Good morning. My name is Brian. I will be your conference operator today. At this time, I'd like to welcome everyone to the first quarter 2018 earnings release and operations update for Oasis Petroleum. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touch-tone phone. To withdraw your question, please press star then two. Please note, this event is being recorded. I will now turn the call over to Michael Lou, Oasis Petroleum CFO, to begin the conference. Thank you. You may begin the conference.
Thank you, Brian. Good morning, everyone. This is Michael Lou. Today, we are reporting our first quarter 2018 financial and operational 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 on both Oasis Petroleum and Oasis Midstream Partners, 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 releases and conference calls.
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 make reference to non-GAAP measures and reconciliations to the applicable GAAP measures can be found in our earnings releases and on our websites. We will also reference our current investor presentation, which you can find on our website. With that, I'll turn the call over to Tommy.
Good morning. Thank you for joining our call. Oasis completed another solid quarter as we began to execute on the 2018 plan we outlined in February. We closed the Forge acquisition on February 14th and have taken over operations and continue to integrate that world-class asset into our portfolio. We're off to a great start to the year, producing 76,800 BOEs per day in the first quarter, while maintaining top-tier capital efficiency, cash margins, and resulting recycle ratio. We maintain our projection of being free cash flow positive on our E&P business for the year, while continuing to grow volumes at 15%-20% year-over-year. Internally controlled infrastructure through OMS supported flow assurance, reduced costs, and provided access to liquid marketing points. This combination resulted in reduced downtime and per-barrel operating costs in spite of abnormally difficult winter conditions.
We remain on pace to exceed our stated 2018 combined exit rate of 88,000 BOEs per day, and we are focusing on the second quarter, ranging between 76,000 to 80,500 BOEs per day. Additionally, we have increased our full year guidance to 81,000 to 84,000 BOEs per day. The team did a tremendous job of managing capital costs and delivering several capital efficiency gains over the quarter. Our well services business continues to drive down costs and increase frac efficiency on our Williston wells, and OWS completed about two-thirds of our wells during the quarter. Our third-party frac performance has been very good as well. In spite of higher oil prices, our well costs remain in line with where they entered the year. We continue to see limited cost inflation or service tightness in the Williston or in the Delaware.
We are focused on continuing to streamline operations with lower costs, and we look forward to transferring our Williston expertise to the Delaware Basin, where we can use what we have learned in the Williston to address current challenges that operators are dealing with there, especially as we plan for future full field development, employ our detailed two-year forward planning model. Due to our long-term relationships that we have developed with our service partners in the Williston, Oasis has secured critical services at market competitive prices in the Delaware. We see many service providers, both large and small, that want to partner with Oasis early on and grow with us as we ramp up operations in the Delaware. Oasis continues to deliver great cash margins and high returns, which results in one of the highest, if not the highest, recycle ratios among our peers, as described on page six of our presentation.
We expect to continue to be E&P cash flow neutral to positive, as we were in the first quarter of 2018, with 15%-20% production growth through 2019 in a $55-$60 WTI world. With that, I will turn the call over to Taylor.
Thanks, Tommy. It was a strong start to 2018 for Oasis as the team closed the Forge acquisition and began to integrate the asset into our portfolio. G&A was a little higher than normal due to the costs associated with the acquisition, but we expect to remain within our guidance for the year. During the quarter, we completed one gross well with 100% working interest in the Delaware. We are currently running one rig, and the second is expected to start in late May.
Completion activity in the Delaware should generally be pretty consistent throughout the next couple of quarters, with a little step-up in activity in the fourth quarter as we look to complete six to eight wells in 2018. In the Williston, we are primarily focused in the core and still expect to complete a total of 100 to 110 gross operated wells in 2018, with the remaining completions this year being pretty evenly spread across the remaining quarters, with the second quarter being weighted more to the back end. We have budgeted some inflation into our full-year cost estimates. We still expect to spend between $815 million-$855 million on upstream capital expenditures, with about 85% of that capital in the Williston and about 90% of E&P capital on drilling and completions.
Keep in mind that all of our guidance on spending and production is before the impact of our divestiture program, which we hope to have a formal update on sometime mid-year. Early interest in the targeted assets has been encouraging. As far as well performance, as you can see in the presentation, our wells in the core of the Williston continue to perform in line with expectations and with our new type curves we showed in February. We budgeted 10 million pounds of proppant for the Bakken and four million pounds for the Three Forks. We will continue to optimize our frac design to further enhance our returns. During the quarter, we have seen strong well performance in our Alger area, with our recently completed Spratley wells performing in line with our Wild Basin and Alger type curve.
As far as updates on our other core areas, as you can see in the presentation, our Indian Hills wells continue to perform above the type curve. In addition, we recently moved Painted Woods into the core due to strong performance seen by offset operators. We plan on conducting enhanced completions and spacing tests in our Painted Woods area in the second half of the year. In the Delaware, our Wolfcamp wells continue to exceed our expectations, significantly outperforming the industry 1.2 million BOE type curves. All wells are still naturally flowing, with our Bighorn well still flowing after almost two years on production. We expect to continue to improve returns through the use of longer laterals and optimizing completion techniques.
On the operational cost front, the team did a tremendous job of reducing lifting costs during the quarter, with LOE per BOE of $6.48 coming in below our guidance range on the year of $7.00-$7.50 per BOE. In light of our operational success, we are changing the low end of our guidance on LOE to $6.50 per BOE, with the full year expected to be between $6.50-$7.50 per BOE. We also continue to realize remarkably tight oil price differentials, with our first quarter average being $1.69 per barrel within our guidance range of $1.50-$2.00 on the year. Going forward, we continue to expect to see oil differentials within that range. While Permian differentials are high right now, we see sufficient long-haul pipelines being built by the second half of 2019 to eliminate the gap.
The increased capacity coincides with the timing of activity acceleration in our program for the Permian. For now, though, 95% of our production enjoy the tight differentials we are experiencing in the Williston Basin. To close, it is a very exciting time in Oasis. We are greatly encouraged by the start of the year as we continue to make progress on our 2018 goals and objectives. I'll now turn the call over to Michael.
Thanks, Taylor. Thanks to the strength of our operations, we were free cash flow positive on our upstream business again on the quarter. We continue to enjoy strong liquidity levels with a total borrowing base of $1.6 billion and less than half of our credit facility drawn as of March 31, 2018. Oasis has a net debt to first quarter 2018 annualized EBITDA multiple of 2.9 times, with EBITDA exceeding $230 million in the first quarter. We have no significant near-term debt maturities and plan on pushing out our debt stack through the tender process we announced back in April. The tender process will be funded by our recent $400 million offering of senior notes due 2026, which price at the tightest level Oasis has seen since going public.
Our 2018 program remains secure given our prudent financial risk management with approximately 70% of 2018 estimated production hedged, and we have added 2019 hedges at high oil prices, ensuring program success in spite of volatile commodity prices. On the midstream front, we continue to leverage Oasis Midstream Services or OMS's ability to improve our world-class operating margins and full field development capabilities. The OMS assets are critical to Oasis's operations, and Oasis will also benefit by OMS' ability to bring on third-party opportunities, which could have a strong positive impact on both Oasis and Oasis Midstream Partners' financial success. OMS has been successful in and continues to pursue accretive third-party projects with strong project-level returns that complement our robust Williston footprint. As you know, gas production continues to increase in the core of the Williston Basin and is starting to push up against existing processing capacity.
Additionally, North Dakota gas capture regulations are getting tighter, but our team has done a tremendous job getting in front of these requirements through forward operational planning and foresight.
Ensuring that Oasis has the gas capture and processing capacity to meet regulatory requirements. We plan to use our new 200 million a day processing plant in Wild Basin to maintain our gas capture rates. The new plant is scheduled to come online at the end of the year and is already over 65% complete, with all major equipment set in place, running both on time and on budget, and is fully funded by OMP with the bulk of spending being in the first three quarters. Going forward, we expect to continue to be free cash flow positive on our upstream business while growing production 15%-20% annually. Midstream capital is expected to be funded by OMP through drops to OMP over time. Oasis is off to a great start in 2018 and remains on track to provide best-in-class capital efficient growth.
With that, I'll turn the call back over to Brian for questions.
We'll now begin the question and answer session. To ask a question, you may press star then one on your telephone keypad. We do ask if you're using a speakerphone to please pick up the handset before pressing the keys. To withdraw the question, please press star then two. Once again, if you'd like to ask a question today, please press star then one. At this time, we'll pause momentarily to assemble the roster. Our first question today comes from Brad Heffern with RBC. Please go ahead.
Hey, good morning, everyone.
Morning, Brad.
On the Delaware, I saw you guys are adding the second rig soon. You also made the comment that your ramping activity is going to coincide with some of the long-haul pipes coming on in the Delaware. Is the implication there that this two-rig program is sort of what's going to be run until the middle of 2019?
The plan is, like we said, is to add this rig in May. When you look at the amount of wells that are going to be drilled relative to the completion cadence for the year, it's six to eight wells that'll be completed. Quite a few more wells are going to be drilled, 15 kind of range. Then as you get into 2019, we'll continue to run two rigs, and somewhere likely in the back half of the year, as we said, we'd pick up the pace and add another rig and then have the ability to complete more wells.
Okay. Got it. Then any results you can give from the well that was placed online this quarter in the Delaware? Also, when are we going to see the first sort of Oasis location selected designs completed well results?
Yeah. The one well that came online is Bone Spring well, but it's only been on for about 30 days, so it's very early time. We're encouraged by what we're seeing, but we're going to need 6 months plus of data to form an opinion of what the wells are looking like. You'll hear more about that one later on. As far as the completion techniques, we've taken what the prior operator was doing, and have started to modify that, and the modifications that we've made so far have been a little bit of increase in size, so higher proppant loadings and higher fluid amounts as well. We're working on a number of stages in the wells, cluster spacing, a number of other things that we'll talk about as we get more into the program.
Okay. Thanks all.
The next question today comes from Dave Kistler with Simmons Piper Jaffray. Please go ahead.
Good morning, guys.
Hey, Dave.
You briefly touched on the divestiture updates, I know with the process ongoing, it's hard to give us a lot of color commentary on it. Commodity prices had a pretty nice uplift since you first mentioned what you were looking at doing. Can you talk a little bit just generally about whether that might impact the size of what you sell, i.e., selling less, still garnering $500 million, or potentially looking at an increase in the aggregate cash received if you go ahead and sell everything you'd originally targeted?
Dave, we've talked about what we're looking at, what we talked about was all the fairway acreage in our presentation. It's about 200,000 acres along with some of the non-op. It's about 8,000 to 10,000 barrels a day of production. What we said at the time was that we don't think we have to sell all of it to get to that $500. I think that's still true. We're going to evaluate. We've had strong interest. We're going to evaluate, and we'll figure that out. It certainly could be $500 selling less assets or selling the same amount of assets and getting more proceeds. We don't have an answer to that. Like Taylor mentioned earlier, we'll give an update, a more formal update call in the middle of summer.
Great. I appreciate that clarification. Then maybe thinking a little bit about the commentary on an expectation of a drop-down to OMP. Just trying to think about it more in terms of balance sheet and whether we should be looking at the divestiture coming first, the drop-down coming first, indifference on that front, and target of what you're hoping to get to on a balance sheet perspective by year-end.
Yeah, good question. We've talked about drop-downs. Obviously, we've got some outspend on the infrastructure side this year that we said we're going to fund through OMP. I think you will see that. We don't have an exact timing on that. Obviously, we'll update you as we get along. I'm going to guess that's going to be the back half of the year.
Okay.
From a balance sheet standpoint, obviously, we'll look at divestitures along with the drop-down, and we'll see where we come out. At under three times debt to EBITDA now with EBITDA growing, naturally we're de-levering without even any divestitures or drop-down. Those two things are going to obviously improve the balance sheet pretty significantly when those happen. It'll obviously be dependent upon size and what we actually get done.
Okay. Appreciate that. Can I sneak one last one in here?
Please.
Just looking at the hydrocarbon mix, obviously gas level ticked up a little bit. You made the commentary about the 200 million processing facility coming online. How should we be thinking about that going forward? Obviously great to have that access so it doesn't inhibit oil growth, just so we can kind of model out mix and make sure we're heading in the right direction when we're looking at that 88 exit.
Yeah. I think when we put out guidance at the beginning of the year, we were thinking about 76% kind of throughout the year. 76.4% at the beginning of the first quarter is right in line with where we expected it to be. I think that 200 million a day plant, what you'll see is that we'll have some operations in Wild Basin that will come online and help fill the plant. I think we'll kind of stay in that 76% neighborhood. I think that's how you should think about the exit rate too, is kind of in that 76% neighborhood.
Perfect. I appreciate the clarifications, guys. Thanks so much.
Thanks, Dave.
Thank you.
Next question comes from Jeoffrey Lambujon with Tudor, Pickering, Holt & Co.. Please go ahead.
Good morning. Thanks for taking my questions. First one's on the Delaware. Just wondering what the current plans are for approaching the midstream side of the operations there. Are you looking to take out capacity on some of the systems that are scheduled to start up around that back half 2019 timeframe you mentioned? Also from the gathering and water standpoints, would be great to hear what the approach is there as it stands.
On the midstream side, as we did the acquisition, everybody saw that midstream was going to be very tight in the basin really for the next call it 18 months until call it the second half of 2019. We didn't get into any big acceleration plans until really seeing that. We've talked about that was one of the reasons why we're growing up in the Williston. Great differentials there. We'll wait for that big pipe to come in on the crude side as well as the gas and NGL side in the second half of 2019. From a gathering perspective, there's actually a lot of opportunities there. We're continuing to evaluate the gathering opportunities. A lot of great third parties that are out there that we'll continue to talk to.
Obviously, we think there's a lot of opportunities for OMP as well. We'll continue to evaluate that. You can look to what we did in the Williston as a way to think about things. We were, I think, very thoughtful in the Williston when we put our long-term gathering agreements in place. It got us to multiple points, very liquid markets, and because of the thoughtfulness of our marketing team, we enjoy some of the best differentials in the Williston. That's what we're looking for in the Delaware. We set up really well on that position because we're very close to the Wink, which will be the crude hub, and as well as we're very close to Waha, which is the gas hub. You sit location-wise from the Delaware perspective, very close to the two largest hubs, both on the crude side and the gas side.
Feel advantaged on that side as well. You mentioned the long-term pipe, and as you can imagine, we are securing some of that long-haul transportation. It gives us a lot of comfort on differentials in the Delaware being similar to the strong differentials in the Williston or maybe even better on a longer-term perspective.
Great. Appreciate the detail there. Second one's on the Williston, just regarding the gas capture regulations you mentioned. I guess first, can you talk about what the main changes are that are coming over the course of the year that you're watching the closest? Also maybe we can get a reminder of how you're positioned until that second plant comes on.
The regulations change from 85% capture rate to 88% at the end of the year, in November timeframe. We're capturing above 90%, and we have been for a while, the 200 million a day plant basically keeps us in a position to keep that capture rate very strong in that 90% range. The gas plant will obviously be helpful to us because we have a lot of our activity that continues to go on in Wild Basin. We also see quite a bit of third-party opportunities for OMS/OMP in that area as well. A lot of producers active in that area, and we know processing capacity is definitely tight.
Great. Thanks a lot.
Thank you.
Next question comes from Mike Kelly with Seaport Global. Please go ahead.
Hey, guys. Good morning.
Morning.
In the Delaware, I just wanted to get a sense, if you could remind us what percentage of this acreage is held, and I wanted to get your sense on how committed you are to going to a two-rig program here in the face of these differentials potentially being stressed through maybe middle of next year. Thanks.
In terms of the program needed to hold the acreage, it's a modest program. This year, it's on the order of one and a half rigs or so in terms of activity at current drill times. As you go forward, that steps up a little bit. As you get to 2019, it's on the order of two to maybe two and a half rigs, and then it steps up in 2020, a little beyond that, but not a huge amount. For us, it's really a manageable program, and it coincides with what we were talking about, that increase in activity level, which really gets more back-end loaded towards 2019 and 2020.
It also allows us, the way it's set up, to really optimize from a spacing and a testing standpoint. A lot of this acreage, if you'll remember, is on University Lands, the majority of it. We've got an agreement where we don't have to jump around and drill wells to hold. We can optimize that program and drill wells in the same spacing unit and satisfy drilling obligations to hold that land. It really gives us the benefit of being able to test and go to full field development sooner than you would be able to otherwise, compared to some of the other things going on in the basin.
Got it. Appreciate that. Sticking to the Delaware, how should we think about your appetite for continued bolt-on acquisitions? Maybe if you could touch on the opportunity set for acreage swaps, trades with your neighbors here in the play. Thank you.
We've got around 22,000 acres with the current position. As you think about the amount of core inventory here with the thickness of the section, as we compared it to the Williston with this thicker section, you can think about per surface acres, what you're getting is three to five times what we'd consider from a surface footprint in Williston. We've got a big runway of core locations, over 500 with the new acreage. We're very focused right now on continuing to core up the position. It's really smaller deals, trades, trying to block out more of the acreage, put ourselves in a position to drill more long laterals, even though most of this is set up for long laterals at this point, and then continue to block it together. We don't have a big need to go do a large-scale acquisition.
It's really supporting this position. Over time, yeah, we'd love to continue to add to it. It's not unlike what we've done in the Williston. When you look at the Williston, we built that position over a seven-year period. Highly focused on adding positions that really accrete to our skill set. We're going to do the same thing here. We're going to, over time, look for more opportunities to add chunky acreage that has high control and will allow us to get the benefits of both infrastructure and our well services business.
Great. Thanks, guys.
Thanks.
The next question comes from Ron Mills with Johnson Rice & Company. Please go ahead.
Morning, guys. Just to stick on the Delaware a little bit. Good job on the infrastructure. Can you talk about access to two rigs as you look to go from two rigs this month and a third rig next year, and also, how you plan to fold in completion crews in terms of when would you potentially need a dedicated crew, how does OWS fit into that equation, and so forth?
As far as the rigs are concerned, fortunately with the relationships that we developed in Williston, a lot of the same providers are in the Permian in West Texas. That's really led us to ample opportunities both on the rig and the frac crew side of the business. Picking up this, as we said, this second rig in May, third rig next year, and we think when we get to that point, we'll be able to do that without a problem. What we've seen in terms of frac crews has actually been quite a bit of availability. We've reached an agreement on the balance of the year to do our frac work. We're not at a point where we've got a full schedule where we can have a dedicated crew. We've got some spots along the way where we'll get our wells fracked.
A good example is we were planning on fracking a well this quarter, but probably a little later this quarter. With the arrangement we've reached, we're going to get a frac a little earlier than we originally thought, which is right now. We're fracking today. We think we'll see the same thing with the provider that we're working with for the balance of the year. We don't expect any problem in getting the wells fracked on time. As you look forward in time, to get to the point where we can justify a dedicated frac crew is probably second half of 2019 to early 2020. Again, that period when we're talking about ramping up. We're actually looking at it right now, and we're continuing to evaluate going forward, whether it makes sense for us to bring one of our own crews into the basin.
In that event, we probably just build an additional spread. We're under evaluation, and we've got really the rest of this year to make that decision. We'll talk about that later in time.
I guess, kind of a corollary, relative to your original expectations in the Delaware and even on what you expected up in the Williston, with the increased oil prices, are you seeing any cost inflation or much at all? If so, what items have been more susceptible to inflation?
Ron, if you look at the well cost quarter-over-quarter, so going 4Q to 2017 to 1Q, we're really flat. We haven't seen increases on the big ticket items. Really, it's been fairly flat, fairly well-behaved. There's a number of items that we're keeping an eye on. Steel will be one of those. Labor in the Permian is pretty tight. Really, we feel pretty good about the well cost at this point. We'll continue to track them as we go through the year and see where we end up. As we talked about in our prepared comments, we've incorporated inflation in our budgeted numbers. Fortunately, we haven't really seen much of that to this point, and we'll update you as we go.
Great. One more, since you've moved Painted Woods over to the core now in the Williston, can you just provide an updated core inventory account at your current activity levels? Once you fill this Wild Basin plant, do you anticipate starting to maybe move some rigs around to other areas outside of Wild Basin, Alger, et cetera?
Ron, you're right. We're going to move the rig into Painted Woods. We're actually drilling there, and we'll complete wells in the second half in Painted Woods. If you look on page four of the presentation, you can see. Actually, turn to the better one for Williston. It's page 10. You can see that our core inventory incorporating Painted Woods, with that inclusion, we went from 483 to 585 net locations in the core. Nice expansion of core locations in that area. Now, when you think about where the drilling activity is going to be, we're going to run rigs this year in Wild Basin, Alger, Indian Hills, and as I said, in Painted Woods to do the pilots in Painted Woods.
As the gas plant comes on at the end of the year and going into next year, we'll still have at least one rig running in Wild Basin. It's going to be one to two rigs going forward to throttle to keep the volumes where we want them for our internal volumes. The additional rigs, as you think about the five-rig program we've been talking about, are going to be Alger, Indian Hills, and then branching out into places like Painted Woods and East Red Bank.
Great. Thank you.
Next question comes from Gail Nicholson with KLR Group. Please go ahead.
Good morning, everyone. I'm just looking at the oil differential. How much of the Williston volumes go to premium markets versus going to Clearbrook? Is that something that you think that can continue to shift to the premium markets? Have you locked in any contracts and considered maybe hedging directly to Brent?
Yeah, our hedging has to date all been to WTI. We're continuing to watch that in terms of where you hedge. Most of our barrels get to premium markets. Most of them are able to get to either the East Coast or the Gulf Coast, both being more of that Brent type pricing. That's one of the reasons you're getting very strong differentials in the Williston is that you have opportunities to get to those stronger markets overall.
Looking at the February presentation versus the recent released May presentation, I'm looking at the other core areas of Bakken well performance. The new presentation that the curve is above the actual average cumulative production in the wells is above the type curve versus the previous presentation, it was on the type curve. I was just wondering what the driver was there.
It's just the performance of Indian Hills wells versus that type curve over time. That's all the wells that you're seeing in that other core area is just Indian Hills at this point. Then over time, as we look at some of these other areas, in the core outside of Indian Hills, Alger and Wild Basin, we'll add additional information for those areas. We hadn't been drilling outside of Wild Basin long enough to have more data with these bigger frack jobs, we'll have more of that as we go forward.
Okay, great. Thank you.
The next question comes from David Deckelbaum with KeyBanc. Please go ahead.
Good morning, guys.
Hey, Dave.
Just was looking, I'm not sure if you commented on this already. The comment in the press release that you'd been ahead of schedule this year so far. Considering some of the weather that you saw up in the Bakken in the first quarter, where are you seeing some of the time savings or efficiency gains? I guess you guided the rest of the year that things smooth out. Are you just assuming that you converge back to the original timing of your plan?
Yeah, there's a couple of things. Taylor can give you some more color. The group did a really good job in the first quarter on managing downtime. Plus, with the infrastructure that we've got in place, where you don't have to move trucks, that helps a lot. I think a lot of it was just capital well performance and reduction in downtime relative to what we had modeled or planned originally.
Yeah, that's accurate. As you look at the remainder of the year, the total activity levels or wells completed in Williston for the quarter were 16 with 100 to 110 projection. If you smooth that out for the rest of the year, that's about 30 wells a quarter. It's a big step up in activity. Now, in terms of wells fracked, if you look at the DUCs, we actually built a DUC backlog this quarter. We bumped it up from high 70s, I think, to around 90 or so. That's a reflection of frack activity. We're able to frack a number of wells that we didn't get cleaned out during the quarter, which sets us up with better weather now and being outside of breakups. We go from the winter weather, which slows us down a bit, and then also breakup, where you're in road bans.
We're pretty much past that at this point. We've got a good runway of weather and conditions that we can get more of these wells online. We expect, like we said, about 30 a quarter for the balance of the year in Williston. When you look in Delaware, the six to eight wells, we did one well this quarter, and you're probably going to see around that for the next few quarters, and then a little higher pace of activity at the end of the year.
I appreciate the color on that. Just the last one for me is just as you think about the program ramping in the Delaware with the second rig, how are you thinking about your own spend on water handling going into 2019 in the area versus third-party services available to you, either for sourcing or for disposal?
With the addition of a rig, we've been looking at the early time projections on production, and water's certainly one of those things that's important in the Delaware. We will add some internal disposal capacity this year. We'll be drilling an SWD well, our second operated SWD well, in the not-too-distant future, likely this quarter. We're looking at additional capacity as well. We've also got some agreements where we can offload to third party. We've got a couple of those, which gives us a lot of flexibility in terms of where we send the barrels. Longer term, Michael talked about this earlier, we're developing a view of what the production profile looks over the coming years, and we'll have really a more holistic approach for midstream services and potentially OMP to incorporate that water into our business.
This year and next year, well-covered, developing a bigger plan as we go beyond that.
Understood. Thanks, Taylor. Thanks, guys.
Thanks.
At this time, this will conclude the question and answer session for today. I'll now turn the conference back over to Thomas Nusz for any closing remarks.
Thanks, Brian. The Oasis team is off to another great start and has the resources and planning processes in place to exceed expectations in an uncertain but improving market while maintaining top-tier capital efficiency and cash margins. Thank you again for joining our call.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.