Good morning. My name is Ginger, and I will be your conference operator today. At this time, I would like to welcome everyone to the year end 12 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 the conference.
Thank you, Ginger. Good morning, everyone. This is Michael Liu. We are reporting our 4th quarter year end twenty 12 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 our 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've 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 and our quarterly report on Form 10 Q. We disclaim any obligation to update these forward looking statements.
During this 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. Following our normal format, I'll make some introductory comments, Taylor will follow with some operational color with a focus on our 2013 plan and Michael will finish with a few financial highlights. For the 1st 18 months post IPO, you heard us consistently talk about executing on our identified drilling inventory and focusing on holding our tremendous acreage position. With that objective in sight, our senior leadership team gathered at the beginning of 2012 to identify strategic risks and opportunities that we would be facing over the following 12 months as we transitioned from just holding acreage to full development.
We had a broad dialogue covering important topics like our safety program, organizational development, capital discipline, oil movement and the resulting differentials and continuing cost control. With this as a framework, we established ambitious milestones and target metrics for 2012. As you've seen in our results, the team delivered on our objectives with results including value added growth and production, reserves, acreage and drilling inventory, capital efficiency and oil price realizations. As we look to 2013, we have again outlined our strategic agenda for the next 12 to 24 months, including optimizing our development program, including pad operations, infill density and continued focus on cost control. Oil supply demand in North America and the resulting pricing and differentials organization development and improvement including additional focus on regulatory items and community relations and finally business growth.
Taylor will touch on 2013 in more detail in a moment, but before he does, I want to start with a discussion of value added growth in 2012. We grew production 110 percent in 2012 to 22,500 BOEs per day, and we exited the year with 27,600 BOEs per day in the 4th quarter. Our proved developed reserves grew by 95% to 70,000,000 BOEs and total proved reserves grew 82% to 143.3 1,000,000 BOEs resulting in a proved developed to total proved ratio of 49%. Most importantly, we accomplished this growth while improving capital efficiency. Additionally, we were able to improve overall operational performance significantly in 2012 by staffing the right personnel throughout the organization and working constructively with our service providers on both costs and efficiency.
We also successfully high graded and grew our net acres by 9% in 2012 up to 335,000 383 total net acres. Of this, we count approximately 305,000 as core to the Bakken. As of year end, we had 265,000 acres held by production. Through acreage acquisitions and various trades in 2012, we added 37 controlled operated drilling spacing units to our inventory, increasing the number of drilling blocks, further derisking the Three Forks across our position and improving comfort around infill density resulted in an increase to our gross operated primary inventory up to 9 87 locations. Next, Oasis delivered a great year in terms of capital efficiency.
We drove down average well cost from $10,500,000 in the first half of twenty twelve to approximately $8,800,000 while maintaining our EURs. This was accomplished through a combination of lower service costs, efficiency gains and completion and well design optimizations. As we move into 2013, we expect 60% to 70% of our wells to be on pads, which should continue to improve efficiencies and reduce costs. The 3rd driver of value the team has been focusing on is improving price realizations. Just over a year ago, we started moving our operated oil production into a third party oil gathering system, which gives us access to 6 different rail facilities and 4 pipeline connections.
The increased optionality that rail provides has allowed us to drive down differentials. In 2012, our differentials to WTI dropped from 14% in the Q1 to 1.6% in the 4th quarter. We've been able to utilize rail to get crude to coastal markets where it can achieve better price realizations than if the volumes were piped. We currently have about 80% of our crude transported via rail to take advantage of the strong differentials. With that, I'll turn the call over to Taylor.
Thanks, Tommy. In 2013, we are expecting production for the year to range between 30000,34000 barrels equivalent per day on average and are targeting 27,000 to 29,000 barrels a day equivalent for the Q1 of 2013. In an effort to mitigate the impact of tough winter conditions, we are utilizing multiple well pads that will limit the amount of rig moves during this time. On pads, production tends to be delayed as the time from spud to first production is increased for all but the last well drilled. Consequently, early year pad drilling should result in backloaded production with moderate growth during the first half of the year and a ramp in the 3rd and 4th quarters.
In 2013, we have a total capital expenditure budget of just over $1,000,000,000 and plan to complete 128 gross operated wells and 133 total net wells. Approximately 88% or a little less than $900,000,000 of the capital budget is directed to our drilling and completion activities with the remainder spent primarily on other items such as leasehold, infrastructure, geology and well services. As Kami mentioned, our pad development program is a key initiative in 2013. As we move into pad drilling, we will be able to mobilize rigs more efficiently, improve frac crew utilization, decrease our footprint and implement central tank batteries to reduce well and operating cost. Ultimately, we expect to reduce well cost by 5% to 10% compared to a single well.
We're budgeting an average of $8,600,000 per well and have set an internal goal to drive well cost down to $8,000,000 by the end of the year, although this is not reflected in our budget. One of the key cost reduction drivers in 2012 was the impact of OWS and it will continue to be a key initiative in 2013. Through the utilization of OWS, we were able to save $17,500,000 capital expenditures on Oasis operated wells. In 2013, we are forecasting savings of approximately $500,000 for gross well completed and we intend to use OWS on approximately 40% to 50% of our wells. A third initiative for Oasis will be to improve our understanding on both infill density and 3 Forks prospectivity across our position.
We expect to drill infill pilots in 22 spacing units with effective spacing ranging from 6 to 12 wells per spacing unit. We currently include from 3 to 7 wells per spacing unit in our primary inventory, so the results of our pilots have the potential 2013, we hope to move more of our Three Forks inventory into the primary category as well. Currently, we have approximately 110,000 acres or about a third of our acreage included in our primary Three Forks inventory. At the end of 2012, we brought on production 2 additional extensional tests, the Justice and Hebron in the Mercedes and Red Bank. Early results from these wells are encouraging as they look similar to nearby Bakken wells.
Additional extensional test in 2013 include 8 Three Forks wells in North Cottonwood, 10 in Red Bank and 2 in Montana. The results of the 20122013 Three Forks extensional program will help us to ship more of the Three Forks inventory from potential to primary. Including the extensional wells, we plan to drill we will have 6 vertical pilot wells drilled into the lower benches by the end of the Q1. The vertical pilot wells will have cores and high resolution logs to provide data in the lower benches in each of our major producing areas. These results will help us to select the areas where we will pilot test 2nd and possibly 3rd bench wells in late 2013 and in 2014.
To wrap up our operational highlights, our infrastructure is substantially complete for oil, gas and produced water. Our oil gathering system will be complete on the east side by the end of the Q1 and a small section of Indian Hills just north of the river will be completed by the end of the second quarter. Once these are established, we'll have more than 80% of our volumes flowing through pipe. Our gas infrastructure currently captures approximately 90% of our gas in liquids production and will continue to kick up as we connect our wells. In the Q4, we were able to produce and sell approximately 15,300,000 cubic feet per day or 50% more gas than the Q3 due to new well connections in October.
Finally, through our SWD system, we are currently disposing of approximately 75% of our produced water into Oasis operated SWD wells with approximately 55% flowing through our pipelines. We will continue to leverage the backbone of our SWD system as we connect new wells and ultimately reduce our operating costs associated with water handling. In 2013, we are expecting LOE to be between $5.75 $7 per BOE. With that, I'll turn it over to Michael to discuss the financial highlights.
Thanks, Taylor. We had another great year as we continue to execute on our plan, drive down well costs, expand our leasehold position, capitalize on higher price realizations and build out our team. For the year, we spent $1,150,000,000 and completed 117 gross operated wells. Differentials for the quarter were at an all time low at 1.6%, largely due to the benefit of rail getting to the coast and we'll continue to look for ways to optimize our realizations. Production taxes were 9.4% in the year, and LOE closed out the year and the quarter at $6.68 per BOE, down from $7.23 per BOE in the 3rd quarter.
Our total G and A was $57,200,000 including the G and A associated with OWS. In the 4th quarter, we had adjusted EBITDA of $164,000,000 an increase of 17% over the prior quarter, primarily due to production growth and differential improvement. For the full year, adjusted EBITDA was $512,000,000 and we exited the year with $239,000,000 of cash on hand. Combining this with our revolver capacity of $748,000,000 we had total liquidity of $987,000,000 available to invest in the business in 2013. In light of this, to protect our drilling program, we have also hedged approximately 20,700 barrels of oil per day in 2013 at approximately $90 floors and 8,500 barrels of oil per day in 2014 at approximately $91 floors.
To close out, we are excited about what 2013 has in store. We have a great team and the right assets to drive execution, growth, efficiency and shareholder value. With that, we'll turn the call over to Ginger to open the lines up for questions.
Your first question comes from Peter Mahone.
Good morning, guys. I just had two questions. You talk about well costs going down in 2012 and going down further in 2013. Can you give me some idea of how that should roll through the depletion line? Like when should we start to see that line item decline?
Because steadily throughout 2012, we saw that increase on a per BOE basis. So how should we think about that in 2013 and into 2014?
Yes, Peter, DD and A is a lagging indicator of our well costs. And so we reset our DD and A twice a year. So what you'll see is that the 3rd Q4 of last year really reflects what happened in the early part of 2012. So reflects the higher well costs from the beginning part of the year. And as we move into this year and the first and second quarters of this year, you should start to see that come back down.
And certainly throughout the rest of the year, you'll see that DD and A rate come back down a little bit.
Sounds great. And then you also mentioned that more of your production is coming out of the Montana side of the play. When you look at the wells results so far, have they been consistent with kind of your decline curve that you set out maybe a year or 2 ago?
Yes. Generally, the wells in Montana have been consistent with what we were seeing about a year ago and continues to play out Montana positively. I'll be it.
They tend to be more to the lower end of the type curve range that we've set out there.
Yes. So they're probably more in the type curve is 600 MBOEs and the average wells in Montana are probably more in the 450 to 500 MBOE range.
Question is from Eli Kantor.
Hey, good morning guys. Nice quarter.
Good morning.
I had two quick questions. First is on the Middle Bakken and TFS 3x3 down spacing pilot that you completed last year. It looks like results from the Middle Bakken were
pretty much just as good as
what you had achieved from standalone completions in the field. But the rates from the TFS wells were not as prolific. And I was wondering, if you're seeing any what you're seeing on the performance end from the TFS wells? And if the lower peak month rates are related to geology or if it's a completion issue.
So which pilot you're talking about? The Davis unit? Is it in Indian Hills?
Yes. That's right. It's the Davis unit.
Okay. So there one of the Three Forks wells in that pilot, we are only able to initially get 10 stages off in the well. So the early results on that well were muted. We have gone back and finished that frac. And so the rate is up on that well.
In general, when we look across the positions, so the areas where the Three Forks is working, Alger, wells in North Cottonwood, Indian Hills and Eastern Red Bank. Generally, the Three Forks wells are performing pretty close to what the Bakken wells are doing in the area to a little bit below it. So about the same to at most 10% down, but it's still early days in terms of the Three Forks program. To date, we've drilled 25 total Three Forks wells versus 100 in the Bakken.
Okay. Thanks. That's helpful. My second question is on TFS development in Red Bank. When you look at your recent results from the Arliss well and then peer results from Brigham and from Continental, it looks like peak month rates decline as you move from East to West.
And I'm wondering if that's a fair assessment? And if so, would you expect the Mercedes well or has the production that you've seen from the Mercedes well been below that of the Arliss? Just trying to get a sense of the production variances in your opinion are due to differences in completion design or to a change in geology?
So as you go east to west, I think that's a fair assessment. And it's consistent in the Bakken as well as in the Three Forks. So production tends to drop off as you go further west and water production tends to increase. So the Mercedes is likely to not produce at quite the same rate as the Arliss, but we'll be in the ballpark. And it's likely that the Mercedes well is likely to be similar to the Bakken wells and in and around which it produce.
Great. Thanks, guys. Thanks.
Your next question is from Ron Mills with Johnson Rice.
Good morning. A couple of questions. One maybe, I don't know who it's really for, but on the marketing side and the price differentials, you talked about currently 80% rail and within the next few months you have 80% available to you via pipeline of your production. How flexible are you in terms of being able to change between pipe and rail to take advantage of regional differences and getting your crude to particular markets?
Yes. So there's 2 things that are in there Ron. And so it's probably good to clarify that a little bit. But when we talk about what's on infrastructure that's our gathering system. So pretty soon we'll be at 80% gathering on the gathering system inside the basin.
And then that gathering system allows us a lot of flexibility of ways out of the basin. And so when we talk about 80% rail and 20% pipeline, we've got access with that gathering system to get to 6 different rail sites, 4 different pipeline sites. And then it's pretty easy for us month to month to move that back and forth to basically the best price, right? And so what we've kind of consistently said is we do want to keep some diversification. We'll kind of keep in that 15% to 20% range in both pipe and rail and then we'll use that middle 60% to 70% of our volumes to go to the best price.
Currently that's on the rail side and that's continuing into the Q1, but we'll just kind of continue to monitor where we're going to get the best price and go there and it gives us the flexibility to do that.
Okay, great. And as you look out over the course of 2013 in terms of the differential outlook, do you expect the 4th quarter numbers to move back towards where the historical is, maybe not to the same magnitude, but or is there something that's going on in a short term basis that provide a lot more comfort over the first half of this year versus the second half of the year from just a differential expectation standpoint?
Yes. From a long term perspective, I think it's hard for us to do anything but go back to kind of historical levels. If you look at lease sales, probably more in the kind of 12% to 15% historically. Now with this infrastructure, with the gathering system that we got, long term differential is probably more in the 8% to 10% because of the reduction of trucking. So that would be kind of that long term historical norm is probably 8% to 10% differential.
Early part of this year, this Q1 currently what we've seen is it's looking low single digits kind of like it was in the Q4, but we'll see how that continues to progress through the year. Okay.
And then one last one on the infill spacing test that you're going to
do. How are those going
to be spread through the year in terms of it sounds like at Indian Hills you may be testing upwards of 6 potential Bakken locations per in different areas, tracking to increase from 3 say North Cottonwood to 4 plus. Does that progress through the year? Or do those are those infill programs going to occur kind of more sporadically? I guess I'm trying to get a sense as to how you're going to go from the 3 to 4 to 5 to 6 in terms of your infill pilots?
Yes. So Ron, we've got them they're kind of spread out through the year. We do have a fair number of them designed for really starting right now, so that as we go into break up, we'll have a lot of wells on pads. But we're not going to start with doing 3 wells per formation in a spacing unit and then build to fix. We've got test in common areas where we're testing multiple concepts.
So for example in North Cottonwood, we have one spacing unit where we're going to drill the equivalent of 11 wells per spacing. We're not going to drill all 11. So it would be the equivalent of 5, 3, Forks and 6 Bakken wells. And then right next to that, we're going to drill 1 that has the equivalent of 8 wells in the spacing units, so the equivalent of 4 Bakken and 4.3 Forks, but with a smaller number of wells and we won't drill out the whole thing. And we've got tests like that in each of the areas testing variance in those number of wells in the spacing unit that are just really kind of spread throughout the year.
Okay, great. I'll let someone else jump in. Thank you.
Your next question is from Noel Parks from Ladenburg Thalmann.
Can you hear me?
Yes.
Great. Good morning. A couple of things. I know you said that your HBP acreage count was up to 265,000 and I see you have about 25,000,000 dollars allocated for leasehold this year. What's left to drill in the inventory at this point before you get to the being entirely HBP?
So we've got the acreage that is not yet held by production. Quite a bit of that is on the east side of the basin. We picked up a lot of acreage last year in the Cottonwood area, new acreage that has expirations on it. In the existing position, it wasn't last year, it wasn't didn't have as many expiries that we had to get to. So a lot of that was more backloaded.
So you have quite a bit that's the east side in North Cottonwood. And then there's a fair amount also over on the west side in the Missouri area. So that's in Montana and it's further out to the west. So those are 2 of the big honks. And then there is also some additional acreage that's far south on the west side down on Mondak.
It's on the order of 2000, 3000 acres that we may not get to because results aren't quite as good there. And then on the East side in the very north end in St. Croix, we've got around 10,000 acres that ultimately we may not hold.
Those last two bits are what bring you down from $335,000,000 down to $305,000,000 roughly of what's core and what's not.
Got you. That's just what I was looking for. Yes. And just wanted to turn to hedging for a moment. Just noticing sort of the pattern you've maintained usually and how far you hedge.
I just wonder what your thoughts are going forward since we're continuing in this relative flatness of the curve. Just wondering if you're feeling a little bit like there's not as much urgency out there or you kind of prefer to wait and see directionally where we're headed with oil going forward?
Yes. We've always kept a pretty balanced plan probably a little bit more on the aggressive side on the hedging to make sure that we keep cash flows at a certain level, especially as we're out spending cash flow. We're clearly out spending cash flow this year as well, while not nearly as much as we did last year. And next year, we'll likely, with a similar type program, outspend cash flow by call it $150,000,000 to $200,000,000 So call it $350,000,000 to $400,000,000 this year $150,000,000 to $200,000,000 next year. And with that, we'll probably try to lock in with hedges that pricing to make sure we maintain cash flows.
But what we've done is we've kind of kept it to a 2 year type program and continue to layer in opportunistically throughout the year and we'll probably do the same this year.
Great. That's all for me.
Great. Thanks.
Your next question is from Dave Kinstler from Simmons and Company.
Good morning, guys. Good morning, Dave.
Hey, when I look at the E and D spending budget you guys put out of, I want to say about $996,000,000 and then I look at net wells and the cost you're putting in per well, there's a gap of about $100,000,000 that I assume is associated with a bunch of science work, etcetera. Can you kind of walk us through that deviation and what that captures?
You're working off of 12 or 13, Dave?
I'm sorry, I missed your first part of your comment.
You're working off the 2012 CapEx or 2013? 2013.
I was just looking at, I guess, in your slides that you've got the E and P budget set at $996,000,000 and then you've got your net wells at $103,400,000 and if I'm using $8,600,000 as your well cost dollars 500,000,000 back
The drilling and completion dollars, it's just right under $900,000,000 So that additional 100 dollars basically is land geology?
Yes. So you've got a little over $40,000,000 in infrastructure Dave, dollars 25,000,000 in land, other facilities $20,000,000 and then microseismic and logging on our vertical program is about $10,000,000 on top and that gets you to the $996,000,000
Okay, perfect.
And then there's another 25,000,000 dollars that's OWS and non E and P capital, which gets you to a little over $1,000,000,000
Perfect. And then as I think about your kind of marketing side of things, can you guys walk through what the pricing is for accessing pipe and pricing is for accessing rail? Just so then when we look at where LLS and TI are and the like ANS, we can kind of try to triangulate a little better to maybe where realizations will work out throughout the year?
Yes. It's moving around quite a bit. But in the Q4, you had historically, it was easier to try to triangulate around the clear book price on the pipe side. And the clear book pricing was anywhere from a $2 discount to $5 discount kind of in that range most of the 4th quarter. On the rail side, you were getting quotes kind of at WTI or a little bit of a premium too.
So there was a decent gap between rail and pipe in the Q4. That's holding somewhat through the Q1, but we'll see where that goes going forward.
Okay. So they're not quoting you a specific kind of cost on the rail. They're just quoting you a differential off of the representative pricing hub?
That's generally how we get it.
Okay. Okay. Appreciate that. And then one last one and maybe this is for Taylor. When you talked about completions as you move to pads having delays as you're not necessarily delays, but as you complete multiple wells, it takes longer to tie those into sales.
Can you talk maybe a little bit about how those are trending right now? Are we looking at completions that are going to be back end loaded in this quarter? Or how you're kind of thinking about staggering those throughout the maybe the next two quarters?
Yes. So what's going to end up happening, Dave, is we've you're in pretty good shape, kind of caught up on completions right now. And as we work into the Q1 and get close to breakup, we're starting to drill quite a few wells on pads. And so you're going to have anywhere from 2 to 4 wells on most of these pads. And so those are going to get by the time you get the production from those, they're really going to be back end loaded like you said more in the 3rd and the 4th quarter.
So you're going to end up with 1st and second quarter production being fairly flat to 4Q of last year.
Okay. All right. That's very helpful. I appreciate it guys. Thank you.
All right, Dave. Thanks.
Your next question is from Ryan Oatman from SunTrust.
Hi, good morning guys. Good quarter.
Thanks.
I know you guys list a little over 700 net primary locations and another 800 potential locations and I can kind of see the map on page 10. Can you walk us through kind of the primary locations and years of inventory remaining kind of per area at different areas such as Indian Hills and South Cottonwood? Or do you see a variance between all these different areas listed in terms of primary remaining drilling inventory?
Yes. What I would do what I would suggest Ryan as opposed to trying to work through all those mathematical gymnastics on the call, we can follow-up with you. But there's a table also in the appendix of the presentation that might be a good starting point for that. Okay.
Okay, very good. And then as you guys shift to pad development, what potential do you see to decrease costs further given the great job you guys have already done decreasing those costs?
So as we go to pad development like I mentioned we're thinking we'll get about 5% to 10% of savings relative to just drilling a single well. And then on top of that over time, it's just continuing to focus on efficiency cycle times, want to continue to drive down time to drill a well, to frac it, a little more focus on technology that will help to bring down cost over time. So our goal this year is really to drive that down to that $8,000,000 range by the end of the year and we'll continue to work on bringing that down in 2014 and beyond. Okay. Thank you, guys.
Thanks.
Your next question is from Moe Dehaney from Wunder Securities.
Thanks. All my questions have been answered. Thank you.
Great. Thanks.
Your next question is from Steve Berman from Canaccord Genuity.
Thanks. Good morning. Just one question. You said in your prepared remarks, you hope to bring those the well cost down to $8,000,000 by the end of the year. If you are able to achieve that, would you as you sit here today, would you pocket those savings, I.
E. Bring your CapEx budget down? Or might you keep the same budget but drill more wells?
I think it's a little bit early to say at this point. We'll kind of see where we stand as we go through the year and make a call on that based on well results and oil price and all the other things that go into it. But to really make a call on it at this point, I think it's a bit early.
And is there a
I just think it's early.
Okay. And just one more thought. Is there any flexibility? I believe you said 40% to 50% of your wells would be done by OWS. Any flexibility in that number?
That's we're obviously going to try to drive that to the higher side and do as many wells as we can. But from where we sit today, we think 40% to 50% is a reasonable number.
All right, terrific. Thank you.
Great. Thanks.
Your next question is from Gail Nicholson from KLR Group. Good morning, gentlemen. Just two quick questions. The internal goal to get your well cost down to $8,000,000 does that include the savings from OWS?
No, it does not. As you said, there's about $500,000 gross per well savings that we realized through OWS, but we haven't included that.
Okay. And then just looking at the Justice well, was there any difference in completion technique or methodology between the Justice and that will the other Montana Three Forks well, the Wilson?
Really the completion techniques have advanced over on the West side. So there are some changes mostly in how we pump the job to get all the stages away and we found ways to do that more effectively. The amount of profit, I don't in stages that we're trying to pump in the Wilson were pretty similar. We just got more effective stages I think into the Justice.
Are no further questions at this time. Mr. Lu, do you have any closing remarks?
Yes. This is Tommy. 2012 was a year where Oasis differentiated itself as one of the premier operators in the Williston Basin, and we're proud what the team has done across all fronts, not only in what we do, but how we do it. In 2013, we're putting in a strong foundation with more efficient operations, lower well costs as we've talked about, and optimized price realizations. We've also continued to rapidly grow the company while maintaining a strong conservative balance sheet.
We believe we're focused on the right things and have the right people in place to execute on our plan. As always, thanks for everyone's participation in our call.
Gentlemen, this does conclude today's conference call. Thank you for participating. At this time, you may now disconnect.