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Oasis Petroleum (NYSE:OAS)

Q2 2013 Earnings Call

August 07, 2013 11:00 am ET

Executives

Michael H. Lou - Chief Financial Officer and Executive Vice President

Thomas B. Nusz - Chairman, Chief Executive Officer and President

Taylor L. Reid - Chief Operating Officer, Executive Vice President and Director

Analysts

Michael Hall

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Irene O. Haas - Wunderlich Securities Inc., Research Division

Andrew Venker - Morgan Stanley, Research Division

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Peter Mahon - Dougherty & Company LLC, Research Division

Operator

Good morning. My name is Gina and I will be your conference operator today. At this time, I would like to welcome everyone to the second quarter 2013 earnings release and operations update for Oasis Petroleum. [Operator Instructions] I will now turn the call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference.

Michael H. Lou

Thank you, Gina. Good morning, everyone. This is Michael Lou. Today, we are reporting our second quarter 2013 results. We're delighted to have you on our call. I'm joined today by Tommy Nusz and Taylor Reid, as well as other members of the team.

Please be advised that our remarks, including the answers to your questions, include statements that we believe that to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our earnings release, as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements.

During this conference call, we will also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measures can be found in our earnings release or on our website. I'll now turn the call over to Tommy.

Thomas B. Nusz

Good morning. I'll start the call today with a few key items that we're focused on and then Taylor and Michael will cover more detail on operations and financial highlights.

Oasis has experienced tremendous growth over the last few years and we've experienced a considerable transformation. Our consistent and exceptional results were the combination of years of planning, foresight and execution. I'm very proud to what the team has accomplished and the direction that we're going. This year has been a transition year for us. Up through 2012, it was really about holding our global ops and laying the groundwork for future development. This year has been a move more towards full-scale development mode. We're beginning to realize the benefits of the efficiencies and cost savings of resource manufacturing as we improve our planning and processes and drill more multi-well pads. In the second quarter, approximately 75% of the spud wells were on pads and we maintained our drilling pace. At the same time, we moderated our completion activity consistent with our original plan in order to control costs during breakup conditions. As a result, we built our backlog of operated wells waiting on completion from 21 as we entered the quarter to 37 as we exited the quarter. So with the rigs continuing to operate on pad locations, we avoided many of the restrictions associated with operating during the wet season and deferred completion activity to the summer months when it's more cost effective to undertake frac operations. Even with May as one of the wettest months on record, we executed well against our original plan. In the second quarter, we completed 20 gross and 14 net operated wells and kept production relatively flat quarter-over-quarter as we expected. We will obviously now ramp up as we go through the second half of the year. In fact, we've recently added 2 rigs, so our current rig count is 11. We anticipate completing 40 to 45 wells during the third quarter. With this, we expect production to grow to between 31,500 BOEs per day and 34,500 BOEs per day for the third quarter. The team has continued to do an excellent job of optimizing well costs on multiple fronts. For the second quarter, our average well cost dropped again to $8.2 million, excluding the cost savings from OWS. With the progress we've made already to date, we can drive well cost to our year end target of $8 million per well if not below, and that's excluding the impact of OWS. So in terms of activity, we're right on track, and may be able to do a bit more than we had planned on a gross operated basis and very likely on a net basis than we planned for the year originally. But that will depend on the pace of activity, weather and our ability to pick up working interest on our operated units. Plus, with the cost efficiencies we're seeing, we still expect to spend in and around our original budget of just over $1 billion for 2013 and have spend about 42% of that year-to-date. So we're off to another good year as the team continues to execute on our plan and maintain that momentum through the end of the year.

With that, I'll turn the call over to Taylor.

Taylor L. Reid

Thanks, Tommy. As we discussed on the last call, 2 items that will have significant impact over the long-term are inventory growth and surface design of our multi-well pads. We have spent a lot of time on both of these value drivers this year and we'd like to give you an update on our work.

First, when we think about our inventory at Bakken, in first benched Three Forks wells, we continue to feel comfortable with 4 wells in each horizon across our core acreage position. The variations in reservoir quality and thickness across our position, we will ultimately have a range of spacing densities. We believe in some areas, we will be in the 5- to 6-well range for each horizon while in other areas, it may be in the 3- to 4-well range. It is still too early to make the call, but 5 of our planned 22 spacing tests for 2013 are on early production and 9 more will be on production prior to year end. There are an additional 8 tests that will be completed at or near year end. These wells will help us determine the optimal number of wells per spacing unit. Another part of the inventory growth is our work on the lower benches of the Three Forks. During the first quarter, we cored 6 wells across our acreage to assess the potential in the lower benches. Based on encouraging results from the preliminary core analysis, we have commenced drilling on 2 separate second bench Three Forks wells. The first well is in Indian Hills and is between 2 Bakken wells. We will obtain micro seismic data on the well, which will provide data on how the lower bench completion reacts with the Bakken wells. The second lower bench test is in North Cottonwood near the border of Burke and Mountrail counties. We will finalize our lower bench assessment in the second half of the year and plan to incorporate additional lower bench test in our 2014 drill plans. The second key item we have been focused on this year is determining the optimal surface arrangement for pad development. In this objective, we are continuing to find ways to drive down costs while becoming more efficient. An example of this is the Romo Brothers' 3-well pad located in Montana. Oasis Well Services was able to pump a total of 96 stages and 9.9 million pounds of sand in 9 days or just 3 days per well. The average well cost for these wells was about $6.7 million per well for about a 10% cost reduction when compared to a single well completed with all sand in that area. In the second quarter, we added 5 different 4-well pads in the drilling process and we're now drilling an 8-well pad. We'll have about 60% to 70% of our wells on pads in 2013 going to about 90% in 2014. Increased efficiency and reduced cycle times on these pads will drive cost improvements through 2013 and into next year. Oasis Well Services has also delivered great results, saving the company approximately $400,000 per net well completed, which puts us below an average well cost of $7.8 million across all of our operated wells.

Finally, our infrastructure continues to provide us with excellent cash margins. Currently, we gather about 85% of our oil on our gathering system, which gives us access to pipe or rail takeaway capacity. To give you some perspective on our takeaway optionality, we went from about 1/3 of our production on pipe in June to 2/3 on pipe in July. This flexibility has driven our superior results and price realizations as the market dynamic change. In addition, we now have about 90% of our wells connected to gas infrastructure and Oasis Midstream captures approximately 80% of our produced saltwater into our disposal wells with over 65% traveling through our gathering system. All these items are adding to the bottom line.

With that, I'll turn it over to Michael to discuss the financial highlights.

Michael H. Lou

Thanks, Taylor. As Taylor mentioned, we were able to use the flexibility in our gathering system and access to multiple different sales points to maximize our price realizations in the second quarter of 2013 and we achieved a 3% differential to WTI. As a premium that the coastal markets receive compared to WTI eroded during the second quarter, our differentials began to widen a bit compared to the first quarter of 2013. More recently, with the compression of the Brent WTI spread, we have been able to move oil back to pipelines to capture better pricing versus the current rail alternatives. In the second quarter, we had adjusted EBITDA of $185 million, realizing an impressive $67.55 of EBITDA per BOE produced. We spent approximately $189 million in CapEx and as Tommy mentioned, we are expecting that to ramp up in the third quarter in line with the drilling and completion activity. We have $1.4 billion of liquidity and in addition, we continue to execute our hedging strategy and currently have approximately 24,500 barrels of oil per day hedged for the remainder of 2013 and we're up to approximately 20,500 barrels per day hedged in 2014. One thing I'd like to note is our bulk oil sale in the second quarter. We basically traded oil with a third-party marketer and booked a gross oil sale and associated cost, both of which were $5.8 million. So the trade was gross margin neutral. In our press release, we backed out the impact of this transaction for you as it related to realized oil prices and marketing transportation gathering expenses on a per barrel basis. So to close out, we are excited about the direction that we're going and the best is yet in store for us as we move to full manufacturing mode. With that, we'll turn the call over to Gina to open the lines up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Michael Hall with Heikkinen Energy.

Michael Hall

Heikkinen Energy. I guess, I want to get a little better feel on completions pace as you move further and further into pad development mode, in particular kind of thinking about how the -- waiting our completion backlog grows or contracts and when we should think about -- how we should think about the timing of oil being drilled versus terms of sales? And in that context, I'm thinking about the 60% being drilled on pads in 2013, 90% in 2014. As you move more and more towards pad, is it fair to assume then the waiting on completion backlog will continue to increase through that period just as you kind of built the backlog up on the pad? And so we wouldn't really see a material contraction in that backlog until you kind of peak out on your pad development? Am I thinking about that correctly?

Thomas B. Nusz

Yes. What I would tell you is, is that, obviously, as we get -- as everything gets on pads, then you start to normalize that but what we said before is as we -- if you run in, call it 11 rigs, you're going to have 2x waiting on completion. So you're always going to have about 25, 20 to 25 or so. So -- but it probably will contract a bit.

Taylor L. Reid

Michael, it's Taylor. You'll see it come down from the 37. We're working off quite a few wells in this quarter but we're going to continue to have more wells on pads, like you mentioned, through the second half and going into next year. And over time, it will normalize a bit when you don't have all your pads starting at one time, then you got them kind of spread out through the year so it should normalize over time. The other thing that will help as we go forward is doing simultaneous operations. So we are currently on an 8-well pad that we're going to do our first set of simultaneous operations where we'll be both drilling, we'll drill a set of 4 wells and then while we're drilling the next 4 wells, we'll be frac-ing the first 4 wells. So rather than having to wait til all 8 of those wells are drilled and completed, come on production, we'll be able to cycle through the first 4 and get them on production earlier. So that's going to help out with that waiting time.

Michael Hall

Okay, that's helpful. So I guess, when I think about it, as the -- the backlog contracts a bit this summer and then maybe starts to grow back up again to -- as you move more and more of your activity of the pads into 2014. Is that a fair comment?

Taylor L. Reid

Yes, it will contract a bit this summer and then kind of flatten out from there.

Thomas B. Nusz

But I think you should expect -- I mean, once it starts to -- even when it starts to normalize, I think you're probably always going to have a bit of a bill during the second quarter just because we're trying to manage costs and if it's real wet like it was this year, then, in our opinion, it's better to differ a bit versus spend a lot of money just to get the volumes on.

Michael Hall

No, that makes sense. That's helpful. And then the 11 rig program. Just to be clear, is that going to be maintained, is the intention to maintain that through the rest of the year and into '14 or is that kind of swing capacity this summer?

Thomas B. Nusz

No, I think that's kind of -- that's going to be our -- going forward, at least as far as we can see at this point, it will [indiscernible] about 11. And now the guys are continuing to be more efficient. So again, it kind of goes back to project count but effectively, yes.

Michael Hall

Okay, great. And the last one of mine, I'm just curious, can you, by any chance, provide any sort of IP 30 average, IP 30 or something along those lines by area during the quarter? West Williston, East Nesson and Sanish on the operated -- or I guess, just West Williston and East Nesson on the operated IP?

Thomas B. Nusz

Yes, I don't know that we've got average 30-day IPs for the wells brought on production, Michael.

Operator

And your next question comes from the line of Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

On the downspacing, I gathered from the commentary that, obviously, it's a little early to declare success but I wanted to drill down there. Did you see any areas where downspacing to more than 4 wells per DSU, would it work? Did you see more areas that are encouraging? Any color you can provide around the downspacing test?

Taylor L. Reid

Right. So we -- as I mentioned, we got 22 this year, there's 5 that are currently on production and really, only 3 of those have a significant amount of production. Two of them were just really on within the last week. All of those 5 are 4 per formation. So results, as you mentioned, beyond 4 per formation are still in front of us in the second half. For more than 4, we'll be doing 2 that have 5 wells per formation in the spacing unit and 2 that will have 6 wells. And like I said, those will be second half wells. The other -- I guess, on a comment I made on the ones we do have production on the date, the 3, it looks like -- and those are 4 wells per spacing unit that the new wells are producing on the same amount of production as the original well within that spacing unit.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Got you. That's helpful. And then moving to the lower Three Forks. Not surprised to see you test Indian Hills given the nearby industry results there. North Cottonwood, see a little bit less in terms of industry activity there. I was curious what color you can provide on what you saw on these cores that has encouraged North Cottonwood. And then -- and I think there were 6 cores. So on the other 4, what you saw there as well.

Taylor L. Reid

So Indian Hills, you know that one, you obviously got that one. When we look at the cores there, it's confirm that we did want to do a second bench test. When we look at Cottonwood, the cores show good porosity and good oil saturations, enough that, for us, merited a test into a second bench. And so, this is our way of taking the next step and confirming that there is enough recoverable oil to make economic wells in that area. And really, we're optimistic about the whole Cottonwood area. We just have one well that we're testing right now but as we look from Alger, on the east side all the way up to North Cottonwood, it's -- we're optimistic based on what we we're seeing in the cores that we've taken and the logs in the area. In the other areas where we took cores, there was also one in east Red Bank and then one in Montana. Those wells, we're still evaluating. Haven't planned a second bench test at this point but you might see us do something next year. So still evaluating.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then one final modeling one for me. You had very good cost control this quarter both on the LOE and OpEx side. What should we expect per unit cost moving forward?

Taylor L. Reid

So on our unit operating expense, we're at, for the quarter, 6.65 and the trend has been down, so down quarter-over-quarter. We would expect to continue that general trend. Maybe a little lumpy month-to-month. Part of that is that we're getting a larger component of workover expense that is due to frac protect as we drill and frac more wells in and around local wells. So that depending on the wells you're competing in a month or a quarter, you can see it bump up and down but in general, I'd say it's on a downward trend.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Great. And I think I misspoke. I mean, G&A also looked pretty low this quarter as well. Any thoughts on third quarter, fourth quarter for that guidance?

Thomas B. Nusz

Yes. Same thing on G&A. As our production grows, obviously, our G&A continues to grow as we're adding people to the organization to continue to execute on our program. But our G&A cost overall on a per unit basis will likely start to continue to trend down a little bit as well. We have been running a little bit under our kind of guidance on that G&A side or on the lower end of that guidance as you guys can see.

Operator

And your next question comes from the line of Irene Haas with Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

I mean, obviously bypassing the issue of wet weather, you're planning infrastructure investment is really kicking in and it just seems like you have Williston Basin in good order. So sort of any appetite for building a new core area?

Thomas B. Nusz

You know, Irene. As we've talked about, we've got a -- I guess, it was this time last year where we really kind of formalized the business development team and they've been doing some other recognizance outside of the Williston but more Upper Rockies things that look like it -- but we've actually kept them pretty busy over the last 6 months or so just working Williston projects. So we've had enough to keep them occupied with that. So in the near term, probably continue to focus on Williston and we'll just see where it takes us.

Operator

And your next question comes from the line of Drew Venker with Morgan Stanley.

Andrew Venker - Morgan Stanley, Research Division

I was hoping you could talk a little bit about what you see as a potential for slickwater fracs to improve performance and if you have any ideas as far as what the difference in well cost would be.

Taylor L. Reid

So we've been doing some work on the slickwater fracs and we actually have a couple of wells scheduled for slickwater fracs this year. In fact, one was just completed and has been on production that is flowing back, it's only been on for 3 days. So we're going to evaluate the results of those slickwater wells relative to our typical fracs in those areas. The slickwater fracs that we're doing are more expensive, primarily because of the volume of water used in those fracs. So our typical frac is about 70,000 barrels of fluid. The slickwater fracs we're doing are closer to 225,000 barrels of fluid. So a really significant increase in total fluid. As far as an incremental capital cost, it's over $1 million. It just depends on the area.

Andrew Venker - Morgan Stanley, Research Division

Okay. And then what areas are you testing, or is it just kind of all over?

Taylor L. Reid

The first well that we've done is in Indian Hills called the Pikes. And there will be another well that will be probably in Indian Hills or East Red Bank and then we'll branch out from there if we decide to take more steps.

Andrew Venker - Morgan Stanley, Research Division

Okay. And then, I guess, going back to simultaneous operations you guys have talked about. Do you have any initial estimate of the improved -- potential improvement and spud to first sales on average for a pad?

Taylor L. Reid

I don't have days but the way you can think about it is you would drill without simultaneous operations, you would drill 8 wells back to back and we're now drilling -- spud to rigs release is 23 days. We kind of think each of those close to a month. And so rather than waiting 3.5, a total of 7 to 8 months to start competing wells after 3.5 to 4 months, we'll be competing wells within that pad.

Andrew Venker - Morgan Stanley, Research Division

So is cutting that time in half a reasonable expectation just on average?

Taylor L. Reid

Yes, not quite half but relative to -- if you did a full 8-well pad, it's going to help you on time. Now on smaller pads, you can't really apply that across the spectrum because, say, a 2- to a 4-well pad, you're probably not going to do simultaneous operations or less likely to, you're just going to drill them out and put them on production.

Operator

And your next question comes from the line of Gail Nicholson with KLR.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Just a couple of quick questions. Continuing with that simultaneous operations, have you guys made a decision on out of that 90% of the wells being drilled in '14, what percentage will be done with the simultaneous operations yet?

Taylor L. Reid

No, we haven't. We've got -- this is the first one that we're doing simultaneous operations on. So we'll assess it when we get done. It's going to be most impactful to do that on the pads where we have a larger number of wells. And as we go to more full pad operations, you'll see that but we just don't have a percentage or assessment of that yet.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Okay. And then looking at those 3 DSUs that have been on production for some time, what areas were those located in?

Taylor L. Reid

Two in what we call Alger, which is the east side, south of Cottonwood. And then there was one that was in Montana, in Hebron.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Great. And then my last question is do you have any update on the Three Forks wells that you guys have planned to drill outside of Indian Hills and South Cottonwood in 2013, what's going on there?

Taylor L. Reid

So we've got 3 additional wells in Cottonwood, in North Cottonwood that will be drilled in the first bench in the second half. And then as I mentioned, we have one second bench well that will be in Cottonwood as well that will be in the second half. And they're going to be -- they're either drilling currently or will spud within the next couple of months.

Operator

And your next question comes from the line of Peter Mahon with Dougherty.

Peter Mahon - Dougherty & Company LLC, Research Division

I just have one follow-up question. Well costs have come down quite nicely. I was wondering if you could just characterize how much of that decline is downward pricing pressure in the service sector versus how much comes from efficiencies that you guys have built into the model.

Taylor L. Reid

So the -- we talked about the cost savings this year are -- there is some service component but the majority of it is really efficiency, well design, pad operations, all those things through cycle times.

Peter Mahon - Dougherty & Company LLC, Research Division

Got it. And could you talk through kind of what you're doing now in terms of just your frac-ing model or your approach that's different today versus, say, a year ago and what you're doing differently?

Taylor L. Reid

Compared to a year ago, it's really tweaking our fracs. The standard frac that we had historically done a year ago was 36 stages and depending on where it was, it was either all sand in the shallow areas or a combination of sand and ceramic in the deeper areas. The things that we've been experimenting more with have been in a few areas, less stages but generally, we're still around 36 stages. We're trying a higher percentage of sand in a number of areas like we mentioned in Hebron earlier, we did some wells that were all sand, that was the 3-well pad. Historically, we had done sand and ceramic in Montana and we're kind of shifting that and then the other thing we're experimenting with is sleeves in some areas. So there are some areas where we've done as many as all 36 stages with sleeves, some areas where we got 20 stages and in some areas, we don't use a whole lot of them. It just depends on the area but we're trying to get enough control with the new things that we're trying so we can compare it to the existing wells and make changes that we know is going to impact both cost and production.

Operator

And there are no further questions at this time. I'll now turn the call back over to Oasis Petroleum for closing remarks.

Thomas B. Nusz

Oasis continues to differentiate itself as one of the premier operations in the Williston Basin. We're proud of our culture, the accomplishments of our team and the direction we're going as a company. This has been an exciting year as we work to further grow our inventory and improve the economics of our business. As always, thanks for everybody's participation on our call.

Operator

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

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