SandRidge Energy Inc (SD) 2014 Q1 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the first-quarter 2014 SandRidge Energy earnings conference call. My name is Glen, and I will be your moderator for today.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Mr. Duane Grubert. Please proceed, sir.

Thank you. Welcome, everyone. Thank you for joining us on our conference call. This is Duane Grubert, Executive Vice President of Investor Relations and Strategy. With me today are James Bennett, our President and Chief Executive Officer; Eddie Leblanc, Executive Vice President and Chief Financial Officer; and David Lawler, our Executive Vice President and Chief Operating Officer.

We would like to remind you that in conjunction with our earnings release and conference call, we have posted slides on our website in the Investor Relations section. Keep in mind that today's call contains forward-looking statements and assumptions subject to risk and uncertainties, 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, and other non-GAAP financial measures. A reconciliation of the discussion of these measures can be found on the website. Please note that this call is intended to discuss SandRidge Energy and not our public royalty trust.

So now, let me turn the call over to our CEO, James Bennett.

Thank you, Duane. Let me kick off by recapping the first quarter, some of the accomplishments we've made in developing our asset base, and how all of that positions us to continue to execute our three-year plan.

In February, we closed the divestiture of the Gulf of Mexico assets. Now our focus is completely on the Mid-Continent: Oklahoma, Kansas, and Permian Basin. We want to operate and focus our people and our capital where we have real competitive advantages, such as our acreage position and scale, the knowledge base of our teams, and well set of over 1,200 horizontal wells, having the lowest well cost in the basin, and our extensive infrastructure.

On this, our Mid-Continent asset base continues to perform. With severe winter weather, which Dave will review in more detail, slowed our production and well completions in drilling, but now the program's back on track thanks to the great work of our operational teams. Notwithstanding the weather challenges, we managed to deliver an excellent quarter, with a well set containing the second-highest ever 30-day IP, which is over 400 BOE per day, and most ever, seven wells over 1,000 BOE per day 30-day IP.

Next, we continue to improve and add to our opportunity set, with Northern Garfield being an example of this. Thanks to the great work of our geology and engineering teams, we set up an appraisal well test program in this area. After this successful 11-well appraisal program, we have now launched a full development effort here, and added Northern Garfield into our focus area.

I like what this area brings to our asset mix, as we are seeing more consistent results and our tighter distribution around our IP rates, higher oil percentage, and a lower water cut. Also, in this area we've identified additional stacked pay opportunities. So adding these 10 townships increases our asset base, scope of the play, and our opportunity set by adding another area of high rate, high return oil wells.

Recall that earlier this year we also added Sumner County to our focus area, and that area continues to perform, with high oil content and IP rates above our type curve. We continue to develop our multiple zones in the Mid-Continent. In addition to the Upper Miss, we're having success in the Middle and Lower Miss, and Dave will talk about our Chester and Woodford programs.

Next, we continue to innovate in the play. An example of this is our multilateral well program. At Analyst Day two months ago, we showed you examples of our multilateral and stacked lateral prototypes. While still in testing, these programs are taking hold and have delivered excellent results here, both in terms of cost and production rates.

We highlighted one in the earnings release, a Kansas stacked lateral we have, doing over 700 barrels of oil equivalent per day. On the cost side of these multilaterals, by lowering the effective well cost to about $2.5 million per lateral, this program has the potential to make already good areas of play even better, and importantly, allow us to access other zones that otherwise would deliver lesser returns at a single well design with a standard $3 million well cost.

On another matter, we continue to develop our midstream saltwater disposal business and explore alternatives for that business. In the quarter we added another third-party producer to the system. We also filed a private letter ruling with the IRS, and are proceeding with an audit of the financial statements of that entity.

So tying these together, our asset continues to perform, and we deliver better results every quarter. We're expanding our opportunity set and growing our net asset value by adding both geography to the play, as well as exploiting our other zones. We continue to bring innovative solutions to bear on our asset base, such as our multilateral program.

We are funded with almost $2 billion of liquidity and growing cash flows. We laid out a three-year plan that we're still confident in, in our ability to deliver 20% to 25% compound annual growth in production and a higher growth in EBITDA and cash flow over three years.

Recall that we rolled out a mission statement in Q1 of this year, which was to create the premier high return growth-oriented resource conversion company focused in the Mid-Continent. Our teams remain intensely focused on this and the themes we outlined at our March Analyst Day needed to execute this mission. We believe this mission will provide returns for our shareholders.

First and most importantly, we need to continue to deliver profitable growth in cash flows by converting our resource base into cash and asset value. We need to capitalize on our competitive advantages here in the Mid-Continent. We need to continue to drive innovation in the business and create more upside; continue to improve our per unit cost in all areas, well cost, LOE, and G&A; improve our leverage and balance sheet in getting closer to funding CapEx within cash flow; and driving shareholder returns. Our job as managers is to allocate capital in the highest risk-adjusted returns, and we come to work every day thinking about that point.

Finally, I want to thank our employees both here in Oklahoma City and out in the field for their excellent work, dedication to safety and to our mission, and commitment to delivering returns for our shareholders.

With that, let me turn the call over to Dave Lawler.

Thank you, James. Good morning to everyone joining us on the call. During the first quarter we made significant progress on our value-enhancement themes. We improved well performance, expanded the resource base, increased capital efficiency with novel well designs, and enhanced the value of our existing well set with the latest artificial lift technology. All of these initiatives directly support our three-year plan, and I'll provide greater detail on each just a minute.

The first quarter also included a number of challenges related to extreme weather in the Mid-Continent region. This was the 12th coldest winter on record, and the prolonged freezing temperatures created disruptions in our development program. As a result, our Mississippian production averaged 50.6 MBoe per day, which was 2% lower than in the fourth quarter of 2013. This decline is linked to weather, and represents a deferment of 300,000 BOE.

To give you a better feel for the impact on our efficiency, we connected only 71 wells versus the planned number of 94. In addition, the vast majority of these connects occurred late in the quarter, so the primary production benefit will be realized in Q2.

In spite of the weather challenges, our teams responded quickly and connected 45 wells in April. The production from these wells has put us back on track with our production targets, so we've elected to leave full-year production guidance unchanged. To recover the deferred volume, we are accelerating key projects across the play, and we believe these actions will allow us to make up the production in the coming months.

In terms of CapEx for the quarter, weather also slowed our expenditure rate, and correlates with the decrease in production. Approximately $25 million was deferred, but we anticipate the majority of this amount will be spent in Q2 and Q3 as we get caught up on our well delivery program.

For the 71 wells delivered to sales, the average cost was approximately $3 million. This cost includes 56 days of weather-related rig downtime. In many cases, the downtime was due to county-ordered moratoriums on heavy-load permits or lost time to thaw equipment. It also includes an ESP implementation rate of 97%.

We anticipate that our average well cost will be under $3 million in the next few quarters as we improve efficiency and drill more second and third wells for multi-well pads. For reference, 20% of our Q1 wells were on single pads and 80% were drilled from multi-well pads.

Moving onto well performance. Our Mid-Continent 30-day IPs averaged 410 BOE per day, or 29% above type curve. This increase is primarily due to our subsurface modeling efforts and the use of open-hole packer systems in our completion operations. We also delivered seven wells with 30-day IPs over 1,000 BOE per day. This is the largest number of high-rate wells in a single quarter since the inception of the play.

One of the seven wells was drilled using 3D seismic, and was positioned near several uneconomic wells. The seismic identified a subtle structural feature, and it has now allowed us to map additional targets in multiple sections surrounding the discovery. It's also important to note that this group of high-rate wells are spread across the play, located in Alfalfa and Woods County in Oklahoma and Hartford County, Kansas.

Beyond improved well performance, we've made significant progress on the value enhancement themes we've presented at Analyst Day. As with Sumner County last year, we've been testing various geologic concepts in Northern Garfield and Southern Grant, with the intent of expanding our resource base and adding high quality drilling inventory. This appraisal program has been highly successful.

During the first quarter, our team drilled 11 test wells, primarily in Northern Garfield, which delivered an average 30-day IP of 406 BOE per day, or 28% above type curve. The oil content on these wells was 55%, and helped deliver an aggregate rate of return of 66% with an average well cost of $3.1 million.

We are confident that we can decrease this initial cost as we continue to develop our learning curve in the area and implement multi-lateral and pad drilling initiatives. With this appraisal success in Garfield, we are adding 10 townships to our focus area and nearly 40,000 net acres for near-term development.

Further to the north, we continue to see success in the Sumner County project area. Four laterals were brought online during the quarter with an average 30-day IP of 353 BOE per day, or 11% above type curve. While these wells didn't contain high gas volumes, the oil content was impressive.

Of the 353 BOE per day, the oil content was 67%, or 236 barrels per day. Importantly, with NGLs included, we expect the total liquids content to be near 80%. We currently have five horizontal rigs drilling in the area, with three rigs testing geologic concepts, and we have one rig drilling water disposal wells to support future development.

Our Chester horizontal program is off and running, with a group of wells drilled back to back during the quarter. Presently, one of these wells is online and delivered a robust 30-day oil IP of 194 barrels per day. Five additional wells are projected to be online over the next few weeks. We were the first company to pursue the horizontal Chester in the region, and we are continuing to expand the concept along the regional sub-crop.

We also continue to see encouraging results from the Woodford program, with two wells coming online during the quarter. The average 30-day IP was 133 BOE per day, with a 71% oil content. These are the last two wells based on our initial geologic model.

As shared during Analyst Day, we've developed an updated geologic model that we will utilize to test the next three wells. This new model targets locations with proximity to Misener and Hunton production, and where the Sylvan shale will provide a frac barrier. We now have a total of six Woodford wells online as part of the nine-well appraisal program we launched last year.

In terms of capital efficiency, we completed a successful dual-stacked lateral well in Harper County, Kansas. From a single-surface wellhead, we landed one lateral in the Upper Miss and one lateral in the Lower Miss. The total cost of this project was $5.2 million, or $2.6 million per lateral. This cost can be compared with two separate wells that would typically be in the range of $6 million combined.

The well delivered a 30-day IP of 707 BOE per day at 44% oil. We believe this novel well design can be exported across the play where we have two stacked zones to develop. In the second quarter, we will have three additional dual-lateral wells online, and we will report on those in our next call.

We're also pleased with the production results of our first trilateral well, which was drilled late last year in Harper County, Kansas. We believe this well design can be repeated in many parts of the play for around $4 million per section.

Learning from our initial work on the dual-lateral and trilateral projects, we plan to develop two full sections by the end of Q3 that will have four to five laterals each and will extend from a single wellhead position in the corner of a section. We are excited about these programs, since they demonstrate our ability to conceive and execute innovative concepts and highlight our commitment to deliver breakthrough economic results, which ultimately translates into shareholder value.

We also made significant value -- or significant progress increasing the lifecycle value in the EUR of our existing asset base with advanced artificial lift technology. During the quarter we converted 34 existing wells from gas lift to ESP, or from gas lift to beam pump. The results were stellar.

The projects increased production by 1,461 BOE per day, and of this amount, 402 barrels per day was oil. The single project conversion economics routinely exceed 100% rate of return.

In closing, while our operations were impacted by the extreme weather, we have developed plans to recover the deferred volume, and still expect to achieve year-end production guidance. Our employees did an exceptional job working through the difficult situation in a safe manner, and the extra effort is greatly appreciated and noted.

Perhaps more than any previous quarter, we achieved greater progress on our value-enhancing themes. We discovered yet another part of the play with premium economics in Northern Garfield County; accelerated Chester oil development, where we were the first mover; implemented the use of 3D seismic; developed high-rate oil wells in Sumner; and we are continuously improving our capital efficiency and economic returns through the use of novel well designs and advanced artificial lift technology and systems. We look forward to sharing more as the year unfolds, and we thank you again for joining us today.

I will now turn the call over to Eddie Leblanc, our Chief Financial Officer.

Thanks, Dave. We've ended this quarter having completed the divestiture of the Gulf assets. So while we will discuss the actual EBITDA illustrating our reported performance, we will additionally provide pro forma information for the currently owned and operated assets.

The first quarter of 2013 is being adjusted for the divestiture of both the Permian and the Gulf assets, and the first quarter of 2014 is being adjusted only for the Gulf assets. Adjusted EBITDA as reported for the first quarter of 2014 was $230 million, or $32 per BOE, as compared to $270 million, or $30 per BOE for the first quarter of 2013. Pro forma adjusted EBITDA for the first quarter of 2014 was $177 million, or $30.49 per BOE, compared to $112 million for the first quarter of 2013, or $22.77 per BOE.

This $65 million increase in EBITDA was comprised of $53 million of improvement in revenues, driven by an 18% increase in volumes, 72% of which was an increase in liquids. This was partially offset by a $7 million increase in production expense associated with the increase in production. Also included is an $8 million improvement in EBITDA from midstream and other, and a reduction in adjusted G&A of $11 million.

There are two other items of note for the first quarter. First, G&A of $38 million included an $8 million severance expense associated with the Gulf assets divestiture, and second, we recorded a ceiling test impairment expense of $165 million due to the Gulf assets sale, as the PV-10 of the asset sold exceeded the net proceeds of the sale.

We closed this first quarter with $1.180 billion of cash. Our capital expenditures during the quarter were $276 million, which was under plan due to weather disruptions. Additionally, we paid $70 million to unwind hedges associated with the Gulf sale.

Our senior notes remained at $3.2 billion, with a first maturity in 2020. The bank leverage ratio covenant calculation includes debt -- net debt of $2.025 billion and a last 12-months covenant EBITDA of $671 million, yielding a leverage ratio of 3.0 times.

On April 17, our bank borrowing base was reaffirmed at $775 million. Currently, our credit facility borrowing base is undrawn, and used only to support our $29 million of letters of credit outstanding, which leaves us $746 million of availability. This availability, when combined with our cash position at quarter end, provides liquidity of $1.9 billion.

On hedging, 87% of the remainder of 2014's anticipated liquid volumes are hedged, with 27% in swaps at $99.49 a barrel and 60% in three-way collars with a first floor of $90.21 and a ceiling of $100. 63% of anticipated natural gas volumes are hedged, with 62% in swaps at $4.27 per MCF, and 1% in collars with a floor of $4 and a ceiling of $7.78. Given this position, you can understand why we remain confident in our 2014 revenue expectations.

Additionally, for 2015, we have liquids hedges of 2.92 million barrels and three-way collars with a first floor of $90.82 and a ceiling of $103.13, as well as 5.59 million barrels of swaps at $92.44. Natural gas hedges for 2015 are comprised of 15.4 BCF of swaps at $4.50 and 1.1 BCF of collars with floor of $4 and a ceiling of $8.55 per MCF.

We are reaffirming our 2014 guidance, which has only been updated to account for an increase in production from the Gulf assets, improved NGL realizations to account for first quarter results, and lowering of our total DD&A rate by $0.30 per BOE, due to the Gulf asset sale and the related first-quarter impairment effect. Otherwise, our guidance remains unchanged.

Operator, that concludes my remarks. Please open the call for questions.

(Operator Instructions)

Neal Dingmann, SunTrust.

Morning, guys. David, for you or James, just wondering, you continue to outline a lot of different potential completion methods. I'm just wondering, the economics, how different, I guess, are you looking at now, are those between the open-hole and some of these others? I'm just wondering, I guess, when I look at, sort of the type curves and some of your MPVs out there. I mean, again, how different could we see these, or I guess potentially how much could we see these go up as you continue to excel with these?

Sure, Neal. This is Dave. The primary method of completing the wells right now, we have transitioned to the open-hole packer system. Typically, that system is a little bit more expensive than a -- in and of itself, than a typical perf-and-plug. But when you look at the total cost of the operation over the completion period, it saves about $50,000 to $100,000. So not only do we think it supports greater EUR, which we will be able to share hopefully in the future, but it does save $50,000 to $100,000. Then the other benefit of open-hole packer systems is we can typically -- and how they save the money, is we can typically complete that well in 48 hours where it used to take five to seven days. So it's a very rapid way of completing the well, and we think ultimately more efficient.

Perfect. And then last question I had for you, just on infrastructure. Just your thoughts on, I know the new acres that you'd added prior quarter and such, just your thoughts on infrastructure build-out, sort of where do you sit now, on CapEx-wise, James, how much you're going to be attributing to that?

Yes, we still -- we're keeping our infrastructure guidance where it was, at about 12% of our D&C spending. We had built in the budget adding some infrastructure in some new areas, such as this Northern Garfield area. So that's accounted for in our budget. I don't think you'll see that change this year.

Very good. Thank you all.

Charles Meade, Johnson Rice.

Good morning, guys. I had a question that might be best for Dave. On that dual-stacked lateral in Kansas, it seems that that's both a technical success in the sense that you got the well down, completed, and it's flowing, but also a commercial success. But the question that leads me to is, was this in an area that was already known to be good? I know that you have a lot of clusters of good well results. So was it in an already known good area? What I am aiming toward is, how representative is this result of your larger acreage position?

Sure, Charles. This was in an area that we had started to delineate. So we were fairly certain we would have a good outcome here. Typically, we wouldn't spend $6 million on a pure appraisal program to test an upper and lower zone. So we did have a good sense that the well would be an economic success.

And in terms of just the repeatability, there are multiple areas in the play that we've shared that have this dual-stacked opportunity for us. And so, as I mentioned, we have three more of those coming online here in the second quarter, and we believe that this is an opportunity set that has significant upside. I can't say at the moment if it's going to be 50% of our wells or 20%, because the area is so vast and is so rich, but at this point we're very pleased with the result.

The primary benefit here is we did see a greater than type-curve result. And these are wells that we would've drilled independent of each other. So when you do it in the dual-stacked format, we do save $400,000 per well, or $800,000. So we are not advertising this as an EUR initiative at the moment, but certainly capital efficiency is the leading issue here. So if we can go in and knock $400,000 off a well, that's going to be a pretty impressive thing. Hopefully, we have a significant number of these coming through the system in the coming months.

Got it. As I was -- look, if I crossed other plays and look for an analogue of what you guys are doing here, the closest that I've been able to come up with would be, even though it was a while ago, was Austin Chalk in the sense of uncase holes with multilaterals. Is that a fair starting point to try to think about what you guys are doing here? And maybe you can offer what, if it is a fair starting point, what improvements you are doing and what distinguishes you from what operators were doing back then?

Well, we think this is a novel concept. There are analogies that you could pull from around the world, but where we think this is going to have a benefit for us, naturally, this is a carbonate. It's a component rock, which allows us to enter the hole multiple times and complete different sections. And so the opportunity to go in and out of these wells is where we think we have the real upside. As we had mentioned, where we think we can even develop an entire section, we think we can put up to 34,000 feet into one section from a single wellbore access point. And so that's the real upside, is being able to go in and out. Recall if you're in a shale formation, that's a little more difficult because bore hole or wellbore integrity becomes an issue to be able come in and out that many times. So given the competency of the rock, is what allows us to do this. So it is fit for purpose. It is novel. We are the ones that originated this design, and teams are pretty impressive.

Got it. David, I might have misspoke. I meant to say Austin Chalk. Maybe I didn't say Austin Chalk.

No, you did. I know they did a lot of interesting things there in the chalk. But I think for us, this particular design is unique and custom and fit for purpose.

Got it. If I could just sneak just one last one in here. Can you guys -- I see you've maintained your overall guidance for the year, but with the -- you had a little more than a half-quarter of the Gulf of Mexico. Can you talk about what the quarter-to-quarter growth you think will look like for the rest of the year, if you can share that?

Charles, we've stopped short of giving quarterly guidance right now. We've given out annual, and I think and hope we give enough pieces where people can draw a line between the first and the last quarter. The Mid-Con production was down about 2%, completely weather-related.

We expect, as we note in the press release, a lot of those wells we got completed and brought online in April, we think will have a similar robust level of completions in May. So I expect some pretty good ramp-up in the production in the second quarter. But I think we're going to stop short of providing specific quarter-to-quarter guidance right now.

That's great color, James. Thanks a lot.

(Operator Instructions)

Stephen Shepherd, Simmons.

Good morning, guys. One of the defining characteristics of the Miss has been the variability, clearly, of the well results. On one end, you've got the small handful of exceptional wells that come online at these huge IP rates, greater than 1,000 BOE per day in some cases. And then on the other hand you've got, at least what appears to me, to be a larger set of wells that come online at marginally economic rates.

So it's clear that you've been able to increase the average IP over time, over the last few quarters. I'm just wondering if there's anything else, or any other initiatives beyond what you talked about in the past, things like 3D seismic and whatnot, that you are doing to try to truncate that well distribution and create some more positive skew going forward?

Sure. I think there are several initiatives. If you remember at our Analyst Day, and even in our corporate presentation, we showed you the EURs from our 2013 program and then wells prior to 2013. You can see the distribution is shifting to the right. We're drilling less and less every year on commercial or lower EUR wells.

Remember, when we started in the play in the first year, we had 37 wells in our data set. Then we had 145 the next year, and then 600, and now approaching 1,000. When you're dealing with 600,000 acres, going from 37 wells to over 1,000, you learn a lot.

We've climbed up the learning curve. We've changed our completion methods. As Dave talked about, most of our wells are open-hole now. The teams have done a great job of targeting specific areas within the -- zones within the Miss, depending on where we are across the play.

And seismic, you mentioned seismic. We've shot over 1,100 miles of seismic that we're processing. We'll shoot another 700 this year. We think that's going to be a valuable tool.

Between all of those and the learnings that we have on these over 1,000 wells, we think we've tightened that distribution of returns, and we'll continue to do that.

Okay. One more, if I can. Also wanted to touch on downspacing in the play. In the past you've talked about that as a means to potentially increase location counts in the focus area. What's your average drilling density right now for the program in the focus area? And then are there opportunities for that to trend lower moving forward?

Right now we are on predominately four wells per section. There's some areas we're at three, but we're mostly four. I don't think we've referenced downspacing more densely than that. So now we are on roughly 160s in most of the areas.

Okay.

Stephen, this is Dave. I'm going to revisit your question on the variability. One thing I would like to highlight is this Garfield area is very, very tight. We probably won't release the individual well results, but that region is very tight, and our subsurface teams have just done an exceptional job identifying this area and drilling this area. So in terms of just the variability, we think we've got that area understood, and actually understood very quickly. And as we integrate 3D seismic, I wouldn't be surprised if we did see -- continue to see improvements.

So it is a fractured carbonate, so you do see some variability. But overall, we are incorporating all of the variables that contribute to a successful outcome. We are doing better, I think, over time -- each quarter I think we're showing that result, and it does show up in the IPs.

Okay. Thanks.

Robert Carlson, Janney Montgomery Scott.

Hello, Jim. Just a quick comment regarding -- or a compliment to you and your staff. I've been following SandRidge for a number of years. The quality of your calls, the quality of your presentations have just improved dramatically.

It's nice to see the improvements in operations too, but just upfront, the quality of your presentations are great. Just wanted to send along an atta boy, and keep up the good work.

Thank you for that note. One of the changes we've tried to make here in the last year is a little more clarity and visibility into the business, and a little more detail around some of our disclosures, and even just changing the way we present things.

We want to make it easier for the investors and analysts to comb through our information and understand what we're doing and why we're doing it, and lay out the numbers clearly. So, thank you.

At this time, we have no further questions. I will now turn the call over to Mr. James Bennett for closing remarks.

Thanks everyone for joining us on the call. Just in closing, we had quarter -- year-over-year EBITDA was up over 50%. We've discovered another high-return area of the play. We continue to drive innovations in the business. We had the second-highest IP rate ever in the quarter, and seven wells over 1,000 BOE per day.

So I'm pleased with the way things are going, and just want to compliment the team, operational team doing a great job, and across the board whether that's county or legal, we've got all the right people in the right spots, and the team's moving forward to create value for the shareholders. Thanks for joining the call.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect, and have a great day.