Civitas Resources Inc (CIVI) 2014 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q3 2014 Bonanza Creek Energy Inc. earnings conference call. My name is Whitley and I'll be your operator for today. All of this time all participants are in a listen only mode. Later we will conduct a question and answer session.

(Operator Instructions)

I would now like to turn the conference over to your host for today, Mr. James Masters, Investor Relations Manager. Please proceed.

Thanks Whitley. Good morning, everyone, and welcome to Bonanza Creek's third quarter 2014 earnings conference call and webcast. Yesterday afternoon we issued our earnings press release and this morning filed our 10-Q with the SEC. You can access both on our website. On today's call Marvin, Bill, and Tony will provide their respective updates on the quarter and then we'll turn it back to the operator to open up for questions. Please refer to the November Investor Presentation posted on our website as we may reference certain slides on this call.

Our remarks will include forward-looking statements that are subject to many risks and uncertainties that could cause actual results to differ materially. You should read our full disclosures as described in our 10-K 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.

With that, I'll turn the call over to Marvin.

Thank you, James. Good morning everyone, thank you for taking the time to join us as we discuss third-quarter results and provide a strategic overview of our business. I'll keep my remarks brief and allow Bill and Tony to get further into the details about this quarter's results and our outlook for the remainder of 2014 and into 2015.

However I will tell you this, we are pleased with the third quarter. We increased production on pace with our internal plan and drove costs lower while managing an ever larger base of production in the growing organization. As I look back on the strategic decisions we've made this year, I'm satisfied that we've done the right things. We didn't lever up a $100 oil just to boost our growth rate because we knew that lower oil price environment could be right around the corner. This Company faces the future with great confidence today because we've been prudent with our balance sheet and wise with respect to our allocation of capital. We have abundant liquidity of over $600 million on an untapped revolver. We're well hedged on crude oil into 2016 at around $90 per barrel.

Our balance sheet is leveraged to approximately 2 times net debt to trailing EBITDAX, and our projects make an attractive economic return in the current environment. It's been a successful year so far. We executed on a significant transaction, have hit our production targets and raised capital at attractive terms to ensure we operate from a position of strength as we look forward to 2015.

Now, anticipating and regarding the CEO question, the Board has informed me that while they are still conducting a thorough review, they expect to name a permanent replacement in the near future. They, we, I have been pleased with the effort put forth by Management team. Tremendous work on everybody's part and I wish to thank everyone for their patience during this process.

With that, I'll turn the call over to Bill.

Thanks, Marvin and good morning, everyone.

As Marvin said, we're happy with the third-quarter results. Despite dealing with highline pressure due to third-party gas compression and facility downtime in mid-August and early September, we managed to achieve excellent production growth, increasing sales volumes to nearly 2,700 BOE per day or 12% over the prior quarter and 44% over the third quarter of last year. We are particularly proud that we drove both per unit LOE and cash G&A for the quarter down below the respective annual guidance ranges. Altogether, we saw 14% improvement in our unit cash operating costs from a year ago, and we expect both LOE and cash G&A to comfortably land within annual guidance ranges.

However, as it relates to production, we have adjusted our annual guidance range by lowering the midpoint from 24,200 BOE per day to 23,700 BOE per day. The expansion of the Sullivan Compressor Station which has a major impact on our area, experienced recurring downtime issues in parts of the third quarter and again two days in the fourth quarter. We expected downtime related to midstream issues to subside in the fourth quarter but that has not been the case. Nor do we have visibility as it will improve sufficiently for us to hit the midpoint over our original guidance range. As always, we are very focused on what we can do to continue to buffer our operations from the negative impacts of third-party midstream downtime.

We have made significant strides in upgrading the gathering and compression systems on our property, completing a major upgrade on the western side late last year, and with a portion of the 2014 augmented capital budget, we expect to finish our upgrade on the eastern acreage. During the quarter we realized -- our realized price for crude oil declined to approximately $86 per barrel from $92 per barrel in the second quarter. In the Rocky Mountains, we received an average of $13.63 off of WTI, an average corporate deduct of approximately $12. However, despite the softening up in oil prices we still managed an impressive 71% cash margin on a non-hedged BOE sales price of approximately $67.

In the DJ Basin, we have actively pursued firm transportation agreements on pipelines to sell our crude and are pleased to announce a deal that's secured 12,580 barrels per day on Pony Express Pipeline at an all-in differential of approximately $10 off of WTI. We have secured an additional 15,000 barrels per day on another proposed pipeline, projected starting in 2016. Ultimately our goal is to significantly reduce truck traffic by centralizing our gathering facilities and installing pipelines that will more efficiently transport our product to sales, eventually achieving a more modest deduct to WTI. For the fourth quarter we expect some improvement to Rocky Mountain differentials, in the $11 to $13 range.

As we navigate the current downturn in oil prices, our hedging program and strong balance sheet should help the Company maintain steady growth and operational continuity. We took advantage of strong oil prices in late June and increased our hedged oil volumes in third and fourth quarters by 50%, doubled our hedged oil volumes in 2015 and initiated oil positions for 2016. In late September, we achieved a significant increase in our borrowing base from $450 million to $600 million. With total liquidity of approximately $670 million, we are well-positioned to weather a downturn and take advantage of potential opportunities.

Now I'll turn the call over to Tony for an operations update.

Thanks, Bill and good morning, everyone.

Operational execution remains our single-minded focus. All of the positive things Marvin and Bill mentioned about being well-positioned to weather a downturn in commodity prices hinge around our ability to maximize recovery of oil and gas for the lower cost. It starts with a world-class asset and ends with talented people, and I think we have both in spades. Let me start with an update on our catalyst well program and finish with a discussion around the operating environment in the DJ Basin and an outlook for the remainder of the year in 2015.

Over the course of this year, we have dramatically improved our downspacing results by utilizing 28-stage sliding sleeve completions. Our success today continues to validate a combined 32 wells per section in the Niobrara B bench and C benches, and an additional four wells per section in the Codell. We first reported an average IP-30 of 480 BOE per day in May on a four well pad spaced at 40 acres in the Niobrara B bench. All four wells were 4,000 foot laterals using 4 million pounds of sand. The two internal wells were completed with using 28 stages, while the two external wells used the traditional 18 stages. The average IP for these four wells are 416 BOE per day, is almost 20% above our type curve for an 80 acre B bench well, and after 200 total days of production, they are still tracking above that type curve.

However, we would caution folks not to reset expectations without a statistically significant data set. We just completed the second major downspacing test with a five well pad, each well completed with 28 stages, targeting 40 acre spacing in each of the Niobrara B and C benches. It is a direct analog to the tightest-spaced pad on our super section, except this time each well was completed with 10 additional stages. This pad has been on flowback for about 10 days and so far the pressures and early production results look encouraging.

Also in the catalyst well pipeline is a recently completed Niobrara A bench test, which achieved an initial 30-day production rate of 325 BOE per day. The A bench is half as thick as the B and C benches and they well performed about as expected given the less attractive target zone. While lower in rate than the Niobrara B and C wells, we now have our starting point. This well was completed using traditional 18 stages and we are encouraged by the potential to optimize this result over time and to eventually include the A bench into our inventory and reserve assumptions.

Regarding extended reach laterals, we don't consider them to be much of a catalyst at this point. We all know that the economics are better, so the question is, can we successfully execute them over and over again? I believe we can and have demonstrated that today. Our XRLs drilled in 2014 all are holding up very well, and you can expect a significantly higher percentage of XRLs to be included in our 2015 program.

Finally, before we turn the call over to Q&A, let me touch briefly on the operating environment in the DJ Basin and our strategic outlook for the rest of this year and 2015. Regarding the operating environment in the DJ Basin. It used to be that we simply didn't have enough gas processing capacity to keep up with production. But the situation is very different today with the O'Connor Gas Plant and Sullivan Compressor Station directly benefiting our acreage, not to mention that we expect an additional 245 million cubic feet a day of processing and compression capacity online by mid next year. Now from time to time, we will still deal with periods of facility downtime or upgrades to infrastructure, but the larger view is quite positive.

In the fourth quarter this year, we added approximately $55 million to the 2014 capital budget to lay the groundwork for 2015 in three key areas. First, infrastructure. While it represents the smallest relative capital spend, it is our most important. We will complete an upgrade to the gathering system on our eastern legacy position, which will enable us to develop that area simultaneously with the northern acquisition acreage and provide for even lower line pressures in 2015. Second, development. We will kick off our efforts on the acquisition acreage by drilling and completing one well to hold an expiring lease and completing two existing wells. We will also spend additional capital to continue completion technology trials, like more 28-stage and 6 million pound fracs and also two plug-and-perf tests.

Finally, and thirdly, leasing and seismic acquisition. Our land department is focused on increasing working interest and accreting value to the Company post acquisition and we have acquired 3D seismic over much of the acquisition acreage. As we've mentioned in the past, we see significant opportunity to increase working interest and add acreage over the next couple of years. It's important to make clear that the increase to this year's capital is purely supplementary based on projects that we believe are essential to maximizing our operating efficiencies in 2015.

To conclude, I'd like to comment again briefly on commodity prices and their impact on our planning for 2015. As we are in the latter stages of budgeting for this year -- for next year, I can't be very specific but let me provide a view into how we are thinking about the world. We use $80 WTI and $3 Henry Hub as our base case pricing scenario and are very comfortable with how our business performs at those levels given our current well performance to date, recent catalyst well results, and long-term field efficiencies we plan to achieve as our development involves. At $80 WTI, we still expect to increase our capital budget next year. You should also expect a higher percentage of extended reach laterals, possibly as much as one-quarter of the program, as we've gained increased competence in the improved economics and the mechanical proficiency required to execute the program successfully.

If oil prices slide into the low $70s, we will evaluate our pace out of respect for our balance sheet as we remain focused on staying within view of the 2 times net debt to EBITDAX metric which is core to a balanced operating plan. Again, it all comes back to assets, execution, and the safe and environmentally responsible operation of our business. Among the many benefits the Wattenberg offers are low-cost shallow drilling in a competitive price environment -- service price environment. As always, but even more importantly now, we're focused on getting more for less and continue to drive down our per unit LOE and G&A costs.

With that, I'll stop there and turn the call back over to the operator for Q&A.

(Operator Instructions)

Brian Corales, Howard Weil.

Morning, guys.

Good morning, Brian.

I look at your presentation -- you have a good slide that shows the 3P inventory; it does not include anything in the A bench. I know it's early, but is this everywhere? Is this just a little bit of your acreage? Do you have general thoughts there?

Brian, the A bench -- first of all, the A bench is present across our entire acreage position, but it will come down to the thickness of the A bench section, the chalk section itself, and also the contribution of that A marl section that sits below the A chalk. The marls are the calcium carbonate rock that has the clays in it. But they are oil and gas bearing, and they are in-between the chalk sections.

So when we talked about the A bench previously, if it's just the A chalk, that would be something that'd be productive for us. We saw that productivity across our legacy position of about 9,000 acres directionally. But if the marl section is also going to contribute, especially as we stack these with Bs and C benches and Codells; as we put the A bench into kind of the total program development as we develop the entire Niobrara section in combination with Codell, that the A bench -- if the marl does contribute, we can expand that 9,000 actually more across our entire acreage.

But again we don't have it in our inventory right now. But the first result of 325, I think, gives us something to work with.

Okay. Thank you there.

You've talked over the last couple of quarterly calls on the 28-stage, I guess, the near well bore rock, breaking that up first. Are you all fully committed to that yet? 2015, is that going to be your standard completion?

I'm going to say, yes, we're fully committed to the 28-stage fracs, especially if we do our downspacing to 40 acres. No doubt, Brian. We are liking the results we are seeing.

Again, I do want to emphasize, it's only a couple of wells. But we have the second test that we are doing that we have stacked with the B and C staggered stacked test with the 28 stages. 10 days of flowback -- encouraging for us right now. I would expect us to do a lot more 28-stage fracs going forward. Yes.

Okay. I'll let some one else hop on. Thank you.

Phillips Johnston, Capital One.

Hello, guys. Thanks.

You mentioned the midstream issues are still ongoing. Has the upgrade at the Sullivan plant -- has that been completed? And if so, is the plant running at 100% now?

Good morning, Phil.

The Sullivan compression expansion -- the actual setting up the compressor has been completed. They are in the commissioning stages of that as they run through that. So there's some up and downtime, if you will, as they get that lined out. So to answer your first question, the expansion's completed. The second question is, no, it's not at 100% yet.

Okay, and the oxygen issues at the O'Connor and [Mewburn] plants, have those been solved? Or are those issues still?

Those have cleared from the system that we know of right now. We have not heard of any additional oxygen issues in the system at this time.

Okay, great.

And just looking at the four-well pad on 40s. It looks like the decline rate there is still fairly low. And the 90-day average looks to be about 17% above your type curve, if I'm not mistaken; versus a 30-day rate was only slightly above the type curve. So I'm wondering what you attribute that to?

Again, I think what we're seeing on that 40-acre pad is more efficient [rubblization] of the reservoir in between the wells. Placing more sand near the well bore at the 28 stages allows us to do that. It limits, I would say, the frac lengths. It's limiting or almost eliminating the competition between the wells at the tighter spacing. And again more rubblization of the rock near well. And again I would refer you to slide 11 of our November presentation, as you can see how those are tracking out about 200 days above the type curve.

Okay, great; thank you.

Welles Fitzpatrick, Johnson & Rice.

Good morning.

It sounds like the midstream issues are a little bit up in the air, but is it enough and is it centralized enough that you would potentially shift your drilling patterns around in 2015 to try and avoid specific areas? Or are you really routing everything through the same type of systems?

Well, first let me just emphasize, we are really pleased with the expansion that has taken place at Sullivan and we want to commend BCP for doing that. They worked with us really well on getting that upgraded, and that is going to be and will be a significant benefit to us. So I want to point that out.

Obviously we've had some issues as we move into the fourth quarter and get everything lined up. As equipment comes online, it takes a little bit of time to line things up. But we really do expect the combination of the Sullivan plant coming on line in concert with the capital projects that we are doing, that we are accelerating into fourth quarter of 2014 from 2015, the pipeline and compression projects on our Eastern acreage. That, in combination as we go into the 2015, that we will be in a very good position from pipeline capacity for our gas and we'll see lower line pressures. So we don't see a reason to moderate or change our programs based on that.

Okay. Perfect.

I know it's always hard, but any kind of estimation as to how much production was held back by the higher line pressures?

Directionally, in the third quarter, we were hit for about 200 BOE per day.

Okay. Perfect. And then if I could just sneak one more in.

The two wells that you guys are completing on the new acreage that were presumably drilled by the other operator -- were those drilled and landed the same way that you all would have? Is there anything different about their methodology that we should know before seeing those?

No. We think that they drilled and landed those pretty well in the Niobrara B bench, so we feel pretty good about them. The only thing that is limiting on the 4,000 foot lateral, if anything, is, I believe it only has about 15 stages that we're going to be able to complete. They did not run the standard -- even our own standard 18-stage completion. But we still think that, that's going to be an attractive event for us, since the well bore there, and it'll also give us a greater understanding of what's going on. But other than that, I think we feel party comfortable with that.

That's perfect. Thanks so much.

Ipsit Mohanty, GMP Securities.

Good morning, guys.

With the number of extended laterals that are due to come online, drilled in the fourth quarter, and two of them completed now, wasn't that enough to offset any midstream that you had to guide the fourth quarter down? I'm just curious about the timing of extended laterals in the fourth quarter.

We have some extended reach laterals coming on in the fourth quarter, but all wells are subject to line pressure. So when we have higher line pressures, basically, if the wells are drilled in that area they will be impacted. So again, as we talked about it, higher line pressures act as an additional choke on our flows. And it will reduce rates across the field systematically, whether it's a standard reach lateral or extended reach lateral. So I think you would see that no matter what.

And then, Tony, I'm just trying to understand the rationale of drilling in Niobrara A when you have so much of B and C to deal with along with the new acreage from DJs to (inaudible). So would it be safe to assume that as you get more prudent on capital in the low oil price environment you'll probably go slow on that program in 2015?

To answer your first question of why we would drill a Niobrara A bench, it's obviously the next step in evaluating the full resource potential of the Niobrara and also getting an A-bench test gives us the ability to see how we can now factor in the A bench in concert as we drill B and Cs and Codells together.

Going into next year, obviously, I don't want to give away what we are doing in our 2015 program. We're going to keep an eye on oil prices and see how that goes, but being more efficient will obviously be in our mindset as we go into 2015.

On the timing of the 2015 program -- sorry, in terms of color on the 2015 guidance, both on the capital and production side, as well as giving some meaningful rate from the B and C of the 28-stage frac, what are we looking at?

I would think from a guidance standpoint we will be doing that probably by the second week of January or so, of 2015. If we had the ability at that point to have that data on the 28-stage fracs on that pad, we would probably issue that at about the same time.

All right. Great. Thank you, Tony.

You bet.

Michael Hall, Heikkinen Energy Advisors.

Good morning. I guess some of mine have been addressed, actually.

Just one question around trying to think about the cycle times in 2015, given the increased proportion of capital being allocated to the reach lateral program. Anything we ought to keep in mind as it relates to potential lumpiness or just the evolution of cycle times as you move into a more (inaudible) focused program?

Good question. The cycle time on extended reach lateral pads obviously will take slightly longer than our standard 4,000-foot lateral. So that is something to factor in. What I can say is that, when we put together our plan and release our production forecast for next year, or guidance for next year, that will all be baked into that. We'll have that cycle time with the pads that have extended reach laterals on them all baked in.

To give you an idea, extended reach laterals take a few more days to drill. Obviously they're a little bit longer. They take a little bit longer to complete. So that will add some cycle time. I'm not really able to give you a specific number because obviously the pad size is going to factor that, whether it's a three-well pad, four-well pad, or five-well pad, those kinds of things. But that's all going to be baked into our guidance.

Okay. Fair enough.

And then, as we think about extended reach lateral, how are you defining that as we look to 2015 in terms of what that lateral length actually looks like?

Directionally, it's going to be between 7,500 footers to 9,000 footers.

Okay. And then you guys made some really good progress on the LOE and G&A front like you mentioned. Any additional commentary around how sustainable that is as you look to 2015? I think you had some comments in the prepared remarks, but optimistically you keep driving that down. I'm just trying to think, is that driving those per barrel rates down from the third-quarter level? Or down relative to the full 2014 average? Just trying to think about the trajectory as we look to 2015.

Again, looking -- we continue to make progress on LOE year over year and typically quarter over quarter. You may see a quarter, depending on -- winter quarters may have a little bit more LOE than summer quarters. It just depends. But typically, we see our LOE continuing to trend downward. We are offsetting, obviously, some additional costs that come up with environmental regulations and things like that. But again, overall, we see our LOE trending downward.

And on the G&A front we're basically the same. I think we're below our guidance at the moment and we hope to fall within our guidance for the overall year. So we're continuing to see that trending down and we're very focused on that, obviously, in today's environment.

That's helpful.

I guess just to close out with -- nothing in particular in the third quarter, then, that was one-time on either of those lines? Driving them down is more just blocking and tackling, and maybe a little seasonality on the LOE, it sounds like. No particular items to back out?

That would be correct.

Okay. Perfect. Thanks, guys. Appreciate it.

Mike Kelly, Global Hunter Securities.

Thanks and good morning.

Good morning, Mike.

I've got a question, a bigger picture question, on the capital efficiency front for you guys. It seems like each ops update we get from you is great. You guys are at your type curve, if not better. This implies to me about $16 F&D cost. Yet if we look at your DD&A rate, you're close to $27 this quarter, decreased $5 since beginning of 2013 and it's putting downward pressure on your recycle ratio and capital efficiencies have kind of declined at the corporate level. So I'm just trying to understand that and reconcile why the DD&A rate would be going up versus having some downward pressure applied to it.

Thanks, this is Bill here.

I guess we are producing more than we're adding on reserves, and what we've typically seen in a normal cycle is DD&A rate tends to creep up as we go through the year, and then as we kind of go back and redo and report our reserves at the beginning of the year it tends to move down, so we expect that normal cycle to continue and that then will obviously impact the recycle ratios, et cetera. Hopefully, we'll add the reserves that we continue to drill as Tony moves through this program. And we continue to produce oil a lot more than we're adding reserves at the moment.

Okay. Is that a function of just not getting full credit and reserve others being just conservative in nature? Is that (multiple speakers) --

We've tended to be very conservative in our reserve bookings. We had a full as prepared reserve report by Evan Sewell last year, and we're going to be -- we'll have an audited report early in 2015. And we'll continue on that conserved nature.

Lynne, do you want to comment further on the reserve end?

We've done a lot of different kind of testing -- spacing testing -- both vertically and laterally this year, between both Niobrara and Codell. It really takes the acquisition of data throughout the year to make judgments on what can be looked as proved reserves. So as Bill alluded to, the last quarter in the year is when we really have the data to analyze and make those final decisions for year end. So you will see additional bookings that pop up in the fourth quarter.

So as Bill indicated, you would expect your DD&A to go down at that time. And this was an especially interesting year because of all the testing and I would expect something similar next year as well.

Okay. Just maybe order of magnitude if you can give that color on -- you got a 313 type curve, what's an average type of well that you would go into your auditors and try to book as proved?

I'm not really following your question.

313 is your average 80-acre spacing. You are the chief presented in your presentations here. In terms of what you ask your reserve auditors at the end of the year to prove, what is that averaged number? Coming in at 313, saying let's book that? Or is it something considerably lower than that?

Well, our reserves are estimated deterministically, which means that the PUDs are estimated based upon the PDPs which are in their immediate offsets. And so I can't give any light to what our average PUD reserve will be at this year end.

So it varies throughout the field. We see higher reserves on the west side than we do on the east side. And I think if you went back to our Analyst Day and the 3P there, that gives you some color on how that changes across the field from west to east.

Okay. I'll follow up with you guys offline on that. Thank you.

Ryan Oatman, SunTrust.

Good morning.

Good morning, Ryan.

I was wondering if you guys could talk about what you saw in your review of the acquired acreage. No change in the location count at 700 wells, but wondering if you could speak more specifically as to how that acreage compares to what you expected? Did anything surprise you or change significantly behind the unchanged headline there?

The simple to answer to that one is, no, nothing changed. What I can tell you is that we've completed a thorough technical analysis and we are still very excited about the acreage position that we have. We have even more confidence in the numbers that we have out there, the 700 net locations. But we also still feel again that's probably a conservative assessment.

So again our excitement about the acreage is unwavering. We feel good, but we really don't want to do much more on this until we actually get out there and start drilling our own wells, which we start here in the fourth quarter, and moving from there and we'll start drilling even more in the first quarter of 2015.

Makes sense.

Can you just remind me how that compares to the legacy acreage -- whether it's infrastructure or prospectivity in different zones, et cetera? Just kind of conceptually.

You bet.

I tell you what, obviously you probably have seen our map in our investor presentation, but we consider on the north side -- the western north side -- there's about 14,000 acres or so on that western north side, very blocky, contiguous. We think that, that acreage -- we call it high-quality acreage -- the higher working interest for that. And similar to, basically, our legacy position and similar to Wells Ranch. So we feel like we have the B, the C, and Codell potential on that part of the acreage.

The southern acreage is about 8,000 or 9,000 acres, a little blockier; the checkerboarded sections, if you will, on the south side, again very attractive. We call that high value. We feel that we also have the B, C, and the Codell prospectivity there, and similar to our legacy position. The other acreage, as it goes to the north and to the east -- as you know, that's a lower working interest and we haven't really called that high value and we'll look at that later, but that added up to about 11,000 of that total 35,000 that we added in.

That's perfect. That's a great review.

And then one, just kind of tidying up question for me -- on the 2014 capital plan, can you just remind me, what percentage of that $630 million to $680 million is going to the drill bit versus infrastructure, et cetera?

It's going to be about 90%, is going to be a pretty good number for you.

Perfect. Thank you, guys.

Paul Grigel, Macquarie.

Just following up on the acquired acreage and the resources there -- as you guys go into year-end in booking reserves, is there potential upside or is it just with the handful of new wells in fourth quarter that, that will be something that would rollout more likely into 2016?

We won't be booking any reserves that would be new that we would have more drill wells in 2014, this year. Again those would drilled in the fourth quarter late, and we wouldn't have the production available to actually extract that out. So any reserve bookings on the new acreage will take place in 2015.

Great. And then just on the oil mix for the quarter. This quarter's at the low end of the historical oil percentage. Was there any specific driver of that, be it oil declines coming in a little bit faster than gas over time as the wells do? Or just location of wells? And then what should be expect going forward on the oil mix?

I think what you can see is there's really -- I don't think we have anything really anomalous on the oil mix for this quarter that we would say that's going to be changing. It's probably just a factor of the production volumes for this quarter that came in. We do not see anything significantly changing from an oil mix going forward on our assets. That's about how I can answer that one. I don't see anything different going forward from that standpoint.

Okay, perfect, just wanted to make sure. That's it for me.

You bet.

Ken Beyer, Stifel.

Good morning.

On that four-well Niobrara B pad, I was just wondering if you can completely attribute that success to the new 28-stage frac technique? Or are there other factors you can contribute that rate to? Is there anything with the geology over there?

Our objective on that pad was to select an area geologically similar, as close as we could, to the super section test that we did earlier in 2014. That was the absolute intent of that, was to get the geology as best we could similar to that super section test, and we felt like we did that. So we've eliminated the geology as a factor, and tried to get it down to where it is basically just the frac technique being the major influence on that pad performance. That was the specific intent in taking that pad.

Perfect. Thank you.

Jeffrey Connolly, Mizuho Securities.

Good morning, guys.

Wanted to ask about the eastern Codell well in the thinner section. Tony, can you talk a little bit about how that compares to the Codell wells on the western acreage after 60 days?

You bet.

The eastern well is tracking a little bit lower than the western Codell wells, as you probably saw on the IP-30 and the IP-60. But, we do still think -- we think that there is a possibility for that thinner Codell to be something that we can move forward and develop.

Again, remember that we went into that well with our standard 4,000 foot lateral, standard 18-stage frac, again for us to make sure that we minimize variables so that we can compare and contrast the data that we get out. So we think we are at a pretty good starting point for the thinner Codells and we think we can move forward with, hopefully, optimizing that and getting that to where we would be thinking about maybe adding that into our inventory.

Again, it is not in our inventory as of this point. But we'll continue to work on that. We have a second test here in the fourth quarter, will help us move our thoughts on that forward.

Okay, great.

And then on the new drill well on your acquired acreage -- is that on the northern block or the southern block?

Northern block.

Okay. Thanks, guys.

You bet.

Phillips Johnston, Capital One.

Just to follow-up on Brian's question earlier on the A bench -- what sort of EUR do you think that A well is tracking to so far? And do you think the well is economic in an $80 to $90 price environment?

My first answer was, I really probably don't know that answer right now. It is very early. We've got our first IP-30 out. 325 -- obviously that is a lower IP than our B and C, as we have indicated. But we have not gotten a chance to put anything on an EUR yet. We're going to definitely need more time and more production data before we can actually call that.

Can you just give us an update on the progress of your first North Park well?

Yes, actually the first North Park well -- we actually have drilled the first well vertically and successfully cored the Niobrara section and got that out. We pulled that core and we then shut down the rig at that point. We're starting to get into the end of the season up there to where we can actually execute the work. So we shut it down at that point.

We're going to take the core out and look at the core over the winter, and then come back next year and determine at that point whether or not to go horizontal with that well. We also have a second well that we did not have time to get in and drill, but we will target that in next year. Again, based on these core results we'll look at that probably sometime late second quarter, I would suspect.

Sounds good. Thank you.

Wayne Cooperman, Cobalt Capital.

I jumped off for five minutes so I missed something, but what -- you guys are out there in the Niobrara. You've got some pretty good acreage but you got a lot of operational issues. What's your attitude as far as mergers and acquisitions and being part of a bigger company that might really covet your acreage and could fix some of your issues?

I'm not sure I'll answer it, but we'll give it a go.

We think we have very attractive acreage. 70,000 net acres to the Company in the area. We've had a really strong quarter across the board from revenue, EBITDAX, and cost perspective. And we've had some really good results on the production side that Tony's gone through.

Regarding M&A -- there's always talk of M&A in every basin, especially in today's oil environment. But we've continued to focus on our operations. That's how we get paid on a daily basis and that's how the market regards us as a company. Our operational expertise has helped us to acquire the acreage in DJ Basin -- or the DJ resources acreage earlier this year. And our focus is to execute on our legacy and our newly acquired acreage. There's always lots of chatter on M&A, but we're focused on our operations, really.

No offense, but you're the only energy stock in the whole market that's down today, so I guess most people don't agree that you had such a good quarter and a good outlook.

I guess market will react the way the market reacts on a day to day basis, so I can't really make a comment on one day's reaction.

It's not one day. Your stock's down ginormously from lately, but whatever. I guess you guys are thinking you're doing a good job and everybody else doesn't.

David Deckelbaum, KeyBanc.

Tough act to follow, guys, but I'll give it a shot.

Thank you, David. Appreciate this very much.

At the risk of asking an operational question -- you said that next year's program perhaps could be 25% extended reach laterals, but you also said that you feel like you've had a lot of confidence in the execution on that. I guess, what could change that percentage? Is there a sensitivity to the commodity in doing more extended reach laterals? Or is there still a waiting period until you feel like you can pound these things out 100% of the time?

David, I think what you can look for is, we can execute those. We think we can execute the extended reach laterals very consistently. But again, bear in mind, we're working up through 11 right now. Before we continue to move even more forward, I think additional repeatability is needed.

We are seeing that right now. I think we leave our program available for next year for optimization if we think we can put more extended reach laterals in, we would. But also, our programs are always going to have 4,000 foot laterals involved when you look at -- as I've talked about on the road, when you look at our acreage position, a lot of it is conducive to extended reach laterals, but we have 4,000 foot laterals which will be necessary to fill in the blanks, if you will. It's filling in the puzzle to maximize the development of the acreage, so leave that with you.

But we are confident in the extended reach laterals. We are going to be increasing that next year; and long-term, I think extended reach laterals, again, you'll see obviously more and more of those unless something significantly changes, and I don't see anything on the horizon that will do that right now.

I don't know if I missed this, but can you guys quantify at all, had it not been for the downtime at Sullivan, do you know where you would have been tracking relative to your original guidance? Or is there an actual barrel equivalent per day that you feel was lost due to the downtime?

Well, in third quarter, we felt that it hit us about 200 BOE a day in third quarter for the quarter.

Do you have any read on 4Q?

Well in 4Q, I think as we have talked about before, we felt that we were tracking toward the midpoint of our guidance. But with the issues that we are seeing right now, that's why we've made the adjustment. We saw that in October, and we see this continuing through the rest of the quarter.

As I had mentioned probably earlier, we have the infrastructure project that we've moved into 2014. Sullivan's working through the commissioning issues that we see, and again the capacity is there. But we just see this temporary issue on run times and downtimes probably lasting into this quarter a little bit more than we ended -- initially had anticipated in our plan. And that causes us our adjustment. So our plan felt like we'd be up and running full speed ahead right now and that's not the case. So that's why we've made the modifications.

Okay. If I could just ask one more.

It seems like with the downtime in 3Q, Rocky still performs quite well, even with some of the fewer completions than you had originally planned. Would you characterize, or is it too early to say, that for the most part the B bench wells that you drilled this year have been outperforming your base case curve? And how quickly could you look to revise that?

I would say that, obviously, there's a lot of factors in the production performance. Timing, when the wells actually come online, and all that. We'll be looking at our reserves. That data is being analyzed right now. We're going to come through the end of the year reserve process. And I think if any changes are made at the appropriate time, that would be it.

Thank you for the responses. Best of luck, guys.

Thank you.

Curtis Trimble, Brean Capital.

Good morning, everyone. Just hoping to draw down a little bit on the rubblization on 40 acre wells. Have you noticed any change in composition of production for those internal wells completed with more stages and presumably better rubblization?

No, we have not. We see the similar type oil and gas mix, if that's the question. Absolutely. Similar oil and gas, no change on that.

Good deal. How about for the A well? Any difference in composition of production there vis a vis the B?

No, we have not. It seems that the A, B, and C all are very comparable on the oil and gas mix when we look at that. The only place we see a little bit of a change is in the Codell; as we've always mentioned the Codell tends to be just a tad little gassier.

I appreciate it.

You bet.

Andrew Coleman, (inaudible).

I'm with Raymond James, but appreciate your time this morning.

Just had a couple more questions, more on the Sullivan compression station there -- plant. How much of the downtime there is related to ramping that operation up? Or is it just a number of wells that are being brought on in batch completions? And I guess if you could give me a sense also how much of that plant is Bonanza Creek versus other players?

I guess I'll take that in pieces.

The first question is, how much of the time we think is -- I think most of the downtime, in my opinion, the way we see it is associated with getting this thing up and running to 40 million a day. So it's all about the commissioning of the plant, the size, the amount of capacity. Getting everything up and running smoothly. So that's pretty much it.

We contribute probably a good portion of the gas to that plant. That comes from our eastern acreage position. There are several other operators that do have gas going to it, but I think we are probably a majority of the gas going to that plant. Did I get all those?

Think so. As you head into winter -- I don't know if it's lower ambient temperature that are going to make much of a difference in that plant performance, but I think you might smooth out some of those issues through that. Is that a fair assessment?

What we think in the fourth quarter -- again, that's why we revised our guidance, the top end of our range downward. We see downtime associated through the fourth quarter still continuing. I think it will be lined out, the way we see it, by the end of the fourth quarter. That, coupling with the infrastructure project that we have going on, on our eastern acreage that will help us improve our own efficiencies on our own side, that will help us leverage that 40 million capacity much better by the end of the year, so I see still downtime impacts in the fourth quarter.

Okay. Fair enough.

Just one question on the [FX] sales again. Remind me again of what the limitations are between moving to a bigger portion of your drilling program using FX sales?

What we want to make sure on the XRLs before we go down to 40-acre spacing is, we talked about the 28-stage density on 4,000 foot laterals. The next step on the XRLs is to duplicate the 28-stage density on the XRL 9,000 footer. So that would be more comparable to like 60 stages. So that's probably the next step in our process to get us to execute that.

We will be doing that here shortly to get that plan so that we can execute that. So that's probably the biggest piece of that is, we like the 28-stage fracs one 4,000 footers. Love 9,000 foot wells. Now we've got to combine all that.

Okay. It sounds like that's a frac placement less maybe stratigraphic issues with placing the actual well bore (multiple speakers) --

Absolutely.

Given a little pullback we had here in oil prices, as you look at your service contracts, do you think that some flexibility is built in those contracts that you might have a chance to get access to different operators that might help smooth that out if need be?

Going into 2015, lower pricing environment, service costs tend to follow that. But there's also some sort of time period involved before those costs catch up. So all I can say is, we'll keep an eye and do everything we can to obviously get service costs as optimal as we can as we look at this environment moving forward.

Thanks for your time.

Appreciate it.

There are no further questions in the queue. I will now turn the call over to Mr. Tony Buchanon for closing.

Great. I would just like to thank everyone for the time on the call today, and wish everybody a great weekend. Thanks again for joining us.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.