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Cimarex Energy (NYSE:XEC)

Q1 2012 Earnings Call

May 03, 2012 1:00 pm ET

Executives

Mark Burford - Vice President of Capital Markets and Planning

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

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

Paul Korus - Chief Financial Officer and Senior Vice President

Analysts

Unknown Analyst

Ryan Todd - Deutsche Bank AG, Research Division

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

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Operator

Good afternoon. My name is Bishonda, and I'll be your conference operator today. At this time, I would like to welcome everyone to the First Quarter Earnings and Operations Results Conference Call. [Operator Instructions] Thank you. Mr. Mark Burford, you may begin your conference.

Mark Burford

Thank you, Bishonda. I appreciate it. Welcome, everyone, and thanks for joining us today for our first quarter conference call. Here in Denver on today's call, we have Tom Jorden, President and CEO; Joe Albi, EVP and COO; and Paul Korus, Senior Vice President and CFO; and Jim Shonsey, Vice President and Controller.

We issued our financial and operating results news release this morning, a copy of which can be found on our website. I need to remind you that today's presentation will contain forward-looking statements. However, a number of factors could cause actual results to differ materially from what is to be discussed. You should read our disclosure on forward-looking statements in our 10-K, other filings and press releases for risk factors associated with our business.

And with that, I'll go ahead and turn the call over to Tom.

Thomas E. Jorden

Thanks, Mark. Good morning, everyone, or good afternoon, at least for us. First quarter 2012 is a good quarter for Cimarex. We reported net income of $106 million or $1.23 per diluted share, and our cash flow from operations this quarter was $303 million, which continues to benefit from strong oil and natural gas liquids revenues.

First quarter 2012 production volumes averaged 603.5 million cubic feet equivalent per day or a barrel of oil equivalent just over 100,000 barrel of oil equivalent per day. Our first quarter 2012 Permian and Mid-Continent volumes hit an all-time high of 554.2 million cubic feet equivalent per day, growing 26% over the same period in 2011. That growth includes a 50% increase in Permian oil volumes over the first quarter of 2011 to a record 21,800 barrels of oil per day this quarter.

Overall, oil production also reached an all-time high of 29,562 barrels per day, and that is just a consequence of the strategy we've talked about in the past of emphasizing that Permian Basin and growing our oil and other liquids production. That liquids production accounted for 47% of our equivalent volumes this quarter and comprise 79% of our $411 million of oil and gas and NGL revenue.

Oil price realizations increased 9% this quarter to $99.28 per barrel, while natural gas prices fell 34%, averaging $2.92 per Mcf. Driving our growth are continued good results from our drilling programs. We have a great inventory of strong projects. In the first quarter, we drilled and completed 73 gross, 40 net wells, investing $400 million on exploration and development. Of that total, 50% were invested in projects located in the Permian Basin, 48% in the Mid-Continent and 2% in the Gulf Coast and other.

What I'd like to do now is give you a region-by-region walk through, and I'll start with the Permian. There, we drilled and completed 39 gross, 27 net wells during the first quarter of 2012, completing 95% of those as producers.

Permian first quarter exploration development capital was $201 million or 50% of total capital. So as you can see, we're on a run rate of about $800 million in the Permian, and we'll see what we do going forward depending on our cash flow, our results and costs.

And our New Mexico horizontal second and third Bone Spring play, that's our most active play. Year-to-date, we drilled and completed 13 gross, 6 net wells. And our per well 30-day gross production from the 2012 Bone Spring wells averaged 590 barrels equivalent, that's a Boe per day and 87% of that is oil. Throughout our presentation, you're going to hear us talk about 30-day averages. We think that's the meaningful number in some of these wells. From time to time, I'm going to sprinkle in some instantaneous 24-hour rates, but it's the 30-day rate that we look at and that's one we encourage you to look in the measure of the well.

And getting back to second and third Bone Spring, we're continuing to see very strong results in this program. We're very pleased with our recent wells and how it's trending. And that's a number of reasons, all of which are testament to our exploration and operational folks.

Of note, we've upsized our hydraulic fractures, as has many of our competitors. We've gone from 5 stages to 8 stages per lateral, and we've also done some geoscience we've talked about in the past, and we're seeing lower average water cuts. So really getting that program, delivering some nice solid performance.

Coinciding with these results, our future inventory continues to grow. We see somewhere between 150 and 200 future New Mexico Bone Spring drilling locations on our current land position, and that land position is always increasing. It's a very active lease play for us. This account has a potential to grow significantly as we continue to drill and gather more data.

Moving on to the Texas Third Bone Spring play. There we drilled and completed 5 gross, 5 net Third Bone Spring wells in the first quarter. The wells brought online had per-well 30-day average gross production rates of 800 barrels equivalent per day, 82% of which were oil. So these are very, very nice wells, cost a little more to drill and complete, but very, very nice results.

This program is also proceeding with a solid inventory of future drilling locations, which our current count is near 100 wells on our current acreage and, as before, has the potential to grow significantly with more drilling and more leasing.

And then moving on to our Wolfcamp play, we're continuing to evaluate multiple shale intervals in the Delaware Basin. The majority of our drilling, of course, is focused on the Wolfcamp. We talked about that now for a few of our quarterly calls. Most of our Wolfcamp drilling has been our southern Eddy County New Mexico, a property we call White City, and northern Culberson County Texas. In the first quarter of 2012, we drilled and completed 2 Wolfcamp wells, bringing total in the play to 20 gross, 19 net wells.

Our first 30-day production per-well, this is averaging all of our wells, is 6.6 million cubic feet equivalent per day, and that's comprised of 3.1 million cubic feet equivalent per day -- or excuse me, 3.1 million cubic feet per day of gas, 250 barrels per day of oil and 340 barrels per day of natural gas liquids. Or to summarize that, that's 47% gas, 23% oil and 30% natural gas liquids.

So that Wolfcamp play to us is significant in scope. We're currently still delineating it. We have hundreds of locations. As we said in the past, we represent this as very early time in this play. We're still doing a lot of experimenting, both testing the play laterally throughout our acreage, but also vertically. We're testing a section that's 800 to 1,000 feet thick in gross interval, and we're experimenting with different landing zones. But overall, we're very, very pleased with our results in that Wolfcamp play at this point, and that looks to be a major contributor to the future of Cimarex.

Also in the unconventional arena, where there's the Avalon Shale, and as we've discussed in the past, we're also drilling some Avalon Shale wells, especially east of us in Lea County where we began the oil window of the Avalon Shale. We've brought on 2 Avalon wells in the oil window this quarter. One was the Tristy Draw 36 State 1H [ph], where we had 100% working interest, and the Howard 5 Federal 4H [ph] with a 94% working interest. They had 30-day equivalent IPs. And again, this is a 30-day average of 500 to 700 barrels of oil equivalent per day, 70% of that was oil. But I'd also add -- they both had peak rates, their 1-day peak rate on both those wells were above 1,000 barrels of oil per day. So very, very nice wells.

Again, it's early time for our understanding of Avalon, but it looks like it has significant potential for us for hundreds of future locations, significant potential for reserves and production upside, but we're still learning our way forward in that Avalon play.

Moving on to the Mid-Continent. In the first quarter, we drilled and completed 33 gross or 12 net Mid-Continent wells. Mid-Continent first quarter exploration development capital was $180 million or 48% of our total first quarter capital. Now the bulk of that is Cana, or Cana-Woodford play. And at quarter end, we had 39 gross or 18 net Cana-Woodford wells waiting on completion.

At year end 2011, there were 13 gross or 4.9 net wells waiting on completion in Cana. Our waiting -- our wells waiting on completion have increased as a result of commencing of infill development during this year. And we've talked about this in the past calls, but we are infill drilling in Cana, and the methodology there is we're drilling somewhere between 80 and 95 wells side-by-side east-west. We get the bulk of those drilled case and then we come in later and start our completion episode, completing them simultaneously. So that's as planned. We have quite a backlog of wells waiting on completion in Cana. We'll see those come on in Q3, and that's exactly as designed.

We currently have 10 rigs running and -- or excuse me, today, we have 9 rigs running in the Cana core. We just moved the rig to the Permian. And our returns in the core are still good. They're not great, but they're good. If we look at that infill project going from east to west, where the eastern portion is the most liquids-rich portion, the western portion is the driest portion, our return on drilling investment varies from 49% after-tax in the liquids-rich portion to 20% after-tax in the drier portion, and that's our current strip price. So still acceptable returns in the Cana-Woodford. However, we're getting better returns in the Permian. So as we've talked in the past, for the remainder of the year, we'll be shifting some of that capital to the Permian.

We have a lot of flexibility in our Cana investment. We have limited lease expirations. We have very limited rig or other service commitments. So what we're planning on doing is throttling back to Cana a little bit while we watch these gas prices. We're going to go back to 7 rigs in the greater Mid-Continent area. We will probably take from time to time anywhere from 1 to 3 of our Cana rigs in western Oklahoma to test some new emerging ideas. We've talked in past calls about the western Oklahoma, Anadarko Basin being a very active generation program for us. And we have some things lined up that will be from time to time borrowing rigs from Cana in this low-gas environment to test some concepts that are oilier in Western Oklahoma.

And finally, just wrapping up, talking about the Gulf Coast. In the Gulf Coast, we participated in just 1 gross or 0.5 net wells that was operated within our Yegua/Cook Mountain fairway in the first quarter, and that well was unsuccessful and was a dry hole. We're in the process of shooting and acquiring new seismic data, and we expect to be recharging our inventory and back to drilling in the second half of this year.

So overall, we're seeing our program, the flexibility we baked into it in past years, having a liquids portion, having a high-quality Cana-Woodford program, also having a number of different plays. We're getting some benefits in that. And that even in this rather hostile gas environment, we still have a lot of opportunity to choose from that gets us acceptable returns. Obviously, we're trying to live within the guidance that we've talked about in the past, and we're committed to do that. But we're very pleased with our results thus far and very optimistic about our deep inventory and the opportunity it brings us.

With that, I'll turn the call over to Joe Albi, our Chief Operating Officer.

Joseph R. Albi

Thank you, Tom, and thank you all for joining our call today. I'll summarize our first quarter production, update you on our Q2 and full year guidance and then finish up with just a few comments on our current service costs.

Well, Q1 came in for us just about as planned. We reported average net daily equivalent production of 603.5 million a day. That was up 2 million a day from our Q4 '11 reported figure of 601.4 million a day and fell just about at the midpoint of our guidance, which was 595 million to 615 million a day.

Our production during the quarter was slightly impacted by some pipeline and facility shut-ins in both the Permian and the Mid-Continent. Those shut-ins impacted our production by approximately 6 million a day. And without them, we would've come in, obviously, at the upper end of our guidance.

With our continued focus on the Permian and the Cana, we once again set a few records during the quarter. Tom mentioned a few, 4 of them all mentioned. Our Q1 Permian oil production of 21,800 barrels a day is a record, that's up 14% from Q4 '11 and 50% from Q1 '11.

On the equivalent basis, our first quarter Permian production came in at 240.3 million a day, that's also a company high, up 12% from last quarter and 38% from a year ago. And although we were impacted to the tune of about 3 million a day in facility shut-ins during the quarter in Cana, our Q1 equivalent net Cana production of 161.3 million a day is also a new record, up 2% from Q4 and a respectable 56% from Q1 '11.

As Tom mentioned, driven by the Permian, our total company Q1 oil production of 29,562 barrels a day was a new record. That's up 8% from Q4 '11 and 10% from last year. While our total company liquid production of 47,249 barrels a day also set a new high mark for us, up 6% from last quarter and 8% from a year ago. During Q1, liquids now make up 47% of our total production, that's up 3 points from the 44% that we saw one year ago.

As compared to 4 '11, on an equivalent basis, our Q1 total company production of 603.5 million a day was up 2 million a day, with the Permian being up 25 million a day, the Gulf Coast down 21 million a day and the Mid-Continent down slightly at 2 million a day. And this, again, as I mentioned earlier, primarily result of the pipeline at facility shut-ins that we saw during the quarter.

As we mentioned during our last call, we now see the headwind of our past Gulf Coast declines to be behind us, and it's reflected in our year-over-year numbers. As compared to Q1 '11, our Q1 '12 total company production was up 13.4 million a day, with the Permian up 66.6 million a day, and the Mid-Continent up 47.8 million a day. That's a combined increase of 114.4 million a day, which more than offset the 101.3 million a day drop we saw in the Gulf Coast over the last 12 months.

So as we look forward into Q2 and the remainder of the year, as we mentioned when we first issued our 2012 guidance, the significant portion of our anticipated 2012 production gains were projected to occur in the latter half of the year. And Tom alluded to this, this is driven primarily by our Cana infill well frac schedule.

Well, that picture hasn't changed, and as we modeled at the beginning of the year, our Q production -- Q2 production is forecasted to be relatively flat to Q1 as a result of basically 2 items: Number one, our anticipated Gulf Coast production decline, albeit a relatively small drop of 8 million to 10 million a day from Q1 to Q2; and two, the buildup of our completions that we have with the Cana infill project.

As of March 31, we had 39 gross or 18 net Cana wells waiting on completion, with our infill frac activities slated to begin here in late May and then continue to the end of the year. So with this frac schedule, the production adds associated with the infill project are really projected to make an impact on our production in Q3 and Q4.

With knowledge of some significant Q2 pipeline facility shut-ins and likely at a rejection associated with our processed gas in Cana, as many of you have written or read, we've reduced our second quarter guidance by approximately 10 million to 12 million a day, which resulted in a projected Q2 guidance range of 580 million to 680 million a day for the quarter.

Incorporating our new Q2 estimate into our full year model, results in a revised 2012 guidance range of 612 million to 613 million a day. The current full year model calls for a Gulf Coast production to drop to levels of 25 million to 30 million a day by Q4, with combined Q4 Permian and Mid-Continent volumes to be in the range of 625 million to 650 million a day, up a respectable 18% to 22% from our Q4 '11 combined Permian and Mid-Continent equivalent volume of 531 million a day.

So outside of the external impacts on our Q2 production, the bottom line to our guidance is basically that we're about where we thought we'd be at this point in the year. Adjusting our Q2 guidance for the 10 million to 12 million a day of shut-ins and possible ethane rejection puts Q2 right in line with Q1, which is how we modeled it at the beginning of the year, with the impact of our Cana infill program and increased Permian activity projected to boost our Q3 and Q4 volumes.

Shifting gears to our OpEx. Our Q1 lifting costs came in at about 23 per Mcfe. That's up slightly from Q4 and at the upper end of our guidance. The primary component of work here was our slightly higher workover activity during Q1 as compared to quarters passed, with our first quarter workover component of $0.04 per Mcfe from Q4 '11. So with Q1 coming in at $1.23, we bumped our 2012 lifting cost guidance up slightly to about $1.15 to $1.30.

On the service cost side in general, during Q1, we saw our drilling cost components remain relatively flat, while completion costs appear to be softening a bit. And that's driven primarily by frac service cost reductions and overall prop cost reductions with the use of white sand. Only where we've increased fracture upsizes have we seen completion cost increases.

In Cana, through drilling efficiencies gained by pad drilling, such as mobilization and facility cost savings, utilizing biofuel for -- power for our rigs, installing pipeline infrastructure for water sourcing and disposal and by consolidating our services and equipment, our current Cana core infill AFEs are now running $7.6 million, and that's down from levels of $8 million just 3 months ago.

Our current Permian AFEs have remained fairly well in check since our last call, with improved drill time efficiency, our Paddock-Blinebry vertical AFEs are now running $2 million to $2.2 million, that's down slightly from Q1 and back in line with equivalent costs a year ago. Our 8,000 to 9,000 foot TVD New Mexico second Bone Spring wells are running $5.8 million to $6.5 million, that's flat with the numbers we gave you in Q1, but up 15% to 20% from Q2 '11, and that's, as Tom mentioned, to us increasing our frac size in that program basically going from 5 stages now to 8.

Now as we drill a little bit deeper into the basin and approach TVDs of close to 11,000 feet, we'll see some of these second Bone Spring wells get closer to a $6.8 million to $7 million range. The heart of our activity today has been in the 8,000 to 9,000 foot range.

Our current West Texas Third Bone Spring AFEs of $7.5 million to $8.5 million are again flat with Q1 yet down considerably from where they were a year ago at about $9 million. This primarily a result of us changing our completion design going to cemented liners, fewer stages and using white sand. And our current Wolfcamp AFEs continue to come in at $8 million to $8.5 million, right on track as well with the estimates that we provided last call.

So in a nutshell, for us, Q1 came in about as planned. Adjusting for known Q2 pipeline facility shut-ins, our second quarter looks relatively flat to Q1. Our model continues to call for strong Q3 and Q4 production growth from the Permian and the Mid-Continent. Our service costs appear flat with signs of softening on the completion side, and our program efficiencies continue to improve our total well cost as we've evidenced with our Cana infill project.

So with that, I'll turn that -- I'll turn the call over to Paul, our Senior VP and CFO.

Paul Korus

Thank you, Joe. Consistent with our track record, our earnings release is probably once again noteworthy in that it doesn't contain any surprises. Our operational and financial results were good and generally in line with guidance and other expectations. I would say that the earnings and cash flow numbers were very clean, so I don't think they require any further explanation.

However, I would like to comment and update you on the right side of the balance sheet. Subsequent to quarter end in early April, we issued $750 million of new 10-year Senior Notes priced at par to yield 5 and 7.125%. We used the proceeds to repay our old $350 million of 7.125 % Senior Notes that were due in 2017 and to repay bank debt that we had outstanding at the time. I probably should add in case any investors are on the line, thanks very much for your participation in that offering.

Pro forma for the new notes, we have nothing drawn on our $800 million bank credit facility and approximately $150 million of cash.

Our credits stats after the offering remain strong. Pro forma for the new offering, our debt-to-cap ratio is about 19% and total current debt and projected debt outstanding at the end of this year remain below 1x to our EBITDA or any other measure of cash flow.

We -- our capital projection for the year remains $1.4 billion to $1.6 billion, midpoint of $1.5 billion. We think we're very well positioned to fund that with cash flow derived from production this year, proceeds to this offering and perhaps drawing on our credit facility to the tune of $150 million to $200 million by year end.

With that, I'd like to turn it back to the operator for questions, please.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Mario Bizara [ph].

Unknown Analyst

Just wanted to get some color on the Texas Bone Springs. It's just going back sequentially for the past few quarters, you're seeing steadily improving average 30-day rates. I know you commented briefly about using more sand, and what exactly are you guys doing or have you changed in your drilling techniques over the past 6 to 9 months to drive this improvement?

Thomas E. Jorden

Sure. This is Tom. I think primarily, we're in a better area. We've -- for the past couple of years have been a little bit of a tug-of-war on leasing. And there's a part of the play we really like that we haven't aggressively drilled in because we were in lease competition and wanted to not race market players. And that has kind of come to an end, and so we're drilling in some areas that are a little thicker, a little higher oil cut and just better quality rock than some of our prior results. That and the upsized completion, I would say, explains our increasing results.

Unknown Analyst

Okay. And then you mentioned about looking to still acquire land here. I mean, with the recent debt offering, you still have a pretty solid debt to cap around 19%. What's your appetite for making an acquisition in this market that could be comparable to what you made with Magnum Hunter a few years ago, which got you really a significant position in the Delaware Basin?

Thomas E. Jorden

Well, I would say our appetite is strong, but it's about returns to us. And we look at a lot of water package, I assume you're talking about Permian in particular, we look at water packages in the Permian that we like, and we are unwilling to pay what the successful buyers are paying because we don't think the returns are there. Now maybe we're just not seeing it fully, but we see it as we see it. So we're about returns. We love the Permian, but we're generating very nice returns on our internally generated opportunities, and we're able to increase that. I'll answer you straight on, though. We would love to find another opportunity like we had in 2005 when we bought our land to that 370,000 net acre position in Permian. This is -- these transactions today, it's very difficult for us to justify with our return metrics.

Unknown Analyst

Would you consider a new play or are we really just concentrating in the Permian and the Mid-Continent here?

Thomas E. Jorden

Well, of course, we consider a new play. We would love to find something that we think generates significant drilling opportunity and would give us another core business area. So yes, we are opportunistic for that. I wouldn't say that we wake up every morning and go look for it, but they tend to kind of find us. And it's one of the strong reasons why we we're trying to preserve some flexibility with our balance sheet in case that were to happen.

Paul Korus

I'll add -- this is Paul, I'll add that in the meantime until the right opportunity comes along, we have -- we can be patient and selective because we are already long drilling inventory in both the Permian and the Mid-Continent area.

Unknown Analyst

Okay. And then just since talking about the drilling inventory, just last question here. You mentioned about maybe borrowing some rigs in Oklahoma to possibly expand on your drilling inventory. How long or far away are you guys from disclosing a new position or a new play within your current acreage position?

Thomas E. Jorden

I don't think you'd see us come out with some huge threshold announcement. It's not the -- western Oklahoma is our oldest operating arena. And it's also one of most competitive land arenas that we compete in. But I wouldn't expect to see us come out with some new stealth play where we're going to say we have hundreds of thousands of acres. That said, in western Oklahoma, a 20,000 to 50,000 acreage position in the right play can be extremely meaningful to company our size. But I think we're probably targeting something along those lines. We're currently leasing in a couple of areas. But it's very, very difficult, and it's part of our business as usual that we use every day.

Operator

Your next question comes from the line of Ryan Todd.

Ryan Todd - Deutsche Bank AG, Research Division

I just had a question on your guidance. If we look at your production guidance for the year, what are the implications in terms of rig activity? I know you mentioned dropping from 10 rigs to 7 rigs in the Cana or in the Mid-Continent region. How many rigs is that emission going to in the Permian?

Thomas E. Jorden

Well, we're currently running -- depending on when you quarry us between 13 and 15 rigs in the Permian. And we have the opportunities lined up to increase that, and we're talking about that. As I said earlier, though, one of our disciplines is our -- these low gas prices have some impact to our cash flow and we're trying to manage our capital program with some discipline. And we had a little bit of additional capital in Cana. You know there are a lot of companies infilling out there, and we have a little more non-operating capital in Cana that we initially planned for. And we're going to stay flexible. We'll be probably somewhere between $600 million and $800 million in the Permian this year, and it's going to be a function of our results, rig availability and our cash flow.

Joseph R. Albi

With regard to guidance, this is Joe Albi, with the rig, any type of rig transfer occurring for the most part, in the second half of the year, our 2012 modeling really didn't change, especially considering Q3, Q4 production as from Cana and the Cana infill project, we're basically in complete mode there where any slowdown in drilling activity would more affect the first part of '13 than '12. And on the other side of the coin, moving those rigs into an area like the Permian, we might be able to realize some oil production in Q4 relatively quick. So when we tinkered with those sensitivities in our modeling, 2012 didn't change much.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. And I assume, I know you talked about ethane rejection right now in Cana. How long of a period of ethane rejection are you modeling in there?

Joseph R. Albi

Well, that was a topic of conversation between Mark and I, and all we feel comfortable with is just trying to predict about as far as we can see pass our nose. So we only incorporate in what we thought we'd see in Q2, and that was only for the Cana portion.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. And then finally, if I could switch over briefly, we've seen a lot of attention in the Midland Basin around the emerging plays decline and then the north Midland Basin and the Wolfcamp obviously. What are you seeing -- are you looking at equivalent zones in the Delaware Basin? And what are some of the other horizons that, I guess, you have your eyes on right now?

Thomas E. Jorden

Well, yes, this is Tom. Obviously, our Wolfcamp play in the Delaware Basin is the direct equivalent to the Wolfcamp in the Midland Basin. They also pursue a deeper shale, which would be the equivalent of our Penn Shale. We're pursuing that. Midland Basin is different, but it does -- we don't play that. We don't have a big position, although we're studying it pretty hard. I think critical difference is as normally pressured whereas we're overpressured. But we're pretty pleased with our own Wolfcamp so we don't feel a need to race over there and pay top dollar for a big acreage position. We like what we've got at Delaware.

Operator

Your next question comes from the line of Brian Lively.

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

On this ethane discussion, can you remind us, one, how much ethane do you guys produce specifically out of Cana? And then what percentage of the Cana barrel is ethane?

Joseph R. Albi

Brian, this is Joe Albi. Here's how I'd look at it as far as how it translates into guidance. And if Mark wants to chime in, please do, Mark. But what we modeled was an impact of about 5 million to 5.5 million a day worth of volumes on an equivalent basis that we'd see as far as a reduction is concerned. When we look at the specifics of it, in Cana, about 24% of our wet gas stream or produced wellhead gas stream is dry, 76% is processed. We look at a May Mid-Continent price of $1.87. Had we not had ethane rejection, we would have received at the wellhead $2.82 -- excuse me, $2.97 in Mcf. And with rejection, it's $2.82. So it's hitting us to the extent of about $0.15 on a wellhead Mcf. But on the other side of the coin, we have a little bit more residue coming off the back side of the plan. So our residue with rejection is about, for 1,000 Mcf into the plant would yield $8.62 per reservoir volumes versus $8.02 had we not had the rejections. So we see about 7.5% increase in our gas, and I think that may help you translate it into Mcfes, which is how we try to look at in our model. I don't know, Mark, if you want to add anything?

Mark Burford

Yes. I guess, we just throw you a question, Brian, of our Cana NGLs in the first quarter produced 6,700 barrels a day of NGLs in Cana. So about all those NGLs, almost nearly half of that barrel is ethane.

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

Right. My point was more on if you look at the NGL realizations in Q1 at about 36%, the volume impact of rejection is one thing. But by the same token, what are you guys thinking then going forward in terms of actual realizations versus WTI for your NGL base?

Joseph R. Albi

This is Joe again. Mark and I looked at that this morning and, I guess, the best way we'd answer that is based on the one other time that we saw rejection, which was August of 2010. We might say that might move a couple of points. So like 36% to 38% or something like that.

Mark Burford

Yes. We have a 34% of WTI in the first quarter, Brian. So yes, if you do your 4% uptick in our realization, WTI is probably reasonable.

Joseph R. Albi

And that's a guess, Brian. That's a market in itself.

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

Right, exactly. The -- on the Permian, what -- just on average, can you guys provide kind of that same breakdown of ethane for an NGL barrel?

Mark Burford

Yes, Brian, I think roughly the ethane barrel is similar, so half of that's staying there also in 25% propane heavier.

Thomas E. Jorden

And then the Wolfcamp's our biggest probably contributor. I think that is half.

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

Okay. And then last for me. The Permian, I guess, with some down -- some infrastructure downtime recently, it seems like the differentials are widening and maybe they're starting to narrow now. But can you guys comment at sort of the same commentary, I guess, on the NGL realizations going forward, but what should we expect from the Permian on the oil side?

Joseph R. Albi

As far as receipt price?

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

Right. What kind of differentials? I mean, you guys gave some pretty good guidance on expenses, but I'm just looking for more details on the actual realizations side as it relates to crude?

Thomas E. Jorden

Okay. So for -- as an example, the differential that we were seeing between Midland and Cushing in 2011 was running around $0.50, $0.70. In Q1, we saw that on an average basis increased to $1.48. In April, we're guessing, with the preliminary data that we have, that that's probably somewhere close to $3.85 to $3.90 differential. And in May, probably the high $5, $5.85, $5.90. And June, we target somewhere maybe $5.25. So when you compare Q2 differential to where we saw Q1, we're seeing about a $3.50 difference between Q1, obviously on the lower side, and that represents about 75% of our oil. Now we are seeing the reverse, obviously, with Louisiana with our LRS differential. But unfortunately, it's a smaller percent of our volumes now. So we're seeing about a $6 increase there but that's about 5% of our volumes.

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

And that -- do you think that's transitory in the second quarter? Meaning as you go third and fourth quarter, the realizations should improve? Or do you think the run rate that's kind of there?

Thomas E. Jorden

Well, we -- I mean, at some I'd love to hear your thoughts on. But we're hearing the bottlenecking, we're hearing the basin pipeline expansion taken out of the equation. We're hearing that turnaround season's over, that ought to help. And a general line coming on in '13 ought to help. We've got a West Texas Gulf expansion. It should add another 100,000 barrels of takeaway at the end of the year, and then there's always talk about rail. So this is definitely anomaly when you look over time that we've seen something like this. Our hopes, obviously, are that it's not at the end of the second quarter.

Mark Burford

And if you were to ask a commodity trader, if you went into the over-the-counter derivatives market to try to swap or hedge something near -- in that case, it says it does return to normal by September or October.

Operator

[Operator Instructions] Your next question comes from Duane Grubert.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Can you talk a little about the Gulf Coast reduction in activity? You're still spending about $80 million there. So I'm wondering, have you cut back on your internal personnel that are looking at the Gulf Coast and were truly winding it down? Or is it more that last season's batch of wells weren't so hot and we may still be surprised by a good batch this year?

Thomas E. Jorden

Brian, this is Tom. That $80 million of plan capital and it'll be -- if it comes to fruition, it'll be back-end loaded to the second half of the year. We're in a rebuilding phase. We've got 3 to 5 new 3D programs that are going to be coming into our shop here between now. The first one hit our shop a few days ago. Between now and middle of fall, we'll have 3 to 5 new programs. And it's a constant rebuilding of the inventory, and this is being -- since 2002, when we first played the Gulf Coast, we get new data, we analyze it, we would look for anomalies, we come up with a prospect inventory and we'd get at it. What you're seeing here is because of some permit delays on some federal level [ph]. We lost about a year of debt cycle. So we have a -- probably at least until Q3, you're going to see a level of activity. No, we have not -- in fact, we're increasing our staffs with a little more horsepower, and we'll look at this Gulf Coast data. And I would expect this to be at temporary level. But that said, as you've heard us say in the past, we have no Gulf Coast inventory. It is always build-it and drill-it type deal. So until we get those data sets interpreted, get them analyzed, we wouldn't be able to say anything definitive about where our upcoming inventory is. That $80 million is our best guess for money we set aside.

Operator

[Operator Instructions] And there are no more questions at this time.

Mark Burford

Very good. Thank you for everyone for joining us today on the conference call. I look forward to meeting you in person in the next coming conferences in -- over the next quarter. Thank you very much for participating.

Operator

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

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