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Executives

Joseph R. Albi - Chief Operating Officer and Executive Vice President

Thomas E. Jorden - Chief Executive Officer, President and Director

Paul Korus - Chief Financial Officer and Senior Vice President

Mark Burford - Vice President of Capital Markets and Planning

Analysts

Jeffrey W. Robertson - Barclays Capital, Research Division

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Ryan Todd - Deutsche Bank AG, Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Gil Yang - BofA Merrill Lynch, Research Division

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Cimarex Energy (XEC) Q3 2011 Earnings Call November 3, 2011 1:00 PM ET

Operator

Good afternoon. My name is Lakishia, and I will be your conference operator today. At this time, I would like to welcome everyone to the Third Quarter 2011 Financial and Operating Results Conference Call. [Operator Instructions] I would like to turn the call over to our host for today, Mr. Mark Burford. Thank you, sir. You may begin your call.

Mark Burford

Thank you very much, Lakishia, and welcome, everyone. Thanks for joining us today for our third quarter conference call. On today's call here in Denver, we have Tom Jorden, President and CEO; Joe Albi, EVP and COO; Paul Korus, Senior Vice President and CFO; and Jim Shonsey, Vice President, Controller.

We did issue our financial and operating results news release this morning, a copy of which can be found on our website. We will be making forward-looking statements in this conference call. Please refer to the end of our press release for our disclaimer regarding forward-looking statements.

Before I turn the call over to Tom, I'll recap a couple of our financial items. Our statement earnings release reported a net income of $128.2 million or $1.49 per share for the quarter, and which is current -- which matches last year's third quarter, and current year earnings include the $0.04 per share noncash mark-to-market gain on our hedges.

Third quarter oil and gas sales revenues were $420 million, 15% greater than last year's third quarter, and cash flow from operations totaled $357 million, which is 20% greater than last year's third quarter. For the first 9 months of 2011, we had cash -- cash flowed $1 billion. Higher earnings, revenues and cash are a large result of our liquids production. Liquid this quarter made up about 45% of our quote on production on a 6 on an equivalent -- 6:1 equivalent basis and 67% of our revenues.

Realized oil prices this quarter are about 20% higher and NGL price were 36% higher over third quarter of last year. So with those couple of items, I'll now go ahead and pass this call over to Tom.

Thomas E. Jorden

Thanks, Mark. I'll hit on several operating results and give an update in this year's joint program. But before I go into region-by-region detail, I want to address a consistent theme we're seeing in all of our areas. As we track our rates of return from our drilling or reinvestment program, there's no other way to put it other than plainly. We're not very pleased with the trends in some of our results today. Our costs have continued to escalate, and I know that something you're hearing from a lot of our peers. But in addition to our costs being too high, one of the things we do as a company, we don't buy our drilling inventory. We invent it. I mean, we are first and foremost a team of -- teams of geoscientists that generate our drilling opportunity. And so it's very important that we track our progress, that we measure our results and that we make sure that our actual results are in line with our expectations as we make our investments. And we do that to calibrate our investments and to tune our program when it occasionally steers off-center. And we're seeing that in a number of our areas. Not only are costs too high, but we're in the process of reexamining and going back to the drawing board in a number of our areas because our results are not consistent with our pre-drill predictions. And we'll get into that in a little more detail and I would just think we'll have some questions on that.

So as we work on our 2012 and the remaining 2011 plans, we're challenging ourselves throughout the organization on how to innovate and improve on all aspects of our business. Our operating group is working very, very hard to study our drilling completion techniques and see how we can lower our cost structure. Our exploration teams are working very, very hard to throw some science at our problems to come up with unlocking the reservoir and just flat out improve our results.

We're now in the middle of our planning process for 2012, and we'll provide some 2012 capital and production guidance as we typically do with our fourth quarter release in early February. And the reason we're going to doing that in February is that we're still working through it. We're having a lot of debates internally on what place we want to emphasize next year and how we can improve our results.

We have a lot of really great projects, that said, and we'll continue to work to improve our returns. But we are getting fairly good returns in a number of our projects. We've had an active first 9 months of the year. We drilled and completed 242 gross or 138 net wells year-to-date. We've invested $1.2 billion on exploration development. Of our total expenditures, 47% were invested in projects located in the Mid-Continent area, and that's by and large our Cana play and Anadarko Basin. 46% of our capital has been in the Permian Basin and 7% in the Gulf Coast and others.

Starting with the Permian Basin. In the Permian Basin, year-to-date, we've drilled and completed 106 gross or 79 net Permian Basin wells during the first 9 months of 2011, and we completed 95% of those as producers. At the end of the quarter, 13 gross and 7 net wells were still waiting on completion. Our Permian Basin exploration development capital year-to-date through the third quarter totaled $543 million, or about 46% of our total capital. So as you see, we've ramped up our Permian program this year. It's a higher percentage of our capital. And that's where we're seeing some of the best returns in the company are in the Permian basin.

Starting with our New Mexico horizontal Second and Third Bone Spring play, where year-to-date we've drilled and completed 42 gross, 27 net wells. This year, we stepped into some new areas. We mapped some very thick Second and Third Bone Spring sands and our results, although still good, have not been to our expectations.

As we moved into new areas, we're starting to see our water cuts increase, and that's a bit of a challenge. One of the things you'll hear me say here this morning, I'll probably be willing to discuss a lot of problems and few solutions because we are throwing a lot of technology at this problem right now.

But we're observing flow similar in total fluid to what we've seen historically, but we're seeing higher water cuts. For example, in this play in 2010, our average water cut across the play was 46% for the wells we've brought on, but it's increased to 56% on average this year. And so what we're seeing is as we drilled a little thicker reservoirs, we're seeing a little higher water cut. We're going back to the drawing board on that and saying what petrophysically could we and can we do to anticipate that and attempt to mitigate it. Those will still generate very nice returns, but again, as I said at the outset, we look very carefully at our actual results and compare it to our pre-drill expected results and that's the shortfall.

The 30-day gross production from Bone Spring wells we drilled this year, we've had an average first 30-day production rate of 510 barrels equivalent per day, of which 83% of that is oil.

The average 30-day rate has decreased this year with the higher water. We're working hard to better predict this water cut and incorporate this in our pre-drill analysis. Now we get a lot of questions about our type curve in the Second, Third Bone Spring play. One of the things I'll say that we've learned is it's a fairly broad area. Our Second, Third Bone Spring play covers multiple townships of varying thicknesses and varying depths. So a single type curve, as we've discussed in the past, has probably been a wrong way to characterize the play. I would say for a range of results, we hear others talk about a range of 400,000 to 600,000 barrels of oil, and that's about what we're seeing as a range. But certainly, our actual average results have come down a little bit from what we've discussed in the past and we're looking to see how we may high grade that and get back on track.

We do continue to bring on some very strong wells, however, such as in the Quail Ridge area, the Lynch 23 Federal 2H was 100% working interest well. It came on for its first 30 days at a 959 barrel per oil equivalent per day. And in the Chigrid [ph] area, the West Chigrid [ph] 32 Federal 1, where we have 75% working interest, came on at 755 barrel of oil equivalent per day. So this is a play we still very, very much like.

Another question that we get frequently is at what oil price will we still go and continue to go aggressively. And one of the things I always answer there is it depends on the lease terms. If we have a 75% net revenue interest lease, we can still generate acceptable returns down to a mid- to low-60s oil price. And as our net revenue interest goes up, obviously, that price can go a little lower. But we are slowing down a little bit, we're going to probably drop a rig or 2 and attempt to high grade our inventory. We have lots to do here. We have many years of inventory and we need to understand the science a little better so that our actual results are more in line with our pre-drill prediction. That's not say that we're going to lower our pre-drill prediction. We're looking to high grade and understand.

As we move into the Texas Third Bone Spring area, we drilled 12 gross and 9.8 net wells. On average, we've realized a 30-day gross production rate of 660 barrels equivalent per day, of which 74% is oil. And this average includes some really good wells, although that's a really good average.

For example, this quarter, we brought on the Intimidation 33-63. So while we had 100% working interest up and it came on at 1,339 barrels of oil equivalent per day for the first 30-day average. The Pits R8, another well we had 100% working interest. We average for 30 days 1,140 barrels of oil equivalent per day. And the Lazy M 1-30, a well we had 99% working interest, averaged its first 30 days 932 barrel of oil equivalent per day. So very good results in that play and that will continue to be a major part of our program going forward.

We've talked in the past about some emerging plays, some emerging liquids-rich plays. We have a large acreage position of over 160,000 net acres perspective for some or all of the Wolfcamp, the Avalon and Cisco/Canyon Shale formations. This year, we've drilled and completed an additional 7 or 6.6 net horizontal Wolfcamp wells, bringing our total wells in the play to 14, or 13.4 net. So we have a nice high working interesting in that play. And our first 30-day production average from our horizontal Wolfcamp wells has been 6.2 million cubic feet equivalent per day, of which 46% is gas, 32% natural gas liquids and 22% oil. So that play continues to be very, very encouraging to us. That said, that's one that's challenged by drilling completion costs and we are working it hard to try to get our costs down.

We're also pursuing the Avalon and Cisco/Canyon in this area. And those are 2 additional objectives that stack for much of this area. We've brought on a very good Cisco/Canyon well this year called the Taos Federal 3H. It came on first 30-day average at 6.4 million cubic feet equivalent per day and that's in Southern Eddy County. The yield, however, that's oil that's produced and trucked off location, the yield was only 6 barrels of oil per million cubic feet, plus it was a wet gas stream that generated an additional 56 barrels of natural gas liquids per million cubic feet. So it's a very good well. In fact, it's an excellent well, but it's a gas well and it needs higher gas prices to make sense.

We're also testing the Avalon. We've talked about that and we'll continue to talk about that. We have a couple of Avalon wells in the oil window. We're currently drilling and evaluating. And we'll talk about that in subsequent calls.

I will say, one of the things we are observing that we're studying hard is we're seeing a little higher decline in some of these ultra-tight oil reservoirs than we had expected. I think that's probably true around the industry. And we have a lot of very, very dedicated bright people internally trying to figure out how to optimize that, how to tune up our stimulations and get a little more out of those reservoirs. As we work in our 2010 plans for the Permian, as I said, not to sound like a broken record, but we're challenging ourselves in how to innovate and improve. And we'll likely let a few rigs go.

You know our focus is on returns, not on top-tier growth, and we're trying to improve our performance. And as we've done in the past, sometimes we've made some of our best strides when we slow down a little bit and really focused on improving our results. So that's what we're focusing on today.

Moving on to the Mid-Continent. For the first 9 months of 2011, we drilled and completed 128 gross or 52 net wells, completing 99% as producers. At quarter end, 19 of those wells gross, or 9 net, were still waiting on completion.

Our Mid-Continent exploration development capital year-to-date through the third quarter totaled $557 million, or 47% of our total capital. So if you take that Permian and Mid-Continent, you'll see that's 93% of our total capital year-to-date. Majority of our Mid-Continent activity has been our Cana-Woodford play, where we've drilled and completed 108 gross or 40 net wells.

So as the Cana play began in late 2007, we've participated in 283 gross or 111 net wells, and of the total wells, 251 gross or 96 net were on production at quarter end and the remainder were either in the process of being drilled or awaiting completion. So we've got a lot of data on this play. That said, it's still one of our most challenging technical problems.

We focus most of this year's drilling on delineating and holding acreage outside of what we've discussed as our defined core. As we look to 2012, we're working on plans to shift back to the core and possibly begin an infill drilling program. That's where we find the best returns. We don't have an acreage exploration issue anywhere in the play that we can't manage. So next year, it's highly likely that a significant portion of our capital will be directed to a core infill drilling project. Again, we haven't finalized those plans. They're still actively being discussed, but it's fair to give you a little hint on what we're thinking.

Moving on to the Gulf Coast, our last area before I turn the call over to Joe Albi. This year in the Gulf coast, we drilled 8 gross or 6.7 net Yegua/Cook Mountain wells, of which 3 or 2.4 net were successful. So I'll just interject there, we're not having a particularly good year drilling in the Gulf Coast. It does tend to ebb and flow. We're still very dedicated to developing and high grading our prospect inventory and we have a lot of projects in the hopper.

Gulf Coast exploration development capital year-to-date to the third quarter total $69 million or about 6% of our total capital. So it's not a lot of our capital but it certainly is a program that has and we expect will generate tremendous returns for us. The Gulf Coast production drop has been masking our growth in the Permian Basin and Mid-Continent. We averaged 81.8 million cubic feet equivalent a day for the third quarter of 2011, a 51% decrease in the Gulf Coast as compared to third quarter 2010 average of 166.8 million cubic feet a day. So we're seeing the backside of the tremendous success we had bringing on some of these monster wells in 2009, 2010. But the drop really is a result of our lack of drilling success in this year's program and also a natural decline in these highly productive wells over the last 2 years.

So with that, I'll turn the call over to Joe Albi, our Chief Operating Officer, to give you a little more color.

Joseph R. Albi

Thank you, Tom, and thank you all for joining us on our call here today. I'll be summarizing our Q3 production. I'll touch on our Q4 and full year guidance, and then follow up with a few comments on service cost.

As we reported, our Q3 average net daily equivalent production came in at 592 million a day, that was about as expected. We're up 6.3 million a day from Q2 and just a bit below the midpoint of our guidance, which was 585 to 610. That said, our production was impacted by about 6 million a day from numerous pipeline maintenance and repair type shut-ins that occurred during the quarter, primarily in the Permian. Without the shut-ins, we would have come in at 598 million a day, which would have put us just above the midpoint of our guidance.

Once again, we also set a few new records in Q3. Our Mid-Continent net equivalent production of 303 million a day is a new record. And with it, Mid-Continent now represents 51% of our total company production. Our Cana equivalent volume of 139 million a day is also a new high. Cana is up 66% from the 84 million a day we reported in Q3 of 2010 and now represents 23% of our total company production.

Our Permian oil production of 17,578 barrels a day is also a new record. As is our Permian net equivalent production of 206 million a day. The Permian now represents 35% of our total company production.

Our combined Mid-Continent and Permian oil and NGL volumes, or our liquid volumes, of 37,106 barrels a day is also a record. These 2 regions now make up 85% of our total liquids, which is also a new high for Cimarex.

So I point out these new records primarily because they really emphasize and they focus our business strategy, and that's our long-term growth programs in the Permian and the Mid-Continent, as well as our recent, when I say recent, over the last 1.5 years emphasis on oil and liquids-rich gas-type plays.

As Tom pointed out, on an equivalent basis, Q3 was a repeat of what we've seen in recent quarters. Production increases from our Mid-Continent and our Permian programs offset by anticipated and expected declines in the Gulf Coast. As compared to Q2 '11, our total Gulf Coast equivalent production dropped 35 million a day from 117 million a day in Q2 to 82 million a day in Q3. That's a 30% drop. But offsetting this decline, our Mid-Continent production increased 18 million a day, from 285 million a day in Q2 to 303 million a day in Q3, a 6% increase. While our Permian production increased 24 million a day from 182 million a day in Q2 to 206 million a day in Q3, a double-digit 13% increase. Combined, the Mid-Continent and the Permian were up 42 million a day for the quarter, which more than offset 35 million-a-day drop that we saw in Gulf Coast.

In comparison to Q3 '10, our Q3 '11 total company equivalent production of 592 million a day was down slightly 1% from the 600 million a day we reported in Q3 '10. But as we break down the numbers, we see the similar story, significant but anticipated drops in the Gulf Coast offset by attractive year-over-year production gains in the Mid-Continent and the Permian.

Over the last year, Gulf Coast volume dropped 85 million a day, from 167 million a day in Q3 '10 to 82 million a day in Q3 '11, that's a 51% drop. But offsetting this, our Mid-Continent-Permian programs increased to combine 77 million a day, with our Mid-Continent production up 40 million a day, from 263 million a day in Q3 '10 to the 303 million a day we just reported in Q3 '11, it's a 15% year-over-year increase.

And our Permian production was up 37 million a day, from 169 million a day in Q3 '10 to 206 million a day in Q3 '11. That's a 22% annualized increase. Combined, the Mid-Continent-Permian programs, which now make up 86% of our total company production, grew to a respectable 18%.

Mark mentioned the value that liquids play to our cash flow. And our third quarter liquid mix of 44% was virtually flat to that of Q2. But with our focus on oil and liquids-rich gas, we're up 3 points from the 41% that we reported in Q3 '10.

As we mentioned earlier, the Mid-Continent and the Permian are the catalyst, really, to our liquids growth. Our Q3 '11 Permian liquid volumes are now at 21,499 barrels a day, that's up 31% from where the Permian was in Q3 '10. And our Mid-Continent liquid volumes are at 15,607 barrels a day, that's up 42% from Q3 '10.

As we've mentioned already on the -- excuse me, as we've reported today, our Q4 reported guidance was 588 million to 613 million a day. And what's built into that is really projected, continued growth in the Mid-Continent and Permian, offsetting an anticipated and expected 7 million- to 12 million-a-day drop that we foresee in our Q4 Gulf Coast production, which we anticipate will average at a level of maybe 70 million to 75 million a day during the fourth quarter.

We've also built into our guidance the continuation of some Permian plant and pipeline shut-ins that we've seen during the month of October, which we believe will impact our October volumes to the tune of 6 million to 9 million a day.

As we have scheduled, our Q4 guidance midpoint puts us around 600 million a day, which will reflect yet another quarter of sequential growth for us.

Our Q4 projection, now with this last quarter projected out, that calculates into a full year guidance of 589 to 595. So we're, in essence, flat to 2010, where we reported 596 million a day.

On the surface we're flat, but underneath the hood, you'll see that our 2011 Gulf Coast production is forecasted to drop by about 70 million a day, with our Mid-Continent and Permian programs forecasted to make up the difference. As we've alluded to earlier in the call, as far as 2012 goes, we're currently in the midst of our planning cycle and we're certainly going to be in a better position to project guidance once our budgeting is over and we get a better feel for the market.

Shifting gears a little bit to cost. No big surprises with our Q3 lifting cost. We came in flat to Q2 at $1.14 per Mcfe. We see LOE cost somewhat stabilizing, and with them doing so, we've kept our full year guidance at $1.02 to $1.22. I say that and we've got a strong emphasis in our operations group to continue our focus on fighting the cost increases that we've seen, especially in the areas of salt water disposal, in particular the Permian. We're also focusing in on the basics: chemicals, lease maintenance, power and fuel.

On the drilling side, drilling and completion side, we've yet to see any real significant cost relief in our drilling and completion cost. And as Thomas mentioned earlier in the call, they're certainly playing a role in the economics of our program. Most of these cost increases, as we've talked about last call, are happening on the completion side. And as we've mentioned last call, frac cost as compared to the beginning of the year have gone up anywhere from 5% to greater than 100%, but the biggest increase is being seen in the Permian. Now that rate of increase has slowed down a bit in Q3, where we've seen anywhere from flat to 30% increases as compared to Q2. And this is due primarily to not only job design but we have seen some service cost increases, again, more associated with the Permian.

That said, equipment is available. The costs to get to significantly soften, although we're seeing some early signs that they may be and we hope that to play a critical role in our cost reductions that we hope to obtain here in the fourth quarter.

On the drilling side, the majority of our cost pressure once again seems to be in the Permian and I think that's indicative of the rapid rig count rate that we've all seen in the industry happen in the Permian. But in general, our drilling group has done a fairly good job of keeping our well cost increases in check. We just need to get the darn cost down.

Our Cana core wells are still running 7.5 million to 8.5 million a day. That's basically flat to where we were in January, and that's due to a lot of the efficiencies that we've derived or put together in that program. Due primarily to a change in our frac design, our third quarter, Second and Third New Mexico Bone Spring wells are running around $5.2 million to $5.5 million. That's up from the levels of $4.8 million to $5.2 million that we've quoted in previous calls. And as we move here into Q4, you'll see us look at different completion designs, which may mean more cost, and/or lateral length, which may mean more cost, but in doing so, we would be anticipating that we'd get obviously some offsetting production and economic value in doing so. So we'll continue to look at that as well.

Our Permian Paddock-Blinebry wells are still coming in around $2 million to $2.2 million, that's up 5% to 10% from late Q1, early Q2. And as we continue to develop and really try to refine our Wolfcamp shale play in more ways than one, just not only geologically but from a drilling standpoint and completion standpoint, our current AFEs are now running $7.5 million to $8 million, and that's up from $6.5 million to $7.5 million that we quoted at the end of the first quarter.

As we move forward, as Tom alluded to, our operation teams and exploration teams are joined at the hip, focusing on means to improve efficiencies and design where we can to offset these cost pressures that we've seen and get our rates of return up to where we need them.

We're going to work hard on not only cutting down drilling time through efficiencies but the completion costs make up a valuable portion of these wells, how we design those completions, getting those cost down are going to be key to us really enhancing our rate of returns.

So in summary, Q3 was another good quarter for us. We had continued production growth in the Mid-Continent and the Permian. Our guidance midpoint projects likely continued total sequential quarter-to-quarter company production growth in Q4. Our lifting cost, that remained in check, and we are going to continue to find out the cost pressures we've seen on the drilling and completion side. At the same time, we believe we're starting to see early signs of the market possibly loosening up a bit, especially on the frac side. So with that, I'll turn the call over to Paul.

Paul Korus

Thanks, Joe. Just a couple of things. We cash flowed about $1 billion through the first 9 months of the year, and includes $44 million that we won't collect until early next year, the tax refund that we intend to apply for in the very near future or early next year. We -- our capital investment was $1.2 billion. So that was call it $250 million in excess of cash flow that the GAAP was funded with $200 million of property sales and dipped into the cash balance that we carried into the year.

Borrowing have collapsed and oil prices here in the remaining part of the fourth quarter. And combined with our expectations for where December bid prices might come, we're poised to cash flow something between $250 million and $300 million in the fourth quarter as well. So by most expectations, we should be close to $1.3 billion of cash flow for the year and which we anticipate then combined with property sales and cash, we'll fully fund our $1.6 billion program this year.

With cash cost, pretty much having leveled off in reasonable expectations. Prices next year, I think, most would expect us to be cash flowing in the range of $1.2 billion next year. So very similar to where we're at this year. So more likely than not, I would say our capital will come down from the $1.6 billion that it was this year. We'll probably round cash flow. But as Tom and Joe have emphasized, those plans are still being pulled together.

With that, operator, we would be very happy to take questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Brian Lively with Tudor Pickering Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Tom, first of all, just really appreciate all the open dialogue this morning. I'm sure other companies face similar cost pressures as you guys but do appreciate the open thoughts there. My question is on the Permian. If you look at the amount of completions you guys had in Q2 and then you look at Q3, I guess we would've expected a bigger build sequentially, given you had a full quarter of production. I'm just wondering if there were some other infrastructure or other delays in your Permian over this third quarter that would have kept some of the production down?

Joseph R. Albi

Brian, this is Joe Albi. As I've mentioned earlier in the call, we saw about a 6, its a little bit high -- more than 6, but call it 6-plus million a day impact in our Q3 volumes with really through the most part I've anticipated from our forecasting standpoint, pipeline and plant-related type of shut-ins. And it was fairly consistent during the quarter. And those have continued into October. And in October, it even jumped up to about 9 million a day. Now most of those are behind us and we've tried to build that into our Q4. So you probably see our Q4 number a little bit impacted there. At the same time, it did have an impact in Q3. Tom has mentioned to some of the steeper declines. I think that's probably playing a role in the whole thing from the forecasting of the base standpoint. But overall, our programs are still generating some very healthy year-over-year type analyzed growth and it's something that we hope to continue, obviously.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then the -- on the plant downtimes, I'm sorry, I just -- I must have missed. That's in the Permian as well as in the Cana?

Joseph R. Albi

Yes, most of that 6 million a day that I mentioned in Q3 came out of Permian. And the 9 million a day I referenced in October, specifically the Permian, and we had, I think, another 0.5 million a day in the Mid-Continent in October.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, and then I know you guys aren't there on 2012 guidance yet, especially on the CapEx side, but given the cost pressures that you guys have seen across the portfolio, is your -- are you aiming to be more CapEx flat year-over-year, down or up? Could you just kind of bread basket it for us?

Thomas E. Jorden

Yes, Brian. This is Tom. I would say CapEx flat is probably going to be higher end of what we're looking at. And again, I reserve the right to later contradict myself. But the way we're currently looking at it, I think, that flat would be probably as aggressive as we'll be. And we're looking at our cost. I think we've said everything I would repeat, but I just want to say again, it's about returns. We're really looking at return on invested capital, and accelerating in a historical high-cost environment just doesn't seem to be very prudent to us right now.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I understand. But at the same time, is there internally or are you going to necessarily stay within cash flow?

Thomas E. Jorden

Well, that's -- yes, something we're also debating. There's no -- I'll say this, we don't have any rule about staying within cash flow. If we think the returns are there and we have to tap our borrowing base and fund it, we would do that gladly. But it's really about where do we think we have returns and what level of activity do we think we can sustain with those kind of returns.

Operator

Your next question is from the line of Amir Arif.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Just had a first few questions for you. First of all, on the water cuts. Can you just give us a little more color in terms of this, is this something -- is it a trend you're seeing from like north to south or east to west or is this something that almost varies well-by-well?

Thomas E. Jorden

Well, we're -- I don't want to be coy because that's not my intent. We're just -- we're really kind of figuring this out right now. We did step out and drill some thicker reservoirs and we do see a little higher water cut in some of these zones that were thicker. Now is that on average and trend? Right now, I have just to tell you honestly, I don't know. We're having a serious roll up our sleeves session next week. We've had a lot of science being directed to this problem and we're in the throes of attempting to understand it. I'm fairly confident that we can high grade around it. Now that may mean that we drop a rig or a couple of rigs in order to get back to what we would consider to be our historical average. But whether it's a function of depth, thickness or core, other parameters, right now, we're just studying that and we don't have any answers for you.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And so again, it is early days but is there a way for you to -- or do you think you can overcome it with your completion approach or is it simply -- certain areas will simply be that way and you just have to figure out which areas those are?

Thomas E. Jorden

Yes, I suspect we're going to overcome it by what we target.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And you talked about potentially dropping a rig or 2 just because of the returns. Can you just give us a sense of what you think the returns are when you talk about the 46% water cut versus the 56%?

Thomas E. Jorden

Well, what happens is returns on this play, as I said at the outset, there really is no average. And if we've erred in doing anything, we've probably talked about an average for a play that has no average. Now one of the things that isn't a good average is the particular lease that you're drilling on. We have a whole host of opportunities out here, very deep drilling inventory. Some of those are on new federal leases where the net revenue interest is 87.5%, and others of them are on leases where we had to take term assignments, or farm-ins, and we may have a low net revenue interest of 75% or less and may have other burdens like carries or back-ends. So the returns are really a function of the core lease. I can tell you that even with our results, we're still getting for a 75% net revenue interest lease, which is we would consider to be a stinky lease, we're still well in excess of better than 30% in our drilling dollar. If we go to a federal lease that's 87.5%, we are well beyond that. So what we're going to do, though, if we look at the lease that we think has steeper decline, high water cut and it's burdened to the extent that the returns fall below what we would consider to be acceptable levels, we're not going to drill it. Even though it will add to production and even though it can keep activity going, we're not going to be activity-driven.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

That makes sense. And just switching over to the Gulf Coast. Can you tell us what the exit rate was this quarter if the average was 82?

Thomas E. Jorden

Joe is looking for that. I don't have that committed to memory.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

If I'm right, I think you guys were talking about 70 to 75 in Q4 was the average.

Joseph R. Albi

Yes. I'm going on a limb here because I don't have that monthly data in front of me. But wait a minute [indiscernible] I'm going to guess it's pretty darn close to that 80.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay, so it's not down to the 60 or 70s -- or below 70s level.

Joseph R. Albi

No, no, no.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. Then that's in same level. Then just on the Gulf Coast, I mean, when you factor in the pre-drill returns, where do you think you come out relative to the Permian? I'm just curious, like would you rather not be dropping a rig or 2 in the Gulf Coast instead of some of the other areas?

Thomas E. Jorden

Well, our -- as we discussed before, our returns in the Gulf Coast pre-drill eclipse anything else we have. I mean, the Gulf Coast is an area of great geologic risk and there is still a relationship between risk and return. Our challenge in the Gulf Coast isn't anything other than drilling dry holes. I mean, these are risky locations. They can be greater than 50% chance of drilling a dry hole. They're not -- it's not pattern drilling, each one is unique. And there is a fair amount of dry hole risk. And although we have a couple of years of just drilling producer after producer, as we've said, we haven't forgotten how to drill dry holes. And we certainly confirmed that this year. We love the returns that this program generates. We're actively rebuilding our inventory and it will be a part of our program on an ongoing basis.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. So you like the returns even with, for example, like this year's 40% success rate so you think on the project economics...

Thomas E. Jorden

Well, I mean, in this year we're not getting good returns in that program. I mean, this year our returns are not good. But I think if you look at any reasonable timeline average, you'll find it's one of our highest return areas.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And I missed your comment on the Mid-Continent site and the Cana. Were -- you mentioned you were going to be focusing more on the core. So are you thinking of potentially dropping a rig or 2 there too or...

Thomas E. Jorden

No, no. We're -- we currently have 12 rigs running in Cana. We lent a rig to the Mid-Continent so if you -- when that comes back, we have 13. If anything, I can tell you that our Cana team is lobbying for a continuation of that level of activity. So I would guess rolling into next year, we'll have somewhere between 8 and 13 rigs running in Cana. Initially, we had talked about maybe throttling back to 8, but they are lobbying pretty strongly that think they can keep 13 running with excellent returns and we're going to look at that.

Joseph R. Albi

Amir, this is Joe Albi. I pulled some data out here. It looks like we entered October somewhere around that 75-ish range. So that gives you a feel for how that compares to the 70 to 75 that I forecasted for Q4. So it's, in essence, saying a slight drop.

Operator

Your next question is from the line of Ryan Todd.

Ryan Todd - Deutsche Bank AG, Research Division

A couple of quick questions for you. In the Permian, your net well completions went from 36 in 2Q down at 23 in 3Q and seems to be below the pace you need to kind of hit that full-year target that you guided to earlier. Was there anything in the quarter that happened from a completion point of view that -- and how should we think about Q4?

Thomas E. Jorden

We're kind of looking closer, that's got to just be a timing issue.

Joseph R. Albi

Yes, primarily completions.

Thomas E. Jorden

Yes. We did have our Wolfcamp program kind of on pause, but that would have -- I don't think that would be a Q2 to Q3 difference. Why don't you let us look into that, and if you want to give Mark a call, we can give you a little more color to that.

Mark Burford

Yes, Ryan. I don't know any trend that cause it to be off here in much quarter to quarter. Only -- what do we do is always capture the wells that we've drilled and completed in the quarter, and there's sometime bulges towards the end of periods that we catch up some completions or not.

Thomas E. Jorden

It always does surprise me how that can ebb and flow just with the timing of where they fall. But I don't know if that's the answer to your question.

Joseph R. Albi

And we did pick up our Permian service unit activity late May, early June so that could have had an end-of-quarter impact.

Thomas E. Jorden

Yes. Is that sufficiently vague on our answer?

Ryan Todd - Deutsche Bank AG, Research Division

That's great. But realistically, you probably expect some amount of bounce back in Q4, is that probably right?

Joseph R. Albi

We're getting pretty caught up on our completions, particularly in the Permian where when we get a well down, we should be able to turn right around and get it completed. And at the same time, I'm telling you that the rig schedule's from our wells out there for us to complete. So it's never -- you'll never get to a point where it's 0 because the well gets down and you need to complete it. Then you throw on top of that some of the areas where we're drilling the infrastructure needs to be developed, and that may come into play too. So It's a little bit wild card there but we've made great strides from where we were at the end of Q1 with regard to our backlog.

Ryan Todd - Deutsche Bank AG, Research Division

Great. In the Cana, I know you've had a couple of operators this week say they were dropping rigs. So from -- I know you just talked about general rig count going forward next year. I mean, would you expect your non-op well cost to be down year-on-year in the next year? And would that free up some extra money for you were to run extra operated or...

Thomas E. Jorden

That's a great question. And I'll -- again, I'm going to say, there are a lot of operators in Cana and we're not omnipotent on what everybody's thinking, but I'll tell you from what it looks like from our standpoint. Cana has expanded to a much larger area than we first had described. Certainly both to the northwest and the southeast, that play has expanded multiple fold. And what looks like it's going to happen next year is a lot of that activity in the extended Cana is contracting. And we see activity actually increasing in the core. We've talked about infill drilling. I can tell you that we're aware of at least a couple other companies that are talking about doing a little infill drilling in the Cana core. And so the direct answer to your question is we're anticipating our non-operating capital to actually increase in 2012 as we participate with significant working interest in other companies' infill programs.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. And then one final question, I guess, is you talked a little bit about the Gulf Coast. Any -- how should we think about expectations for next year on how many rigs that we're on? How much capital you'll spend?

Thomas E. Jorden

Well, we haven't given it, obviously, any capital numbers yet, but I can tell you what we're doing in the Gulf Coast. We currently have 2 rigs running and at least one of those 2 rigs, once drilling the well it's currently on, we'll release it. So we'll have, as we get into the fourth quarter, we'll have somewhere between 0 and 1 rigs running when we finish our current inventory. We have acquired a significant amount of new 3D data through purchase and trade, and we'll get that out of processing. Our model is we get 3D data. We either purchase it, trade for it or we shoot it new. And we process it with the latest geophysical techniques, which are always evolving, and we generate prospects based on that newly processed data. We acquired a considerable amount of data over the last few months through trade and that will be coming out of the processing shop here in the fourth quarter. And we have 2 proprietary 3D programs currently underway. So what's going to happen in 2012 is we'll enter the year with a low level of activity. And then based on what we identify, we'll ramp up. Given the area we're working, our history, I will be extremely surprised if we don't ramp up fairly significantly. So our wild-guess number for 2012 is somewhere around the level we've been this year and that will be probably $75 million to $100 million in drilling capital in 2012. But not having the prospects yet identified, that is a guess based completely on our historical experience in the area. But that's what it looks like.

Operator

Your next question is from the line of Gil Yang.

Gil Yang - BofA Merrill Lynch, Research Division

Can you talk a little bit about the performance issues again? Sorry to talk about this more. But is it -- you said it's -- the results aren't matching your type -- your pre-drill expectations. Have your pre-drill expectations also, for those particular wells, are they also sort of -- have they deteriorated as well or your pre-drill expectations are the same as it's been for the last 2 years? Is that just the way...

Thomas E. Jorden

No, no, no. We're in the process of revising that now. What's happened, Gil, is our first 30 days, what we -- there's really a number of parameters that control our viewpoint of the program. As Joe said, our first one, what is the cost to drill and complete the well. And then the initial production rate, or our first 30-day average, is the number we dial in carefully and focus on, and then the decline of the well overtime. Our costs have gone up. Our first 30-day average really hasn't changed much. Our type curve trend has been somewhere between 550 and 600 barrel per day for first 30-day average. And year-to-date, we're north of 500 on that. So we're a little below average but really, when we say, "Okay, what's gone a little haywire here," our initial production is not it. Which is why it took us a little time to catch this because you had to watch these wells and see how they performed over time. If you only watched the initial production of the first 30 days, you'd high-five one another and go on. But we watched these wells carefully and we calibrate our actual results against our pre-drill estimates. And what we've observed is these ultra-tight reservoirs are declining faster than we modeled. And that's -- so if you ask, what's the disconnect from your type curve, I would say our cost are disconnect and our decline is a disconnect. We still argue about what the tail reserves are. But on a rate-of-return basis that first year decline is really going to control it. And our returns are still very good here. I mean, this is not -- we're probably being a little too dour in representing the play. It still is generating very, very good returns when the lease terms are acceptable. But on several or our marginal leases, because of this phenomenon, we're seeing our returns erode and we're adjusting.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Talking about the water cut issue, is the water cut problem a rate issue, is it an LOIP issue or is it a EUR issue or some of everything?

Thomas E. Jorden

It's not a rate issue. Total fluid is about what you'd find, if you looked at 2 wells, the total fluid is equivalent. So it is a oil-in-place issue, I believe. And this is a very nuanced petrophysical problem. It's not something you can just lay a log down and say, "Oh yes, look at that versus that." We have a fairly sophisticated petrophysical group that's dug into this and they think it's a predictable -- it would be unfair for me to say solvable because it's an oil-in-place issue. But I think we can predict it and target areas where we can get higher water cuts.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. So being an LOIP issue, it's also an EUR issue?

Thomas E. Jorden

Yes. No, that's right, that's right. But, EUR, Gil, it's tough -- EUR is funny number on a reservoir like this with 6 months production. So there's a lot of argument.

Gil Yang - BofA Merrill Lynch, Research Division

And you guys have a strong balance sheet and you've been very disciplined about trying to spend more or less within cash flow. As you think about sort of pulling back, have you given -- or what kind of thought have you given towards using a strong balance sheet at sort of the bottom of the cycle, so to speak, to maybe high grade the inventory in a offensive way rather than defensive way?

Thomas E. Jorden

Well, we think about that everyday. And if you know people that are selling assets at reasonable prices, give us a call. I mean, it still feels like a seller's market out there, Gil. I don't know what you're seeing but we see these assets transact at fair premiums.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. So it's still not -- it hasn't reached the point that you think it's really completely attractive?

Thomas E. Jorden

Well, I -- let me just say, we haven't found anything we would want to stretch for. We look all the time, balance sheet is ready. And as we've discussed, an asset we would stretch for is one that we think has significant drilling upside that we can capture. But for the time being, we're still creating our own inventory.

Operator

Our next question is from the line of Joe Allman.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So in terms of the Wolfcamp play, Tom, I think you mentioned there are cost issues there. But have you seen any performance issues with that play?

Thomas E. Jorden

It's -- the play spans, I don't know how many miles it spans, but it's a big, big area. And yes, we do see differences in our results based on where we are in the area. There are some portion of the area that we're kind of struggling, making an economic well, and there's some portions of our area where we're making great wells. That average we quote of our 14 wells is an average that includes a high and low, that's a true average. But yes, we're seeing performance differences. And Joe, we're, again, I told you we'd discussed some of our thinkings on problems more than solutions. We are really, really digging into this. We just took a core in the Wolfcamp that our chief petrophysicist is here today analyzing. We just recorded our first microseismic job, finished last night in the Wolfcamp, so we can understand our fracture geometry. I mean, we are just very early time. And we're encouraged our results are good thus far. But I have to say, if we had to call Cana after just 14 wells, we'd have gotten it way wrong. So we're trying to build this thing as we fly it. We have 2 rigs drilling Wolfcamp wells right now. And I'm encouraged by the returns, but we're trying to really improve them.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

And Tom, I think in that play you defined a core, so are you seeing a lot of variability within that core or is the variability -- is the core consistent and you are seeing differences outside the core?

Thomas E. Jorden

Yes, I don't know if we -- it's fair to say we've defined a core yet, Joe. I mean, we -- there are areas where we're getting better wells than others. And I'll say this, it's not a laydown to explain that difference. A lot of rocks look the same, a lot of the structure looks the same. It's not a depth difference. So we're kind of focusing on the next order. What's the stretch we're seeing? What is the fracture geometry? But I don't think I can honestly represent to you that we understand an area we can draw a circle around and say, "That's the core."

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, that's helpful. And then in terms of the rig count, I think, you talked about, for 2012, 8 to 13 rigs in the Cana-Woodford. And then I think you're running about 14 rigs right now in the Permian and where did you get...

Thomas E. Jorden

We currently -- yes, we currently have 14. And we'll -- we're going to decrease that. I would say going forward, we'll be somewhere probably 9 to 12. But again, that's not a forecast. We're still arguing about that.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. And will the drop be primarily from the Second and Third Bone Spring or...

Thomas E. Jorden

We're -- there will be some drop there. We also will probably throttle back a little bit in the Wolf Camp and that's -- we want to give our operations group with the exploration group some time to get our costs down. We're drilling some really, really nice wells and if we could shave our cost, the returns would be something we'd be a little more excited about.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

And Tom, are you seeing -- in terms of cost, are you seeing -- you focused on cost in the Permian really being the issue primarily, are you still seeing cost increases as of the past 30 days or 2 months, or I guess you're seeing it plateau for the...

Thomas E. Jorden

Yes, Joe Albi said they slowed a little. But I want to be fair to our listeners and our operations group. Our problem in the Permian is a combination of costs and our performance. And I think we can make significant strides on both areas.

Joseph R. Albi

Joe, a little bit more flavor to there. I mean, as far as day rate increases, mboe increases, cement increases, rental increases, we feel a little bit more cost-pressured down in the Permian than we do, let's say, in the Mid-Continent. In discussions, I had yesterday with the gentleman heading up our fracs. He's starting to feel a little bit a lightening or loosening in some of the majors in particular, their willingness to kind of move a little bit on these fracs. To me, it's just a matter of time and it's when it happens. Completion costs make up such a big percent of wells we drill today as compared to years past. That's where the focus has got to be. And that comes down to the design. Are you overdesigning these things, under designing them, number of stages, prop type, gel or fluid type? How many pounds? How many barrels? And then of course on, obviously, the cost to get it off. And some of these companies perform better than others. Some of the majors, they give us a job down in 4, 5 days versus 7 on some of these longer days. So in my mind, we're not only on the completion side. That's where we got to focus, but also on that drilling side, we got to get those day time curves shifted to the left and improve our efficiencies there. We're also talking to our competition, trying to understand what they're doing, what we're not, what's working for them and what's working for us and trying to put it all together to better improve our overall program.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, that's helpful, Joe. And then I know -- my question is what kind of spending do you think you need to keep production flat? And I know it depends on what you are going to spend your money on and service costs and everything, but what's your best guess at how much you need to spend to keep production flat?

Paul Korus

Well, that's a hard question to answer since we haven't completed, really, a lot of our 2012 forecast. What I will say there, Joe, is just based on some of the wedge volumes that we've put together for 2011, where we would anticipate our 2012 production to start at and end at, without any new wedge, is no different than what we've thought in years past, where an exit rate might drop around 30%. So 25%- to 30%-type drop, I'll let you guys do the numbers there as to how you'd put capital towards that. But that's about as far as I can go with that.

Thomas E. Jorden

We'll do some work on that. We get asked that question a fair amount, and maybe on our next call, we'll talk about our plans, we'll discuss that.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

That's helpful. And then lastly, a question for Paul. Paul, any thoughts on hedging for 2012?

Paul Korus

We have no hedges in place for 2012, and have not had any active discussions about doing it either.

Operator

Your next question is from the line of Jeff Robertson.

Jeffrey W. Robertson - Barclays Capital, Research Division

In terms of activity levels in the Permian, is -- do you think by running as many rigs as you have, you all got a little bit out ahead of your ability to maintain the kind of quality control from the technical teams that you generally like?

Thomas E. Jorden

Boy, I'd love to be -- I'd love to say yes to that but that's not the case. I think that what happens, and it's just part of the business, this is not an excuse, I'm going to give you my clear, straight answer, Jeff. When your returns are great, you get a little -- you don't look as carefully at the numbers. I mean, about mid-summer, we took a close, honest look at our actual to expected numbers. We have a lot of machinery internally that calibrates our decisions. Our -- we run this company by doing good science, generating opportunity but also making sure that our decisions are well calibrated. When your returns, $100 in oil and a low-cost structure, our returns were so phenomenal that a lot of our operating groups weren't paying very careful attention to the calibration of our decisions. When the rate of return is north of 50% all in, it's easy to forget that, that's an important part of your business. As our cost increased and our results decreased a little, we had to kind of remind ourselves of first principles: understand your results, recalibrate them to your drilling decision and make sure you're making good decisions. I can't really chalk that up to activity and blame activity as much as I can blame the aura of success and what that does to our core discipline.

Jeffrey W. Robertson - Barclays Capital, Research Division

If you all reduce your rigs, do you think -- and then decide at some point, a quarter, 2 quarters or 6 months from now, that you want to increase, do you think there'll be -- given the Permian today, do you think you'd have any issues trying to get back some of those rigs if you let them go and let to other operators?

Thomas E. Jorden

I think we can get them back. And -- but you know what, Jeff, even if I told you I didn't think so, we wouldn't do anything different. And one of the things that we're reminding ourselves is don't driven by that rig -- by that rig count. Be driven by the quality of the investment and the confidence you have that you're going to achieve the result that you predict. So I -- yes, I think we can get them back. I think that they'll be there and we've given our teams the mandate to figure this out and get back to full throttle.

Joseph R. Albi

Tom, I'll chime -- this is Joe, I'll chime in a little bit there too. We have -- the rig situation is tight. And, I guess, the way I'd explain it overall is, day rates haven't come down but there's no huge waiting lists like there used to be. We've actually moved some rigs from the Mid-Continent down to the Permian. I don't think it'd be an issue with the Permian to get a rig. But what I do want to emphasize is I see our regrouping there in the Permian, it's all about rate of return. We've said that over and over again and that's what it is for us. We still have a large inventory of opportunity in the Second and Third Bone Spring New Mexico program. All we're doing is recalibrating, taking a look at our current results. We're reevaluating, reshuffling and high grading. Now through that high grading process, all of a sudden more opportunity surfaced than we knew about. That could bring a rig back to work in a heartbeat. So I think it's after we go back and sift through our project inventory that we can better answer that. And that's really kind of underlying our fourth quarter budgeting process.

Thomas E. Jorden

Yes. We tend to be a dour group, but we have a couple of new opportunities in the Permian that we'll be testing here shortly. It has a tremendous running room. So we ought to end this one on the note that we love the Permian. It's generating some of our best returns. We have some of the best generating teams that I think work anywhere in the business. We have systems in place to give us the opportunity to have real returns based on real results, and we are -- we will come roaring back in the Permian with the existing opportunity set and new ones that we're working on.

Jeffrey W. Robertson - Barclays Capital, Research Division

Tom, you touched on my last question was going to be, if you all think about your 2012 Permian plans, can you give any color on, maybe in a percentage term, of what you might spend or what you might try to do on what you consider to be new ventures apart from some of the plays you all have discussed previously?

Thomas E. Jorden

Jeff, at this point I really can't. I can tell you that there over the next quarter, we're going to test a couple of new ideas that have significant running room. But what that could mean in capital, it wouldn't have any meaning if I gave you a number because the concepts may not work.

Operator

There are no further questions. I'll turn it back over to the presenters.

Mark Burford

Great. Thank you, all, for joining us today. We appreciate all the attention and appreciate your questions. I look forward to reporting back to you next quarter. Thank you very much.

Operator

This concludes today's conference call. You may now disconnect.

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