Civitas Resources Inc (CIVI) 2016 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Bonanza Creek Energy first-quarter 2016 earnings conference call. (Operator Instructions). As a reminder, this call is being recorded.

I would now like to introduce your host for today's conference, Mr. James Edwards, Director of Investor Relations. You may begin, sir.

Thank you. Good morning, everyone, and welcome to Bonanza Creek's first-quarter 2016 earnings conference call and webcast. Joining me on the call this morning are Richard Carty, President and Chief Executive Officer, and Tony Buchanon, Executive Vice President and Chief Operating Officer.

Yesterday afternoon, we issued our earnings press release and filed our 10-Q with the SEC. You can access both on our website. If you haven't done so already, I would encourage you to access the slides that we will reference this morning during our prepared remarks, available on the investors section of our website at bonanzacrk.com.

Please be aware that our remarks will include forward-looking statements that are subject to many risks and uncertainties that could cause the actual results to differ materially. You should read our full disclosures as described in our 2015 10-K, first-quarter 10-Q, and other SEC filings.

Also during this call, we will refer to certain non-GAAP financial measures because we believe they are good metrics to use in evaluating performance. Reconciliations of these measures to the most directly comparable GAAP measures are contained in our earnings release.

We have kept our prepared remarks short to leave ample time for Q&A during this 60-minute call. Now it is my pleasure this morning to introduce Richard Carty, Bonanza Creek's President and Chief Executive Officer, who will begin the call with our first-quarter results. Rich?

Thanks, James. Good morning, everyone, and thank you for joining us for our first-quarter earnings conference call. This morning on the call, I would first and foremost like to mention how pleased we are with the ongoing performance of our assets, with the Wattenberg Field continuing to respond strongly since the addition of our RMI infrastructure.

First-quarter 2016 marks the third consecutive quarter Bonanza Creek has exceeded expectations on both production and operating costs. Our sales volumes over these last three quarters have outperformed the midpoint of guidance by 2%, while (technical difficulty) together have been under budget by approximately $50 million over the same time period. These results validate our corporate strategy of optimizing production while safely reducing cost structure.

It is not coincidental that our asset outperformance started in Q3 of 2015 when our RMI infrastructure system was fully placed into service. These field-level assets have been critical in lowering line pressures, creating redundancies in gas evacuation, and providing centralized facilities, resulting in enhanced well performance, reduced downtime, lower LOE, and mitigating weather impacts.

Our operational teams have dedicated their time to optimizing these assets during a period of drastically reduced activity, striving to squeeze incremental performance out of wells and reduce operating costs. While each of these incremental efficiency gains are not game changers, their cumulative effects are very material and will carry through when we get back to drilling and completing wells.

While we do not have any update for you today on the results of our asset sales, we continue to market these assets and look forward to monetizing them to supplement our liquidity runway for the Company.

Coming back to the Company's operational performance, I will briefly walk through the Company's first-quarter results. As you can see on slide 5, the Company reported sales volumes of 24,300 BOE per day, exceeding the top end of the Company's guidance of 24,000 BOE per day. Our LOE and midstream expenses were far below our guidance range, as was E&P CapEx.

Our cash G&A for the quarter was impacted by a one-time severance charge of $2.2 million, which was attributable to the reorganization of the Company executed at the end of the first quarter. The Company has downsized its G&A staff twice since the fall to match its staffing to its activity levels, which has resulted in annual cost savings of approximately $13 million, or 25% from 2015.

Moving to slide 6, we have provided guidance for the remainder of the year. It is worth noting our guidance assumes the Company has no additional drilling or completion activities for the remainder of 2016. For the second quarter, our production guidance implies a sequential decline of 5% from the first quarter and a year-over-year decline of approximately 25%. These declines are attributable to drastically reduced activity levels, with 2016 CapEx expected at $40 million, a 90% decrease from 2015.

On the cost side, you will notice that we have guided annual dollar amounts for LOE, midstream expense, and cash G&A because our cost structure in 2016 is primarily fixed in nature. As you look to model the remaining quarters, it is safe to assume that these costs will be proportionally spread across quarters for the remainder of the year.

Another item of note is this year we have broken out our LOE and midstream operating expenses into separate line items on the face of the financials and are guiding each line item separately. Historically, we have combined both of these expense items in the LOE line of the income statement.

With that I will turn the call over to Tony for his operational update.

Thanks, Rich, and good morning, everyone.

Before diving into the operational details, I do want to reiterate Rich's point from earlier. We truly are proud of the operating teams working our assets. It is a testament to the quality of our personnel and to the quality of our acreage.

On slide 8, I will walk through our first-quarter Wattenberg program. During the quarter, we operated one rig and completed and connected to sales 11.4 net wells. As I had talked about in our fourth-quarter earnings call, we were targeting SRL well costs of $2.5 million per well. And I'm happy to report that our last 20 wells were in the $2.4 million to $2.5 million range, on average.

These achieved well costs are inclusive of the wells drilled and completed with monobore construction, increased profit loading, and plug-and-perf completions.

On slides 9 and 10, we have updated the production history of the wells completed in 2015 with plug-and-perf and increased proppant loadings. As you can see on the slides, these wells continue to outperform their sliding sleeve and 4 million pound proppant counterparts, respectively.

While we did not drill and complete an XRL well in the first quarter, we still expect the cost of those wells to be in the $4.3 million range, based on the cost efficiencies we have seen on our SRL wells.

Though we currently have no drilling in the field, we expect to take the efficiency and well design learnings from the past 18 months and utilize them when we reallocate capital into the basin, allowing us to pick up where we left off.

Consistent with our expectations described at the last earnings call, we completed our 2016 D&C program by the end of the first quarter and proceeded to release our last operated rig, thereby suspending our drilling and completion activities. At the end of the quarter, we had six drilled and uncompleted wells in our inventory, two of which were XRLs successfully drilled and cased with monobore construction.

Unless circumstances change, our intention is to idle activity for the remainder of 2016. We will revisit our activity levels as we get more clarity on our upcoming bore and base determination and asset sales processes.

We are often asked the question, at what price will we stand rigs back up and put money to work? This question is always tough to answer as there are many assumptions and variables that go into it. What I can say is that at our current cost structure at a leased level, our Wattenberg program can produce mid-30% IRRs at $50 oil.

While project-level returns are attractive, we need to be mindful of our balance sheet. When deciding to allocate capital, many items go into our assessment, but we will look intently at the Company's available liquidity and the payback time with the wells. These two inputs will be critical in determining a sustainable program that does not rely on additional external capital. While this is not a hard and fast number, hopefully it provides some context of how we assess capital allocation in the current environment.

I will now turn the call back to Rich to walk through our financial section.

Thanks, Tony. To start, I will walk through our financial position at the end of the quarter.

On slide 11, you can see that we have a very simple capital structure, with $288 million drawn on our revolver, $218 million of cash on the balance sheet, and two issues of unsecured notes. As of the end of the quarter, we were in compliance with all of our debt covenants. Our borrowing base redetermination is currently ongoing and we expect a conclusion to that process by the end of the month.

Our focus in 2016 continues to be around maximizing liquidity to get us through the low of the commodity cycle.

Moving to slide 12, we have presented our hedge book for the remainder of 2016. As you know, we restructured our hedges in March by unwinding the 5,500 barrels a day of three-way collars and replaced them with increased volumes of a combination of swaps and long puts, providing a more predictable cash flow stream for 2016, while retaining upside if prices recover.

Before turning the call over for questions, I want to walk through our 2016 outlook and strategic initiatives. From an operational standpoint, our operating teams are continuing their intense focus on optimizing our base production and cost structure. We are taking advantage of these slow times in the cycle to intensely look at our business and find ways to be more efficient. The efficiencies gained today from these initiatives will be critical to improving margins and ever improving our status as a competitive operator in the Wattenberg.

In addition to operating (technical difficulty) initiatives, we will continue our efforts to divest assets. These potential asset sales could provide significant near-term liquidity and the Company remains active in considering alternatives to improve our balance sheet and liquidity profile.

Based on the results of these processes and the status and outlook of the commodity price environment, we will continue to reevaluate our activity levels in the basin, making prudent decisions on capital allocation so that we can be best positioned to develop our tremendous Wattenberg asset.

The Company stands poised and prepared to resume activity and accelerate field development of our 3,200 gross locations.

I will now turn it over to the operator for the Q&A portion of the call.

(Operator Instructions). Brian Corales, Howard Weil.

A couple of questions for you. Rich, I don't know how much you can say on the asset sales, but can you maybe just comment on where you all are in the process? Is the data rooms open? Are they closed? Any color you could provide would be great.

Both processes are underway. We don't comment on those processes in mid-stride, for obvious reasons, but as we have said in the past, we look forward to having some definitive news to report to the market in Q2.

Okay. So it sounds like they're sooner than later, I guess? Okay, and then (multiple speakers) on the borrowing base, can you maybe comment on what your thoughts are with the borrowing base and what it ultimately goes to?

The borrowing base process, the redetermination process, is underway. We had our bank meeting with our banks recently, so it would be out of turn for me to speak on their behalf, of course, but I think it's fair to assume that with the production and the prices from last time to now and with the increasing regulatory scrutiny that borrowing bases are trending lower, so we look forward to resolving that and having some news for shareholders in the month of May.

Okay, and then one for Tony, if I could. Tony, we have seen all these -- the [hanes] completions, the plug-and-perf, are you all fixed on a set completion standard now or is it still under the evaluation?

As for going forward, we have set ourselves on the monobore construction for the drilling and completion of a well and going forward with the plug-and-perf design and going with the increased proppant loading, so that is the 1,500 pounds per lateral foot or 6 million pounds for a 4,000-foot lateral. So, that's our go-forward basis for our D&C.

And I assume longer laterals if it is -- if that option is there?

Yes, absolutely, Brian. Anytime we can fit an extended reach lateral in, we will go to the extended reach lateral. Those are our optimum wells from an economic standpoint.

Okay, great. It sounds like there is a lot of news coming up.

You bet. And again, Brian, just to remind again, a great portion of our acreage is set out for extended reach lateral development, so we have talked about that previously. But a great portion of our acreage is.

Yes. Thanks, guys.

Phillips Johnston, Capital One.

My question is about the shape of your production profile in a low case scenario where you have no more completions this year. It looks like your guidance implies about a 5% sequential decline in the second quarter and then accelerating back to a mid-teen sequential decline rate in the third and fourth quarters, which I think would put Q4 around 20,000 a day, give or take. So I think that would imply about a 40% to 45% decline rate, exit to exit, which I think is pretty consistent with the PDP decline rate that you've estimated in the past.

First of all, is that math at least directionally correct? And secondly, what would you estimate the exit-to-exit decline would be for 2017 in a low case scenario where you had no more completions again as wells next year?

I appreciate the question. So I guess the 40% PDP decline rate, I think, is a pretty consistent number to use for us. We have talked about that. We do see that decline rate decreasing as we get into 2017, of course.

I think as we came out of first quarter into second quarter, we have a mitigated decline rate, somewhat. We did have some completions in the first quarter and that would carry over into second quarter, but then we will be on straight, standard, normal well declines after that.

But I think directionally you are probably thinking about it right if you are looking at that 40% PDP decline rate.

Okay, and then for 2017, it is obviously lower, but would you estimate it is, what, like 30%, 35%, 25%?

Yes, for 2017, we're probably looking at somewhere in that mid-20%s.

Okay, great. Thanks.

Vedran Vuk, Wunderlich.

I had a question about hedging, what your outlook is for 2017, and was just wondering how maybe hedging out to next year affects the midstream deal, if that's something that the bidders would look forward to see more of the production locked in so that those 30% economic returns are a little bit more guaranteed. Just wondering if you could provide any commentary on 2017 hedging.

It is Rich. We don't have any 2017 hedges in place currently, as you know. I can't speak on behalf of the parties looking at RMI, but generally speaking, those parties are interested in volumes, not price. They like to know that (technical difficulty) development program, which is why the consideration for RMI in the past has been incentive based, as well as upfront cash. But so long as we have a commitment to develop the wells, that typically satisfies those parties.

And I was just wondering if you would add more 2017 hedges just so you can -- you are better insulated to keep up a development program, regardless if prices deteriorate a little bit from here.

In the past, we have instituted hedges when we have committed capital, so as 2016 moves forward and we have more visibility in what the 2017 program is, we will have more visibility in what the 2017 hedge program is.

Okay, thank you very much.

David Meats, Morningstar.

Just wondering, change tack a little bit, if you guys could comment on the Rockies basis differentials that you have seen, the trends so far, and maybe your outlook for the rest of 2016.

David, this is James. Yes, so we saw, I think, differentials for oil in Q1 were around that [830] mark. We do have the committed volumes on Pony Express, which are -- so as we have declining volumes throughout the year, the amount of additional volumes that we will have that we can trade on spot pricing will decrease. So, we expect those differentials to increase more towards the $9.50 range.

Okay, that's perfect. And just one more from me, I was wondering if you have any other divestiture candidates beyond RMI, such as the Mid-Con or maybe a JV in the Wattenberg?

We have disclosed that we have the Mid-Con asset and engaged in process with it, so we confirmed that on our Q4 call last year. So the Company is effectively considering all its alternatives to make sure that we can be vigilant and ensure a robust liquidity profile looking forward.

All right, that's perfect. Thanks a lot, guys.

(Operator Instructions). David Deckelbaum, KeyBanc.

Thanks for taking my question today. Was curious if you could give us -- I guess my assumption is that the RMI package that you're marketing right now, you expect to have something to talk about in the second quarter, I guess at least an update. Are the terms substantially the same as what we saw before in the last iteration or have you guys restructured what you would be looking for? Is there any color that you can give us on that side? Not (multiple speakers) on the price, not necessarily price, but just the structure of the deal.

Yes, we have a lot of key learnings from the first process. I think the number one takeaway for us, as you know, is we have a third-party advisor running that process for us, instead of running it internally. That has allowed us to cast a broader net and include more types of capital parties for that. With more confidence in our operatorship of the asset, that has made some small changes to how we approach new candidates. But largely speaking, we are trying not to predetermine too much and engage parties in ways that provide the most value back to the Company.

Got it. I guess we will see what happens with the second quarter. Tony, you talked about what your field-level returns would be at $50 and certainly compelling from an IRR perspective. And, Rich, I know the previous caller asked about other divestiture candidates, but given the returns and the liquidity situation, would a well participation agreement or a JV be something that you would be looking to market as a way of enhancing your liquidity profile or at the very least keeping sustaining production for longer, or is that on the lower end of priorities?

No, we are happy to consider those kinds of things, David. Generally speaking, the attractiveness of a program like that would be that it would effectively off-balance-sheet the D&C capital, which would pro forma increase the [liquidity of] the company, while still maintaining volumes to -- for the benefit of the RMI stakeholders. So, there is merit to some of those ideas.

Okay, fair enough. And then, just the last one for me is you talked about the base declines assumed for this year. So far in the first quarter, you guys did bring on some wells and it looks like 2Q was a little bit above where people have been thinking, and perhaps in the back half of the year, maybe for now, there is some conservatism there. But on the other side, are you doing anything different since the last quarter to enhance production that is just in the base decline profile, or could you add any color on that?

Yes, David, just looking at our production, we're making a conscious effort, obviously, to manage our base production, but I think the biggest impact has been again the impact of the full implementation of our RMI infrastructure that came online at the end of second half of 2015 and into 2016.

As an example, weather impacts in first quarter were mitigated tremendously, I think, by us having our infrastructure in place. I know there was other impacts throughout the basin, from DCP downtime through the winter storm that we had. We were fortunate that we have our equipment in place that helped mitigate a lot of that and I think that helped us with our production performance.

We are seeing consistent line pressures, we are seeing lower line pressures, and that has been a big driver to our base performance. We had talked about our flattening of the curves. The more data we get, we continue to see that, and we have a slide in our slide deck. I think the last slide documents some of that work and how that has been impacting our decline rates.

And, again, that's probably been the main driver and we will continue to do that as -- for conservatism for the second half of the year. Being an engineer, you probably hear at this side always have a little bit of a conservative bent on myself. But I think a lot of good work has gone on by our base operations team to help mitigate that and a lot of it has been around the RMI infrastructure and the consistent line pressures that we are seeing.

Thanks for that, Tony, and thanks for the answers, Rich and Tony. That's all for me.

Vance Shaw, Credit Suisse.

This is a Vance Shaw from Credit Suisse Asset Management. Good morning. I wanted to ask a follow-up question. Are you actually in talks at this point with any outside capital with an intention to help fund CapEx?

We don't have a -- we have a -- we don't disclose processes that are underway, but we have mentioned that we are very vigilant and are pursuing any and all alternatives and that a drilling JV would make sense, so if something like that is complementary to RMI, then we are very objective and transparent about that.

Got you. Thanks. Also, you mentioned earlier that at $50 oil the ROIs are pretty good, 30% range. Is that 50% realized to your economics or is that $50 WTI with an assumed basis?

Yes, that would be the $50 WTI price.

Okay, and then with that -- and then the assumed basis that you're saying roughly $9, you think? It is going to stay at?

Yes, $8 to $9, you bet.

Okay, got you. And then, finally, if you could, give us an update on what is going on in the Niobrara in general, production trends in the basin, supply/demand balance for logistics assets and the like, and whether there has been any large parcels for sale or any recent sales that have actually taken place.

I guess Tony and I will both take that. There has been a recent transaction in the basin, just a couple days ago, Noble exiting some acreage to Synergy. So, that has been another good third-party validation point about the value of Wattenberg as a basin. It is widely recognized in offset operators as a highly productive place. So, that might be helpful for you to take a look at.

Tony, do you want to speak about the operations trends?

Yes (multiple speakers)

If I can ask just real quick, is that near you guys geographically? The Noble (multiple speakers)

It is a pretty small basin, so everything is reasonably close. It is not offsetting our acreage, but it is not too far away.

Got you. Thank you.

Yes, and then on operational trends, obviously everybody is -- a great portion of activity has dropped off significantly, but I think as a basin, we are a very strong economic basin and I think we are all making headway on reducing well costs, and the move to extended reach lateral drilling is another way to leverage the economics.

And I think with us, from our standpoint, our acreage fits that really well, and when we do pick back up, you can look for us to leverage those costs and extended reach laterals moving with the plug-and-perf, the larger sand loading, all that to improve the productivity of the wells. The basin is moving that way and I think it helps us from our economic returns. So in general, that's what I have.

Got you. And how is the -- you were saying line pressures are lower, so you think the logistics imbalance that was the case years ago is not really as big a deal now, I would think, right?

Well, I think, obviously, the -- DCP spent a lot of time building out infrastructure in the basin the past year or so with the Lucerne 2 coming online, but we are differentiated significantly by having our own internal infrastructure.

The acreage position that Bonanza Creek has, the blocky contiguous acreage position that we have enabled us to build out an infrastructure internal to ourselves, which is what we are marketing as RMI. And as I mentioned in my comments, we were able to mitigate weather downtime that DCP had, probably, that impacted some others in the basin because we have our own infrastructure in place with our own compression and our acreage position allows us to do that. So, that is a differential.

But I think -- I am confident with our own acreage, with our own infrastructure, coupled with (technical difficulty), yes, I think Bonanza Creek is in a pretty good spot.

Yes, that's a pretty big advantage. There is no doubt. And just to clarify, if you guys were to sell the midstream assets, you would not necessarily have to use those proceeds to pay down bank debt, correct? You would be able to use that to fund CapEx?

It would depend on the type of consideration that the asset sale represented. So, we would have to get back to you on that, pro forma the transaction closing.

Okay, so the issue, I guess, is if it is -- whether it is cash upfront versus cash deferred? Is that basically the issue?

The way the last transaction was structured was some cash upfront, some payments to the corporate entity, and D&C participation payments. So, these transactions can take different types of substantive form, so as we make more progress on determining the party and the structure of the deal, we'll make sure we communicate that to the market.

All right, thank you.

Sean Sneeden, Oppenheimer.

Thank you for fitting me in. Rich, maybe for you, but just remind me. The, call it, $220 million of cash that you have on the balance sheet, is that all unrestricted cash at this point or is that in a collateralized security account with the bank?

That is not in the public domain.

Okay. Fair enough. I guess maybe said another way, is there any restrictions on you being able to use some of the cash on hand to repurchase any of your debt, which is obviously trading at a pretty significant discount at this point?

There is no restrictions. The restrictions would be outlined in the credit agreement, which is a publicly available document.

Okay. Is that all part of your discussions with the banks currently, I would imagine?

Yes, it is just a sensitive point. While we're in the middle of a redetermination process, I don't want to get over my skis and make reps that the banks would find objectionable.

Okay, that's fair. I guess when thinking about CapEx, the guidance that you guys gave, and trying to reconcile that with what you guys actually spent in the quarter, which is roughly $35 million, how much of that was carryover CapEx from 2015?

I think what we had for the quarter was a total spend of about $20 million, and so we did carry in some work in from 2015. We had some completions and things like that, but, yes, we had about a $20 million spend in the quarter, and some of that was carrying and some of that was drilling the new wells that we had targeted. So, I don't know if that answers your question, but that's what it was from a total spend standpoint.

Okay, so from a cash perspective, we should think about the balance of it, $20 million, throughout the rest of the year is how you guys are thinking about it?

Yes, I think that would be the case. We are targeting somewhere around that $35 million to $45 million for a total CapEx spend and we spent about $20 million in the first quarter and the rest will be distributed out through the rest of the year.

Okay, that's helpful. And then, maybe just lastly, but if you were to see prices come back maybe a little bit above where we are today, when you guys are thinking about things you could do to optimize the base, are you looking at refrac potential or anything like that? Or is it mostly holding on to try to put a rig back to work?

Yes, typically what we are doing to optimize the base, again, is just your bread-and-butter base operations, reducing downtime, maintaining lower line pressures, which helps us maintain the flowing of the wells, helps our artificial lift, which is mostly gas lift at this time.

But, again, all that optimizes, and what it does, it translates into better production performance and lower downtimes, and then, again, with our RMI infrastructure in place, it positions us to mitigate any other downtimes that are associated from the macro environment, if you will, with DCP.

That's helpful. Thank you very much, guys.

Phillips Johnston, Capital One.

Just to follow up on some of the asset sale questions. Is there any appetite for selling some of your undeveloped Wattenberg acreage outright? It seems like the Noble/Synergy deal that Rich mentioned had a price tag of around $12,000 an acre adjusted and your stock is implicitly valuing your 70,000 net acres at close to zero, if not negative, depending on what value you give to existing production. So, what with the drawbacks be in selling acreage outright here?

We don't have any current intent to sell anything in the Wattenberg. We have lots of processes underway that help us focus on redeploying cash back into the Wattenberg. So, as you know, it is a core asset, and while not totally out of the question, it is not a current contemplation of ours.

Okay, thank you.

I'm not showing any further questions at this time. I would now like to turn the call back to Mr. Richard Carty, President and CEO, for any further remarks.

Thank you very much, everybody. If there is any follow-up questions, we are available to be helpful, and we appreciate your participation in today's call. Have a good day.

Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program. You may all disconnect. Everyone, have a wonderful day.