SandRidge Energy, Inc. (SD) Q3 2017 Earnings Report, Transcript and Summary

Good morning. My name is Marcella, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Third Quarter 2017 SandRidge Energy Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there'll 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 third quarter 2017 conference call. 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. Both James and John are 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 tomorrow morning. Now, let me turn the call over to James.

Good morning. I'll be referencing the earnings presentation that we posted on our Web site this morning. And I'd like to start with a high-level look that's on page three. We first came out with slide in October of 2016 to outline our strategy for creating value. Importantly, this strategy and the tactics on how we executed have remained durable during the last year, and we'll continue those into 2018. Starting with our balance sheet on the left, we have zero net debt, $100 million of cash, and a fully undrawn $425 million revolver. We'll continue to protect the strong balance sheet as evidenced by the moderate level of outspend we have in 2017. We have two very competitive oil-weighted plays in the Meramec and Osage in the Northwest STACK, and the Niobrara in North Park Basin. John now will talk about how we're delineating the plays, both vertically and horizontally, and we believe creating real resource value that will ultimately be reflected in our enterprise value. Also, the drilling participation agreement augments our drilling program, and allows us to develop the Northwest STACK, while allocating capital to North Park Basin, and back to my first bullet, on a strong balance sheet, preserving our liquidity and low leverage. To the right of the page, the Mississippian assets continue to generate material free cash flow. Our Ops team has further reduced LOE in the Mid-Continent, which is the main source of the LOE improvements that John will discuss further. Page four contains bullet points that highlight the quarter. But moving on to page five, at the top of the page we have our objectives for the two main assets we're developing, Northwest STACK and the North Park Basin. We've made real advances in both assets this quarter and year-to-date. First, in the Northwest STACK, we've now drilled and produced the Meramec and Osage in true STACK pay configuration within a 60 acre section. This confirms that we have STACK formations that can be developed on the same vertical plane. Adding more resource and PUD locations is also an objective. At the end of 2016, we had under 10 PUDs in play. And while our 2017 reserve report won't be complete until early next year, with our drilling of about 20 Meramec wells this year we expect material reserve bookings on this asset. In the third quarter, we closed our drilling participation agreement. In the earnings release we outlined the major terms of this agreement. This $100 million initial funding significantly enhances our returns, and given the carry structure allows us to continue to develop and delineate the asset, book reserves all with minimal CapEx. Based on our results as well as those of other operators in the area, we're seeing 30-day IP ranges for extended laterals of between 600 and 800 barrels of oil equivalent per day at about 65% oil, with EURs of 800,000 to a million barrels of oil equivalent. If you combine that with our well cost, in the $6.5 million range, we're generating a 25% rate of return on these wells, and that's before taking into account our carry from the drilling agreement. We've also expanded our HBP position in the Northwest STACK to just over 40%, up from 30% at the beginning of the year. In total, we've made material progress advancing this asset in 2017, and look forward to more well results in the fourth quarter. Turning to the North Park Basin objective on the right side of the page, we commenced drilling here at the end of the second quarter. This program is expanding the resource in North Park Basin. In the Niobrara we have now confirmed production from all four benches. If you recall, in 2016, we drilled primarily the D and the C benches, and now we've confirmed production from the more shallow A and B benches, additional wine rack spacing test in Q4 2017, and into 2018 will also confirm additional production. We'll be stepping out in Q4, and join three federal unit wells that will hold another 37,000 acres, brining our total held by production and held by unit to over 85%. Our teams have delivered some exceptional production and cost performance which has improved our Niobrara capital efficiency and returns. On the cost side we're now pad drilling two-mile laterals for $6.7 million, this is down from $7.2 million. This cost improvement adds 8% to our rate of return and $500,000 in PV-10 for each well. Also, earlier this year we updated our type curve to reflect improved early well oil life production. This increased our returns by 15%, and added $1 million in PV-10 per well. In fact, you can see the performance of the 11 laterals versus the improved type curve on page 13 in the appendix of the presentation. Based on all this, our 513 MBO type curve and $6.7 million well cost yields and IRR of about 45% on our Niobrara wells. In terms of 2017 guidance, we're reaffirming our production guidance range for the full-year, which you can find on page 14 of the appendix. The third quarter represents a low point in oil production as our program is end-of-the-year weighted, and oil will start to turn the corner and grow in the fourth quarter. You hear me talk a lot about oil growth and not 6:1 BOE growth, that's because it's oil that provides the cash flow growth and value generation for SandRidge. On the cost side, we continue to make cost improvements and are reducing the guidance ranges for both LOE and G&A. The combination of these lowers our cash cost by $7 million at the midpoint of guidance. In our 10-Q, you will see that we've closed year-to-date non-core asset sales of $20 million. We often get the question, what is your outspend in 2017. I think one good way to calculate it is something like this, if you take consensus EBITDA of about $180 million less $255 million in CapEx at the midpoint, back out $2 million in net interest expense, and add back $20 million in asset sales that gets you right at a $60 million outspend. Your call in February, I said our outspend would be in the $60 million to $70 million for the range, and I believe we'll be at the low end of that range. Now, let me turn the call over to John Suter to give us an operational update. John?

Thank you, James. I'm planning to walk you through our production results, Mid-Con developments, North Park Basin well, and economic highlights, LOE guidance reduction detail, and finally our CapEx results for the quarter. Production for the quarter was 3.6 million barrels oil equivalent, comprised of 27% oil, 23% NGLs, and 50% natural gas. Consistent with the midyear rig addition in North Park and continuation of our Mid-Con two-rig development activity, we're anticipating a heavy fourth quarter production delivery schedule. We have six Northwest STACK wells in various stages of flowback that will bolster our current rates. Two North Park completions are flow testing, and two more are coming online as they complete frac operations. Mid-Con production in the third quarter was 36,000 barrels oil equivalent per day, comprised of 22% oil, 24% NGLs, and 54% natural gas. We continued our focus on Meramec drilling in the Northwest STACK delivering seven SRLs and two XRLs. With two rigs running in the third quarter, we achieved two significant strategic accomplishments. You'll notice on slide six, we drilled Audra Claire 1-24H, a Meramec SRL, which produced a 30-day IP of 397 BEO per day, 88% oil. It was directly above an existing Osage horizontal. This well confirms vertical spacing, and supports multiple zone development within the same section. Second, we drilled our first Dewey County SRL, the Regina 1-18H, which produced a 30-day IP of 598 BOE per day at 71% oil. The Regina confirms the expansion potential outside of our primary Northwest STACK development area in Major, Woodward, and Garfield counties. Now, shifting to North Park, our production in the basin was approximately 1,400 BOE per day in Q3. With one rig deployed we've achieved numerous objectives, including additional bench testing, cost reductions from pad drilling, and wine rack spacing tests, all which add value as we head towards full-field development. We drilled a pair of long laterals on the north side of our play, the Grizzly 2-1H36 and the Grizzly 4. They provided the fastest XRL cycle time in the North Park Basin to date, with an average of 12 days from spud to rig release. Both brought the sales in the late third quarter. Currently they're flow testing and preparing for artificial lift installation in the next two weeks. On slide seven, you'll see we now have successfully produced from all four possible Niobrara benches. As the diagram shows, all wells prior to 2017 produced only from the C and the D, while the Grizzly 2 and 4 established oil production from the remaining A and B benches. Further confirmation is expected with the results from an additional B bench test in Q4. This implied value of this achievement is significant. Since we really only had C and D locations in our inventory, future A and B wells could add significant value. We spud four Castle wells from the same pad in Q3. As you can see on slide eight, we've identified numerous operational efficiencies that have provided cost improvements related to multi-well pad operations for this asset. Reduced cycle times in addition to utilization of skid rig moves, zipper fracking and shared facilities have lowered our XRL cost to 6.7 million using pad drilling. We are planning for a higher percentage of pad drilled wells in 2018. As seen on slide nine, with our Wine rack test utilizing the same set of wells will test vertical bench to bench spacing. In 2018, we plan to test 80 acre horizontal spacing within the same bench. Oil in place calculations from our two courses will support this spacing evaluation work. As we work on our long-term plan, all of the previously mentioned tests will quantify the total resource potential and will generate capital efficiencies in our development program. By knowing the bench count by area, how the benches interact vertically and the optimal bench -- our per bench well spacing, we'll know the well count for section to develop. If you will reference Slide 8 again, the cost reduction chart on the left and the corresponding return graph on the right show our current 6.7 million well cost delivers 47% IRR. Additional efficiencies in progress show past to 6.45 million which improves the return to over 50%. You may recall that in the second quarter earnings release, we reduced our annual LOE guidance by 15% from a midpoint of 850, down to 725. As James mentioned, we are now decreasing the midpoint to $7.08. In the first nine months of 2017, we realized an impressive $28 million reduction in lease operating spend that's attributable to sustainable operational improvements in our Mid-Continent assets. A few of the primary cost reduction initiates include a $6 million reduction in electrical cost by streamlining our maintenance operations and employing more efficient artificial lift design. Our [indiscernible] exception program facilitated by our manned operation center contributed to a $4 million reduction. Artificial lift design improvements led to longer runtimes and a $5 million reduction in related work over and rental expenses. Finally, we've implemented a more proactive chemical management program which led to $2 million savings compared to the first three quarters of last year. Finally, capital expenditures for the quarter were 71 million with drilling and completion cost equally spread between Northwest STACK and North Park Basin. We are current drilling the first wells in the Northwest STACK under the drilling participation agreement James outlined previously. In the fourth quarter, we are planning to run one to two rigs under the agreement drill four SRLs and two XRLs in the Meramec with approximately 15 million in capital expenditures. The remainder of our drilling and completion budget will be focused on developing our assets in North Park Basin. So I am very pleased with the team's performance this quarter. In the North Park Basin, they were able to deliver 500,000 well cost reduction confirmed both A and B Niobrara bench production and progress in exciting Wine rack spacing test. In the Northwest STACK, our team continued delineation with Virginia well in Dewey County and the STACKed pay test for The Audra Claire. Above all, we continued our excellent safety record. I'll now turn the call back over to the James for some closing remarks.

Thank you. Closing the year and looking forward to 2018 to release full-year 2018 guidance in the upcoming first quarter. Right now, we estimate maintaining a similar activity level into 2018, which would be approximately two rigs in Northwest STACK and one in the North Park Basin. Moving on to fourth quarter, the closing of the drilling participation agreement allows simultaneous development of both assets while minimizing capital spending and will allow us to advance drilling and completion costs and innovations, further delineate both plays, finalize our spacing tests, all while maintaining a moderate level of outspend and protecting our balance sheet. On commodity prices, for budgeting and economics we're using $50 crude and $3 natural gas, which approximates strip prices. We remain very cognizant of commodity behavior, and will be nimble, and adjust our plan, spending, and activity level as needed. In terms of hedging, we have 2.4 million barrels of oil swapped at just under $55 a barrel, and natural gas swaps of 17 BcF at approximately $3.15. Look for us to continue to hedge in the mid-50s for 2018 and beyond. In fact, last week we took advantage of some strength in the market, and added 2018 oil swaps at $53. Closing out with reviewing how we've advanced the business and our assets in 2017. We've maintained our strong balance sheet, liquidity, and no leverage. We expanded from our existing Mississippian-only potion into the Northwest STACK where we now have 70,000 acres, completed a true vertical STACK pay Meramec Osage test, and closed a very impactful drilling participation agreement. In the North Park basin we have now confirmed production from all four Niobrara benches. We outperformed our type curve, and further reduced our well costs. And the Mississippian continues to generate material free cash flow for the enterprise. Look for us to maintain this disciplined focus on returns, execution, and continued cost reduction with every decision being made answer the question, how does it create value for the enterprise. Operator, we'll now turn it over for questions.

[Operator Instructions] Your first question comes from the line of James Lazool [ph]. Your line is open.

Good morning, and thanks for taking my question. Just wanted to clarify your comments on oil becoming a larger portion of production, how can we think about this trend in the fourth quarter given the increasing activity in Colorado?

Sure, if you look at the third quarter, oil production was about 10,400 barrels per day, little rounding. That's third quarter actual. If you take the midpoint of guidance, that's gets you to about 11,600 barrels a day. So we're on that trajectory. And we've said for a long time that oil turns a corner at the end of this year, and it is this quarter. So we've got the two Grizzly wells coming online, and then the two more Castle wells, that John mentioned, will also be coming online in the fourth quarter. So that really contributes quite a bit to the oil turn in the quarter, that and a set of Mid-Con wells that are coming online right now.

Great, thanks. And then related, had LOE increase a bit in 3Q. The midpoint of the updated guidance for the year suggests it could trend even higher in the fourth quarter, and that's not necessarily surprising given your oilier production, but how can we think about that trending in 2018?

We've got a little bit on a BOE basis; we still have a little gas decline. So while we're focused on oil and cash flow growth, we're still seeing a total BOE production decline. So that will have some of your fixed costs in your LOE costs on a BOE basis to increase slightly. But if you look at this year, we've taken LOE guidance down twice and continue to improve it. So not ready to give multiyear LOE outlook yet, but looking into next year I would consider it to be similar to where we're going to end this year.

Great. And then just one more, I noticed your 2018 hedges are all in swaps. Do you have any idea how much you're looking to hedge in 2018? And are you planning to add any flexibility into that hedging program with two-way or three-way collars?

We have flexibility in the program to do all of those. We've done three-way collars in the past. And when we looked ahead we look at all those alternatives. For us, lately, with the volatility and the market swaps have been the most cost effective for us, but we've used all those method before. And previously, we've hedged quite a bit of our production for the current year, for the upcoming 12 months pick it [ph] on the crude side, given that's where most of our cash flows, and then lesser percentage in years two, and even a little bit in years three. So I don't want to give you the exact percentage, but look for us to continue to hedge particularly the first 12 and 24 months of production.

Thanks a lot. That's it for me.

Your next question comes from the line of John [indiscernible]. Your line is open.

Thanks. Good morning, and thanks for taking my questions. Following up on the oil growth question, as you look into 2018, if you do indeed hold this level of activity constant, just two rigs in the Northwest STACK one in the Niobrara, was wondering what well growth could look like for next year? I'm not necessarily looking for a hard number, don't want to pin you to anything, but was wondering if you could maybe kind of bookend what the implications could be or just any type of color you could provide on the oil growth for next year. Thanks.

Yes, I understood the question. Appreciate you're not looking for a hard number. But there's really no other numbers besides hard numbers because they don't tend to be very soft. So we'll probably wait till we come out will full-year guidance early in the fourth quarter, because it's really going to depend on how long we maintain those rigs, do we keep them all three going for the entire year or not, do we do one-and-a-half or two rigs in the Mid-Con. So give us till the first quarter until we come out with full-year guidance to answer that little question specifically.

Okay, that's fair enough. Appreciate it. And then my final one was on Northwest STACK, was just wondering when we should expect timing of additional tests. You have the 20 wells schedules for this year, and the two rigs running right now. But obviously there's a lag in time between drilling the wells and putting them online, and then you have to wait for them to peak. So was just wondering if we should expect a bigger set of results here in the near-future? And then also on the timing of those results, whether you wait for the Q4 update early next year or do you potentially have enough results coming here in the near future where it would warrant an intra-quarter update?

Yes, we have, as I mentioned in my discussion, there's six wells coming on in Mid-Con right now. So we should have a much stronger set, more numbers to talk about in our Q4 results. So I suspect we'll be waiting to that call to discuss those.

Yes, we usually don't give out interim quarter well results, and you just hold those for the end of the quarter.

Okay. That's it for me. Appreciate it. Thanks.

Thank you.

[Operator Instructions] Your next question comes from the line of Amir [indiscernible]. Your line is open.

Thank you. My first question is around the Northwest STACK. What are the milestones for the additional funding to coming in, and when is it expected to come in from your joint venture?

Sure. I think you're referring to the drilling participation agreement. So we closed that in July. We've already started drilling wells under that agreement. And I believe we're at well number three, is that right guys? We're in the third well now. And we've received our initial GIAB [ph] funding from that. So that will continue to fund for the next 18 to 20 months as we roll out the program. It calls for drilling about -- we anticipate about 25 wells under the program. So it'll continue to fund every month. It's not a lump sum. It doesn't fund all at once at the beginning or the end, it funds 90% of the cost as the wells are drilled. And there are no milestones to think about.

Understood. And on page 11, you guys give industry averages for these wells. Can you give us some sense of where your average has come in for these as well?

Yes. So you look at the table in the bottom-right. So our averages are very close to those, right in line with those. We've got some outliers on either side as we step out and delineate the plays to the east and the west. Our acreage is over 100 miles east to west, so as we stepped out and delineated we've had some lower results on the edges of the play. But our averages are right within those same range, 400 to 500 BOE for a single, and 600 to 800 for an extended lateral.

Understood. And my last question is regarding, again, trying to get a sense of when can we expect the overall production to trough from a companywide perspective, is there in your mind a rough timeframe for that. I know you've talked about oil, but what about the overall company?

Yes, honestly I don't think about total BOE growth. I mean, I'm focused on cash flow growth, and growing our cash flow, and closing any outspend. So I'm not ready to say here's exactly when our total BOEs will trough. It really depends on what we spend next year. Kind of gets back to the other question, you know, what's your oil production going to look like next year, really gets back to the spending. So, we need to finalize our budget for 2018, get that approved and roll that out in the first quarter, but again, get me to the first quarter, so we come out with 2018 budget and then we can tell you what oil production looks like and further what total BOE production looks like.

Thank you very much.

There are no further questions at this time. I'll now turn the call over to James Bennett.

Thanks everyone for joining. We appreciate you listening. We will be back on again in the fourth quarter. I think we'll have as John mentioned, a lot more results, well results in the Mid-Continent and in the North Park Basin. Thank you for your interest, and give us a call with any further questions.

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