Good day, and welcome to the Cimarex Energy Third Quarter 2014 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Mark Burford, Vice President of Capital Markets. Please go ahead.

Thank you very much, Andrew. Thank you, everyone, for joining us today on our third quarter conference call. Speaking today will be Tom Jorden, President and CEO; Joe Albi, EVP and COO; John Lambuth, Vice President of Exploration; and also in Denver, we have Paul Korus, our CFO; and Karen Acierno, our Director of Investor Relations. We did issue our financial operating results, it was released yesterday after market closed. A copy of which can be found on our website. We also posted on our latest investor presentation, which may make some references today on today's call. I need to remind you that today's discussion will contain forward-looking statements. A number of factors could cause actual results to differ materially from what we discuss. You should read our disclosures on forward-looking statements in our latest 10-K and other filings and news releases for the risk factors associated with our business. We have a lot to cover today, so I'll go ahead and get the call turn over to Tom.

Thank you, Mark, and thanks to all of you for participating in today's conference. We appreciate your interest in Cimarex. A lot has happened since our second quarter call in August, and I'd like to take a few minutes upfront to touch on some of the highlights before turning it over to John and Joe for more detailed update. Well, despite the impacts with severe weather on the Delaware Basin, which had a significant impact on our third quarter, Cimarex produced a record 942 million cubic feet equivalent per day, which was at the high end of our guidance. And this was a testament to the extraordinary efforts made by our field personnel to safely restore our operations and to a continued strong result in the Mid-Continent region. We had a real mess in our hands with this weather in the Delaware Basin, and I really do want to credit our field personnel for getting after it, performing operations safely and getting our production restored in a clean, environmental way. When it comes to the Mid-Continent, the Permian, our technical teams have really refocused their efforts to improve the way we complete our wells. In the Cana-Woodford, this is having not only a strong impact in our production, but it's also extending and completely redefining the boundaries of that play. We've got an opportunity set and return profile that really puts us in a nice position, and John will give you some more updates on that. In the Mid-Continent, we drilled 6 additional Merrimack wells and have completed our initial mapping in Merrimack opportunity. And today, we can tell you that we think we have approximately 70,000 net acres in that fairway, of which 60,000 are held by production. So a really, really nice layer of opportunity added to our…

Thanks, Tom. I'd like to quickly cover some of the highlights of our overall program before getting into the Permian region. I'll then finish with our Mid-Continent region and some results in Cana. Cimarex drilled and completed 66 gross, 36 net wells during the quarter investing $460 million. 74% was invested in Permian region, and the rest of it toward activities in the Mid-Continent region. Of those 66 gross wells, 36 gross or 27 net were in the Permian region, where we continue to be focused on the Wolfcamp, Bone Spring, and the Avalon formations in the Delaware Basin. Bone Spring activity in the second quarter included 12 net wells into Mexico and Texas. We continue to have some of the best -- our best results in the Culberson/White City area, which is located in southern Eddy County New Mexico and Northern Culberson County, Texas. This geographic area is defined by a fixed hand section that produces more gas in a historical Bone Spring production. We have tested upsize fracs with good results and thus, our drilling program in these areas now incorporates a larger 15 stage frac design. Cimarex has completed 29 wells in the Culberson/White City area in 2014. Of those, 12 wells have been completed with this new 12 stage frac design, and have a 30-day average IP of approximately 1,150 barrels of oil equivalent per day, of which 65% or 744 barrels per day is oil. About half of our 2014 Permian drilling program, or $650 million, will go towards further delineation of our significant Wolfcamp opportunity in the Delaware Basin. This number is down some of our $35 million from our previous estimates due to weather-related delays and our completion program. The $650 million does include downspacing pilots, wells drilled to hold acreage, testing the…

Well, thank you, John, and thank you, all of you, for joining our call today. I'll touch on the usual items, our third quarter production, our fourth quarter and full year production outlook, and then I'll follow-up with a few comments on where we see operating and service cost. Starting with production. We had another great quarter for production, despite shut-ins of approximately 15 million to 20 million a day for the quarter, as a result of September's severe weather and flooding in the Permian. Our third quarter production came in at 942.4 million a day that put us at the upper end of our projected guidance, which was 920 million to 945 million. It also set a new record for us at the total company production level. I want to echo a few words right behind Tom with regard to the storms and the severe weather that we saw in September. We are extremely proud of the manner in which our operations teams responded to the rains and flooding that we had in the Permian. The severe flooding impacted the majority of our Triple Crown, our Reeves and our Ward County drilling completion and production operations over a fairly lengthy period, 2 to 3 weeks. Our teams acted quickly and most importantly, safely, to sustain drilling operations, shut-in production, secure facilities, move oil off of our leases, transfer gas markets to other markets, evacuate field personnel from all the exposed area, just a handful of thanks. And as a result, we saw virtually no damage to our facilities, but we did experience the delays we talked about and that's in reestablishing our drilling completion and production operations in effectiveness across the board. The impact wasn't the locations, so to speak. It was more severe row damage that was associated…

[Operator Instructions] The first question comes from Drew Venker with Morgan Stanley.

I was hoping you can talk about the price that you might plan to budget on for 2015 on a philosophical level, whether you would start with a strip as we getting closer to year end or some discount to the strip. I think, particularly, because you're not hedged. So I want to know how you're thinking about pricing.

Drew, this is Tom. Our approach there hasn't changed. We'll look at the strip as sort of our base case, but we're also going to look at downside protection, and we're going to run $60 oil and $3 gas and those are NYMEX pricing. So we will subtract from those downside pricing when it takes to get back to the wellhead and that's going to be true on all of the price files that we quote. We always look at wellhead when we see price. And we're going to make sure that we get a reasonable return at that downside case. So yes, the strip will be our first half, but we're going to really try to be disciplined and make sure that we see a $60 oil, $3 gas environment, we don't destroy capital. So that's a little of both, it's a bit of a polarity because we look at the strip. But if you got something that works at the strip but it couldn't stand what we think is a reasonable downsize stress test, we won't fund it.

That's really helpful, Tom. And if we can shift to the Permian. It sounds like, for the most part, operations are back on track. Are there lingering impacts from the flooding? Can you talk about, when you think everything will be fully back to normal in the Permian in terms of completions and general operations?

Yes. This is Joe. We are back on track. We had a little bit of production that was still impacted about a week or so back, but that looks to be cleared up this week in a little bit. I mean, maybe 5 million a day out of what was a fairly significant volume during the flood. So our completion schedule is intact, roads are accessible, and we're back to normal operation.

So I guess a follow-up on that. So the run rate of completions will probably be back to a normal pace for a full quarter by 1Q?

Yes. If you look at the numbers, we basically slid 15, 16 net wells into 2015 and had -- ultimately now Q4 has about in the same number of completions that we've modeled last quarter when we gave our guidance and that will carry -- I suspect, that it will carry itself over into January. This is basically new things, 3 to 4 weeks, because you have to reconfigure your whole frac schedule. You have some pilots involved in all this. We had different interest in different wells and the way it plays out on a well basis is a really just cut into the tail end of September and early October, November, where things are really picking up here from this point forward.

The next question comes from Brian Gamble of Simmons & Company. Brian D. Gamble - Simmons & Company International, Research Division: Tom, you touched on the -- touched what I thought was an impressive plan for the Cana, the 10 lateral section, you mentioned the 7 rig peak obviously I'm sure that dovetails in with your discussion of '15 and successful return at various prices. But any more color there as far as the timing to actually have that available to run the 7 rigs, if you wanted to? And maybe even talk about returns vis-à-vis the new completions and how that may impact decisions to ramp that activity level up in '15?

This is John. I guess, I'll try to answer that for you. We have a plan in place. I'll send our partner to ramp up our rig activity. As I mentioned, we're already at 2 rigs on it. We envision ourselves being upward of 6 to 7 operated rigs. Likewise, our partner will be bringing in rigs, again, at the beginning of the year. When you go to row development, you really got to get a lot of wells drilled way ahead of you before even bring those frac crews in, as you can imagine, especially with 10 sections. And so there will be a lot of drilling going on before you finally get to the point where those frac crews will start showing up some time, probably in the June time frame. And then finally, about a month or so after that you start seeing the production coming in. So we have a pretty aggressive plan for 10 contiguous sections to go forward. And right now I would just say, based on, as Tom mentioned, our stress testing of those wells with different commodity prices, those 10 sections looks very, very attractive to us. So it's -- to us, in a sense, it's full steam ahead on those 10 sections going forward. Brian D. Gamble - Simmons & Company International, Research Division: Great. And then on the Merrimack, you mentioned, obviously, the one in the last quarter you got 6 in various stages. How many results are we expecting to get potentially by Q4 results?

We will have quite a number of those wells that we can comment on Q4. We just don't have our typical 30-day peak average to talk about on any 1 well. But of those 6, 3 are currently flowing back -- actually 4 are flowing back, 1 ready to frac and 1 is just about done drilling in terms of its lateral. So theoretically, yes, we will probably have more information to talk about those going forward on the next call.

Yes. This is Tom. We stick to our discipline on that. We really would like to have 30 days of peak production before we discuss wells publicly. And that's just because that's a number that's meaningful to us and our technical teams. And so we actually -- we are close on a well, but we decided now we're going to hold off and make sure that we're consistent with the information and results we communicate. Brian D. Gamble - Simmons & Company International, Research Division: And Tom, one last one kind of a micro thing. As far as your discussions with other operators and there was some discussion of cost pressures on the completion side, but the rest of your '15 budget came here dependent on kind of how realistic we'll call it, people are with their cost expectations. Have you started having those sorts of conversations? And if so, any color you can lend us to help other people that are looking at '15?

Well, I -- and I think you all on the call probably know more than we do because you have one-on-one significant engagement conversations with these companies. But I'll say this, we're looking at the landscape of companies that have been greatly outspending cash flow incurring nothing debt to do so, and I said there were 3 elements: One is investment -- the robustness of our investment portfolio; 2, cash flow and balance sheet; and third is market psychology. I think we're curious as to who's going to blink out there. I mean, how deep is this trough, how low could prices go, and there are people wanting to be continuing to incur narrowing debt in order to fund their program. And it's going to take the market laying some rigs down to see service cost reset. Service cost aren't going to respond to the oil and gas price, they're going to respond to demand for services. So -- and I know I'm not answering your question, but we're watching that carefully. And that something that will color our thinking as to how much we want to get aggressive in 2015.

Yes. And this is Joe, I'll add a little flavor to that. Our operations teams have been in contact with our major service providers over the last 2 to 3 weeks. And they -- the providers are fully aware of the fact that should economics dictate us laying out rigs, we're going to align ourselves up with those that react the quickest and compete in -- this is not a new cycle, we've been here before. Market share will be important to those companies, and we'll align ourselves up with the people who want to react first.

The next question comes from Cameron Horwitz of U.S. Capital Advisors.

Quick question in the Cana. I know it's a fluid number, but can you give us your best guess for what you think the Cana inventory looks like based on the step-out work that you've done so far to date?

This is John. Well, that's a great question, and I wish I had a number for you right now as I sit here. We still are drilling additional what I'll call re-delineation wells throughout the play. So with each new well, like the one I just announced, it just continues to grow. I'll be honest. It's -- it looks pretty promising for us in terms of that acreage number that I quoted in terms of the total amount of net acreage we have on those perspective. And yes, we still have more wells that we are going to be drilling and testing that will certainly define that. I'll say this much, the Glenda result certainly has given us some encouragement to push that road development further to the west and what we normally would've done. And so again, that got us to the 10 sections we're at right now. And with each new well, yes, we're more and more encouraged with what we see there, with the acreage we currently have. But I don't have a number I could just lay in front of you, like number of locations right now today.

Yes. This is Tom, Cameron. Just to echo what John said. We're -- re-delineation is a great way to characterize it. We have been continuously surprised and impressed with how this new completion is taking areas that we would have looked at and said it's marginal, maybe submarginal and all of a sudden, it looks really, really robust, and that Glenda is a case in point. And we have lots of areas in the field that we still need to test. Thus far, we're wholly encouraged. I mean, it's just redefining the investment landscape for Cana. So we are really, really optimistic. But we don't have a number for you.

Okay, I guess what goes hand-in-hand with that, can you just remind us where you stand on what you all were thinking about spacing and maybe how that's evolving?

I'm sorry, rephrase -- say the question again? I didn't quite hear you.

Just in terms of the unilateral spacing out there in the Cana, which you all are testing at this point.

Yes. I mean, our typical development peers is 8 new wells in addition to the current well, which will be 9 wells per section. But I can tell you this, that because of these well results and just the metrics we look at in this new well development we're going to that I mentioned, we are going to go to some tighter spacing on subsection. In some cases, upwards of 11 wells on a section.

11 new wells.

11 new wells in addition to the parent. And that's just a reflection of the great resource in place we have there. When we truly look at the thickness of that shale, look at the resource and again, we do the different measurements we make, yes, we ask ourselves why not? Why wouldn't it support 11 wells with this frac design? And that, in fact, is what we're going to do on at least 1 section and it will vary by section by section dictated by that resource in place per section.

Okay, great. I appreciate that color. Just going back to types of Permian. On the Cleveland pilot, is the -- I guess, is the conclusion there that you think optimal development Reeves will be on 80-acre spacing, or is it still too early to tell?

I think the easy answer is too early to tell. I'll simply say this. If we take that result and then take our expectations for a 10,000-foot lateral, which as I mentioned, we're completing one right now, those economics look pretty robust to us in terms if you were to go forward with an 8 well. But in no way does that mean that we know that's the right answer. There'll be more pilots in that area. But suffice to say, we're very encouraged with the results of that pilot and what that means for us going forward with that acreage block we have there.

Okay. And I guess just last for me just so I'm clear. In terms of the oil trajectory out of the Permian. If you took the noise out from the completion slippage and the shut-ins, do you all -- would you have cleared that 40,000 barrels a day that you all had talked about in Q1 and the Q4 period?

Well, you can start counting to 40,000 barrels per day, and this is Mark. In the Permian, Cameron, what are you referring to?

Yes in the Permian, I think in Q1, you had put out a 40,000-barrel a day number for Q4. I'm just trying to understand. Taking the noise out, where you on that trajectory?

Yes. I mean, Cameron, taking the noise are meaningful, trying to put back the wells when they would have been completed when we thought they would be completed, plus take the storm downtime out. Yes, that's it. It would be on that trajectory. But we have 2 moving pieces there, we both had wells on production that didn't produce, like we thought they would because of storm down fund. Hopefully, shifting about 15 wells from this period to next. So if you put everything back, we had a construction which we could achieve, or x the storm I think we would have hit those numbers.

Property sales that....

Same property sales are on top, which we didn't have to opt into the number. Now whatever is -- the minimum base in Wolfcamp which we did sell, it was about 1,500 barrels a day in the fourth quarter that we didn't sell so. That we had to open into our numbers. There was no element in our numbers that we removed out post of sale.

That's a big piece of it.

The next question comes from Joseph Allman of JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Tom, it sounds as if you already are in the process of ramping up, especially in the Cana. And so, is that correct that just in terms of planning and getting ready to add additional rigs, you're already there? Or are you are you already in the -- or are you tapping the brakes already to sort of waiting and seeing how this oil market plays out? And if...

Well -- go ahead. Joseph D. Allman - JP Morgan Chase & Co, Research Division: No, go ahead, Tom, I'll follow-up later.

No. That's -- you're absolutely right. We have committed to do this additional development row in Cana, and we're bringing some rigs in to prosecute that and that's steady as she goes. We think that project really can stand tall in this commodity-priced environment. Not only standing alone, but compares favorably our investment landscape. Additional delineation we're doing in the Merrimack, we think is really something that we want to continue to do. And then as we look at the Permian, we look at Culberson County and the joint development agreement we have when we look at really that whole fairway that's in our corporate update. So we kind of think of Culberson County and then up to that White City block in Eddy County as one geologic province. We're going to do as much of that as we can with long laterals where we can. Those stand tall. And then the rest of it is a jump ball. I mean, quite -- everything else, either in the Mid-Continent Permian, is up for discussion. Now I will say that I think you're going to see a higher percentage of our capital be going to the Anadarko Basin next year than this year. This year with 75% Permian. You'll probably see a little higher percentage in Anadarko. A little higher, I don't think it will be half, but we're working our way through it. I mean, the good news is we're really testing this on a rate-of-return metric. We're not testing it on what our preferred commodity type is. We're looking at which of our opportunities have the robustness to the downside of commodity, and we have lots and lots to do. Joseph D. Allman - JP Morgan Chase & Co, Research Division: That's helpful. Tom, and just a follow-up on that, so how much are you willing to outspend cash flow in 2015? And what metrics would you be looking at to judge a comfort level with outspend?

That's -- Joe, I can't answer that today. I mean it's that -- I said there are 3 elements, the third is market psychology and that's the most touchy-feeling of all 3. I can drill a lot into that. And then we want to see where do we think this oil price is heading? Where do we think service costs are heading? What do we think will be the duration and depth of this correction, if you will? And make that -- we'll have to make that decision today, and there will be -- it will be really clueless to do that today and talk about it. There's one thing to talk about cash flow next year. We also are going to exit the year with a lot of cash on hand. I mean, we think we're up, really cash flow plus about $400 million cash on hand. So that's all available to us before we have to borrow $0.01 next year. So there -- we have a lot of flexibility. Joseph D. Allman - JP Morgan Chase & Co, Research Division: That's helpful. Tom, and just an operations question. So in terms of the completion designs and the changes you're making, what can we look forward to as some of the kind of most interesting things you're trying and where, in particular?

Well, this is John. Well, I was allowed to say this much. In as much as we really, really like the type of returns and the performance we're seeing sales, those Cana wells, likewise, what we're seeing now is the Bone Spring wells, I mentioned. We have a lot around here where we're not satisfied. And yes, we are constantly challenging ourselves how could -- what could we do better with the completion design. And so there are more things that we're going to test whether it's stages, whether it's the maker of the proppant, but I'm not going to sit here and just tell you what our recipe is to that degree. I'll say that we're not satisfied always we were at and always want to try to push that envelopes to make sure could we get more out of that lock and that's pretty much our go forward model in a sense -- in exploration right now.

This is Tom. We have a lot of mysteries in our stimulations here today, a lot of technical challenges and that's a good thing. There's a lot of upside. Now do we have our upside equal to what we've seen? Obviously, we've taken bold steps. We don't know. But I will say this, if I were to tell you that we understood every element of this, that would be dampening, because I would say that we don't have additional upside. We have a lot of mysteries yet and we have a lot of really smart people really working at making this better.

The next question comes from Jeff Robertson of Barclays.

Most of my questions have been answered. But just from a philosophical standpoint, I guess it sounds like you all planned to enter 2015 with some flexibility around your capital program to see where cost go and maybe also, if you have a prolonged period of lower prices to see what other opportunities may come up on the acquisition front, is that fair?

That's absolutely the case, Jeff. And one of the things that I'll say, we don't wish for corrections but, boy, we all kind of leaned forward. We're trained for this. This is in our DNA, and our history is that in these down cycles, there is tremendous opportunity. And we'll be as opportunistic as we possibly can. We're going to stay flexible. You're probably going to -- we'll talk about wide ranges in what we're continuing to do and we won't apologize if we have to accelerate or decelerate. We're going to be as opportunistic as we possibly can.

And secondly, Tom, have you all talked much with -- as you're playing your 2015 capital program, have you talked much with the service providers about cost directions and especially in areas where you know you're going to be busy? Are there -- are they -- have you shown any willingness yet to make any concessions or help you all out on prices?

Yes, this is Joe again. I'll just react on what I mentioned a bit ago. We have had initial discussions with our larger service providers. They are aware of our position. They're aware of the market. They're finding some of the same things we are. They've got cost that they're incurring that even as early as September, we saw rate increases on the drilling side, primarily on the labor side. It's going to have to be a trickle-down effect, but I will tell you this, and Tom hit it right on the head. Once rigs start laying down, then it's a scramble for market share. And once it's a scramble for market share, we're in a pretty good position because we will be active, and we will be a viable customer. So it's going to have to trickle down, and we're got to keep the heat on them.

Then lastly, you all have not built any expectations of lower cost into some of the returns you're talking about yet have you?

No. This is John. Any of our go forward economics, we absolutely do not build in price reductions into our capital cost. We assume the cost is what it is today, and we base our decision on that today. If cost come down, then we will adjust at that appropriate time. But no, nothing built in on our go forward modeling for future well returns.

The next question comes from Irene Haas of Wunderlich Securities.

So 2 questions. Firstly is at what level would you -- what's your maintenance CapEx, i.e., what's the minimum amount that you could spend to keep your production flat? And secondarily, for the Merrimack, the wells you have drilled that straw how variable are the pace? Are they kind of the same location where you expect or are they more scattered?

Yes, Irene, this is Mark. On your first part of your question there with the seen as capital required to invest to order production. Honestly, it's on the measure we spend really any time evaluating that is, we still bottoms up and look what are the things we'll invest in the period. And then based on a rate of return, and we see the outcome of the production is. We don't use a lot of sensitivities on that. I don't have a hard number for you. I mean, honestly, what that would represent at this point. Obviously the mix of what we drill, timing of what we drill. Even as John touched on like with Cana really for development, there's this amount of capital being incurred in the first half of the year that we won't see production until second half, this is all a variability timing, often this is development that always -- it just compares to some of our logical thinking too, because timing and year-over-year comparisons are neat, but clearly, we had return in the cash flow, which generate all the investments we're making, that's what we focus on.

And this is John. In terms of your question on the Merrimack. Of the 6 wells, they are very diverse in their geographic location, as well as in their geologic intervals that they're testing. I mean, they are truly delineating our acreage position, such that with those results in hand, we'll have a much better feel for just what's the breadth and scope of this opportunity. And so far, I would just say, "I'll just going to make another comment." We're obviously not alone here. In the Merrimack, there are lots of other wells being drilled by other operators. And so far, and I guess you could -- you can kind of draw that conclusion by the fact we have 6 wells now and plan to -- probably plan to drill more, we do like what we see here so far. But again, we need those well results in hand to figure out just what the overall size of the price is right now.

Is it fair to say that this is probably more complicated than the Cana-Woodford play?

In terms of how we see right now, yes. It is a play that we are quickly coming up to speed and in terms of our understanding of the rock, the whole core we take, the analysis of that core, the logs, we're really at the intimacy here of just understanding the nature of this play. And so it will all take us some a while here to get more and more comfortable with. But again, so far, we like what we see.

Also Irene, this is Tom. The play like Cana-Woodford has a lot of geological variation. It varies in thickness. And one of the things it varies is in hydrocarbon-type and also pressure. And so the window we're playing it in is a little different than where a lot of the announced activities has been. And so a lot of -- we as you know, you know as well, we study our competition and it's not always a direct analog to where we're playing at. But as John said, we're very, very encouraged about what we're seeing thus far.

The next question comes from Jason Smith of Bank of America Merrill Lynch.

Just a follow-up on the Cana again. Can you just remind us on infrastructure and availability of labor? I'm just trying to figure out is there any limitations to -- if we look at this differently to potentially going beyond the plan that you've laid out in this call.

This is Joe. We don't see that to be an issue as far as personnel to get the job done and get the wells drilled. Services are there. We're proactively working with the -- our processing entity for market, for capacity and for market availability for residue gas sales and NGLs. And so we're about 6, 9 months ahead of that, and don't foresee issues there, but everything looks like it's on track.

And on the 7 rigs that you guys mentioned, I mean is that -- that's just Cana, right? So are there other rigs that you guys are planning to allocate to the Mid-Con?

Yes. This is John. Yes, there will be some additional rigs drilling. As Tom mentioned, for sure, some additional Merrimack delineation, as well as other concepts and things that we're pursuing. I don't have an exact number for you today. Obviously, that's depending upon where we think we're going to fund and what level next year. But above and beyond the 6 to 7 rigs on that row development, there will be other rigs active for us in the Anadarko region.

And maybe just a similar question, but taking it to the Permian. Can you maybe just update us on where things stand on oil gathering and gas processing for you guys over there?

This is Joe. We're right on track with our plans. We continue to put pipe in the ground, both in Triple Crown as well as in the Reeves County area. We've locked in to some firm volumes with 2 or 3 additional processors since our last call. We're aware of their capacity. At the same time, there's somewhere around several bcf a day of new processing coming on in the next 2 years. So Triple Crown's working out as exactly as we'd hoped. We got to take away to the North, take away in the middle, take away to the South. And so far so good, but again, just like Cana, we got to stay out ahead of this. With the drilling activity is going to look like and then try and react in proactive manner rather than after we drilled the wells to ensure capacity take away.

And on the oil side, Joe?

On the oil side, things are blowing and going. We're not having any issues hauling. We continue to be in discussions both in Triple Crown as well now in a new -- in 2 other areas, the Reeves County and Lee County area for oil gathering projects, both of those were working towards inking agreements and are in the process right away for oil gathering, which has really take a lot of pressure of this by the end of next year.

The next question comes from Ipsit Mohanty of GMP Securities.

Just a couple of broad questions. The delivery basin as good as anyone else. When you look at various traffic scenarios in '15, do you look at your development at the basin equally across the 8 stage? Or would there be areas that you would rather focus and then some that you have not touched? And then as -- and in relation to that, would there be particular zones that you're going to first? Or would you just develop the way that you're doing right now? I'm just curious to see how you look at developing that portfolio, let's say, if oil goes down even further.

This is John, I guess, I'll try to answer your question first. You're absolutely right in that, but our basin is a very broad, large basin. And within that basin itself, we see lots of variability in terms of the type of hydrocarbons we make. As we spoke about many times, say for instance, in Wolfcamp, we have the breadth of acreage where we could be anywhere from being almost mostly oil in the reservoir to all the way up in Culberson, where it's predominantly gas with a really good yield component to it. And in some ways, commodity price dictates where we go with that. Right now, as -- again we've talked about Culberson looks still extremely attractive to us from a rate of return standpoint. On the flip side, I will tell you right now, Ward County, Wolfcamp gets a little bit of a struggle right now, given the current prices with oil. And just given the depth we have to drill to and to the lack of pressure, I would say, within that reservoir, Ward is a little bit of a struggle. But the nice thing is that we have this large acreage position that we can move those rigs to, again, maximize our returns throughout that basin. That's no different than also in the Avalon. Right now, we haven't really talked about it, but we have quite a few Avalon wells that would be coming on in the next quarter. And again, we're targeting that area, the Avalon, where the product mix is such that we feel like we hit our best returns out of that basin. So we have a lot of flexibility within that basin, as the way I would put it.

Yes, I might add to that. It's not just a function of commodity price, it's also a function of technology. And our thinking on the various sweets spots has changed over time, and they will change again. So we're continuing to work it and adapting as we go.

Was that - and then in that case, let me scratch in looking deeper and see that in terms of -- assuming that all your drilling from your own will be on upsized fracs, how do you see the extended lateral program developing? So in terms of -- for example, going forward, I know it's dictated a large by lease geometry, I understand. But then as you look at spending that incremental capital going forward, how do you see -- what's the extent of extended laterals that you'd be drilling across your region?

This is John. I will tell you anywhere, quite frankly, that our acreage allows us to do it. Our main goal is to ultimately make it an extended lateral play. Because as you mentioned, that incremental capital to drill that extra 5,000 feet is more than offset by the type of returns we get out of that well from the hydrocarbons that we flow out of it. So that's why areas like Culberson, the JDA, it's so valuable to us because that JDA gives the large continuous operated acreage position that allows us to do that. In fact, that this our go forward plans in terms of Culberson is long laterals. Unfortunately, I wish in all years we had acreage that we could do that everywhere. But again, where the acreage allows us to do it, that is, ultimately, our plan and goal on a go-forward basis, especially when we think about it from a development standpoint.

And that will also be true in Cana. We have scenarios with Woodford where we think we have long lateral development to do. And as we look at the Merrimack, I think that we're going to be looking long and hard at long laterals.

Did you have any longer lateral drilled in the Cana in the third quarter? Maybe in...

No, no long laterals in the third quarter. The only long lateral is the one we've talked about in our last earnings release. Again, as I mentioned earlier, in this mode of delineation, of undelineating are not going to do it with long laterals. I'm going to do with 5,000-foot laterals, as I tried to establish economics. I will say again, we have future plans of development in Cana, nothing written down just yet, but we clearly have a large acreage position that would lend itself very nicely to 10,000-foot development in the Cana-Woodford shale for future drilling.

And Page 20 of our presentation highlights that 10,000-foot lateral in the Woodford.

And due to time constraints, the last question today will come from Dan Guffey of Stifel. Daniel D. Guffey - Stifel, Nicolaus & Company, Incorporated, Research Division: You guys have been very clear in the past that you're focused on not leaving PV behind by entering development mode too quickly in the Permian. So looking at Culberson, I wonder if you can remind me approximately how many Wolfcamp A wells have you drilled? And then also provide some color on kind of a Wolfcamp A performance first, the B bench, and then also give a little color on your pilot between the C and D stacked lateral and really kind of how you're thinking of development on a long-term basis going forward in Culberson White City.

This is John. In terms of the Wolfcamp A, we have reported on a couple of them so far. We have a few more that are coming on. Again, they look very attractive to us relative to the Wolfcamp D interval that we mentioned before. In terms of build-forward development plans, on our previous release, we talked about the results of our 8 well spacing pilots. I will tell you that we already have in the works our next pilot which, tentatively, we start drilling on sometime in the December time frame. I think it's fair to say that we're still internally debating what is the right thing to do with that pilot to further understand and ensure that, like you just said, that we come up with the right plan, so we do not leave any PD behind. But that's where we're at right now. We have both a pilot and the works and for later this year, and we have still some more drilling that we have to do in terms of holding an acreage and still testing for the balance of that Wolfcamp Shale play for us in Culberson. I hope that answered your question. If there's a follow-up, let me know. Daniel D. Guffey - Stifel, Nicolaus & Company, Incorporated, Research Division: No, I appreciate the color. I guess, you guys have additional data from the outside frac in Cana and throughout the Wolfcamp and throughout Delaware. I guess, when do you guys feel it's appropriate to put out a detailed cut-type curve in EUR estimates by player area. I mean, obviously, you guys are modeling internally, giving some of the guidance you have in terms of the long lateral and upsized at EUR. Just wondering when you guys think it may be appropriate to publish some of those EUR estimates?

Yes, this is Tom. When we have results that we think are meaningful. And so I know that there's some pressure for us that talk about wells early, but I just want to say again, we're a company built on ideas, technology and innovation, and we really focus on the science and get a good meaningful data. And we don't want to get ahead of ourselves and we want our investors to -- our credibility in our communication. And so that will occasionally mean, we're going to be able to slow and release data once it's in the solid results category and not in the promise or hope category. And so we'll release that as we have it. We have a lot a wells that are currently flowing back. So I think, certainly next quarter, we will have much data to release, and we'll release the data we have. Now as far as EURs, we typically don't talk a lot about EURs, but we'll certainly show you our type curve and what it means to us.

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

Thank you, everyone, for joining us today. We appreciate your time with us, and we look forward to give you report -- results in the future. And again, thank you for your participation.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.