Chord Energy Corporation
Q4 2015 Earnings Call Transcript

Published: 25 Feb 2016

[Operator:]

Good morning. My name is Chad and I will be your conference operator today. At this time, I'd like to welcome everyone to the Fourth Quarter 2015 Earnings Release and Operations Update for Oasis Petroleum. Please note this call is being recorded. 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 Lou, Oasis Petroleum's CFO, to begin the conference. Thank you, sir. You may begin.

[Michael H. Lou:]

Thank you, Chad. Good morning, everyone. This is Michael Lou. Today we are reporting our year-end 2015 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, 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 of adjusted EBITDA to the applicable GAAP measures can be found in our earnings release and on our website. We plan to file our 10-K today following this call. 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.

[Thomas B. Nusz:]

Good morning and thanks for joining our call. While 2015 proved to be more challenging on the macro front than many had anticipated, from an operational standpoint it was arguably our best since inception. The team worked diligently throughout the year to continuously drive down costs and improve operational efficiencies. As a result, we increased annual average daily production by 11% to 50.5 Mboepd in 2015, which is above the top end of our guidance, while spending 70% less in drilling and completion capital year-over-year and approximately $100 million less than our original total capital budget. Additionally, we drove LOE costs down by over 20%, reduced well costs by roughly 30% and saw differentials improve by about 40%. We were able to power down activity quickly in response to lower oil prices, reducing our rig count from 16 to 3 rigs in the course of five months while incurring only $3.9 million in rig termination penalties. To begin 2015, we anticipated needing five rigs to execute our capital drilling program, but through operational efficiencies the team found a way to accomplish the same workload at a run rate of three rigs. We have since dropped another rig and plan to remain at two rigs for the balance of 2016, both of those being in our Wild Basin area. OMS also beat expectations, delivering $66 million in adjusted EBITDA versus an estimate of $40 million coming into the year. We have spoken throughout the year about the continued success that we've seen through our high-intensity completion program. We completed 60% of our wells with high-intensity jobs in 2015, and the results continue to be extremely impressive with production uplifts ranging from 30% to in excess of 60% and in some cases 2x, as you can see in our presentation posted this morning. At the same time, our well costs have come down significantly, and Taylor will talk more about that. With the tremendous results we have experienced, we anticipate completing 100% of our wells with high-intensity jobs in 2016. The substantial total well cost improvements we have recognized coupled with significantly increased well performance all translate into a meaningful increase in our capital efficiency, generating much more with much less. We've also been able to remain strong and well positioned in a challenging environment, which is reflected by our continued ability to remain cash flow positive, all in, including midstream capital, starting in the second quarter of 2015 and carrying on throughout the remainder of the year, despite a significant decrease in the commodity price year-over-year. Given the macro environment, we're keenly focused on our balance sheet with an eye on liquidity, leverage, our hedge profile, and how our operational choices impact all of these items. We ended the year with a revolver balance of $138 million and with proceeds from our January equity offering, that facility is undrawn today. We are continuously watching the oil markets and opportunistically hedging to lock in 2016 and 2017 prices. We have about 70% of our estimated 2016 oil production hedged at over $51 a barrel and we've started to chip away at 2017 with 8,000 barrels a day hedged with an average floor price of approximately $47. Since the end of 2015, 100% of our drilling activity has been in our Wild Basin area, which will continue to be the sole focus of our drilling activity in 2016. As we've discussed in the past, Wild Basin is in the deepest part of the basin and is some of the very best rock, not just in the company or the Williston Basin but across all of the North American resource plays. We can still drill economically attractive wells in this area at $35 WTI. So while the macro environment in 2015 presented us with a lot of challenges, our organization transitioned quickly and performed extremely well. We powered down our activity in an orderly manner, contracting to the core of the basin and reducing rig count from 16 to 3 and frac spreads from 6 to 2. We optimized completions from our base design to high intensity, and significantly increased per-well recoveries. And we materially impacted both capital and operating costs through both service cost reductions and operational efficiencies, all resulting in us exceeding internal and external expectations. But all that's behind us now. We'll continue to remain flexible and adjust to our macro environment. Our liquidity, our overall inventory, our inventory of uncompleted wells, and our continued operational improvement give us the ability to execute on our 2016 plans and the optionality to scale operations in the future. With that, I'll turn the call over to Taylor.

[Taylor L. Reid:]

Thanks, Tommy. I want to start by saying that 2015 was a great year for us operationally. We continued to see strong results from our high-intensity completion program and as a result we increased our high-intensity wells from 20% in 2014 to about 70% in the second half of 2015. We also made a big transition to the core of the basin, completing 86% of our wells in the core in the second half of the year. On our previous earnings call we mentioned three all-sand slick water wells in our Indian Hills area. We now have about six months of production data on those wells. And just as we saw in Montana, Red Bank, and in competitor wells, they are performing in line with nearby ceramic proppant wells. As a result, we have transitioned to 100% sand slick water wells going forward. This design change reduces well costs by $0.5 million per well. Those cost savings continue the rapid well cost reduction we have seen over the past year. Coming into 2015, we were completing wells for over $10.6 million and they were taking approximately 21 days to drill. In November we said those costs would come down to $7.4 million with the changes evenly split between service cost reductions and efficiency gains. Today, with a combination of the switch to sand, updated rig contracts, and continued improvements in efficiencies; we expect slick water wells in our 2016 plan to cost $6.5 million. And we are currently drilling them in 16 days on average. Following these latest developments, we have also updated our type curves. Turning to slide 11 in the presentation we released this morning, we are now modelling our core area type wells at 1,050 Mboes in the Bakken and 875 Mboes in the Three Forks. These estimated recoveries reflect our latest data on high-intensity results and our weighted averages of remaining inventory estimates. When you pair the core inventory data on slide eight with the returns depicted at the bottom of slide 11, it shows that even at today's strip we have over 13 years of economic inventory at our current pace of 46 wells completed per year. During our last call we talked about living in a $50 world and keeping production flat to slightly growing. As oil prices have continued to drop, we have updated our 2016 plan to reflect current oil pricing. To start the year, we have reduced activity to two rigs and one frac crew. Our rigs will remain in Wild Basin and our frac crew will remain in Indian Hills until it transitions to Wild Basin later this year. Under this program, we expect to complete 46 gross wells and 28.6 net wells in 2016, all with high-intensity completions. With the reduced well costs and pace of activity, our drilling and completion capital will drop substantially from 2015 and come in at $200 million for the year. Another great outcome for the year is our proved reserve numbers. Year-end 2015 developed reserve slightly increased over year-end 2014 levels. Thus, while our total reserves of 218 MMboe reflect a 20% reduction from 2014, the difference is driven entirely by undeveloped reserves and is a reflection of both a 47% decrease in the SEC price deck and our reduced activity levels. Proved reserves now represent 68% of our total reserves compared to 54% at the end of 2014. As we move further into 2016, we will continue to keep an eye on the oil markets and will be prepared to adjust activity accordingly. As we mentioned on the last call, our rig contracts matured around the beginning of the year. As we approach new contracts, we will continue to maintain flexibility and work to lower costs through both cost reductions and operational efficiencies. In addition, our backlog of 85 wells waiting on completion at year end provides us with immediate flexibility from a price recovery and operational standpoint. In closing, I want to commend the team for an outstanding 2015 and challenge them to maintain the momentum going into 2016. With that, I'll turn the call over to Michael.

[Michael H. Lou:]

Thanks, Taylor. Coming into 2015 we talked about being cash flow positive as measured by adjusted EBITDAX less CapEx and cash interest. And for the past three quarters we've accomplished this, coming in cash flow positive by $167 million during that period. Excluding midstream capital, we are projecting to be cash flow positive at $35 per barrel in 2016. Differentials grew much tighter throughout 2015, ending in the $4 to $5 range where we expect it will stay for 2016. This was driven by a combination of factors, including the HH pipeline which came online last summer, by reduced rates at certain rail facilities, and by the overall flexibility of our crew takeaway systems, all of which highlights our marketing team's ability to access the best markets at any given time. Over the course of the year we were also able to dramatically reduce lease operating expenses, ending the year at $7.84 per BOE, a 23% reduction versus 2014. OMS was a large contributor to this success as we exited the year with 75% of our produced water volumes connected to OMS gathering pipelines for the last four months of the year, which is almost double our 2014 exit rate. Other significant contributions to our operating cost reductions included managing uptime on producing wells, better efficiency on high-cost wells and lower workover activities. Throughout 2015, OMS exceeded our expectations and guidance, and the fourth quarter was no exception. OMS delivered $18 million of adjusted EBITDA in the fourth quarter and helped drive LOE to the lowest level in two years. For the year, OMS delivered $66 million of adjusted EBITDA versus our original plan of $40 million. That is 2.4 times our 2014 levels, and 1.8 times our original guidance. The infrastructure buildout in Wild Basin, which is critical for our 2016 development, is on schedule and on budget. We expect OMS adjusted EBITDA to be relatively flat in 2016 with a ramp-up coming from Wild Basin towards the end of the year. We'll provide you with a strategic financing update on OMS when it's appropriate. Given the uncertainty in the markets and the commodity prices, we elected to undergo our spring borrowing base redetermination early and we just completed it on Tuesday. Our borrowing base is now $1.15 billion as banks are now running a much lower deck than in the fall. The lower bank pricing was offset by operational cost improvements our team delivered in 2015. Today, our borrowing base is undrawn, providing us with about $1.2 billion in liquidity. Our next redetermination is not until October. With all of the hard work of our employees, we continue to position Oasis to be able to make solid returns at much lower oil prices in 2016 and beyond. Our assets are concentrated in the heart of the Williston Basin, and our acreage is almost entirely held by production, providing us with tremendous option value. We will continue to focus on balancing CapEx and production growth, spending within cash flow, and preserving our strong liquidity position. With that, I'll now turn the call over to Chad for questions.

[Operator:]

Thank you, sir. We will now begin the question-and-answer session. Our first question comes today from David Deckelbaum with KeyBanc. Please go ahead.

[David A. Deckelbaum:]

Morning, Tommy, Taylor, and Michael. Thanks for taking my questions.

[Thomas B. Nusz:]

Morning, Dave.

[David A. Deckelbaum:]

Curious, I know you guys had some successful financing recently through the equity markets, and you came out with a 2016 plan that basically matches cash flows on the E&D side. It seemed like there was still some variability around building out OMS. And I know you said you would update us on external financing, but when I look at things now you guys are 70% hedged this year at $50 a barrel and change. Is it fair to say that the decision to go forward with building out OMS right now is sort of set at this point, absent a significant incremental deterioration in the commodity prices, and would you really need to bring in an external partner this year to accomplish what you want just given the borrowing base redetermination and the amount of liquidity you have?

[Michael H. Lou:]

Yeah, Dave. A good question. We still think that we can bring in external financing for OMS and that's our current plans. We're continuing to move down the road on Wild Basin for now. Things can obviously change there if we need it to, so we have some optionality, but Wild Basin is a great area for us and we're going to continue to move down that path given what we see in the marketplace and what we think is our ability to finance at OMS on an external basis.

[David A. Deckelbaum:]

Thanks, Michael. And then just any incremental color on well costs in the basin? I know there's very little activity right now. We've seen well costs steadily coming down. Are you guys expecting another round that you should be realizing this year? And then could you quantify that at all for us?

[Taylor L. Reid:]

Obviously, the huge move in well costs last year, going from $10.6 million to what we see as currently as $6.5 million on slick water wells, and from where we stand we still think there's room to move and it'll still be a combination of efficiency, so getting more efficiency on the drilling and completion side. And then also a bit on the service side as well. The service side's certainly not going to move as much as it did last year. They just don't have as much room to move but we think it's reasonable that we could get it down another 5% to 10% by the end of the year.

[David A. Deckelbaum:]

And what – Taylor, do you know what the conceptual cost is of what a Wild Basin completion would be right now or what you have planned currently? Just total D&C cost?

[Taylor L. Reid:]

Yeah, it's $6.5 million.

[David A. Deckelbaum:]

Okay. So it's in line with everything else in the portfolio then?

[Taylor L. Reid:]

Correct.

[David A. Deckelbaum:]

Got it. All right. Thanks, guys.

[Thomas B. Nusz:]

Thanks, Dave.

[Operator:]

The next question is from Ron Mills with Johnson Rice. Please go ahead.

[Ronald E. Mills:]

Good morning. Maybe another one for Taylor. When you look at your core position with the 13 years, if you look at Indian Hills versus Wild Basin versus Alger, are there meaningful differences between those three areas? Or is the whole core subset in terms of EURs and costs pretty similar across those three portions of it?

[Taylor L. Reid:]

Overall, Ron, they're pretty similar. We represent that core type curve. I would say that Wild Basin's probably a little better than the other two, but it also has a little bit higher gas content where you tend to have a little higher EURs there. The costs in all three are pretty comparable, so the economics aren't wildly different. But Wild Basin has probably got an edge on the other two.

[Ronald E. Mills:]

And then when you talk about the move to 100% sand completions from the ceramic, is that going to be – just to make sure I understand, is that going to be applied across all of the core as well based on those initial 30-well results?

[Taylor L. Reid:]

Yeah. Correct. It'll be all across the position, so we'll use it in all of our wells in the core from this point forward.

[Ronald E. Mills:]

Okay. And then, Michael, on OMS, what is the timeline there? You talked about the project being on time and on schedule. Where are you on that project? Have you already started construction? And I'm just trying to get a sense as to – I guess it's more clear today than it was three months ago that you are really moving forward with Wild Basin. But I'm just curious where you are in the construction process?

[Michael H. Lou:]

Good question, Ron. The timing is that Wild Basin will be coming on line sometime in the back half of the year, call it around the end of the third quarter, really into the fourth quarter. The project obviously is – we've spent capital already there, and you can see by the picture that we've had in our investor presentation that the gas plant is fairly well constructed already. We do have a number of lines that need to go in that area. And so we've got more capital to spend this year. Most of that work is not done until things clear up in terms of the winter weather and breakup season occurs. So that will be kind of in the middle part of the year.

[Ronald E. Mills:]

And just to clarify, the $140 million is what the 88's (22

[Michael H. Lou:]

That's exactly right.

[Ronald E. Mills:]

Okay.

[Michael H. Lou:]

And we've already spent some capital there. So even if you did something that brought in $140 million, we have kind of additional capital that was spent in Wild Basin already.

[Ronald E. Mills:]

Which you would recover as well.

[Michael H. Lou:]

Yeah. That project is a little bit bigger than just that $140 million.

[Ronald E. Mills:]

Understand. Okay. Great. Thank you.

[Thomas B. Nusz:]

Thanks, Ron.

[Operator:]

The next question is from Brandon Bingham with Cowen and Company. Please go ahead.

[Brandon Bingham:]

Hi. Good morning.

[Thomas B. Nusz:]

Morning.

[Brandon Bingham:]

Just curious if you guys have had any consideration for OMS in your credit facility. And if not, would you expect that to change going forward?

[Michael H. Lou:]

There's not a lot of consideration in the credit facility for OMS. A little bit on the LOE side but not for the rest of that property. Most of it's just on the E&P reserves side.

[Brandon Bingham:]

Okay. And just switching over to differentials right now, how sticky are differentials right now at the current levels? And what steps is the company taking to protect against a potential widening up in the Bakken?

[Michael H. Lou:]

Yeah. We think the differentials will hold pretty strong. There's a lot of good pipeline and rail access. And so there's a lot of varied areas that we can go to across the country to access the best differentials for us. Our gathering system that we're connected to allows us that flexibility. So we feel fairly confident that we can keep those differentials lower. We have done some longer-term work on the differential side which had not been available historically to lock in some of those, but continuing to work that every day.

[Brandon Bingham:]

Great. Great. That's it for me. Thanks, guys.

[Thomas B. Nusz:]

Thanks.

[Operator:]

The next question is from Stephen Berman with Canaccord Genuity. Please go ahead.

[Unknown Speaker:]

Hey, guys. This is Michael Katz (25

[Michael H. Lou:]

Yeah. The fourth quarter oil percentage came down mainly because we were connecting our wells at a higher rate and so we flared less gas. The impact of Wild Basin, it will be a little bit gassier so you'll continue to see that gas percentage, or the oil percentage continue to come down a little bit. So we'll continue to keep you updated on where we think that'll go. But it should continue to inch down a bit as we do more and more Wild Basin wells.

[Unknown Speaker:]

All right. Thank you. And then additionally, we've seen that both Continental and Whiting are deferring their Bakken wells. And if prices are to stay depressed, can you see yourself doing the same in the future?

[Thomas B. Nusz:]

At this point, based on what we see in pricing, we look at current and strip pricing, the economics still support the program. So we think it makes sense to move ahead. We've got a good hedge position, as you've seen for this year with 70% of the volume hedged, and that certainly – and that's at over $51 a barrel and so that's a big supporter of the program, and have started our hedging program with 8,000 barrels a day in 2017. So when we put all those things together, we think it makes sense to continue to complete the wells there. We're getting great returns.

[Unknown Speaker:]

All right. That answers my question. I appreciate it. Thank you.

[Thomas B. Nusz:]

Thanks.

[Operator:]

The next question is from Neal Dingmann with SunTrust. Please go ahead.

[Neal D. Dingmann:]

Morning, guys.

[Thomas B. Nusz:]

Hey, Neal.

[Neal D. Dingmann:]

Tommy, it looks like obviously you're doing the prudent thing and cutting back to continuing to focus obviously on your high-graded area there. Just I was wondering, besides Wild Basin, price-wise or is it more on key returns, what would it take for you to start looking and returning to activity in some of the other areas outside of that?

[Thomas B. Nusz:]

It all boils down to oil price and the resulting returns, and some traction on time window on that oil price or our ability to lock some of it in, additional in through hedging. But then you've got the overlay of how much damage has been done to the service sector and as you look to potentially ramping up at some point in the future, how easy is it or difficult to get services back? So that's probably going to be a bit of a throttle when we come out the back side of this.

[Neal D. Dingmann:]

Okay. And then just lastly, one more just to follow up for Michael. As far as – obviously not in this environment, Michael, at what range would you guys think about adding some more hedges?

[Michael H. Lou:]

Tommy mentioned that we've got 70% of our oil hedged this year at pretty good numbers. Next year we're a little bit more lightly hedged and so we'll continue as we normally do to be opportunistic around layering hedges into 2017 or the next year out. And then as we get further into the year, we may continue to layer into the back half of 2016 a bit if we see prices that we like. Usually we do that to protect cash flow as well as we're fairly opportunistic when we see some prices that we like.

[Neal D. Dingmann:]

Got it. Thanks, guys.

[Thomas B. Nusz:]

Thanks.

[Operator:]

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

[Thomas B. Nusz:]

Thanks. As I said earlier, we'll continue to remain flexible and adjust to our macro environment. We have a tremendous asset base, multiple financial options, and a strong team that continues to perform exceptionally well in a tough environment. With all of that, we're well positioned to bridge this current down cycle and be prepared for a rebound. Thanks for joining our call today.

[Operator:]

Thank you, sir. The conference is now concluded. Thank you for attending. You may now disconnect.