Chord Energy Corp (CHRD) 2016 Q2 法說會逐字稿

Good morning. My name is Aaronson, and I will be your conference operator today. At this time, I would like to welcome everyone to the second-quarter 2016 earnings release and operations update for Oasis Petroleum.

(Operator Instructions)

Please note, this event is being recorded. 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, Aaronson.

Good morning, everyone, this is Michael Lou.

Today we are reporting our second-quarter 2016 financial and operational results. We are 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 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 and other non-GAAP financial measures. Reconciliations of our non-GAAP financial measures, to the applicable GAAP measures, can be found in our earnings release and on our website. We will also reference our current investor presentation which you can find on the Home Page of our website.

With that, I will turn the call over to Tommy.

Good morning, everyone, and thanks for joining our call today.

I am proud to report Oasis had another great quarter, as the team continued to carry momentum forward in spite of a challenging macro environment. In the second quarter, Oasis produced 49,507 BOEs per day, driven by continued improvement in operational results. This number would be essentially flat with the first quarter when adjusted for divested volumes.

While living within cash flow, we have effectively kept volumes flat for the last six quarters. In the second quarter we transitioned our completion activities from Indian Hills to Wild Basin, where we continue to see outstanding operational results. In total, we completed 13 gross or 8.7 net wells in the quarter.

We have spoken at length in the past about our dramatically-improved capital efficiency as a Company which, over the last two years, has changed the way we operate and plan our business. That momentum has continued through a combination of service cost reductions, operating efficiencies, and increased recoveries as we have further delivered significant gains in the first half of 2016. The team has driven down our well costs from $6.5 million last quarter to $5.9 million today. And LOE from $7.84 per BOE in 2015 to $6.89 per BOE in the first six months of 2016.

Even with these improvements, we do not believe the team is done yet and think well costs still have a bias downward through further efficiency gains. This continuous improvement in capital and operational efficiency, coupled with our strong well performance, continues to increase the trajectory of returns for Oasis. As a result of these improvements that we have seen to date, we now plan to complete 53 gross and 34.3 net wells in 2016. While continuing to operate two rigs and one frac spread and remaining within our original guidance of $200 million of drilling and completion capital.

The performance of our originally budgeted program has been encouraging enough to give us the comfort in raising our full-year production guidance to 48,500 BOEs a day to 49,500 BOEs a day up from our original guidance of 46,000 BOEs to 49,000 BOEs per day.

With that, I will turn the call over to Taylor.

Thanks, Tommy.

The team delivered another quarter of basically flat production, which was an outstanding achievement given our reduced activity levels. Our average spud rig release dropped by 2 days this quarter to around 13.5 days for a remarkable achievement considering how far we have already come on that front.

As a point of reference, we were averaging almost 22 days from spud to rig release at the start of 2015. And it was taking much longer than that back when we went public in 2010. The drilling efficiency gains we have delivered continue to be extraordinary.

On the completion side, the team also continues to find ways to get better. In fact, our completions team has done a great job keeping track with the rig efficiencies I just mentioned. We are routinely fracking 36 states' slick water wells in a little over 4.5 days, whereas the same operation was taking about 7 days when we entered 2015. You can see we have had about a 35% improvement in efficiency in the last 1.5 years

Equally important to cycle times are job design and implementation. Last quarter, we spoke about many of the completion designs that we are testing this year. These tests fall into two camps: higher proppant loadings and proppant placement efficiency.

For high proppant loads, we have completed multiple 10 million and 20 million pound fracs in Indian Hills and Wild Basin. For proppant placement, we have completed several 50-state slick water jobs and have also tested both diverters and precision proppant placement techniques. Across all of these test, results are very early time and data sets are limited. So it is simply too early to draw definitive conclusions.

However, based on encouraging early time data, we have elected to conduct additional testing on all of the techniques mentioned. We believe these designs and techniques have the potential to further enhance both EURs and returns for Oasis.

We brought a handful of wells online late in the second quarter in our Wild Basin project ahead of all the infrastructure being 100% complete. This staged approach to the project has been a great success story for the Company. As our planning, drilling, completion, production, and midstream teams all worked together throughout the quarter to make it happen. Demonstrating the importance of project integration and the impact that controlling infrastructure can have on the pace of project development.

We always knew the infrastructure would be commissioned in pieces, and the challenge for us would be taking advantage of what was operational ahead of the gas plan. While it was a pretty rainy spring, OMS was able to complete two SWD wells and certain water and gas gathering lines. That allowed us to complete Wild Basin wells in June and move gas to third parties through interconnects.

Most importantly, this operation has allowed us to build critical mass ahead of our gas plant startup and gather important early time data on well performance. The new well completions are choked back and ready to be opened up when the full Wild Basin infrastructure project, including gas gathering and processing, oil gathering and transportation, and produced water gathering and disposal, comes online this fall.

Lastly, LOE came in at $7 for the second quarter. A slight increase over the previous two quarters, driven by a more normalized level of workover activity. We moved 83% of our produced water in the quarter through our gathering system, which continues to be a strong contributor to our low LOE. While we have said before that we thought 4Q 2015 and 1Q 2016 were below our run rate, we are continuing to realize efficiencies throughout our operations. And as a result have now updated our full-year 2016 guidance to $6.75 to $7.50 per BOE.

To wrap up, I want to again commend the team for yet another terrific quarter. It has really been impressive to watch the coordinated efforts of our teams and our vendor partners throughout this commodity down cycle. And the results speak for themselves. That being said, I know they are up for the challenges ahead and will continue to carry the momentum forward.

I will now turn the call over to Michael.

Thanks, Taylor.

The Oasis story continues to be one of growth and value enhancement. Our team has consistently delivered both operational improvements and capital efficiencies. In addition, we have proven our capital discipline by quickly adjusting to the new commodity price environment and being cumulative free cash flow positive by $46 million since the beginning of 2015.

On the hedging front, we continue to protect our future cash flows from downside risk due to lower oil prices. We have certainly seen the impact that hedges can make in protecting cash flows, both in 2015 as well as the first half of 2016. We now have approximately 80% of the second half of 2016 crude volumes hedged with a weighted average floor of $49 per barrel and have around 18,000 barrels of oil per day hedged in 2017. In the back half of this year, we will continue to layer in hedges for 2017. And we will begin to layer on hedges for 2018.

Crew differentials for the second quarter were $4.85 per barrel below the average NYMEX price for the quarter, generally consistent with the past two quarters and in line with our guidance. With significant pipeline capacity additions planned for late this year or early next year, we continue to believe that Bakken differentials will remain in the $4 to $5 range for the rest of the year, with the potential for further improvements into 2017.

Our team continues to do an incredible job of maintaining some of the best-realized oil prices in the basin, benefiting from a strong and flexible gathering system. Gas realizations remained challenged in the second quarter, but are beginning to improve from early second-quarter lows.

As you have heard, we have kept production flat for seven quarters now. And, in fact, when you adjust our production for our non-core asset sale, the second-quarter production would have been over 50,000 barrels of oil per day as well. Our production mix was slightly gassier this quarter than the past two, driven by further improvements in gas gathering infrastructure which has increased sales and reduced flaring. It was also marginally affected by new production from Wild Basin, which produces at a higher gas-to-oil ratio than the rest of our asset base.

We mentioned in our first-quarter call we expected G&A to further reflect our efforts to become more efficient. In the second quarter, total G&A was 10% lower than the first quarter, and E&P G&A per BOE was 15% lower. Following that progress, we are lowering our full-year G&A guidance to a range of $88 million to $92 million for 2016.

The well and operating cost savings the team achieved, along with the well productivity improvements we have seen in the first half of the year, exceeded our expectations. In addition, the efficiencies that our team had generated across all of our operations allow us to drill faster and do more work with our two rigs and one frac crew program than we thought possible at the beginning of the year. Those cost savings and efficiency changes obviously affect our 2016 plans, but they have an even more significant impact to 2017 and beyond.

For 2016, as you have already heard, we will be drilling and completing seven additional gross, 5.7 net, operated wells. Importantly, this will all be within our $400 million capital program. Our improvement to capital efficiency, along with an improved oil price environment from the beginning of the year, allow us to execute on this plan while minimally outspending cash flow for the rest of the year.

Additionally, for 2017 and 2018 in a $50 to $60 oil price environment, we are now in a position to significantly grow our production base within cash flow. Simply put, the strength of our asset base and the dedicated focus on efficiency and cost have put us in an excellent position in today's highly uncertain commodity price environment.

If we see strength, we can accelerate through our drilled uncompleted backlog and add rigs as we progress. Allowing us to achieve double-digit oil production growth within cash flow over the next two years. If we see weakness, we can continue to focus on our core and extended core assets, where we have over two decades of inventory that is economic in lower oil prices. All of this together is a significant achievement for Oasis and speaks volume to the quality of our assets and our team.

With that, I will now turn the call back over to Aaronson for questions.

Thank you very much.

(Operator Instructions)

Our first question comes from Neal Dingmann of SunTrust. Please go ahead.

Morning, guys and excellent operations. Tommy, looking at that slide 10, where you guys lay out quite well the core, the extended core in your Fairway, as prices start to move back up, how would you guys, number one, would you burn through the entire core before you start looking at the extended query? And then, secondly, as you go in the extended core, maybe give me an idea of how you would try to tackle that or develop that.

Yes, even with all of our best plans the thing tends to be a little plastic and move around a bit. I do think that we would continue to focus on the core area and then just move out in a progression that would probably be, Eastern, Red Bank, close into the core. So, just move out in a step-wise pattern.

That being said, we would also be looking to do some testing on the edges of the extended core, as well as the Fairway just to see -- get some further confirmation on our ability to lower well costs especially in the outlying areas. But again, what I would tell you is even whatever plan we come up with today, I guarantee by the time we get to it, it will morph a bit.

Exactly, okay. And just lastly, M&A Tom, your thoughts. Bakken, I have not heard obviously, it's been a few smaller deals here and there. Thoughts -- are you seeing some things open up and if so what is your appetite?

Yes. I think that as always been the case we continue to look for acquisition opportunities in and around our core blocks and we did some at the end of last year. Albeit small deals, right? And a lot of it associated with acreage -- so it's trade, then cash, but continuing to core up in our existing operated positions. We have been able to do a number of deals over the last nine months but again, smaller things that are anywhere from $0.5 million to $10 million, to $12 million, $13 million. We did one at the end of last year that was over $20 million.

But it gives us -- these low price environments do not put you in a position to steal assets. It puts you in a position to where you can acquire asset -- really good core assets at a reasonable price. And we will continue to look for opportunities to do that and to be honest, we do not necessarily have -- we will look at anything, regardless of size, as long as it is accretive to our core positions.

Thank you so much.

You bet.

Our next question comes from Kashy Harrison of Simmons Piper Jaffray. Please go ahead.

Good morning guys. Thank you for taking my questions.

You bet. Good morning.

In the prepared comments you mentioned delivering double-digit production growth over the next few years in a $50 to $60 oil environment. Could you just share some color on what are the inputs that go into that scenario?

Yes, Casey. What we are looking at is, as you think about a higher price environment in that $55 to $60 neighborhood, obviously cash flows go up and as you remember, we had more infrastructure capital to spend, but that is primarily focused around our capital spend in 2016 and so you actually have more that frees up in 2017.

In addition to that, with our capital efficiency improving, we actually have the ability to increase our program from a two rig and one frac spread scenario to something higher. Initially we will do that through our large DUC inventory, which we have 83 DUCs currently and so we will use the DUC inventory and draw that down. And then if we continue to see that price hold steady in a good environment, then we will start to think about adding activity through rigs and frac crews.

Okay. Excellent color there. On page 14 of the presentation, you highlighted that you were signing longer-term contracts that have fixed differentials. Could you just share some color on how much production you would like to sign on these longer-term contracts?

You know, we do some of our work and it is always a blend of fixed versus floating. The good thing for us in the basin is, that we have a lot of take away capacity and like I mentioned in the prepared remarks, we are seeing pipeline capacity expand significantly here at the year or early next year.

With that we think the differentials in the basin will continue to favor producers, so we will sign longer-term fixed differential pricing if it makes sense. We are not tied to a certain percentage. We will see what we think about that longer-term market and we will adjust at that level.

Okay. And just last one from me, if I could sneak one more in here. You have done a really good job just driving down the cost structure and providing some good color on cyclical versus secular cost savings on the drilling completion front. With respect to operating unit costs, LOE, G&A, are those -- is there any -- are those at any risk at all for cost inflation or anything of that sort?

On the LOE front, part of the savings have been reductions through vendors but the biggest hunk of that LOE reduction that we have seen has been due to the capturing more of our water volumes on our saltwater disposal system. So that is going to stay with us. If you remember back into 2015, we were capturing about 40% of the volumes, produced water volumes, on our systems and now that is close to 85%. That big jump in water captures had the biggest impact.

Alright. Thank you. That is it for me. Good quarter.

Thanks.

Our next question comes from Don Crist of Johnson Rice. Please go ahead.

Good morning, guys. Taylor, just one point of clarification, in your prepared remarks, I believe you said that the wells that you brought on in Wild Basin were flow-in to sales but at a curtailed rate. Is there any way that you could quantify what those wells could be producing today? Is it 1,000 or 2,000 barrels a day or is it more substantial than that?

It is hard to quantify what the wells would do but they are choked back pretty substantially. They have got high pressures on them and I as mentioned, it is really around infrastructure. And we have got some takeaway capacity on third parties for gas, but until we get our processing plant and the rest of the infrastructure built out, at that time is when we will really be able to open the wells up. Based on the flow-in rates and pressures, we are encouraged by what the wells are doing so far and we're excited about it.

Okay. And more a general ramp up question as we go into winter. With the Wild Basin infrastructure hopefully online here in the fourth quarter, do you see kind of a steady ramp up through the first quarter? Or is it going to be similar to past years where everything slows down in the first quarter and then it picks back up in the second quarter through the end of the year?

You know, the way we are thinking about it is, is really a pretty steady progression of wells in terms of completions. It does tend to be lumpy at times just because of the nature of the drilling out and in completing full spacing units at a time. But, at this point you project a pretty even spread of wells across the year. Now you do have -- we tend to model a little over volumes over the winter and that is just because of winter weather downtime and it can impact activity and you can have a little bit more downtime in your wells as well.

Okay. One final question for me. I see you hit $5.9 million or under $6 million for your wells now. Do you think we are at a bottom in where you think you can get? Or do you think there is more efficiencies that you can squeeze out here in the future?

You know, we obviously made a big move over this past quarter. We are at $6.5 million and earlier in the year we were thinking we would get around $6 million by the end of the year and obviously, we have already moved past that at $5.9 million. That being said, we think there is probably still additional reductions and somewhere in the 5% range is probably reasonable. More of that is probably going to come from efficiencies at this point, maybe a bit on pricing but a little bit more weighted to efficiency. But I think another 5% is reasonable to think about.

Okay. That is all the questions I had. I will turn it back. Thank you.

Great. Thanks.

Our next question comes from John Freeman of Raymond James. Please go ahead.

Good morning.

Hello.

Hello. A follow up on the last question, at the current $5.9 million completed well cost, could you give me what just the completion cost on a $5.9 million is now?

So on the $5.9 million, the completion cost alone is about $4 million.

And where would that have been when you were at $6.5 million last quarter?

At a $6.5 million, it was at about $4.5 million for completion.

Great. Thanks. Just my one follow-up, obviously, I know it is still early with trying these different optimized completions. I am just curious if, again, understanding it is early, if there is any one or two you could point out, whether it is -- you would say, okay this is definitely -- going forward this works. The magnitude maybe is still up for debate but we know going forward we're going to incorporate X or Y into a go-forward completion plan.

John, it is still early. We have got -- what we are going to look at is the improved performance relative to the cost increase of these different completion techniques that we are employing. As I said, we are seeing encouraging early time data. But these wells have only been on for -- gosh, a month or two months; that kind of timeframe.

And we'd really like to see at least six months production to get a decent feel for what the impact is going to be. On top of that we have got these wells in Wild Basin are choked back, so it is hard to compare those to the other wells that we have done in the past. When we get all of the infrastructure in place, get those wells opened up, we will get more normal flows, more comparative data that we can then draw conclusions on. So just, like I said, encouraging, but early.

I appreciate it guys. Thanks.

All right, John. Thanks.

Our next question comes from Gail Nicholson of KLR. Please go ahead.

Good morning. Historically you guys have done a lot of work on down spacing in the lower benches. I was just curious, when you look at the efficiencies that you have achieved, as well as the enhanced completion techniques that you are now utilizing, is that something that you might want to revisit and you feel like you can maybe squeeze some more spacing? Or maybe the lower benches look more productive at the current cost and current uplift from the completion techniques. I am just curious on any color on that.

We continue to look at the spacing and we have actually -- are drilling a handful of lower bench wells in our current programs -- just second bench wells. As we go forward, with the combination of the lower cost and then importantly, as commodity price, if and when that happens they rebound, it will impact that decision on whether we include more lower benches in our patterns going forward.

We do feel like with the modeling and results we've seen, that we are doing a pretty good job of draining the reservoir just with the Bakken and the first bench. When you get into those lower bench wells, you may be adding some incremental reserves but it is also looking at acceleration. Just looking at all of those factors we have not ruled them out. We still count a few lower bench wells in our inventory but not a big number at this point.

When you look at the drilling efficiencies, spud [data] out, (inaudible) were released down to 13.5 days, when you look at your core inventory what do you think is the optimal number of rigs that you can run on the core without over depleting the inventory?

You know, we tend to look at it by area. If we are going into an area like Wild Basin, we think two rigs is a good number especially when we consider the infrastructure. We could also, as we pick up the pace, support additional rigs and other core areas. We could support one to two rigs at Alger, we have got additional drilling in Indian Hills and it could support another one to two rigs in those areas as well.

Okay. Great. Thank you.

Thanks.

This concludes our question-and-answer session. I would like to turn the conference back over to Tommy Nusz for any closing remarks.

Thanks. The team has done a great job across all disciplines, adjusting to the current environment and setting us up for future success. We have kept volumes flat for seven quarters, lived within cash flow all-in for six quarters, brought well costs down by 45%, while increasing lower coverage by over 30%, optimized operating cost structure and minimized service contract exposure and we have established a strong hedge in liquidity position. So, we feel really good about where we stand and where we are going forward and being able to get to the other side of this current environment. Again, thank you for participating in our call.

This concludes today's conference. Thank you for attending today's presentation. You may now disconnect.