SandRidge Energy, Inc. (SD) Q2 2017 Earnings Report, Transcript and Summary

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. 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. 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, 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 Web site 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. We will also make reference to adjusted EBITDA, and other non-GAAP financial measures, a reconciliation of which can be found on our Web site. 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 two main plays resulting in an increase in production guidance, and an improvement in our type curve, a 15% reduction in our lease operating expenses for the year, and finally, review our capital plans and guidance for the remainder of 2017. Starting on page two 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 three summarizes a few of the items from this quarter. We had a moderate level of activity, averaging just under three rigs, two in the Northwest STACK, and in June, picked up one 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 two other Meramec wells that went to sales, as outlines in the earnings release. Our teams are doing a great job on lease operating expenses to reduce 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 two 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, 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 un-drawn $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 Northwest STACK, on page four. This is our Meramec and Osage play in Major, Garfield, and Woodward counties of Oklahoma. Here we had a 70,000 net acre position, and this is within and adjacent to our legacy Mississippian [Lime] [ph] 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 five, you can see the continued industry presence. There are currently 20 rigs in these four counties from 12 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% for 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 PV-10 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 six. 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 operator, and the investor is receiving a working interest in the wellbore only. This is important because SandRidge retains future un-drilled spuds 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 pre-clearance from SEC of certain accounting matters related to the transaction. Now turning to the Niobrara, I'm on page seven. Here, we have a 125,000 contiguous acre position in the North Park Basin in Jackson County, Colorado. We're targeting the Niobrara at depths between 5,800 and 7,500 feet. This is a high-quality asset due to its greater than 80% crude content, the 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 two benches of the Niobrara, and two 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 eight. 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, and this approach has proven very effective as we zeroed in on the most effective completion technique in targeting. Our last two 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 nine are the results from the eight 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 [indiscernible] 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 grey 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 PV-10 per well. This improved production in 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 eight, from the three planned originally. With well costs of just over $7 million per XRL, at the strip, this is an IRR of 32%, and PV-10 of 3.3 million per well. I am 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 nine 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 are 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 two new federal units. These two units will hold another 13,000 acres once the initial wells are drilled. Additionally, these two 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 eight long laterals to the program, and allow us to continue to test other Niobrara benches and spacing. To support these two federal units, and 2018 development, we are increasing our infrastructure spend by $11 million. Of this $11 million, just over half is pre-spend for the 2018 program. Here, winter weather and wildlife stipulations dictate that construction needs to occur in the back half of the calendar year, these will consist of central tank batteries, pads, and facilities. I'm still on page 12, in the Northwest STACK we're 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 loans, 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 shoot that we licensed in the Northwest STACK covering parts of three 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 200,000 MBoe, with oil making up half of that increase, or 100,000 MBO. It's worth noting that the additional wells we're 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 the 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 if we will not result in a greater level of outspend. With our EBITDA from rising production guidance, and lowering lifting guidance, along with $15 million of non-core asset sales occurring in the first six months of 2017, we will maintain the same level of outspend under this revised plan as in our original guidance. In closing, we have two 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, and un-drawn 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 for 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 allow 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 in non-core 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 in page two; 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'd 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. Your line is open.

Hi. Good morning, and thanks for taking my question, and congrats on the nice update here. I wanted to get your thoughts on just your production trajectory as you exit '17. And James, you've kind of talked about his 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? Thanks.

Sure. I you look at the oil production this quarter was just over a million barrels. And we said, well, it troughs in the third quarter, and then turns the corner. So, next quarter you'll see oil down slightly from this 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 two rigs in the Mid-Continent drilling in the Northwest STACK, and one 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, two rigs in the STACK and one in North Park Basin.

Okay, fair enough, it's helpful. And then I guess just kind of turn to the Northwest STACK results. I was maybe hoping you could help us think about how to compare the results. Just getting to the type curve you have laid out there, particularly in 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 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 are still encouraged by its flatter oil production upfront even though the IP was little bit lower. So, we continue to watch that.

Okay. Great, certainly helpful. And then in terms of The Adams well was released in June I believe, 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 generally kind of generally maybe some lessons learnt from that well or any type of information you would share that?

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 one 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 EOGs, DrillCo, in some shallower horizons. So we continue to monitor that as well for upside on -- potential upside on that acreage, but we are kind of test what we have and sit back and evaluate that area as well. There's other operators in that position.

Got it. It's very helpful. That's it from me. Thanks.

Thank you.

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

Hi, good morning folks. Thanks for taking my call. I had -- I can start in Colorado quickly. You talked about target drilling complete cost of about 3.6 million in the play and back of the envelop math here around 5.5 million right now. Given the improvement in the type curves, you will be active here. How aspirational is that 3.6 million and how did you get there, because that will be important kicker on well level economics.

Yes. And it's -- it seems you are confused between per lateral and per well and extended reach lateral wells. What we are really saying is that it's 3.6 million per lateral, so 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 yield is at strip about 32% rate of return. That makes sense?

Okay. Yes, yes. But you talked about 60 million this year for 11 extended reach laterals.

Yes, and some of those will be completed in 2018 as we talked about the call. Lot of these wells were adding. We added in the fourth quarter. So the drilling cost…

Okay.

Sorry, the completion cost will really roll in the 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 gain a partner in the 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 will take advantage of whatever is the best cost of capital and risk adjusted returns 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, well you did give some color on the infrastructure spend 18 million, I guess you are building up pads given that you wanted to do so. It doesn't look like there is 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. He has a very good update on that.

Yes, so in our midstream we really view that in the short, mid, and long term strategy. James mentioned already that an oil lease 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 are 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 TDs 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 will be installing. In the midterm, we can -- on 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 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 the CapEx in 2017 on right away acquisition, architectural surveys, and wetland delineation to be able to get pipe up to [indiscernible] Colorado to start with before ultimately looking that the IED 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 in short and long term perspective.

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

Sure. Yes, that makes sense. That is a very comprehensive answer. Just to clarify, you said the permitting is underway for the -- I guess the [indiscernible] unit at your largest battery. Do you say 1 Q18 is the target?

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

Okay, Okay, that's all I have right now. Thank you.

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

Hey, good morning gentlemen. Nice update.

Thank you.

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

Sure. We -- we spiked up to three rigs just for a short period of time as we had just a little overlap here. But really anticipate keeping two rigs at the end of the year. With the drilling agreement, around 30 wells. Ultimate number will depend on working interest, how many of those are long or short lateral. 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 rig or rig and a half or so to drill that. So yes, we could pick up the level of activity more, but we are cognizant of the outspend. And keep in mind, our contribution here is 10%, so we are exposing 10 million in capital for that DrillCo and we get a 100% carry on that. So I think that -- hope that answered your question.

No, no, that's helpful. I mean then just a sort of follow-up some of the other question in the North Park Niobrara just related to take away gas flaring. Is gas flaring volumes or permits, is that a constraining factor which would push you to new pipelines earlier? Or could you flair for 18 months to 2 years give what you know now relative permits?

We can flare for some longer period of time as long as we have the permits in place and long term -- longer term development plan. You can have a plan to just flair combust indefinitely. But we do have a longer term plans. We are buying options on right away. We are looking at the 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 we wanted to go to the six rigs next quarter just to pick a book end on it that might be a constraint. But this level of activity is not a constraint.

Understood and appreciate it. Thanks for your time.

Thank you.

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

Good morning.

Good morning.

The press release mentioned Niobrara B bench test second half '17. I just wanted 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.

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

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

Yes, that sounds pretty comprehensive improvement effort. It's impressive. I just wanted to ask one final big picture question. I am kind of thinking out loud, but above all this the DPA strikes me fundamentally is 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 oil results which is obviously a big positive. So is this -- do 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 two pretty sizable assets here. So, we are very long run opportunities and have somewhat limited balance sheet. So this allows us really 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 of type curve. Returns are higher. We have got a lot of permits and opportunities there. Our extended reach 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 are able to concurrently develop two plays. We have a lot of opportunities with 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. Yes, and I think the reason I characterized it the way I did is we had an earlier question ask me about a potential JV in Colorado but same looked to me that that's not a place to have a JV because capital is being attracted organically because of an improved well results. Whereas the industry is still doing a lot of work to delineate the northwest stack and why not get that information while spending less money. Sounds like -- sounds good deal for me.

Yes, northwest stack we said there is 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 operator. Losing operatorship is another softer point to that.

Okay, well anyway it looks like a great quarter. Congratulations. And we will see you next week at our conference.

Thank you. Appreciate it.

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 you have follow-up questions, just send them in our way. But 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 across the broad. So, team here has done an excellent job. We'll continue to execute here at Sandridge in the coming quarters and see you all again in the call in November. Thanks for joining us.

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