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 2nd quarter 2013 earnings release and operations update for Oasis Petroleum. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.
I will now turn the call over to Michael Liu, Oasis Petroleum's CFO to begin the conference. Thank you. Mr. Liu, you may begin your conference.
Thank you, Gina. Good morning, everyone. This is Michael Liu. Today, we are reporting our Q2 2013 results. We're delighted to have you on our call.
I'm joined today by Tommy News 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 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 ks 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.
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 for the culmination of years of planning, foresight and execution. We're very proud of what the team has accomplished in the direction that we're going.
This year has been a transition year for us. Through 2012, it was really about holding our drill blocks 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 Q2, 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 and orders 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, executed well against our original plan. In the Q2, 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 recently added 2 rigs, so our current rig count is 11. We anticipate completing 40 to 45 wells during the Q3. With this, we expect production to grow to between 31,500 BOEs per day and 34,500 BOEs per day for the Q3. The team has continued to do an excellent job of optimizing well costs on multiple fronts.
For the Q2, our average well cost dropped again to $8,200,000 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 $8,000,000 per well, if not below, and that excluding the impact of OWS. So in terms of activity, we're right on track and maybe 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 in 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 $1,000,000,000 for 20.13 and have spent 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.
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 of Bakken and First Bench Three Forks wells, we continue to feel comfortable with 4 wells in each horizon across our core acreage position. With 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 Q1, 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 2nd bench 3 Forks wells. The first well is in Indian Hills and is in between 2 Bakken wells. We will obtain microseismic data on the well, which should provide data on how the lower bench completion reacts with the Bakken wells. The 2nd lower bench test is in North Cottonwood near the border of Burke and Montreal Counties.
We will finalize our lower bench assessment 20 14 drill plants. 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 cost 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 £9,900,000 of sand in 9 days or just 3 days per well.
The average well cost for these wells was about $6,700,000 per well for about a 10% cost production when compared to a single well completed with all sand in that area. In the Q2, we had 5 different 4 well pads in the drilling process and we are now drilling an 8 well pad. We will 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 $7,800,000 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 third of our production on pipe in June to 2 thirds on pipe in July. This flexibility has driven our superior results and price realizations as the market dynamics 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. 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 Q2 of 2013 and we achieved a 3% differential to WTI. As a premium that the coastal markets received compared to WTI eroded during the Q2, our differential began to widen a bit compared to the Q1 of 2013.
More recently with the compression of the Brent WTI spread, we've been able to move oil back to pipelines to capture better pricing versus the current rail alternatives. In the Q2, we had adjusted EBITDA of $185,000,000 realizing an impressive 67.5 $5 of EBITDA per BOE produced. We spent approximately $189,000,000 in CapEx. And as Tommy mentioned, we are expecting that to ramp up in the 3rd quarter in line with drilling and completion activity. We have $1,400,000,000 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 2nd quarter. We basically traded oil with a third party marketer and booked a gross oil sale and associated costs, both of which were $5,800,000 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.
Your first question comes from the line of Michael Hall with Heikkinen Energy.
Good morning, Michael. Heikkin and Energy. Good morning. Appreciate taking the call. I guess I want to get a little better feel on completions pace as you move further and further into pad development mode?
And in particular, kind of thinking about how that waiting on completion backlog grows or contracts? And when we should think about how we should think about the timing of wells being drilled versus turn 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 pads, is it fair to assume then that the weighting on completion backlog will continue to increase through that period just as you kind of build 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?
Yes. What I would tell you is that obviously as we get as everything gets on pads, then you start to normalize that. But what we said before is, is we if you're running, call it, 11 rigs, you're going to have 2x of waiting on completion. So you're always going to have about 25 20 to 25 or so. But it probably will contract a bit.
Yes. This is 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 and 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 do a simultaneous operation. 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 in the first 4 wells. So rather than having to wait till all 8 of those wells are drilled and completed come on production, we'll be able to cycle through the first four and get them on production earlier.
So that's going to help out with that waiting time.
Okay. That's helpful. So I guess I think about it as the backlog contracts a bit this summer and then maybe start to grow back up again to as you move more and more of your activity that pads into 2014. Is that fair comment? Yes.
It will contract
a bit this summer and then kind of flatten out from there.
But I think you should expect I mean once it starts even when it starts to normalize, I think you're probably always going to have a bit of a build during the Q2 just because we're trying to manage costs and if it's a real wet like it was this year then in our opinion it's better to defer a bit versus spend a lot of money just to get the volumes on. Okay. Maintained?
Is the intention to maintained? Is the intention to maintain that through the rest of the year and into 2014? Or is that kind of staying capacity this summer?
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 Yes. Obviously, we've got 11. Now the guys are continuing to be more efficient. So again, it kind of goes back to project count, but effectively, yes.
Okay, great. And then last one on my end, I'm just curious, by chance provide any sort of like IP30 average, IP30s 30s or something along those lines by area during the quarter on West Williston East Mestin and Sanddesh on the operated or I guess just West Welles and East Mestin on the operated piece? Yes.
I don't know that we've got average 30 day IPs for the wells of Pronom production, Michael.
Okay. Fair enough. I appreciate it guys. Thanks for the color.
You bet. Thanks.
And your next question comes from the line of Ryan Oatman with SunTrust.
Good morning. Thanks for the update on the Three Forks and spacing test. On the down spacing, 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 down spacing 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 down spacing test? Okay. So we as we mentioned, we've got 22 this year. There's 5 that are currently on production.
And really only 3 of those have a significant amount of production. 2 of them are 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 the comment I'd make on the ones we do have production on to date, the 3, it looks like 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. Got you. That's helpful. And then moving to the Lower Three Forks, not surprised to see you test Indian Hills industry activity there.
Was curious what color you can provide on what you saw in these cores that has you encouraged North Cottonwood. And then I think there were 6 cores. So on the other 4, what you saw there as well? So Indian Hills, that one obviously you got that one. When we look at the cores there, it confirmed that we did want to do a 2nd bench test.
When we look at Cottonwood, the cores show good porosity and good oil saturation enough
that
for us merited a test in the 2nd bench. And so this is our way of going taking the next step in 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 you look from Alger on the east side all the way up to North Cottonwood, it's we're optimistic based on what we're seeing in the cores that we've taken in 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 2nd bench test at this point, but you might see us do something next year. So still evaluating. Okay.
And then one final modeling one for me. Very good cost control this quarter both on the LOE and OpEx side. What should we expect for per unit cost moving forward? So on our unit operating expense, we're at for the quarter 665 and the trend has been down. So down quarter over quarter.
We would expect to continue that general trend. It may be 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 completing in a month or a quarter, you can see a bump up and down. But in general, I'd say it's on a downward trend.
Great. And I think I misspoke. I mean, G and A also looked pretty low this quarter as well. Any thoughts on Q3, Q4 for that guidance? And I'll hop back
in the queue. Thanks guys.
Yes. Same thing on G and A. As our production grows, obviously, our G and A continues to grow as we're adding people to the organization to continue to execute on our program. But our G and 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 and A side or on the lower end of that
guidance as you guys can see. Thank you. Thanks.
And your next question comes from the line of Irene Haas with Wonderland Securities.
Great. Congratulations on a really strong quarter. I mean, obviously, bypassing the issue of wet weather, your planning and infrastructure investments 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?
Irene, as we've talked about, we've got a I guess, it was this time last year where we really kind of formalized a business development team. And they've been doing some other reconnaissance 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.
Okay. Great. Thanks.
You bet.
And your next question comes from the line of Drew Zinker with Morgan Stanley.
Hi, good morning. Good morning.
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 idea as far as what the difference in well cost would be?
So we've been doing some work on 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 and is flowing back. Only been on for 3 days. So we're going to evaluate the results of those slick wells relative to our typical fracs in those areas. The slickwater that we're doing are more expensive primarily because of the volume of water used in those fracs.
So in 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 incremental capital cost, it's over $1,000,000 It just depends on the area.
Okay. And then what areas are you testing? Or is it just kind of all over?
So 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.
Okay. And I guess going back to the simultaneous operations you guys talked about, do you have any initial estimate of the potential improvement in spud to first sales on average for a pad?
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 rig releases 23 days. You kind of think of each of those close to a month. And so rather than waiting 3.5, I mean a total of 7 to 8 months to start completing wells after 3.5 to 4 months we'll be completing wells within that pad.
So is cutting that time in half a reasonable expectation just on average?
Yes. Not quite half, but relative to if you did a full eight wheel pad, it's going to help you on time. Now on smaller pads, can't really apply that across the spectrum because say a 2 to a 4 wall 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. Okay.
Thanks.
And your next question comes from the line of Gail Nicholson with KFC. Good morning, gentlemen. 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 2014, what percentage will be done with the simultaneous operations yet?
No, we haven't. We've got like I said, 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
production for some time, what areas were those located in? There
were 2 in what we call Alger, which is on the east side, south of Cottonwood. And then there was one that was in Montana and Hebron.
Great. And then my last question is, do you have any update on the 3 Forks wells that you guys plan to drill outside of Indian Hills and South Cottonwood in 2013? What's going on there?
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.
Great. Thank you.
Thanks.
And your next question comes from the line of Peter Mahone with Dougherty.
I just had 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?
So the talked about for the cost savings this year are there is some service component, but the majority of it is really efficiency, well designed, pad operations, all those things, improve cycle times.
Got it. And could you talk through kind of what you're doing now in terms of just your tracking model or your approach that's different today versus a year ago and what you're doing differently?
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 shallower areas or a combination of sand and ceramic in the deeper areas. The things that we've been experimenting more with have been in the 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 sleeve in some areas. So there's some areas where we've done as many as all 36 stages with sleep, Some areas where we got 20 stages and in some areas we don't use a whole lot of them. 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 to the existing wells and make changes that we know is going to impact both cost and production.
Okay, great. Thanks a lot guys. Thanks.
And there are no further questions at this time. I'll now turn the call back over to Oasis Petroleum for closing remarks.
Okay. Oasis continues to differentiate itself as one of the premier operators in the Williston Basin. We're proud of our culture, 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 in our call.