do less workovers, as James has mentioned, by the -- being able to get more run time out of our ESPs and rod pumps. We've reduced that failure rate, I think, from 8% to 4% this year. So making some really good controllable reductions by our operating team.

That sounds like a pretty comprehensive improvement effort. It's impressive. I just wanted to ask 1 final big picture question. I'm kind of thinking out loud. But above all, the DPA strikes me fundamentally as an excellent way for SandRidge to accelerate necessary information gathering on potential sweet spots while reducing risk. And in the North Park Basin, the play is gaining capital because of above expectation well results, which is obviously a big positive. So is this -- you think this is the right way to think about this? Or am I missing something?

No, it's the right way to think about it. Also, we have 2 pretty sizable assets here. So we're very long on opportunities and have a somewhat limited balance sheet. So this allows us, really, to -- I said -- I kind of used the word dynamic capital allocation. So we see North Park Basin improving a little bit, results are flatter, ahead of type curve, returns are higher. We got a lot of permits and opportunities there. Our extended reach lateral wells are working, so let's allocate a little more capital there. But we want to keep going in the Northwest STACK, so let's bring in a drilling partner to keep that activity going. So we're able to concurrently develop 2 plays that have a lot of opportunities with a somewhat limited balance sheet. So it's balancing risk and advancing both of those plays without stretching our balance sheet or importantly, without increasing our outspend.

Right. And I think the reason I characterized it the way I did is we had an earlier question asking about a potential JV in Colorado, but it seemed like, to me, that that's not the place to have a JV because the capital is being attracted organically because of improved well results. Or is the industry still doing a lot of work to delineate the Northwest STACK and why not get that information while spending less money? It sounds like a good deal to me.

Yes, in the Northwest STACK, we said there's 20 rigs running from 12 operators. So in Oklahoma, you do need to keep some pace and level of operations there or you risk lose operators -- losing operatorship is another softer point to that.

There are no further questions at this time. I would now like to turn the call back over to James Bennett.

Thanks, everyone, for joining us, and thanks for the good questions on the call. If people have follow-up questions, just send them in our way. But look, very proud of the progress of our teams all the way from safety to LOE, to operating, to getting our accounting systems in order and getting fresh start accounting done. Very proud of everyone across the board. So the team here has done an excellent job. We'll continue to execute here at SandRidge in the coming quarters, and we'll see you all again on the call in November. Thanks for joining us.

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