Chord Energy Corp (CHRD) 2013 Q2 法說會逐字稿

Good morning. My name is Gina, and I will be your conference operator today. At this time, I would like to welcome everyone to the second-quarter 2013 earnings release and operations update for Oasis Petroleum. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a questions-and-answers session.

(Operator Instructions)

I will now turn the call over to Michael Lou, Oasis Petroleum's CFO, to begin the conference. Thank you. Mr. Lou, you may begin your conference.

Thank you, Gina. Good morning, everyone. This is Michael Lou. Today we are reporting our second-quarter 2013 results. We are delighted to have you on our call. I am 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 will now turn the call over to Tommy.

Good morning. I will start the call today with a few key items that we are 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 have experienced a considerable transformation. Our consistent and exceptional results are the culmination of years of planning, foresight and execution. I am very proud of what the team has accomplished, and the direction that we are 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 are beginning to realize the benefits of the efficiencies and cost savings of resource manufacturing as we improve our planning and processes, and drill more multi-well pads. In the second quarter, approximately 75% of the spud wells were on pads, and we maintained our drilling pace.

At the same time, we moderated our completion activity consistent with our original plan in order to control costs during breakup conditions. As a result, we built our backlog of operated wells waiting on completion from 21 as we entered the quarter, to 37 as we exited the quarter. So, with the rigs continuing to operate on pad locations, we avoided many of the restrictions associated with operating during the wet season, and deferred completion activity to the summer months when it is more cost effective to undertake frack 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 2 rigs, so our current rig count is 11. We anticipate completing 40 to 45 wells during the third quarter.

With this, we expect production to grow to between 31,500 BOEs per day and 34,500 BOEs per day for the third quarter. The team has continued to do an excellent job of optimizing well costs on multiple fronts. For the second quarter, our average well cost dropped again, to $8.2 million, excluding the cost savings from OWS. With the progress we have 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.

So in terms of activity, we are 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 had planned for the year originally. But that will depend on the pace of activity, weather, and our ability to pick up working interest on our operated units. Plus, with the cost efficiencies we are 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. So, we are 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 will 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 would like to give you an update on our work. First, when we think about our inventory at Bakken and 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 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 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% to 70% of our wells on pads in 2013, going to about 90% in 2014. Increased efficiency and reduced cycle times on these pads will drive cost improvements through 2013 and into next year. Oasis Well Services has also delivered great results, saving the Company approximately $400,000 per net well completed, which puts us below an average well cost of $7.8 million across all of our operated wells.

Finally, our infrastructure continues to provide us with excellent cash margins. Currently, we gather about 85% of our oil on our gathering system, which gives us access to pipe or rail takeaway capacity. To give you some perspective on our takeaway optionality, we went from about 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 of these items are adding to the bottom line.

With that, I will 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, and we achieved a 3% differential to WTI. As a premium that the coastal markets receive compared to WTI eroded during the second quarter, our differentials began to widen a bit compared to the first quarter of 2013. More recently, with the compression of the Brent WTI spread, we have been able to move oil back to pipelines to capture better pricing versus the current rail alternatives.

In the second quarter, we had adjusted EBITDA of $185 million, realizing an impressive $67.55 of EBITDA per BOE produced. We spent approximately $189 million in CapEx, and as Tommy mentioned, we are expecting that to ramp up in the third quarter, in line with drilling and completion activity. We have $1.4 billion of liquidity, and in addition, we continue to execute our hedging strategy, and currently have approximately 24,500 barrels of oil per day hedged for the remainder of 2013, and we 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 a gross oil sale and associated costs, both of which were $5.8 million, so the trade was gross margin neutral. In our press release, we backed out the impact of this transaction for you as it related to realized oil prices, and marketing, transportation and 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 will turn the call over to Gina to open the lines up for questions.

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

Good morning, Michael.

Heikkinen Energy. Good morning. Appreciate you taking the call. I guess I want to get a little better feel on completion's pace as you move further and further into pad development mode. In particular, thinking about how that waiting on completion backlog grows or contracts? And when we should think about, or how we should think about the timing of wells been drilled versus termed to sales? And in that context, I am 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 waiting on completion backlog will continue to increase through that period? Just as build the backlog up on the pad? And 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 is that obviously as everything gets on pads, then you start to normalize that. But what we've said before is is we have if you're running, call it 11 rigs, you're going to have two ex of waiting on completion. So you're always going to have 20 or 25 or so. So, it probably will contract a bit, but --

Michael, this is Taylor, you will see it come down from the 37. We are working off quite a few wells in this quarter. But we are 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. If you don't have all your pads starting at one time and you got them spread out through the year. So, it should normalize over time. The other thing that will help as we go forward is doing simultaneous operations. We are currently on an eight-well pad that we are going to do our first set of simultaneous operations where we will be both drilling, we will drill a set of four wells, and then while we are drilling the next four wells, we will be fracking the first four wells. So, rather than having to wait until all eight of those wells are drilled and completed, come on production, we will 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 is helpful. So, I think about it is as the backlog contracts and bit this summer, and then maybe starts to grow back up again to as you move more and more of your activity to pads into 2014. Is that fair comment?

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

But I think you should expect, 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 second quarter, just because we are 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.

Well, that make sense. That's helpful. And then the 11 rig program, just to be clear, is that going to be maintained? Is the intention to maintain through the rest of the year and to '14? Or is that swing capacity this summer?

No, I think that is, going forward at least as far as we can see at this point, (multiple speakers) the 11. Now, the guys are continuing to be more efficient. So again, it goes back to project count. But, effectively, yes.

Great. And then the last one, I might end up, just curious. By chance provide any IP30 average, IP30s or something along those lines, and by area during the quarter? West Williston, East Nesson, and Sanish? On the operated, or I guess just West Williston, East Nesson on the operated feed?

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

Okay, fair enough. I appreciate, guys, thanks for your color.

You bet. Thanks.

Your next question comes form the line of Ryan Oatman with SunTrust.

Morning. Thanks for the update on the Three Forks and spacing tests. On the down spacing, I gathered from the commentary that obviously it is a little early to declare success, but I wanted to drill down there. Did you see any areas where down spacing 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 down spacing test?

Okay. So we, as a miss, we've got 22 this year, there are five that are currently on production. And 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. So, 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. As like I said, those will be second-half wells. The other, I guess comment I would make on the ones we do have production on to date, the three it looks like, and those were 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 is helpful. And then moving to the lower Three Forks, not surprised to see you test Indian Hills given the nearby industry results there. North Cottonwood, you see a little less in terms of industry activity there. Was curious what color you can provide on what you saw on these cores that has you encouraged, North Cottonwood? And then, and I think there were six cores, on the other four what you saw there as well?

So, Indians Hills, that one, obviously you've 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 core show good porosity and good oil saturations. Enough that for us merited a test in the second bench. And so, this is our way of taking the next step and confirming that there is enough recoverable oil to make economic wells in that area. And really, we're optimistic about the whole Cottonwood area. We just have one well that we are testing right now. But as you look from Alger on the Eastside all the way up to North Cottonwood, we are optimistic based on what we are seeing in the cores that we have taken and the logs in the area.

In the other areas where we took cores, there was also one in East Red Bank and then one in Montana. Those wells we are still evaluating. Haven't planned a second 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. You have very good cost control this quarter both on the LOE and OpEx side. What should we expect for a per unit cost moving forward?

So, on our unit operating expense, we are at for the quarter $6.65 and the trend has been down. So, down quarter-over-quarter. We would expect to continue that general trend. It may be a little lumpy, month-to-month. Part of that is that we are getting a larger component of work over expense that is due to frack protect as we drill and frack more wells in and around local wells. So that, dependent on the wells that are completing in a month or a quarter, you can see it bump up and down. But in general, I'd say it is on a downward trend.

Great. And I think I misspoke, G&A also looked pretty low this quarter as well. Any thoughts on third quarter, fourth quarter for that guidance? And I'll hop back in queue, thanks guys.

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

Thank you.

Thanks.

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

Hello, congratulations on a really strong quarter. I mean obviously bypassing the issue of wet weather, you're planning and infrastructure investments really kicking in. It just seems like you have Williston Basin in good order. So, any appetite for building a new core area?

Irene, as we have talked about, we have got a, I guess it was this time last year where we really formalized a business development team and they have 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 six months or so just working Williston projects. So, we have had enough to keep them occupied with that. So, in the near-term, probably continue to focus on Williston and we will just see where it takes us.

Okay. Great. Thanks.

You bet.

Your next question comes the line of Drew Venker with Morgan Stanley.

Hello, good morning. I was hoping you could a little bit about what you see as a potential for slick water frack's improved performance? And if you have any ideas as far as what the difference in well cost would be?

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

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

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

Okay. And going back to the summer thing in operations you guys talked about. Do you have any initial estimates of the improved, potential improvement in spud to first sales on average for a pad?

I don't have days, but the way you can think about is you would drill without simultaneous operations, you would drill eight wells back to back, and we are now drilling spud to rig release is 23 days. Think of each of those close to a month. And so, rather than waiting three-and-a-half, a total of seven or eight months to start completing wells, after three-and-a-half to four 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 of relative to if you did a full eight-well pad, it's going to help you on time. Now, on smaller pads, you can't really apply that across the spectrum, because say a two- to a four-well pad, you're probably not going to do simultaneous operations are less likely, too. You're just going to drill them out and put them on production.

Okay. Thanks.

Your next question comes in line of Gail Nicholson with KLR Group.

Good morning, gentlemen Just a couple quick questions. Continue with that simultaneous operations. Have you guys made a decision on out of that 90% of wells being drilled in '14, what percentage will be done with the simultaneous operations gap?

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

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

Two in what we call Alger, which is in the East Side, South of Cottonwood. And then there was one that was in Montana in Hebron.

Great. And then 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 in South Cottonwood in 2013? What is going on there?

So we have got -- we've got three 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 are going to be -- they are either drilling currently or will spud within the next couple of months.

Great. Thank you.

Yes, thanks.

Your next question comes the line of Peter Mahon at Dougherty & Company

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

So the, as we've talked about before, the cost savings this year, there is some service component, but the majority of it is really efficiency. Well design, pad operations, all of those things. Pre-cycle times.

Got it. And could you talk through what you are doing now in terms of just your fracking model or your approach that is different today versus say a year ago and what you are doing differently?

Compared to a year ago, it is really tweaking our fracks. The standard frack 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 have been experimenting more with have been in the few areas, less stages, but generally we are still around 36 stages. We are 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 are shifting that. And then the other thing we are experimenting with is sleeves in some areas, So, for some areas where we have 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, but we are trying to get enough control with the new things that we're trying so we can prepare 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 will 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 are proud of our culture, the accomplishments of our team, and the direction we're going as a Company. This is 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 at our call.

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