Good morning. My name is Gina, and I'll 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. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. 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.
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 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.
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 are the culmination of years of planning, foresight, and execution. I'm very proud of 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 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 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. 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 recently added two rigs. 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 excluding the impact of OWS.
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. 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 billion for 2013 and have spent about 42% of that year to date. 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, two 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 in first bench Three Forks wells, we continue to feel comfortable with four 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 five to six well range for each horizon, while in other areas it may be in the three to four well range.
It is still too early to make the call, but five of our planned 22 spacing tests for 2013 are on early production, and nine more will be on production prior to year-end. There are an additional eight 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 six 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 two separate second bench Three Forks wells. The first well is in Indian Hills and is in between two 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 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 tests 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 three-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 nine days, or just three 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 had five different four-well pads in the drilling process, and we are now drilling an eight-well pad. We will have about 60%-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 one-third of our production on pipe in June to two-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 salt water 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 second quarter of 2013. We achieved a 3% differential to WTI. As a premium that the coastal markets received 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. As Tommy mentioned, we are expecting that to ramp up in the third quarter in line with drilling and completion activity.
We have $1.4 billion of liquidity. 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. We are up to approximately 20,500 barrels per day hedged in 2014. One thing I would like to note is our bulk oil sale in the second quarter. We basically traded oil with a third-party marketer and booked the gross oil sale and associated costs, both of which were $5.8 million. 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, and gathering expenses on a per barrel basis. To close out, we are excited about the direction we are going and the best is yet in store for us as we move to full manufacturing mode.
With that, we will turn the call over to Gina to open the lines up for questions.
At this time, I would like to remind everyone, in order to ask a question, please press star, then the number one on your telephone keypad. We will pause for just a moment to compile the Q&A roster.
Your first question comes the line of Michael Hall, the Heikkinen Energy.
Morning, Michael.
Heikkinen Energy.
Morning. Appreciate you taking the call. I guess I want to get a little better feel on completion pace, as you move further and further into pad development mode. In particular, I'm thinking about how that waiting on completion backlog grows or contracts and how we should think about the timing of wells being drilled versus turn to sales. 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 that the waiting on completion backlog will continue to increase through that period? Just as you build the backlog up on the pad. So we wouldn't really see a material contraction in that backlog until you peak out on your pad development. Am I thinking about that correctly?
What I would tell you is that obviously, as everything gets on pads, you start to normalize that. What we've said before is, if you're running, call it 11 rigs, you're going to have two acts of waiting on completion. You're always going to have about 20-25 or so. It probably will contract a bit.
Yeah. This is Mike Lewis-Taylor. You'll see it come down from the 37. We're working off quite a few wells in this quarter. We're going to continue to have more wells on pads, like you mentioned, through the second half and going into next year. Over time, it will normalize a bit when you don't have all your pads starting at one time, and you got them spread out through the year. It should normalize over time. The other thing that will help, as we go forward, is doing simultaneous operations. 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 four wells, and then while we're drilling the next four wells, we'll be fracking the first four wells.
Rather than having to wait till all eight of those wells are drilled and completed to come on production, we'll be able to cycle through the first four and get them on production earlier. That's going to help out with that waiting time.
Okay. That's helpful. I guess I think about it as the backlog contracts a bit this summer, maybe starts to grow back up again as you move more and more of your activity to pads into 2014. Is that a fair comment?
It'll contract a bit this summer and then flatten out from there.
I think you should expect, even when it starts to normalize, I think you're probably always going to have a bit of a build 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 defer a bit versus spend a lot of money just to get the volumes on.
That makes sense. That's helpful. 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 2014? Does that swing capacity this summer?
I think that's going to be our going forward, at least, as far as we can see at this point.
Yeah.
We'll be on 11. The guys are continuing to be more efficient. Again, it goes back to project count. Effectively, yeah.
Okay, great. The last one on my end, I was just curious. By chance, provide any sort of IP 30 average, IP 30s or something along those lines by area during the quarter on West Wilson, East Nesson, and Sanish on the operated, or I guess just West Wilson and East Nesson on the operated piece.
Yeah, I don't know that we've got average 30-day IPs for the wells we've brought on production, Michael.
Okay. Fair enough. I appreciate it, guys. Thanks for the call.
You bet. Thanks.
Your next question comes to the line of Ryan Oatman with SunTrust.
Morning. Thanks for the update on the Three Forks and spacing test. 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 four wells per DSU wouldn't work? Did you see more areas that are encouraging? Any color you can provide around the downspacing test?
Okay. As we mentioned, we've got 22 this year. There's five that are currently on production. Really only three of those have a significant amount of production. Two of them are just really on within the last week. All of those five are four per formation. Results, as you mentioned, beyond four per formation are still in front of us. In the second half, for more than four, we'll be doing two that have five wells per formation in the spacing unit and two that will have six wells. Like I said, those will be second-half wells. The other comment I'd make on the ones we do have production on to date, the three, it looks like, and those are four 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. 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. Was curious what color you can provide on what you saw in these cores that has you encouraged North Cottonwood. I think there were 6 cores, on the other 4, what you saw there as well.
Indian Hills, you got that one. When we look at the cores there, it confirmed 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 in the second bench. This is our way of taking the next step and confirming that there is enough recoverable oil to make economic wells in that area. 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, we're optimistic based on what 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 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. Still evaluating.
Okay. 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 for per-unit cost moving forward?
On our unit operating expense, we're at, for the quarter, $665. The trend has been down. 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 protection as we drill and frac more wells in and around local wells. That, dependent on the wells you're completing in a month or a quarter, you can see it bump up and down. In general, I'd say it's on a downward trend.
Great. Then 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? I'll hop back in the queue. Thanks, guys.
Yeah. 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. 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 guidance on that G&A side or on the lower end of that guidance, as you guys can see.
Okay. Thank you.
You bet. Thanks.
Your next question comes from the line of Irene Haas with Wunderlich Securities.
Hey. Congratulations on a really strong quarter. Obviously, bypassing the issue of wet weather, your planning and infrastructure investment is really kicking in. It just seems like you have Williston Basin in good order. Any appetite for building a new core area?
Irene, as we've talked about, we've got, I guess it was this time last year where we really formalized a business development team, they've been doing some other reconnaissance outside of the Williston, more Upper Rockies things that look like it. We've actually kept them pretty busy over the last six months or so, just working Williston projects. We've had enough to keep them occupied with that. In the near term probably continue to focus on Williston. We'll just see where it takes us.
Okay, great. Thanks.
You bet.
Your next question comes from the line of Drew Zenker with Morgan Stanley.
Hi, good morning.
Morning.
I was hoping you could talk a little bit about what you see as a potential for slick-water fracs to improve performance, and if you have any idea as far as what the difference in well cost would be.
We've been doing some work on slick-water fracs, and we actually have a couple of wells scheduled for slick-water fracs this year. In fact, one was just completed and has been on production, is flowing back. It's only been on for three days. We're going to evaluate the results of those slick-water wells relative to our typical fracs in those areas. The slick-water fracs that we're doing are more expensive, primarily because of the volume of water used in those fracs. Our typical frac is about 70,000 barrels of fluid. The slick-water 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 million. It just depends on the area.
Okay. What areas are you testing, or is it just all over?
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. We'll branch out from there if we decide to take more steps.
I guess going back to the simultaneous operations you guys talked about, you have any initial estimate of the potential improvement in spud to first sales on average for a pad?
I don't have days, the way you can think about it is, without simultaneous operations, you would drill eight wells back-to-back, we're now drilling spud to rig release is 23 days. You think of each of those close to a month, rather than waiting three and a half, I mean, a total of seven to eight months to start completing wells, after three and a half to four months, we'll be completing wells within that pad.
Is cutting that time in half a reasonable expectation, just on average?
Yeah. Not quite half, relative to if you did a four-well pad, it's going to help you on time. On smaller pads, you can't really apply that across the spectrum because, say a two to a four-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.
Okay, thanks.
Your next question comes from the line of Leo Mariani with KS.
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 % 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. 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. As we go to more full pad operations, you'll see that, we just don't have a % or assessment of that yet.
Okay. Looking at those three DSUs that have been on production for some time, what areas were those located in?
There were two in what we call Alger, which is on the east side, south of Cottonwood. There was one that was in Montana, in Hebron.
Great. My last question is, do you have any update on the Three Forks wells that you guys had planned to drill outside of Indian Hills and South Cottonwood in 2013? What's going on there?
We've got three additional wells in Cottonwood, in North Cottonwood, that'll be drilled in the first bench in the second half. As I mentioned, we have one second bench well that'll be in Cottonwood as well, that'll be in the second half. They're either drilling currently or will spud within the next couple of months.
Okay, great. Thank you.
Yep, thanks.
Your next question comes from the line of Peter Mahon 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 a downward pricing pressure in the service sector versus how much comes from the efficiencies that you guys have built into the model?
As I talked about before, the cost savings this year Service component, but the majority of it is really efficiency, well design, pad operations, all those things, improve cycle times.
Got it. Could you talk through what you're doing now in terms of just your fracking 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 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 three-well pad. Historically, we had done sand and ceramic in Montana, and we're shifting that. The other thing we're experimenting with is sleeves in some areas.
There's 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. Just depends on the area. 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.
Yeah, thanks.
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, 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.