Civitas Resources Inc (CIVI) 2013 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the quarter-three Bonanza Creek Energy, Inc. earnings conference call. My name is Caroline, and I'm your operator for today. At this time, all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of the conference.

(Operator Instructions)

As a reminder, the call is being recorded for replay purposes.

I now would like to hand the call over to James Masters, Investor Relations Manager. Please go ahead.

Thank you, Caroline. Good morning and welcome to Bonanza Creek's third-quarter 2013 earnings 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.

In today's prepared remarks, Mike Starzer our President and CEO will discuss results from the quarter and will provide an update on our plans for the remainder of the year. And Tony Buchanon, our Chief Operating Officer, will give an overview of our operations. Bill Cassidy, Chief Financial Officer; Gary Grove, Executive Vice President of Engineering and Planning; Pat Graham, Executive Vice President of Corporate Development, and other members of management are present and will be available during the Q&A portion at the end of the call.

Today's 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-Q and other SEC filings. Also during this call, we will refer to certain non-GAAP financial measures, as 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. Also all results discussed today reflect continuing operations, not counting the results from our remaining California property.

With that, it is my pleasure to turn the call over to Mike.

Thank you, James.

Good morning, everyone, and thank you for taking the time to join us as we discuss our third-quarter results. Before we get started, I would like to take this opportunity to comment on the recent devastating storms that affected many communities along Colorado's front range. We extend our sympathies to the families and businesses that were displaced by the floods and have partnered with organizations focused on helping these communities get back on their feet.

I especially want to thank our operating teams for their professionalism in the face of the storm. Because of their dedicated efforts, we had zero safety incidents related to the flood, and we were able to get back to work quickly, experiencing minimal disruptions to operations.

Now, as it relates to the results we have achieved this year, we understand that the first two quarters were difficult to forecast because our drilling and completion schedule was back-end weighted. As a result, we missed consensus estimates, even though we were comfortably on our internal plan. We asked for your patience as we ramped up our activity, and we are pleased to reward that patience with tremendous financial and operating results for third quarter. These results reflect value creation across both regions and positions us well to continue delivering shareholder value.

Third-quarter production was up 88% over last year, net revenue and EBITDAX more than doubled, and adjusted net income tripled. The Company continues to perform at a high level in the second year after our IPO, as we managed rapid growth and investment, production, and employee count. We maintain a positive long-term viewpoint on our business with an uncompromising focus on operating excellence and disciplined investing.

Specific to the quarter, Bonanza Creek reported sales volumes of 17,656 Boe per day, a 32% increase over last quarter. These record volumes, coupled with strong crude oil pricing, drove net revenues for the quarter to $126 million. Before the effective commodity hedges, our average sales price per Boe of $77.54 and disciplined control of operating costs, contributed to a cash margin of approximately $58 per Boe, up significantly from $45 per Boe last quarter.

Strong margins resulted in EBITDAX of $86.7 million and adjusted net income of $25.6 million, or $0.63 per share. Per unit LOE and cash G&A dropped 24% and 20% respectively from last quarter, primarily because of increased production volumes. Also contributing to the decline in operating expense was a reduction of some prior costs, such as certain gas plant expenditures and legal and professional services.

With the third quarter completed, we continued to confirm previously established ranges for 2013 guidance with respect to production, unit LOE, and CapEx. While we are not altering the range for unit cash G&A, our best estimates are trending towards the top end of the $6.25 to $7 per Boe range, as we continue to add highly experienced employees to enable the Company to execute on our future growth plans.

We are very proud that during third quarter, Tony Buchanon accepted the role of COO, and Bill Cassidy joined the executive team as CFO. Tony and Bill are outstanding additions to our talented and accomplished team. Our core values of integrity, teamwork, and transparency remain the foundation of all of our hiring and training programs.

One other thing to note, as we move into the end of the year, our crude price differential in the DJ Basin has widened as a result of longer oil hauling trips, due to the September floods and seasonal refinery maintenance. We expect both of these issues to be short term.

Finally, our liquidity position became even stronger with the re-determination of our bank borrowing base from $330 million to $450 million just a few days ago. As of September 30, pro forma for the increased borrowing base, Bonanza Creek's liquidity stands at just under $400 million.

I will now turn the call over to Tony to discuss operations in more detail and the encouraging results we are seeing from our catalyst testing in the Wattenberg Field and In Southern Arkansas.

Thank you, Mike.

We are fortunate to have superior assets in both the Wattenberg Field and in Southern Arkansas that performed within a tight range of expectations, allowing us to forecast into the future with a high degree of confidence. As we often point out, we are a Company of engineers, and we like assets that are low-risk, repeatable, and have multiple resource opportunities. We certainly have that in both of our major properties.

In the third quarter, we placed 30 horizontal wells in the Wattenberg Field and 14 wells in Mid-Continent region into sales. Crude oil and liquids volumes remained approximately 72% of total production, accounting for 90% of Company revenues.

In the fourth quarter, we expect to place our remaining 14 horizontal wells into sales in the Wattenberg Field while we move forward with drilling operations on the super-section test. Production from the Rocky Mountain region was 11,802 Boe per day, a 135% increase in volumes from one year ago and a 41% increase over last quarter.

Our horizontal results continue to impress, as production from that program increased 271% over last year and 55% over second quarter. Wattenberg operations were again impacted by high line pressures. We have approximately a 130, or about half, of our vertical wells shut-in, with the remaining wells making up just 6% of our total Rocky Mountain volumes. Horizontal wells, while better able to deal with higher line pressure, are not immune. Most notably, early producing rates are somewhat suppressed as high-line pressures acts as an additional choke, or flow restriction.

Our Pronghorn area wells on the eastern side of our acreage have been hardest hit this year, with pressures as high as 400 pounds per square inch. Also some of our catalyst wells, depending on location, have been impacted.

We are beginning to see line pressures moderate, however, as a result of a number of infrastructure projects put online early in the fourth quarter. Most significantly, DCP brought it's newly named O'Connor Gas Plant online in early October, adding an initial 80 million cubic feet per day of new capacity and added additional compression facilities. We also proactively installed upgrades to our gas gathering lines and installed our own additional compression. Together, these improvements have had a positive impact on our ability to produce gas, reducing line pressures in some areas by approximately 20% to 35% in the past couple of weeks.

Moving on to our catalyst well program, we are pleased with the progress being made to delineate our acreage both aerially and vertically. The results from our three producing Codell wells have really stood out from the group and are tracking above our 313,000 Boe target type curve, producing an average 30-day IP rate of 540 Boe per day at 69% crude oil. (Technical difficulties) a slightly lower oil content than our Niobrara wells, but produce at higher rates.

We intend to test expanding the eastern boundaries of our identified Codell potential in 2014. We have placed all four of our planned Niobrara C Bench wells into sales during the third quarter. The average 30-day IP for the five total wells currently producing is 422 Boe per day, with a very strong crude oil cut of 83%, well within our range of expectations.

We are very pleased with these results. Keep in mind, that the impact of high line pressures continues to be present by restraining initial rate and elevating the crude oil content of the wells by suppressing early gas production. We are getting increasingly comfortable with the Niobrara C Bench's ability to deliver highly economic results across our entire acreage position.

Next, our extended reach lateral testing program continues to provide compelling results. Our second well that we reported on last quarter held relatively flat over its first three months of production from 767 Boe per day to a 90-day average IP of 678 Boe per day, which compares favorably to the typical profile of other extended laterals in the area. Results to date suggest an improved FNB cost versus a standard 4,000-foot lateral. We initiated gas lift on our third long reach lateral a couple of weeks ago. It is still in initial production stage, and we do not yet have a 30-day IP.

Finally, we are encouraged by the early results of our 40-acre Niobrara B-Bench testing. Last quarter, we reported on our first two 40-acre test wells that were drilled next to an existing producer. Three months later, these wells continue to perform similar to the 80-acre B-Bench wells in that area, which of course is what we are hoping to see. Our second 40-acre test completed during the third quarter included four wells on a single path, testing an area that had no existing producing wells. The average 30-day IP rate for these four wells was 343 Boe per day with an 83% crude oil cut. The average 60-day production rate was 292 Boe per day at 77% crude oil.

Though these rates -- though these early rates are below what an average 80-acre B-Bench well produces, they fall within the range of our expectations, especially when you would take into account that we had some operational issues on these wells during the 30 and 60-day periods.

A few things to keep in mind as it relates to these IP rates. First, as discussed earlier, higher-than-anticipated line pressures restricted rates by as much as 100 Boe per day, per well. Remember that these wells were brought online during the height of high line pressures observed in the field during August. Second, we shut in two of the 40-acre wells closest to our latest extended-reach lateral well during flow-back operations to ensure an effective wrap was achieved on the offsetting extended reach increased lateral.

As a result of these two factors, we have seen lower average rates but a flatter decline during the first 60-day period than our typical 80-acre B-Bench well. We continue to be very encouraged by the potential down-spacing to add significant value, and will continue the 40-acre space testing on the super-section.

Speaking of the super-section, all of our three rigs are currently drilling the first of the planned 15 wells. We expect to be finished drilling by mid-December and begin completion operations in mid-January. We will utilize three frac crews to complete the wells uniformly and concurrently across the super-section and expect to see meaningful production in early March. Please keep in mind that due to the super-section drilling program, first-quarter production will be impacted relative to fourth quarter, as few if any Wattenberg wells we brought online in January and February. We will provide greater clarity around our forecast when we release 2014 annual guidance in January.

Moving on to Mid-Continent region, I'm pleased to report very strong results. Our Arkansas properties continue to put up great numbers quarter after quarter. Production from this area averaged 5,854 Boe per day, a 34% increase over last year and a 14% increase over last quarter. We continue to be encouraged by the five-acre down-spacing test. We have drilled eight five-acre infill wells to date and plan to drill three more before the end of the year. We have not observed any interference between wells, and initial production has been above expectations. The second round -- the second of three rounds of re-completions on several of these wells have been especially successful with the results significantly above forecast.

I'm very proud of our operations teams. They have successfully executed the acceleration and drilling and completions during the third quarter, while also ensuring their properties were well-prepared for the epic storm that hit Colorado in September. Being a good steward of the environment and a preferred neighbor to those that live near our operations is critical to our success.

With that, I will turn the call back over to the operator to open up for questions. Mike will close with a final word after the Q&A.

(Operator Instructions)

Brian Corales from Howard Weil.

Good morning, guys, and good quarter.

Thank you, Brian.

Two questions. Are line pressures -- have you seen those meaningfully improve? Are they still an obstacle, and do you think that's -- or do you envision that improving throughout 2014, or is it always going to be an issue?

This is Tony. I will go ahead and answer that question. Yes, we have seen line pressures meaningfully improve here in the fourth quarter with the startup of the O'Connor plant. We expect that plant -- we indicated that it came on at 80 million a day, and it's ramping up to 110 million a day here very quickly. We also see that expansion going to 160 early next year.

We think our midstream partners are really doing everything they can to provide us the capacity to get our gas out. We should be able to mitigate line pressures next year. But we will still have to continue with our own internal projects -- our internal infrastructure projects with compression, pipeline improvements and things along that lines to help abate those pressures. Not that they will go away, but we do see them being there available for us to move the volumes that we are going to be planning to move next year and going forward.

Do you see that impact -- is production going higher as a result?

Every time you lower line pressure, it does have a positive impact on production, and most notably, early-on gas volumes.

Okay. And then one more. The extended lateral well looked very encouraging. How does that fit into your plan going forward?

I'm assuming that the super pad is not going to have any extended laterals. Are you going to get more and more of these each year?

I think you can start to see us expand our extended lateral program. We haven't announced what we'll be doing in 2014 yet, but I think you can see us planning to drill more extended-reach laterals. The execution around laterals -- those long-reach laterals -- continues to be something that the industry need to perfect.

Obviously, we've drilled three to date. I think you could fully expect us to drill more. Maybe as our pads develop, start to see extended-reach lateral-type pads.

All right, guys. Thank you.

Thanks, Brian.

Thank you for that question. The next question we have comes from the line of David Deckelbaum from KeyBanc. Please go ahead.

Good afternoon, everyone. Thank you for taking my questions.

Good morning, David.

To hit on the last point about line pressures and some of the improvement, I know that production this quarter was again hampered by line pressures, but did you see a relative improvement on the horizontal side of the wells that you brought online? At least, were the line pressures a little bit more amenable to bringing on horizontals at higher rates, at least in the first 30 days?

I'm just trying to get a sense -- you look at some of the outperformance that you all had in this quarter. Certainly, there were a little bit more completions, but it does appear that, on average, your core B-Bench wells did a little bit better than your prior batches.

Well, I was going to say, obviously the horizontal wells perform better with higher line pressure than vertical wells. But they still are impacted by the line pressures. What we were seeing, I think, is -- in the early time, is not so much the oil rates affected, but the gas rates. The gas rates are more restricted, and so, it does affect the Boe when we report on Boe's for IP-30s and -60s.

We think those are a little restrained -- or constrained compared to what we probably had previously in lower line pressures back in 2012. Again, it's more around the gas volumes. Overall, our horizontal wells are performing very well, which is obviously why our production for the quarter exceeded our internal plans, but exceeded obviously the expectations.

David, this is Gary. I was going to add one thing to that, too. As Tony mentioned, the plant came online -- the O'Connor Plant came online in October. We really didn't see any impact of any of that reduced line pressure or potential reduced line pressure in the third quarter at all. As you look at those volumes, as Tony's mentioned, that's really due to well performance even in the face of those line pressures.

Okay. Thanks, Gary.

Going into the fourth quarter now, now that all of the rigs have moved over to the super section, how many wells do you guys expect to complete in the fourth quarter? I'm sorry if I missed that.

We expect to have 14 wells completed in the fourth quarter.

Okay, great. Last one, if I might. I know that the production going into 1Q next year is going to be a little bit lumpy. You are also going to be coming out with your 2014 budget sometime in January. Is there a -- how will the super-section performance change that budget? Will there be a process that's initiated quickly after results are evaluated on that, that would drastically alter your 2014 program, or is that more of a 2015 consideration?

I will take a stab at the first thing. Obviously, we expect our production definitely to be lumpy in the first quarter with the super-section wells coming online, really with meaningful production coming on in March. So, fourth quarter coming into first quarter of 2014 will definitely be lumpy.

We will expect to start to extract data off that super section. Obviously, if we bring those wells online in March, it's going to take some time to get production data stabilized. I would suspect it's going to be at least six months of production data before an analysis can really start to tell us some significant things about what is working and what is not working.

I would suspect us to be able to know later in the year of 2014, some analysis from the super section. Expect any changes to our program in 2014 after we come out; it could happen in maybe fourth quarter based on the results. I would suspect most of the changes, so obviously, would impact maybe 2015 going forward.

Great, thanks, guys. Nice quarter.

Thank you, David.

Thank you. The next question we have comes from the line of Ryan Oatman from SunTrust. Please go ahead.

Good morning. Great quarter, guys.

Hi, Ryan. Thank you.

I know you're done with 2013's completion activity, and I guess we have a little lull here. But the unchanged guidance at the midpoint would imply a flat quarter-over-quarter production. Is that a proper take on it, or do you think you guys will be in the high end of that unchanged 2013 guidance with 4Q growth?

This is Gary, Ryan. I will go ahead and take that one. No, I think we are going to probably -- as you look at the numbers, you are going to see us turning towards the high end of that volume guidance. We are not coming out with a change today. Obviously, we expect to see production continue to perform along the same lines that we have seen.

I think, on the completions, we don't have -- we still have a few that were ready to still perform for the fourth quarter. As we have talked about before, we still have another 14 that will come online in the early part of the fourth quarter. You should definitely take that into consideration when you're looking at your fourth-quarter performance analysis.

Okay, great. Over in the North Park Basin, we've seen Ellora generate some solid results over there with the well doing over 1,000 barrels of oil a day on a 48/64-inch choke. Can you describe the quality of that test as you can see it from afar, and how much confidence it gives you or doesn't in your own North Park acreage?

Ryan, this is Pat Graham. I think early on, when we started developing the Niobrara and the Wattenberg, we'd start off reporting 24-hour tests. There's a lot of ways to report that data. So, obviously we got away from that.

I think the same can be said for North Park. They're impressive results, but really, until you know the underlying data that went into determining what that 24-hour IP -- maybe look at it a little bit hesitant, but again, very impressive. We are looking, potentially, at drilling a couple wells up in North Park next year, and the Niobrara. Very similar reservoir characteristics between where Ellora is and where our acreage position is.

Okay. That's interesting. I think on a prior slide, you showed your acreage being separated by a fault from EOG stuff. Is that the case with EE3? Can you just remind us what geologically that fault means or doesn't mean?

Actually, it's -- the old EOG land position is now Ellora. That's what they purchased.

You are correct; there is a large basin-centered fault that separates their acreage from ours. What it does is it really creates a bowl, which puts their acreage and a good part of our acreage at the same depth. Again, very similar reservoir characteristics from what we've seen from the vertical well logs that actually EOG at the time drilled, and what we have on our side of the fault. From the data we have, very similar.

Ryan, this is Mike.

Go ahead.

I might insert real quickly that the Ellora results are not out of the range of expectations for us. 24-hour IPs are a little hard to discern, as Pat mentioned, but we do see that that is consistent with what our thinking is in the area, too.

Okay. That is helpful. Do you think your first test next year will be verticals or horizontals?

The wells will actually be drilled vertically to just really get data, but the completions will be -- are planned to be horizontal.

Okay. That's great. One final one for me. What is your acreage footprint out there?

We are about 25,000 net acres or so.

Okay. Do you feel comfortable with that, or do you think there is an opportunity to add?

It is always the possibility to add up there, whether it's on structure, down dip, up dip. But yes, there is a potential to add acreage.

We're very selective, Ryan. As you know, in our history, we are very technical oriented, and we pick up acreage that we know has a good potential for value creation. That is why we have -- over the years, we have let some acreage go in North Park, and then we've added more as we've learned more about where the sweeter areas are.

Yes, Ryan, this is Gary. I was going to add to what Mike said as well. It's important for us to make sure that, in this commodity cycle especially, that we're in the oily part of that particular window as we're concentrating on. So, the wells that we'll look to drill next year -- as Pat mentioned, we will be targeting that area as well.

That's great. Thank you, guys.

You're welcome.

The next question we have comes from the line of Welles Fitzpatrick from Johnson Rice. Please go ahead.

This is actually Bert. Welles is on another call.

Most of our questions have been answered, but LOE looked great, despite the flooding. Do you expect that to stay flat moving forward, or how should we look at that?

This is Tony. I think you can look at us on our LOE -- we continue to be vigilant on LOE, and want to provide a low operating cost. So, we're targeting to be within our guidance range going forward.

We took out those one-time costs that we had mentioned. Obviously, the volumes are driving somewhat on the unit cost per Boe. But I think you can look at us for landing within our target range for guidance.

Okay, and just one more. On that Codell rate -- that wasn't a stacked Codell [in IOB], was it?

No, they were not.

Okay, great. That's all I have. Thanks, guys.

Thank you.

Thank you. The next question we have comes from the line of Ipsit Mohanty from Canaccord. Please go ahead.

Great quarter, guys. Tony, congrats. I never had a chance before to personally congratulate you, but wanted to congratulate you on your promotion.

I appreciate it, Ipsit. Thank you very much.

Let me just quickly start -- Tony, if you could elaborate a little bit on what happened at those couple of wells on the Niobrara B 40-acre? You mentioned here it was hampered due to post fracking, but if you could add a little bit more color, please?

You bet, Ipsit. Let me just start off on the catalyst wells in general again. With the data that we have -- just to capture it all -- but the data that we have available to us internally, we are pleased with the catalyst results. And they are all falling within our range of expected outcomes.

We are continuing to move forward with development on all fronts, which includes, obviously, downspacing in the B Bench, the evaluation of the C-Bench, the Codell, and extended-reach lateral. Again, I just want to re-empathize we are pleased with all the results on our catalyst testing.

Specifically to your question, Ipsit, though, on the 40 acres, what -- from an operational standpoint, that we saw -- obviously, I talked about high line pressure. That was impactful in the area. But specifically, the two eastern wells of that four-well pad were -- offset our most recent extended-reach lateral that was drilled in the area. During flow-back operations on those two eastern wells, the timing for the frac came up for the extended-reach lateral.

We made a decision at that point to shut those two eastern wells in -- to go ahead and frac the extended-reach lateral. And of course, the technical reason to do that was we wanted to ensure that we properly fracked our extended-reach lateral, and not create any kind of offset pressure sink by producing two wells that were offset to it that could influence a frac job on that well. So, it is not preferred operations; it worked out that way.

You might ask -- why did we do that? Well, that's the way it worked out. But how do you fix it?

How do you fix it? Well, we fix it by super-section ideas. The techniques that we're going to be doing as we go forward with pad development and super-section type operations, where you come in and drill all of the wells, and frac them all at the same time eliminates the need to be shutting in these offset wells as you perform frac procedures on your wells. I think, moving forward, obviously, we are going to be optimizing those procedures to do that.

How did it impact those two wells? Obviously, when you frac an offset well, those two wells were impacted a little bit by additional water being induced from an offset frac. And so, that hampered the recovery in the early time.

But overall, I just want to emphasize that the results that we are seeing from the overall pad, and given the results as they are to date, they fall within our range of expectations, and that we are seeing a flatter decline rate out of these wells compared to our 80-acre B-Bench wells.

That is great color. Thank you.

Great.

Just a quick one -- just to stay on the same line -- the Codell wells that you've given, and obviously, they're getting better as you move from one to the other. But just geologically, are they the same? Is there any differences that you've seen in the rock quality?

All of our Codell wells between our Codell wells may be minor, Ipsit. Typically the Codell -- it is a sandstone, better perm, better porosity. But again, you have some variabilities probably just across the field, but nothing significant.

Again, when we complete these wells, we expect a range of outcomes. There's not just a one number that we're shooting for when we bring these things online. We look at all of these Codell wells as being within our range of outcomes. There is just not that much variability in the reservoir that would cause that.

I think that's a good point. Our first Codell well was a 370-Boe-per-day IP-30. I just want to say that the problem when we brought that out, there was some people that reached -- maybe a little disappointing with that rate. Internally, we were very encouraged, because it indicated that it would be productive, and that we can improve moving forward.

And so, when you think about back to our 40-acre B Bench, that is something to factor in mind. These initial B-Bench results on that four-well pad that we just did is very similar to our initial results on our Codell. And you can see where the Codell has taken us. I just want to capture that there is a range of outcomes, and that all the wells we have drilled are falling within that.

Got you. And my last one -- this is more of a broader question for Pat and the rest of the team. In our past discussions, you have talked about how the Wattenberg is pretty cored up among the guys -- the large camps and then you all at the mid-camp level. As you look outside (inaudible), is there something within -- taking a step back, is there something within the region that interests you? Whiting's talked about its RedTail and how good it's doing. Noble has done about (inaudible). Is there an extension of the increase that you're looking within the basin?

Yes, this is Mike, Ipsit. I will go ahead and field that, and then maybe if some others would like to chime in. Being operators there in Wattenberg since 1999, we have a very strong knowledge of the basin, and we are very selective. But we are also very aggressive. Anything that becomes available in the basin that fits our investment criteria, we are all over it.

There's a number -- now we have -- we pick up small pieces of acreage here and there all around our position. The bigger blocks, although mostly cored up, we look at those very closely, too, and if they become available, we are all over them.

Pat, any additional color from that for Ipsit?

I can say that we have done a number of acquisitions this year. We've probably increased our acreage position by about 10%. Now, it is all in our core area.

As Mike mentioned, we're very aware of what's out there. We have got the whole basin mapped out. We know where the places that we want to acquire acreage would be. And we definitely keep an eye on those blocks, and approach any parties out there that we believe might be interested in divesting.

Thank you.

The next question we have comes from the line of Adam Michael from Miller and Tabak. Please go ahead.

Good morning, guys. I think most of my questions have been asked already. I did catch -- there was a line in your press release about a pipeline system to bring frac water in. I wanted to get a little more color on that. And was curious what you currently spend per well trucking water out, and how much potential savings could we see from this?

I will go ahead and take that. Adam, Tony here again. We have that pipeline system. We just got that up and running. And basically, it's a pipeline system that goes through the middle part of our acreage -- what we call our 70 Ranch area.

We are utilizing that now versus trucking water. We are starting to see a reduction in costs on that. Obviously, anytime you take trucks off the road and can pipe water, that works for us.

I don't have a firm number yet on that, because we have our estimates, but we are actually starting to see the full impact of that here in the fourth quarter as we finish up these completions. I can probably give you a better number going forward. Obviously, intuitively, we are going to be saving some money by doing this. But I hesitate to give you a number today that you can put into a model, because I really want to get some real numbers documented as we come though fourth quarter, now that this thing is up and running.

Again, safety-wise, it is important to get trucks off the road. It is good for the landowners. It's good for everybody to reduce that kind of traffic. So, we will have some savings. If I could leave it at that, I would go from there.

Okay. Fair enough. Do you think that is something that you would expand to other parts of your acreage going forward? Is this kind of a specific project just on that one area?

No, I think you can look for us to expand as we go forward. Obviously, in our 2014 and going forward, as we increase the number of wells we have out there, you can see us to be looking to have infrastructure projects on water delivery, water to disposal, oil piping around our core position. Since our position is so contiguous, it leverages us very well to do those types of infrastructure-type projects. I think you can see us doing those going forward. Anytime we can get that done, it will improve our efficiencies.

Adam, I might just interject also. Tony's team are always looking for continuous improvement in operations and in investments out there. Having contiguous acreage is a real blessing to have, to be able to bring some economies of scale in all of our development going forward.

We will see cost savings. We have quantified that internally. As for significant, and Tony will give you better estimates later on, I think right now, we are still projecting the same cost going forward.

Okay, guys. Thanks. Fantastic quarter.

Thank you very much.

The next question we have comes from the line of Michael Hall from Heikkinen Energy Advisors. Please go ahead.

Thanks, good morning. I wanted to circle back a little bit on a topic that was brought up earlier, as it relates to those 40-acre down-space tests, and how you had to shut them in with -- in advance of fracking the offset and extended-reach lateral. I understand while we better understanding of how to approach these super sections and what not, but it seems like that's probably more of a late 2014, early 2015 type time frame, by the time we move into that on a more widespread basis. So, in 2014, should we expect to see any material amounts of downtime associated with shutting in wells for offset fracs? Or do you think there will be more just one-off, and shouldn't really have a material impact on the year?

I guess what I will answer that first off of -- obviously, as you delineate your acreage, you have wells that are going to be out there that you had to drill first to delineate your acreage to prove that you wanted to go back there and drill again. We're going to try to minimize that going forward. But I would say that obviously in 2014, we are still going to have wells where we go drill offset existing producing wells, and we will have to shut those in. They will be impacted by that.

What I can tell you though is that, when we release our volume guidance for next year, that will all be part of that. We have done a detailed technical analysis of the wells that we have on to date, and that impact from those wells. And that will be factored into our production forecast that you see us providing here when we give guidance in January.

I wish we could avoid it, but once you delineate, you're going to have some of that. Now, we are optimizing our program to minimize it, so I will say that.

Great, that makes sense, and that's helpful. And then I guess the only other on my end was around the -- actually the Mid-Continent program was a bit better than we had been modeling. Seemed like some good strength in the quarter there. Anything in particular driving that? Is that production level sustainable going forward?

Yes, this is Gary. I will go ahead and take that one. I think a couple of things down in Mid-Continent are driving the quarter, if you will. And we've talked about our 5-acre in-field program, and that's been doing well.

Internally, we added some risk on that just because the expectations, as you down space, you might see some interference. As Tony mentioned earlier, we just haven't seen that to date on those wells. So those wells, quite frankly, are outperforming what we would consider for a 5-acre look initially, and performing more in line with the standard 10-acre wells that we've been drilling out there since 2008. That's adding to it.

The second thing I would tell you is that as we drill these wells, we produce the bottom interval first. And then we start to add zone through time, either three months later or even beyond that. Those particular re-completions have been very strong in this quarter as well, both from the ability for us to get them performed and also how they're responding.

Thirdly, I would leave it with the plants that we have and the new plant that we brought online earlier in the year continue to help our performance there in terms of lowering our shrinkage, if you will, and increasing our yields. And so, the combination of all three of those, I think, are leading to a strong quarter in the Mid-Continent. And we would expect to see that continued performance going forward.

Helpful. Thanks, guys. Congrats.

You are welcome. Thank you.

Thank you. The next question we have comes from the line of Joe Magner from Macquarie. Please go ahead.

Good morning. Thanks. Curious on the outlook for first quarter and then 2014. Last year, you all slowed development drilling towards the end of 2012, and that pulled down first-half 2013.

Is it right to think that maybe we will see a flat start to the year, and a back-half loaded ramp? Or beyond the super-section activity in the first part of the year, how might things shape up for the balance? I'm trying -- I know you haven't given guidance yet, but trying to think through the --

Yes, Joe, this is Gary again. I think the important thing to note is, if it didn't come out is, right now the way the schedule looks is probably in January and February we won't be bringing any wells online at all in the Wattenberg, due to the fact the way the super-section drilling has been performed, and the way we are going to complete those wells and bring them online. I think that's probably the biggest piece of information that we'd like to share with you and looking at the first-quarter as it might compare to the fourth quarter of this year.

And then, as you would expect, as those 15 wells, if you will, start to come online at the end of March and then in towards the beginning of April, and then we continue to see that program ramp up from there with the rigs now moving back to a non-super-section type of drilling program. I think that's the best way I would describe it at this point. While it maybe not be for the same reasons, you might see some similar attributes in 2014 as you've seen in 2013 as far as the construction of the volumes go for the year.

Okay. And then I want to make sure I understand this right. That comment was made that drilling on the super section will done in December and then completion activities will start in January. Where will the rigs move? Is it that all of the activity and all of the effort will be focused on super-section completions, and you won't be able to get to new wells that might be drilled in the first quarter until later? Is that -- ?

This is Tony. No. No problem on moving the rigs. Those three rigs that will be drilling once they're done with the super section, other than coming out of the holidays, we will plan to put those rigs back to work quickly in January on our 2014 drilling program. The super section is tied to the one section, but we have plenty other opportunities to go drill, and that's where those rigs will go.

And this is Gary. I was going to add one piece to that, Joe. If you think about a typical well out there when we spud and when we bring it online, you're in that 45-day to maybe 60-day time frame from when you spud to bring it online. So if you don't start drilling again on something other than the super section again, the early part of next year, that's why you say -- look, you probably don't look to bring wells on in January and February just because of that normal cycle time frame on a given well throughout our acreage position.

Okay. That is helpful. And then on the go-forward, granted there's still a lot to learn on super-section development, but given what you've seen already with the need to shut-in offset locations -- in an isolated scenario, granted it makes a lot of sense to drill a section and complete all of the wells at the same time. But moving forward, what kind of a cushion or what kind of a -- I don't know what the right term would be. But as you develop super sections next to one another, how much of a buffer do you need? How many wells might you need to shut-in on those? Granted this is down the road, but I'm just curious how you think about the impact on those -- the drilling completion and shut-in nature of that as it rolls forward?

Yes. This is Tony. I will take a stab at that. Obviously, as we drill wells, wells that are directly offsetting the existing well that we drill and get ready to frac would be wells that we would need to be shutting in. Again, as I mentioned going forward, hopefully what we have tried to do with our acreage position and leave ourselves a lot of places that we can come in and do the full-pad development-type drilling where you don't have to shut-in, if any wells at all or just a few.

But again, going forward, you can look at having to shut-in the offsets. And then every area of the field can be different. We will take a look at it. There may be an area of the field where you don't have to shut it in because of some -- the way the wells are producing, where they are in the production life or something along that line. We will manage that as we go forward, but what I can tell you is when we provide our production guidance going forward, all the technical analysis that looks at all that with all the data that we have, that will be included in those production guidance numbers that we release, especially as we start to talk about 2014. That will all be counted into that.

Okay, and one last one for me. I think in the presentation, you all had been guiding to I think around 18 completions for the fourth quarter. Were some of those pulled forward into the fourth quarter or were some deferred because of the super-section activity?

They were pulled forward into the third quarter, just toward the end of the third quarter.

Again, a week or two could put it in the third or fourth quarter. That timing is a little somewhat nebulous there. It was the best estimate as we go forward.

Okay. That is all I've got. Thank you.

Thank you, Joe.

Thank you. The next question we have comes from the line of David Beard from Iberia. Please go ahead.

Good morning, everybody.

Good morning, David.

Most of my questions have been answered, but I wonder if you would just help me understand -- it seems like down in the Mid-Con, the mix shifted a little bit more towards NGLs and what was driving that mix? Is that sustainable or could that even grow going forward?

It is a combination of a couple of things. First is, we probably seeing a little more wellhead gas. I know it's going to sound a little bit odd, but a little bit more wellhead gas, which obviously brings more gas into our plants. Remember our ownership structure there is we own those facilities 100%.

And so the way the contracts are structured, the plant does receive a bulk of the liquids revenue there, if you will, and corresponding volumes. That is one thing that would lead us to a little bit more liquids yield there. Second one is, as I mentioned earlier, the plants themselves have been operating very efficiently, and our yields have actually been increasing throughout the year with that stream of gas coming into the facilities.

Okay.

About a comment of going forward -- again, we can't always know exactly the mix that's going to come from the wellhead, but given the existing conditions, we think our plants are going to continue to be efficient. I can tell you that.

Okay, and as a quasi-related follow-up, we've seen some competitor advances in the Brown dense. Wanted to hear your updated thoughts on that region.

Absolutely. This is Gary, again. We are excited. Obviously, we are excited to see that Sharp well come on from Southwestern. They really had a lot a conversation around it, and we're excited to see that.

That well is obviously in Louisiana. It's a little bit further away from us. However, they did mention, not their second well, but their third well that they mentioned that just finished up drilling is the McMahon well, and it's about five miles south of our [George Heap] position.

So quite frankly, we feel like were in an enviable position here; all of our acreage there is held. We don't have to do anything with it. We do have brown dense opportunity there, as we have mentioned in the past. We're excited to see this new well, if you will, that is going to be completed, hopefully, very similar in line with the Sharp and their Hollis well, and see the results of that. And if it continues to be successful, that is something that we'll look to basically follow quickly on, on our acreage, again, as that information starts to come in.

I think the other thing that we've seen that would be interesting to us is to report actual costs on the second and third well. The first well came in around $10 million. We'd like to see those costs come down more, and I know they do, too. They've intimated it might be around $7 million on the second well. So, as we continue to see the results even a little bit closer to home, if you will, we'll be quick to follow on that.

Okay. Great. Thanks for the time. I appreciate it.

You are welcome.

Thank you. The next question we have comes from the line of Mike Kelly from Global Hunter. Please go ahead.

Hello, guys. Good morning.

Good morning, Mike.

The catalyst program for this year has obviously -- it's been a huge success. You've still got a lot of work and a lot of excitement left with this super section that you are going to have come on early next year. I'm curious just moving beyond that, and given the technical talent you guys have at the Company, I'm curious to hear if you are starting to think about what potential next vintage of the catalyst program could be out there for you? If the Greenhorn is starting to be something that you are going to think about testing more seriously or some other concepts up there that we may hear about in 2014? Thank you.

Yes, Mike. This is Tony. I will take a first pass at that. Obviously, there's other horizons out there, as with any play where you have stack pays. We always seem to be able to figure out something else that is going to work. If you look at our acreage position, we have the A Bench. We don't have that in our current resource, but you can look for us to be looking at something there in the A Bench testing.

We also have, as we talked about the Codell, as we continue to push to the eastern -- push the Codell development eastern, the Codell sits on top of the Carlile Shale. And the Carlile shale is the source rock for the Codell. As we continue to see how this works as we go to the east, if we can drill wells in the Codell, and need less and less Codell, and can encounter more and more Carlile and still make wells, you can see that the Carlile could have some potential. If that works, that is something that could expand across our entire acreage position.

As you talked about the Greenhorn -- the Greenhorn is another one. We're looking at other companies, and some of the things that they are doing in the Greenhorn, but we have Greenhorn. So, yes, that's another potential resource for us.

The [Grenair] shale is another potential resource. Again, our technical teams will start to look at those resource assessments as we move forward, and apply the key data that we are getting out of the Niobraras and Codells right now to see what we can do to crack those open, if possible.

Okay. Great. Do you think that is something that we see out of you guys in 2014 -- some new horizons tested?

Yes, the one other thing I might add to you is -- the fortunate thing we have on our acreage is we have 3D across our entire acreage. And so what that does allow us to also look for is something a little more conventional, and it is the Lyons Formation. The Lyons Formation sits down at about 9,500 feet, and it's more of a conventional trap. It's not something you would pursue from an unconventional resource play, but if you got 3D seismic on it, and you can see the bumps and you can drill them, you can be very successful.

You can see us looking to test the Lyons potential that we have on our acreage position. We're actually in the process of drilling a Lyons test today, and we will continue to look at that as we go forward. That's another horizon. Again, it's more conventional, if you will. Again, we have the data, and we will take advantage of that.

(multiple speakers) I was just going to say -- just to add to that Lyon's piece really quickly. We're looking for oil initially. It's not -- as Tony mentioned, it's not a huge resource across the area. So it's going to have its opportunities across the acreage.

But we also have, and what we like to firm up is our back-up position there, which would be to use those wells, if they happen to be unsuccessful, as a salt water disposal candidate, which would go towards eliminating or, if you will, reducing some of our operating expenses going forward as well. It's a nice intern opportunity for us at the end of this year and even into the beginning of next year.

Very good. A quick one here -- how much of your acreage do you think now is de-risked for the Codell? What is a good number for us to throw in there for risk factor? Thank you.

We're still carrying, Mike, about 15,000 acres on the western portion of our acreage. We're going to learn more as we develop. That's why Tony mentioned about testing the Codell further, and then in conjunction with the Carlile. But right now we're still holding to that 15,000-acre number we feel very confident in.

Great. Thank you. Good quarter.

Thank you very much.

Thank you. The next question we have comes from the line of Ray Deacon from Brean Capital. Please go ahead.

Hello, good morning. I had a question about the C tests that you announced. Can you talk about whether they were geographically spread out across your acreage or on the same block?

Very good question. This is Tony again. What was encouraging about our C-Bench test -- they were scattered out across our entire acreage position from the furthest western part all the way to the furthest eastern part of our acreage position. We have five of them online, and that's why it leads us to -- I'm not saying it's fully, fully delineated, but obviously, our confidence factor is increasing significantly with the C-Bench potential across our entire acreage position because of that.

Okay. Great. With the super pad, the reason there's relatively fewer C-Bench tests -- is that because of vertical wells in the area or just that you feel it's de-risked?

No, On the super-section test, again, one of the key things that we are testing there is more the vertical stacking. And so, we are stacking B, C and Codells together to get an optimum fit, if you will, from a vertical standpoint on how we want to lay these wells in and how we need to stagger them.

It was more to test the stacking technique, and not so much to delineate the C or the B or the Codell, because that's basically, in that area, it is already delineated. We know that it is there. Now it's try to figure out how we want to stack the wells in there to produce them and complete them efficiently.

Got it. Great. Thank you.

The next question we have comes from the line of Ravi Kamath from Global Hunter. Please go ahead.

Hello, guys, great quarter. I had a couple of questions -- one on the Mid-Continent. How much of your position in Dorcheat you think is de-risked for the 5-acre downspacing, and do you expect to be booking a lot of 5-acre reserves at year end?

Yes, this is Gary again. The two areas that we have the most information on are towards more the eastern and central part of the field. The wells that we are drilling now, that Tony mentioned, are more towards the western part of the field. We will obviously want to continue to see information across the property. That is what we have delineated at this time.

As far as booking for year end of this year, I think what we have determined with looking at it internally is we probably would not look to book any 5-acre offsets at this time, and get a little bit more production history. If you remember that we want to see not only the initial completion, but also the additional zones that get added. And they get added over the course of a year at a minimum. We want to see a little bit more data there before we feel comfortable going to our third-party analysts and recommending any direct 5-acre offsets. So, I think we'll probably be a little -- if you want to call it conservative, that's fine -- in timing of adding any 5-acre's at this year-end reserves.

With that said, though, we have looked at the property. And I think we have mentioned this in our investor presentation, that upside looks to be 200-plus locations at 5-acre drilling. If we deem it that, it ends up being successful with what we're looking at to date, and everything at this point is pointing to very encouraging results.

Got it. Great. And then a second question on the Wattenberg vertical production -- looks like that came down to about just under 700 Boe per day from about 1,200 in Q2. How much of that would you say was related to the flooding? And what do you expect that to do in Q4 -- if you could just comment on that, please?

This is Tony. I will take the first stab at that. The vertical production -- basically, very minimal impact due to flooding. We had a handful of -- we shut in proactively 26 vertical wells. We have most of those wells back online.

So we have minimal impact due to the flooding on the vertical wells. We have about 255 total vertical wells, to give you a flavor for how much that is. Most of the production impact on the vertical wells has been really due to offset frac-into's by our horizontal program. Those wells get fracked into, they knock the wells off.

Then, of course, during this time period, and third quarter is included in that -- emission season. With the emission season being more strict through the end of September, bringing those vertical wells back online is more difficult to do. Typically, we can open tanks and let those wells kick off on their own. With the emissions season, we were not able to open the tanks to do that. And so, therefore, the wells would've required swabbing to get back online.

Compounding that, obviously, is high line pressures. When you have high line pressures, the vertical wells are the most effective. And so, when you try to do all of those things, and then you still have high line pressures, the wells may not come back online and stay online.

What I think you can see going forward is that we will make, obviously, a better -- we're going to be more -- getting more of those wells back online starting in fourth quarter. But it is all tied to with the O'Connor plant coming online, and our internal infrastructure projects that we brought online here early fourth quarter. That's going to help those vertical wells come back.

Again, we will economically be prudent on getting those things back online. Obviously, if we have some that we're going to be fracking another horizontal well in that area. We're probably not going to spend the money to get it online until we have all of the fracking done, so that we can get back out there, get it online at that time, and be able to leave it online. So, I think you can see us to bring those back online gradually here in the fourth quarter and early into first quarter next year.

Great. Thanks, guys.

Thank you.

The next question we have comes from the line of Mike Scialla for Stifel. Please go ahead.

Hello, everybody. Tony, you mentioned the Pronghorn area was particularly impacted by the high line pressures. Can you say how many horizontal wells were affected there?

Well, to be honest with you, Mike, all of the wells in our Pronghorn area were impacted by that. I'm going to say, on a well count, we probably have about 20 to 30 over in that area. So, all of those wells were impacted by that line pressure -- every single one of them.

It was obviously hit with the highest line pressures. That area -- we are going to get some relief now with the Sullivan compressor station that's coming online. We just added -- or we have -- DCP has just added additional capacity up there.

So, we're starting to see those line pressures come down, and it has been pretty dramatic in that area. We have spiked up to 400 pounds over there. Right now, most recently in these past couple of weeks, we are seeing it down in the 225 to 250 range. Still not perfect, but a whole lot better.

Hello, Mike. This is Gary. Just to add to what Tony said is -- if you look at the wells that were drilled in this calendar year, a lot of those wells on that eastern Pronghorn area were drilled earlier in the year. We've just -- directionally, the way the rigs were moving for the year, just to give you an idea of where those wells are positioned. A lot of those wells drilled early in the year have been seeing that high line pressure over in that Pronghorn area throughout the year.

Okay. And if I heard you right, Tony, you said you thought it was about 100-Boe-per-day impact on a 30-day rate for those wells?

Yes, actually, probably, Mike, yes, it's about 100 Boe per day. Actually, if you had even more pressure, what we're looking at is about 5 Boe per day per PSI. So, if you've got a well that's more impacted by pressure, you might even be looking at something a little more than 100 Boe per day.

Okay, and is that something that just started to impact the horizontal wells this year, or was that a factor on horizontal wells last year as well?

It's more of a factor on the wells this year.

Okay. And then, the two wells that you had to shut in for the offset fracs, is there any way to quantify how much those were impacted in terms of Boe per day on those 30- and 60-day rates, or is that too difficult?

I would probably fall back to -- it's around that 100 Boe per day per well. I think that would be pretty sufficient, Mike, on that one. Because it is a little difficult as you bring those wells back on the early time -- flow-back time.

We definitely did see the impact for sure. And those wells do have a flatter production profile, as we've brought them back online as they've cleaned up.

Okay. Thanks. And then, you were asked about the long laterals. It sounds like, if I heard you right, it's something that you're going to continue to work on and maybe slowly ramp up. Do you ever foresee, given the performance, not only of yours, but Noble and Anadarko as well -- do you ever foresee the chance that that becomes the standard for Bonanza Creek? Or do you think it will always just be a smaller portion of the portfolio?

Mike, no, actually I do see it continuing to grow. If the results continue to follow, and most importantly, if we can mechanically execute these things over and over again, like we can our 4,000-foot laterals. I think that's the biggest thing we wanted to get to repeatable to where the success rate of the extended-reach laterals are the same as our 4,000-foot laterals. Where you can basically drill them and count on them coming online every single time.

With that being the case, and where we are progressing, I think you can see the programs evolving to where a majority of your program would be medium reach or extended reach, a variety of those kind of things, but definitely longer laterals than 4,000 feet.

Mike, this is Mike. I might interject also that the key learnings that we have over the next 12 months with the super-section testing -- it is not mutually exclusive to extended-reach lateral development application out there on the field. What we are learning may come -- what I'm excited about is it culminating all together in 2014, both extended-reach lateral technology, as well as super-section optimal stacking technique. And we come together as we plan 2015 and in the future.

Got it. Well, I will look forward to that extended-lateral super section coming up. (laughter)

One last one for you -- Mike, you had mentioned you will be aggressive looking at opportunities within your core area. Curious -- was that Marathon acreage of interest to you at all, or was that outside your core?

Mike, it's Pat. Some of the Marathon acreage is pretty spread out, kind of like Chesapeake. There was definitely some in our core area, although relatively small to the overall size of the package. But yes, there was definitely some pieces of it that were of interest.

That's all I have. Thank you very much.

Thank you, Mike.

Thank you. The next question comes from the line of Irene Haas from Wunderlich Securities. Please go ahead.

Actually this is Mo Dahhane for Irene. Good morning, everyone, and congrats on a good quarter.

Thank you, Mo.

Two quick questions. First question on the Codell. Based on the three wells you have completed so far, are you seeing a higher [GOR] than originally anticipated for the Codell?

Mo, this is Tony. No, we are not. Actually I think it is pretty consistent with what we expected in the Codell. The Codell has always been a little bit more gassy than the Niobrara. Totally, I think we're well within our expected range of outcomes on that.

Okay. Very fair. My second and last question about -- on the extended-reach laterals, looks like the second well had a flatter decline compared to the first well. Can you speak a little bit about what caused that?

I think on the second well versus the first well, the biggest thing is that we got the entire lateral completed on the first well -- on the second well. If you remember our first well that we drilled last year, we were lacking about 1,000 foot of lateral that we were able to complete. So, you are really comparing an apple and an orange there I think. But we've successfully completed this well, and successfully fracked it, cleaned it out and put it online. This is a good test of a well-completed extended-reach lateral well.

Did you have the oil cap for the 60-day rate?

We are looking for that, Mo, real quick. We'll get that to you here shortly.

Mo, can we just get back to you on that, Mo? Because we'll have that handy. We don't have it at our fingertips.

Absolutely. Thank you very much.

Thank you.

The next question we have comes from the line of Brian Steck of Mangrove Partners. Please go ahead.

Hello, guys. Again, congratulations on a great quarter.

Thank you, Brian.

I have one question. You've done a wonderful job of answering a lot of questions here, and so I just have one for you. I was hoping that you could comment on what our reserve expectation should be going into the year-end report in the Rockies?

I appreciate that you're not going to be overly aggressive in adding reserves for 5-acre space in the Mid-Continent. But my recollection was, in the Rockies, there were some offsets last time around because of some vertical wells that would be coming off. Wonder if that was going to continue to be the case?

And also wondered if the horizontal wells that you are drilling this year, how many of those were PUDs versus otherwise?

Brian, this is Gary. I will go ahead and answer that real quick. As far as a number, we haven't guided any reserve number for the end of the year. Quite frankly, we won't be doing that as well.

Obviously, we have drilled a lot of wells that haven't been in our proved reserve ledger in the Wattenberg. Approximately 85% of the wells we drilled this year in the Wattenberg horizontally were not in our proved reserve ledger, as of the end of year last year. You can get a feel for that looking forward on that kind of number.

But you did hit on another point I don't want to ignore, and that is the fact that we did have vertical wells out there. In our PUD reserves, and even a little bit of PDNP work for re-frac work. And as we moved forward last year, we did remove some of those. We will continue to do that as we transition our reserve ledger from a combination of vertical and horizontal wells to what looks today to be mostly horizontal development going forward.

So, there will be some slight impact of that at the end of this calendar year as well. We may or may not decide to transition all of those out. It may take one more year.

But that's very similar to some of our neighbors who are, again, have been just a little bit in front of us maybe on their program by a year or two. Specifically, Noble -- I could point to them. And as I think we've mentioned in the past, they took about three years to completely move off of their old vertical PUD type of reserve ledger, if you will.

Brian, this is Mike. I might interject that we had our resource -- being a strong resource-oriented Company with over 350 million barrels potential through our 3P. As we -- the catalyst testing, and we have received more results and key learnings, we will be adding proved reserves. But as we have mapped it out into the future, we say top quartile reserve additions on our proved reserve growth. I think it is safe for me to say that with that large resource base.

I think just to add to that one little last piece. As folks well understand and look at these resource plays, 1P reserves are important, but 2 and 3P reserves are much more important here in these resource-type plays than they are in maybe a more conventional type of opportunity. As Mike mentioned, it is really just definition driven. The definitions that we use for SEC parameters put blankets around -- or put brackets around, if you will, what we'd put as a proved reserve for any given year.

Great. Thanks, again, guys. Congratulations on a fantastic quarter.

Thank you very much, Brian. I appreciate you following us ever since the beginning.

Thank you, ladies and gentlemen. That concludes your question-and-answer session. I would now like to turn the call back over to Mike Starzer, CEO, for closing remarks.

Thank you, Caroline. Thanks, again, to everyone for your support of Bonanza Creek. To summarize our three key take-aways from this quarter, first, our assets continue to produce consistent, predictable, and highly economic results. Company-wide production was up 32%, while Rockies production was up 41% over last quarter. We achieved an overall cash margin of approximately $58 per Boe.

Second, our early results from catalyst wells continue to impress and support our view of an expanding resource with many years of highly economic inventory. The Codell is outperforming the Niobrara B-Bench type curve, while the Niobrara C-Bench is being delineated across our acreage position.

Finally, number three, the recent 36% increase to our borrowing base provides Bonanza Creek with nearly $400 million of liquidity. We continue to have one of the strongest balance sheets among our E&P peer group, by investing in projects that provide some of the highest economic returns available in the United States today.

I'm proud that Bonanza Creek has consistently been one of the top performers in our sector since our IPO. We believe the diligent management of Bonanza Creek's rapid growth and investment, revenue, and cash flow will continue to underpin our top-quartile returns for our owners. The strong operational progress we are seeing across both regions, combined with our focus on disciplined investment and operating excellence provides confidence in growing long-term, sustainable cash flow and increased shareholder value.

We also continue to be active assisting our local communities and trade organizations to promote good corporate citizenship and public education of the E&P industry, particularly the responsible use of advances in fracture stimulation technology.

Before we go, as alluded to earlier, we expect to announce our 2014 budget and annual guidance in early January. If we don't talk to you before then, we wish everyone a very happy holiday season.

Thank you, Mike. Ladies and gentlemen, thank you for your participation in today's conference. That concludes the presentation. You may now disconnect. Have a good weekend.