Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Cimarex Energ (NYSE:XEC)

Q1 2010 Earnings Call

May 07, 2010 1:00 pm ET

Executives

Mark Burford - Director of Capital Markets

Thomas Jorden - Executive Vice President of Exploration

F. Merelli - Chairman, Chief Executive Officer and President

Joseph Albi - Executive Vice President of Operations

Paul Korus - Chief Financial Officer, Vice President and Treasurer

Analysts

Nicholas Pope - Dahlman Rose & Company, LLC

Jeffrey Robertson - Barclays Capital

Eric Hagen - Lazard Capital Markets LLC

Gil Yang - BofA Merrill Lynch

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

Operator

Good afternoon. My name is Tonya and I will be your conference operator today. At this time, I would like to welcome everyone to the First Quarter 2010 Operating and Financial Results Conference Call. [Operator Instructions] I would now like to turn the call over to Mark Burford, Director of Capital Markets. Please go ahead.

Mark Burford

Good morning, everyone. Thank you, Tonya, for joining us today for the first quarter conference call. We did issue our financial and operating results in the news release this morning. Copies of which can be found in our website. And we will be making forward-looking statements on today's call, so I'll refer you to the end of our press release regarding forward-looking statements.

Here on in Denver on today's call, we have Mick Merelli, Chairman and CEO; Tom Jorden, Executive Vice President of Exploration; Joe Albi, Executive Vice President of Operations; Paul Korus, VP and CFO; and Jim Shonsey, EVP and Controller. So again, thank you for joining us today and it's a bit of a volatile morning but we'll go ahead and just jump into the call and I'll turn it on over to Mick.

F. Merelli

Thanks for joining us on today's call. Cimarex is having a very good year. Our first quarter production grew 25% over the fourth quarter, hitting a record 585 million cubic feet equivalent per day.

First quarter volumes were made up of 32,280 barrels a day of liquids and 391 million cubic feet a day of gas. So our production is 67% gas and 33% liquids, when you use a 6:1 conversion.

Our gas versus liquid revenues on a gas or liquids revenue basis were about 50-50, so about half of our revenues are coming from liquids. We reported first quarter earnings of $204 million, or $2.39 per share. And cash flow from operations totaled $300 million.

Our capital investment in the quarter was a little over $200 million, so we underspent our cash flow, which resulted in paying down $25 million in our remaining bank borrowings. And we're exited the quarter with $62.5 million of cash. The remainder of our debt, which is about $368 million, is turned down.

Our 2010 capital program that we've described in the past will fall in the range of between $700 million and $900 million. And we're still thinking that's about where we're going to wind up.

Our first quarter spending puts us on track to be in the middle of that range. And so that by region, that would be roughly $400 million in the Mid-Continent and $280 million in the Permian and $120 million in the Gulf coast and so those are all net numbers and on our capital.

When we discuss capital, we really don't have a budget. What we do, and I think I say this on every call, we just make investment decisions based on our projects and wells on a risked economic basis. And so the pricing is important to the economics. And as I've stated in the past, we run on the strip but we also run a flat price sensitivity. Our flat price case that we've used for about the last year is $45 for oil and $350 for gas, that's a NYMEX $350 so we correct it for whatever differentials you get and various for whatever reasons in different areas.

And that sensitivity is not a prediction. It's just a way to rank our inventory. And we like to see how close that -- we're looking at things that still get us back to cost of capital even under those situations and hopefully, over the cost of capital.

So in the areas we're drilling, we've a cushion in our economics relative right now. The wells we are drilling, we have a cushion relative to our flat case. Those economics are helped out for different reasons in different areas.

In our Cana-Woodford, we have high NIRs of around 80%. We are liquid-rich high BTU gas. We have condensate in a lot of those wells, and we have a nice production profile that is flattening out nicely for shale play. And one of the things that, going forward is that we continue to improve the effectiveness of our fracs for better production rates and EURs, and we feel like we still have room to get our wells down quicker which will impact the front-end with lower investment per well.

So all of those things make our Canyon project fairly price-resistant. Our Permian horizontal oil plays are working out well. Our second Bone Spring and Abo plays are economic at 45 flat level. We've been pursuing horizontal oil ideas the last few years, and we are well positioned to grow our production.

From the fourth quarter 2009 to the first quarter 2010, we grew Permian oil production 12%. This effort continues to grow. It's fueled by a really good team of people in our Permian area who are developing and continue. They continue to develop and they have a nice inventory of horizontal oil drilling.

Gulf Coast, the Yegua seismic exploration wells are virtually bulletproof to price. What we have to watch out for is of course the dry holes and over the years, we've done nicely not drilling too many dry holes to kill the program. So starting in mid-2009, we've drilled some outstanding wells; starting with our Two Sisters, discovery in near Beaumont, Texas and this year, continues that success with the Nine Dragons, number one discovery. And this area historically has been our highest rate of return area.

So our 2010 capital is moving ahead. We're having a very good year and of course, we define that based on a rate of return that we calculate on what we've been able to accomplish so far. And that's obviously what we focus on. And a good rate of return in our drilling will show up eventually in growing production, cash flow and reserves. We have been realizing great returns on our production and cash flow, and our production and our cash flow reflect that.

We will continue to watch our rate of returns, and hopefully, I hate to beat a dead horse here, but that ought to result in our continuation of production growth our resource growth.

And of course, that's not easy and luckily I have Tom and Jo to worry about all of that and they just happen to be here today to cover our production outlook and our drilling programs in more detail. So with that, I'll turn it over to Tom to cover more detail about our drilling program.

Thomas Jorden

Thanks, Mick. Good morning, or good afternoon to everyone. Operationally, first quarter was a very good one for Cimarex. All of our core areas are performing quite well and we also have a great balance of opportunities. We have our Mid-Continent resource gas, our Permian basin horizontal oil and our Gulf Coast seismically controlled exploration. So all regions are doing quite well and I'll cover and summarize some of our drilling activity.

We drilled and completed 37 gross, 23.1 net wells in the first quarter of 2010, and we had 29 gross and 18.5 net wells at quarter end that were drilled awaiting completion. Our capital in the first quarter exploration development was $193 million and as Mick said, our exploration development capital estimate for the year remains $700 million to $900 million. We certainly have the opportunities lined up ready to go to be in the midpoint there and it will be a function of our own success, commodity prices and market conditions in terms of service costs, as far as how far we want to accelerate, or decelerate around that midpoint.

I'm going to go ahead and drill down through our activity by region. I'll start with our Mid-Continent. In the Mid-Continent, we drilled and completed 22 gross, or 10.4 net wells during the first quarter and we completed what 100% of those as producers. At quarter end, we had 18 gross, or 10.2 net wells that were in the process of being completed, or were awaiting completion. So we have a fair backlog still of wells to be completed in the Mid-Continent.

Our first quarter exploration development capital totaled $90 million, which was about 47% of our total first quarter capital. Majority of that activity in the first quarter was in the Anadarko Basin, and that's primarily our Cana-Woodford shale play, where we drilled and completed 15 gross, or 6.7 net wells and had, at quarter end, 14 gross, or 7.1 net wells awaiting completion.

So we're still on track to get 35 net wells drilling completed this year, and as we talked in past calls, we are catching up with our backlog. We have a frac crew continuously working. They're making some tremendous strides in terms efficiencies. So we're working our way through that completion backlog.

Our economics in the Cana-Woodford shale play are greatly supported by liquids. We've talked about that in the past and certainly, that's been a focus in the industry lately so it bears reiterating. Our production stream in the Cana during the first quarter was 63% gas, 7% oil or condensate and 30% natural gas liquids. Because of the higher value for liquids, the revenues were actually 56% gas and 44% liquids. So in terms of the industry's newfound thirst for liquids-rich clays, Cana-Woodford shale certainly stacks among the best in our eyes.

We've drilled or completed some outstanding wells so far in 2010, and we've talked about a number of those but we have the Rolls 13H which made 5.3 million cubic feet a day, its first 30-day average. The Miller trust, 15H where we have a 61% working interest, made 7.8 million cubic feet a day, its first 30-day average. The Harts, 132H that's a well we have a 100% working interest in, that made 7.19 million cubic feet a day on average for its first 30 days, also made 151 barrels of oil per day recovered at the wellhead. So an outstanding spending well in the core of the Cana play.

We had our little 134H, where we have 84% working interest. That well made 6 million cubic feet a day first 30-day average. And then we have our Harmon 11-5H, made 1.2 million a day, first 30-day average with 253 barrels of oil per day. And then we've also talked about our Straight Arrow well, that's our well on the southern part of the play. That well we had some operational problems on. We've talked to a number of you about that well. We ended up with a problem with our casing, and we had to submit a 3.5 long strain TD in that will. It's made 1.8 million cubic feet per day for the first 30-day average and 43 barrels of oil per day.

We're currently drilling an additional well in our Southern extent of the play and results are still to be determined as far as that area of that acreage. We were a little disappointed that we had that operational issues in that Straight Arrow and we're going to continue at it.

We're continuing to optimize our drilling and completion. Our fracs are -- we're putting our stage interval. We had talked about a type well being 13 or 14 stages and those pages were 350 feet apart. We're currently experimenting with shortening that up a little bit, going to 250 feet first stage with the same overall job size. And we're quite optimistic that that maybe further optimization in our completions.

Our current cost estimates for our new drill are somewhere in the $7.5 million to $8 million range. For that a larger number of stages, we're probably going to be at $8 million, or slightly above there. Then we've also talked about our 80-acre pilot project. We're proceeding a pace. We should be starting our completion here at the end of May or the first part of June. And as we've said in the past, we should have some results to speak about there into the third, maybe early fourth quarter.

We have seven operative rigs drilling in the Cana-Woodford play. We're have outstanding results. It continues to look better and better for as. It's a large resource and it will be an important part of our portfolio for a long time. One of the things, we have a core and we have a fringe acreage and we're defining that through drilling. We're still in the process of understanding where the liquids help our economics, where the dry gas helps our economics, but we're very, very pleased with what we've seen and we're having very, very nice results with our seven operative rigs.

Also in the Mid-Continent, we're active in the Texas Panhandle. In the first quarter, we drilled five gross, or 4.4 net wells, four at Granite Wash and one Morrow. We drill a great horizontal at Granite Wash well. That's our hub 16-5H, where we have a 14.5% working interest. That was in southern [ph] Henpell County. We brought that well on production in early March. It averaged 20 million cubic feet a day equivalent. That's 80 million cubic feet a day of gas and 400 barrels of oil for its first 30 days, so very, very nice well. We're currently drilling an offset to it and have probably six or seven additional offsets to drill there, and we'll probably that 40% working interest in those offset wells on average.

We have nine operating rigs running in the Mid-Continent, seven in the Cana play, one in the Texas Panhandle and one drilling a horizontal Granite Wash well in the Anadarko Basin.

Now moving on to the Permian. In the Permian Basin, the first quarter we drilled and completed 10 gross, or 8.9 net Permian Basin wells, 90% percent of which were completed as producers. At quarter end, 11 gross, or 8.3 net wells were in the process of being completed or were awaiting completion. So we also have a little bit of a completion backlog in the Permian.

First quarter exploration capital totaled $62 million, or about 32% of our capital. And all of our drilling currently is in Southeast New Mexico focused on the horizontal oil, mainly targeting the Abo and Bone Spring formations.

We've had great results in our Abo and Bone Springs programs. Those are, as we've talked in the past, internally generated. We have nice positions there and the economics are very strong. In the Abo, we've had some very nice wells we've brought on in the quarter. Two of which are the Ticonderoga, 16 State 1H. We have 100% working interest in that well and its first 30-day average was 725 barrels of oil per day.

The Ticonderoga 16 State 3H, 100% working interest. We had a first 30-day average of 605 barrels of oil equivalent per day. So we have two rigs running in that trend, and we're very, very pleased and encouraged by the results we're seeing.

In our New Mexico Bone Spring horizontal oil project we've also had some results that very encouraging to us and actually, a little better than our pre-drill model. Our Parkway State Com 3H well is one we have a 62% working interest in. We brought it online in the quarter and its 30-day average was 760 barrels of oil equivalent per day.

Our Mallon 34 16H, 82% working interest, 360 barrels of oil equivalent per day for its first 30-day average. So we have two rigs running in that play as well. That is a very nice internally generated play for us and we're anticipating having between two and three rigs running in that play between now and the end of the quarter.

We also drilled on Avalon shale well. We get asked about that play a lot because it certainly is an emerging play in the Permian Basin. We drilled a horizontal well. We're currently completing and flowing back so we don't have any results to discuss just get. That's not a strong focus of ours just yet. We're watching the play. We have a very nice acreage position that's exposed to the heart of that play. And the drilling is moving our way and we're certainly very interested in that play. We'll be watching our own completion and the completion of others and be evaluating the exposure we have to that.

Now moving on to the Gulf Coast. In the Gulf Coast, we drilled four gross, 3.8 net wells in the first quarter of 2010, of which one was unsuccessful. So we drilled a dry hole 3D test, that we had high hopes for but didn't pan out. We invested $39 million in the Gulf Coast in the first quarter, which is about 20% of our total capital.

Our 2010 Gulf Coast has been primarily near Beaumont, Jefferson County of Texas. That's our river port program we talked about where three gross, or 2.8 net wells have been drilled. We drilled the Jefferson Airplane #1, Jefferson Airplane #4 and their Nine Dragons #1. Jefferson Airplane #1 is on the Beaumont Airport. We have a 96% working interest in that well. We brought it on production in February. Jefferson Airplane #4 we also have a 96% working interest. It's being sidetracked for mechanical reasons. We got that well down, we found our objective as we had targeted. It all looked good but in the early production, we were gaining some sanding problems and we elected to go ahead and sidetrack that well.

Nine Dragons #1 is a well we've talked. We have a 85% working interest in there and drilled into a new reservoir in our Kirby Sand, which has been our main producing interval with our Two Sisters and our Garth wells. It was brought on production late March at a restricted rate of 8 million cubic feet equivalent per day, and we've discussed that in the past, we sell into a pipeline where we get a very nice liquids contract but that pipeline's currently full, so we're restricted to a allocated rate. All the operators that sell into that pipeline are sharing that allocation. Nine Dragons #1 production's expected to be increased to rates comparable to our Two Sisters #1 as pipeline capacity becomes available. The reservoir there looked outstanding. The open flow test showed that it is equal to its better than our existing Kirby producer. So that well ought to be a stellar well for us as the capacity becomes available.

We're currently drilling our [ph] Manyon gas unit number one, which is our Colorado prospect. It's near the Kirby prospect, reservoir comparable to our Nine Dragons or our Two Sisters wells. I can give you some late breaking news on that. We cut our objective yesterday and TD'd the well last night.

We should be logging that well with wire line logs over the weekend, but from mud log, every indication is that we came in structurally quite favorably. We see the sand we're looking for. So we're very, very encouraged by what we see. But again we'll get a wire line logout before we get too excited about.

We'll also be drilling some deeper targets on our river fork survey. We've talked about those two some of you. Those will be riskier projects that you physically control. We're quite excited about them but again, as we go deeper on that survey, nothing we've done up shallow de-risks the deep. We're back to ground floor high-risk expiration.

We have two rigs drilling in or near our Beaumont Project. We expect to keep through the year. You saw from our operations release that the Gulf Coast volumes that we've brought online this year we have some outstanding wells. Our Two Sisters #1 continues to produce handily. We're very, very pleased with the results we've seen in our Gulf Coast program and all of our areas. We like that diversity, we like that play mix, we like the product mix. One of the nice things about our program is having our exposure in the Mid-Continent, the Gulf Coast and the Permian. As the commodity prices change, we've been able to shift our program to focus more on our oil-rich plays by simply shifting our weight. We already have that exposure to the Permian. We'll have somewhere between eight and 10 rigs in the Permian here between now and the end-of-the-year. So probably half our rig fleets focused on the Permian. The remainder are really exploring where we have nice oil and liquids-rich targets throughout our portfolio. And with that, I'll turn the call over to Joe Albi, our Executive Vice President of Operations.

Joseph Albi

Thank you, Tom, and thank you, all of you for joining us. I'll go over our Q1 production results then update you on our 2010 guidance, touch briefly on our 2010 exploitation and production group activities, and then follow-up with a few comments on where we currently see service costs.

We had a great first quarter with success in each of our core areas. We reported, as Mick mentioned, a new record for the company, and our total net daily equivalent production averaging 584.5 million a day. That's up 25% from our Q4 '09 average of 467.6 million a day, and 20% from our Q1 '09 average of 489 million a day. All the while, we exceeded the top end of the guidance we provided in our last call where we issued guidance of 560 million to 575 million a day and beat it by nearly 10 million a day. So we certainly had a great quarter from the standpoint of equivalent production and we're proud of where we ended up.

As compared to Q4 '09, we saw production increases in all three phases; oil, gas and NGLs, and they were all in each of our core areas of activity. Our first quarter total company gas volumes of 391 million a day were up 18% for our fourth quarter average of 330 million a day. Our first quarter combined oil and natural gas liquid production of 32,280 barrels a day, was up 41% from our fourth quarter average of 22,935 barrels per day, primarily a result of increased oil production for the Permian and the addition of Cana NGLs.

With more liquid-rich gas coming from Cana, we are now breaking out as you've observed in what we reported, our NGL volumes when reporting our production. For Q1, we reported average net daily NGL volumes of 4,313 barrels a day, which accounts for about 13% of our total liquid production. So they're making their mark on the scoreboard.

As Mick mentioned, our Q1 Oil and NGL production now accounts for about 33% of our total net equivalent production and about 48% of our total net hydrocarbon sales, as compared to 31% of our production and 41% of our sales a year ago in Q1 '09.

As compared to Q4 '09, we saw production increases in each of our core areas of activity. In the Mid-Continent, our first quarter daily equivalent production of 239 million a day was up 16% from Q4.

In the Gulf Coast, our average of 190 million a day was up 64% from Q4, and in the Permian, our average of 155 million a day was up 7% from the fourth quarter.

Our Mid-Continent region still makes up the majority of our production at about 41%, followed by the Gulf Coast now at 33% and the Permian at 26%. Over the last year, the success of our South Texas program has increased the contribution of Gulf Coast production and really put it on the map relative to total company production from 13% in Q1 '09 to 33% in the first quarter of 2010.

Cana and South Texas have been the primary catalysts as we've talked about so many times. For our production growth over the last year, during Q1, Cana delivered 67 million a day to our bottom line and that compares to 34 million a day in Q4 and 20 million a day a year ago in Q1 '09.

In South Texas, the wells we've completed near Beaumont, those wells alone just hit the books in July of last year and accounted for 149 million a day of our first quarter production, and that compares to the 71 million a day in Q4 and 29 million a day in Q3, so quite a boost in both to those two areas.

Our solid Q1 volumes and continued success in each of our core areas, our current model for guidance projects an increase to the 2010 guidance we provided during our last call, particularly in our full-year guidance as you'll see. Although we still anticipate a portion of our new South Texas production to experience declining during the year as we've talked about, our current projection calls for a big bit more mid-to-late year production support from our active drilling program and it's more so than we projected last quarter. That's a nice bump in our full-year projection.

For Q2, we're projecting our total company production to average in the range of 570 million to 600 million a day. That's a 26% to 32% increase from our Q2 '09 average of 453.9 million a day.

And our 2010 full-year production guidance is now in the range of 570 million to 595 million a day. That's 23% to 29% increase from our '09 average of 462.9 million a day and an approximate 30 million a day increase from our previous guidance of 540 million to 570 million that we've provided in our last call.

Incorporating into both our Q2 and full-year guidance projections, is an estimated 7 million to 11 million a day of an impact on Q2 production that we anticipate has either incurred, or will be incurred for plant and/or facility maintenance repair items planned here in the second quarter.

With our projected 2010 activity in Cana and the Permian, along with the recent amendment to our gas sales contract allowing for the reporting of NGL volumes in South Texas, we anticipate liquids to continue to play a significant roll in our 2010 production and we'll likely see the increase in our oil and NGL mix get up to a level of about 35% by the end of the year.

Shifting gears over to our Production group, during Q1, the group continued its focus on improving its efficiencies in our core operations, primarily at the field level. The results of which carried over into our Q1 LOE. Our Q1 production costs totaled $42 million. That's down 17% from our Q1 '09 average of $50 million. On a dollar per Mcfe basis, our Q1 '10 lifting cost of $0.80 was down 30% from our Q1 '09 average of $1.15.

Some of the larger cost reductions we've seen over the year have come from power, fuel, compression, saltwater disposal and well servicing, where we've seen anywhere from 12% to 39% decreases from 2009 levels.

Although we believe there's still some areas where we can cut cost, our guidance of $0.80 to $1 for the year certainly suggests the likelihood that most of our significant cost items have most likely bottomed out.

On the exploitation side, most of our Q1 activity was centered on lift projects, particularly to our new wells trying to get our IPs up front of us as much as we can. And we also underwent a handful of re-completion projects, primarily in Southeast New Mexico.

Through March, we deployed about $8 million towards the program and the planned increase here starting in the second quarter and re-completion and infill drilling activity primarily in the Permian and Mid-Continent. We are expecting to pick up the pace of capital spending, still seeing ourselves falling in the lower end of our guidance, which account for $50 million to $75 million by the end of the year. And that's right on top of about what we did in 2009.

On the service cost side, the executive summary is that although that we're seeing cost escalations in some items during the quarter, our operating efficiencies have really helped to keep our drilling and completion costs in check. Since Q4, we've seen a slight increased cost pressure in rig rates, which depending on contractor, rig and area, have gone up anywhere from zero to 5%. We've seen 15% to 30% increases in items such as bits, directional and stimulation cost, and we're now seeing signs of increased cost for steel and tubulars.

Frac costs are a bit of a wildcard for us right now, with cost pressures seemingly related to crude availability and the service companies strategically locating themselves in basins that for the most part get their equipment in business model.

In Canada, we've kept up with our seven rigs, running one frac fleet and have experienced for the most part relatively flat pricing. In the Texas Panhandle, our current activity have seen flat pricing as well. But in areas like southern Oklahoma in the Gulf Coast, we are seeing delays and cost pressure due to limited crew availability and in the Permian, we are planning our frac dates well in advance, which has helped us somewhat from a timing standpoint, but we've still experienced some backlog and are seeing some cost increases, which depending on the size of the job have gotten upwards of 20% to 30%.

As I've mentioned, we've been able to offset the increases we've seen with operating efficiencies. Our Cana wells are still at $7.5 million to $8 million and are in check with those of January 2010, while improved efficiencies in our Permian drilling program have really helped to offset the cost grid we've seen there, particularly since the beginning of the year.

As an example, 6,000 frac vertical library Paddock well is now asking for $1.5 million versus $1.8 million that we were seeing in late 2009 and early 2010.

Our New Mexico Bone Spring horizontals, which Tom touched on the good success we're having there, they're running around $3.6 million or $3.7 million. These are at or just below the levels we saw earlier in the year.

So we've done a great job improving our efficiencies and doing what we can to keep our costs down. Our goal obviously, is to continue to work the cost side of the equation as we work the program forward and provide the lower costs that are needed to make the programs obviously more profitable. With that, I'll turn the call over to Paul.

Paul Korus

Thank you, Joe. With healthy oil prices and gas prices that we can at least make money at, combined with across the board lower costs, we had outstanding financial results for the quarter.

Our news release, as well as Mick's comments outlined those accomplishments. So in the interest of time, I think I'll just direct my attention toward our guidance for the rest of the year.

We are against this backdrop of weak and still very uncertain gas prices. So at this point, we have chosen to not increase our overall capital program from the plans that we made for ourselves as we've entered the year. But due to better than forecasted results in Cana, Granite Wash, the Gulf Coast and the Permian Basin, this has caused us to increase our full-year production guidance by about 5% at this time.

With the full year midpoint expectation of about 585 million cubic feet equivalent per day, you should notice that we are basically modeling a flattening of output for the remaining quarters of this year at our current rates. Having said that, I'd be quick to point out though that we did under spend our cash flow by about $100 million in the first quarter and, depending upon where prices land for the remaining months of this year, we have a lot of flexibility to potentially increase our capital to something that might be closer to cash flow which could entail another $100 million or $200 million.

But our approach has normally been and it will continue to be, to be cautious on that front. We'll save some dry powder for next year. We are already thinking about where we'll be next year. And normally, we seek to achieve something that approaches double-digit production growth year-over-year. So we'll keep you posted as the year progresses on that front.

Other things related to guidance, we do outline what our per unit cost guidance is in the news release. One item that we don't mention in there is where we see income taxes. We are making a fair amount of money in this environment, so we will be contributing to the reduction of the national debt.

So we would expect to owe in excess of $100 million of taxes for the year, which means that as you model our cash flow, you should probably assume that about 30% of our tax provision will be current with about 70% deferred. With that, I believe we are ready to entertain questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question is from Gil Yang.

Gil Yang - BofA Merrill Lynch

When you talk about the pipeline capacity freeing up in the Gulf Coast, can you talk about how much of that free up is from pipeline expansions versus decline in the existing production from the other wells?

Operator

[Operator Instructions]

Gil Yang - BofA Merrill Lynch

In terms of the Gulf Coast, are you talking about Nine Dragons being able to ramp that volume up as infrastructure comes available, how much of the infrastructure ability comes from expansion versus decline in the other wells in the Gulf Coast?

Joseph Albi

Gil, this Joe Albi. The first comment I want to make is that the Operations group is not responsible for the polycoms here. That's an IR deal, right. The Nine Dragons is set up now where we can start moving gas to one of either two different purchasers, one of which we can get a better price on the liquids than the other, and I the anticipate that by the end of this month, that well will be back up to rig similarly with the Two Sisters and hopefully that does answer your question.

Gil Yang - BofA Merrill Lynch

And then what happens when Jefferson Airplane comes online?

Joseph Albi

Well, we'll sell the gas. You mean the #4?

Gil Yang - BofA Merrill Lynch

#4.

Joseph Albi

The Nine Dragons is going into that same system as #4, and that's where we could sell excess. When 4 comes on, we can sell that excess to the other party that is not in a competitive situation.

Gil Yang - BofA Merrill Lynch

Nine Dragons would not have to ramp down as Jefferson Airplane #4 comes online?

Joseph Albi

That's correct, that was the reason we put that additional line on.

F. Merelli

Yes, we will have the option to flow it unconstrained. We have a split connect going to two lines and we'll just manage our production stream as we see it most prudent. We're obviously split connecting where we think in a strong competitive situation. And then for where we're not, we're looking and seeing where the most present value lies.

Gil Yang - BofA Merrill Lynch

And what is the anticipated turn on date for Jefferson Airplane #4?

Joseph Albi

Well we're right now shooting for the 1st of January.

F. Merelli

We're still drilling the sidetrack.

Gil Yang - BofA Merrill Lynch

And how much of the competitiveness you'll lose because of the delay in turning that well on?

Joseph Albi

Well we lose a fair amount. We're getting drained across the lease line and we're in a competitive reservoir situation. There will be a total of 10 straws in the tank. We're trying to get our gas out just as fast as we can as are the competitive operators.

Gil Yang - BofA Merrill Lynch

And is there any chance that the mechanical issues or reservoir formation issues, versus things that happened down the hole when you put the hole into it?

Thomas Jorden

We debated that loudly and strongly here. We do not think so. We think it was mechanical. We didn't see any difference between either the rock in any significant nature between the other wells. So we're quite hopeful that we're going to get the sidetrack down and produce it as with our other wells. You want to comment on that, Jo?

Joseph Albi

We're also waddling draw down that we're putting on these wells to make sure that we're not pulling them too darn hard.

Gil Yang - BofA Merrill Lynch

You mentioned the Mid-Continent backlog, you're working hard at it. Do you expect to bring that down to normal levels and what does normal mean?

Thomas Jorden

Well, ideally, we'd like to have zero backlog but it's just a question of frac or availability and how soon we can do it. I will say this: Our conserve is doing an absolutely tremendous job in terms of getting on these wells and completing them quickly. I don't have in front of me when we'd be totally caught up but our goal is to catch up.

Gil Yang - BofA Merrill Lynch

Last quarter I think you had 11 coming out of the quarter and this quarter, have 14, so would you hope to get down like the 10 or 11 range, something like that?

Joseph Albi

Yes it's a function of the timing of our wells. We have our pack project coming down the road now. That's going to be a fair number of fracs all in one location. So there are some distinct advantages we see that to work in one crew, and that is if they're familiar with their operation. And as long as we can stay with the seven rigs and even gain on them, that's going to be the avenue that we're going to keep running down.

F. Merelli

And I think the pad thing is we're going -- obviously we've delayed that until we get all the wells drilled in there, so that's an automatic delay.

Thomas Jorden

They're before that backlog at the pad project, so that's kind of a separate case.

Operator

Your next question is from Nicholas Pope.

Nicholas Pope - Dahlman Rose & Company, LLC

You all discussed in the Cana I guess it's kind of the distinction between the core and what you are considering the fringe. I guess when you look at your acreage position that you all discuss, I just wanted to clarify, is that primarily...

Thomas Jorden

I think you're asking to the extent our acreage is core and non-core. Yes, first off, I'll just define. Different people have different definitions. When we use the word core, what we mean by that is acreage that's clearly richly economic at today's parameters. And that would be today's commodity pricing, in today's cost structure, at the rates of gas and oil they would produce. So in the main Cana play we've talked about, we are sitting somewhere plus or minus 100,000 acres. If you take the overall play that I think a lot of people talk about, which would be from Dewey County down to Grady County, and what people would say is the Anadarko Woodford Shale, we have about 130,000 acres. Of that, if you held my feet to the fire, I would say that probably 50,000 or 60,000 of our acres are richly economic, and we're working through the rest. The core continues to expand and we haven't defined that part of it that we think is richly economic. It's really defined by drilling.

Operator

Your next question is from [ph] Brian Tuzma 53:17.

Unidentified Analyst

And actually, I just wanted to clarify, you got 100,000 in the core Cana and you're saying another 130,000?

Thomas Jorden

Well, Brian, the Cana play is expanding. And so it's important that we make a distinction here. When we have talked about Cana, the map that I put up on the table when we're our running our seven rigs, is where we have somewhere in the high-90s to 100,000 net acres. So that's what we talked about Cana up until we've had a couple of new drills to expand the play. Those of you that follow the play are aware of the continental well up in Dewey County. There's also been drilling down in Grady County. So if we zoom our map out and we say all right and that we've extended those bookends to the extent that Cana is redefined, we have 130,000 net acres in that total redefined area. Now are we running seven rigs on those 130,000 acres? No, we're not. When we talk about Cana and our development program, we're still back to talking about our core position of roughly 100,000 acres. So if the question of how much of that is core, I would say about 2/3 of it today we think we've established is economic at today's go forward parameters, and it's getting better. The other third is in play. We're drilling confirmation wells. Some of it is undrilled, and we're just not willing to call it core to the extent that we define core. And I'll just say once again, we define core as that acreage that we think is fully, richly economic and we've given a green light to development mode.

Unidentified Analyst

I also wanted to ask in the Permian, you guys had decent some growth there quarter-over-quarter, and activity doesn't look like it's slowing down. So is there any reason why the growth is going to slow down? Or do you see that type of growth rate continuing?

Thomas Jorden

I wouldn't see us slowing down. We certainly have opportunity teed up that if we were to increase our capital I think the Permian would be the lion's share of that increase. We're seeing a lot better results than we'd anticipated. I mean, certainly some of our most recent wells are at the high side of our own pre-drill forecast. So yes, I think, we certainly have the opportunity in the wherewithal to increase our Permian activity. We're not going to slow down.

Unidentified Analyst

And could you comment a little bit more on the Granite Wash? I know you guys have a couple of locations teed up right near that good well and you've got some other locations which you previously said, you didn't think was necessarily going to work horizontally. Has your attitude changed at all, or is that still how you guys feel?

Thomas Jorden

Well, Brian, we've discussed that. That Granite Wash well of ours is -- certainly came in on the high side of our expectations. That's our acreage block. It's southernmost [ph] Tenfel County. It's closest to the Wheeler County stuff that has been the headline wells. We were presently surprised when we brought that well online and that produced at the kind of rates it did. So we're currently drilling an offset. There are a couple of other operators drilling immediately offsetting our acreage and we have enough acreage as to offset that well probably six or eight additional locations. We have a Granite Wash portfolio that we've exploited for a number of years and that's a horizontal set. We'll be drilling horizontal Granite Wash wells but we don't see them as the headline makers that we've talked about. So I think our running room in wells that we would hope would be comparable to that half well, is six or eight wells and then we'll see what we've got. Jim, but I want to reiterate that's probably anywhere from a third to 40% working interest in those wells.

Unidentified Analyst

And I just want to make sure that I heard you guys right, did you say anything in terms of '11 and what kind of growth rate you guys are projecting for '11?

Joseph Albi

Brian, this is Joe Albi. We have not done any detailed modeling on 2011.

Unidentified Analyst

Are you planning on, like double-digit growth or, I guess I don't want to put you on the spot if you're not willing to say that but I mean is there any type of outlook there?

F. Merelli

Well, average-wise, we are the high single-digits or low double digits. We've had a lot of growth this year that had to do with the fact that we didn't have much growth the year before, and we've got a lot of projects teed at. So I really feel good about us being in the high-single digit and maybe better. And we've got an awful lot of things to do but a lot of that's going to depend on what gas prices and all of that do. We're fairly strong financially and we have a ton of opportunity, so we can drill like hell and make our production anything we want it to be. But the question as far as the gas is concerned, is how do we want to approach these projects and how fast do we want to go. We're going fairly fast right now, so we'll see how that works out. And in terms of the oil plays, it lines up. We've got an awful lot of things to do. We've got a lot of things on the board but it winds up being kind of people intensive and so we have to see how fast can we get those things done and make sense out of it so that we don't outrun ourselves. So I feel good about '11 for whatever that means, and that's about all I can tell you.

Operator

Your next question is from Mitch Wurschmidt.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

Could you talk a little bit more about in the Cana what your ER expectations are right now in some of the recent wells? They look like they performed pretty well, in comparison to those. And just talk about also the amount of liquids you're seeing in a lot of those wells?

Thomas Jorden

This is Tom, Mitch, Cana is several different plays, I mean, it's really something we don't paint with a single broad brush. In the heart of the heart where most of our drilling has commenced, if we drill a new well today, we're going to model that well at about 8.8 BCF wet gas and then a certain amount of condensate and then a certain amount of natural gas liquids. I will say that the EUR, when we factor in the process gas, so we look at their wellhead condensate, the processed NGLs and the methane stream. In the heart of the heart of the play, we're going to be somewhere 11 to 12 BCF equivalent for a new well. And we think that's defendable and repeatable given our new completion techniques. As we look at the parameter of the play, we go into some more liquids-rich areas, and particularly as we move to the east, we get liquids-rich. To the far east of the play, our current model is about a four BCF equivalent well but of that 4 BCF, about 0.5 million barrels of that are liquid. So the economics there look very, very attractive to us. In the northwest of the play, we're probably down to about a 6 BCF gas stream and then by the time we factor the liquids, we're 8.5 to 9 BCF equivalent. As we goes straight west, we go deep, it gets to a dry gas stream. We loose our liquids and we don't know yet, we're drilling an oil now that's our deepest test in the play and we need to get that well completed and evaluated. So I've danced around a lot of data here but, Mitch, our results are somewhere between 4 and 11 to 12 BCF equivalent, but that all looks very economic to us because that low-side number has a very, very strong liquid stream. We really like our results so far. We're continuing to be pleasantly surprised by the way this play is developing.

Joseph Albi

This is Jo Albi. One other thing I'd like throw out there. Of the 67 million equivalent that we averaged in Cana during Q1, there was about 3,340 NGLs associated with that. And that makes up about 75% of our total NGLs streams. So that should give you an idea of the impact on our total NGL production.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

On the rig count, when you break up the seven rigs, how are those allocated as sort of a different area, Tom?

Thomas Jorden

Well, we have two that are working in the northwest of the play that I would say is somewhat experimental. I mean we're very confident it's going to be nicely economic but it's kind of an extension of the play. We have one rig running in the deeper part of the play where we think it'll be a dry gas stream. We haven't drilled out there yet and we're very optimistic. But we also know that it's going to be dry gas, so it's going to need to be a pretty strong methane stream. We have a well drilling in our southernmost area, that's a well that's east of our Straight Arrow well. That's another test in our southern area. And then we have three rigs running more in the heart of the core play. So we're kind of multiplexing our program between core acreage and when I say core again, I mean the best of the best and then trying to extend that core with additional drilling. As so many others, we do have a lease expiration issue we're having to manage. About half of that 100,000 acres that we say is in the heart of the play is held by Production and the rest of it were drilling preferentially to hold acreage.

F. Merelli

That's all within a plan that we're able to accomplish.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

And also on your year-end exit rate kind of where current production, or work production was in the first quarter, are you guys thinking 100 million a day by year-end, you might want to up that or kind of think you'll get there earlier, what's you're thinking on that now?

F. Merelli

We're thinking still 90 million to 100 million a day right now.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

On Nine Dragons, can you talk on the size of that prospect and sort of how many development wells it might take to develop that? Or I should say the structure?

Thomas Jorden

Well the size is something that we are still debating internally. I will say this. We have the opportunity for offset wells to that. Certainly one for sure and two for probably and we'd like to produce a little while. We're not in any serious competition. There is a well down dipped from us that's on production in the same reservoir but there, they have some issues. They can't pull that well very hard. So we're sitting in a position where we have the luxury to watch and manage that reservoir prudently. So we're going to get that thing on production for a while and watch it but yes, the answer to your question is we have one or two offsets to that we could drill if we choose to.

Operator

Your final question is from Jeff Robertson.

Jeffrey Robertson - Barclays Capital

Tom, or Mick, can you all talk a little bit about capital in the event that you kind of went toward the high end of your budget? Is that based on cost? Or where you think costs may settle out or just based on where you think you'll end up drilling wells?

Thomas Jorden

It's Tom. I'll take a stab at it and then Mick will correct me. We're committed to disciplined investments. And people ask about production and that's a good focus for a lot of people but we still believe that production growth is a consequence of sound, prudent capital investments and not a goal in itself. So we are very careful in what projects we choose to fund this year, next year and beyond. We do have the inventory, if we wanted to increase that capital and if Mick came to my office and said, get her to $1 billion, we have the inventory. We've got it teed up. But we're watching service costs, we're watching our results, we think a pace of development in our current $600 million to $800 million of announced capital is good for us. We're building opportunity on some plays, and we are trying to really invest our capital wisely, get good rates return and so far so good. Now we'll probably pick up the pace a little, I would guess in the Permian here, over the remainder of the year. But it's only going to be because we have investment opportunities that make sense, not because we have opportunity for production growth.

F. Merelli

The only thing I'd say, we've been here before, Jeff, and I don't know where we're going to end up at the end of the year because we may take on more rigs, or may do other things. But if you just ran the numbers and said well heck, you've got $60 million now cash and no bank debt. And if we wind up the end of the year and you say, well heck that might be $200 million, or something like that. We've been there before, and when we've been there before, we've always done something. And last time we were there, we bought our Cana acreage. And that's something that -- we've got our nose in the wind and looking for things and so it's hard to say but we probably won't sit on it all that long. We'll do something with it.

Jeffrey Robertson - Barclays Capital

And a follow-up, Tom, just in the Cana at the pace of activity you're going currently, is that about right given the learning curve that you're on and is there a point later this year, or do you think you would be able to expand that?

Thomas Jorden

Well, we could expand that any time, Jeff. We have the land. We have the opportunities. One place that is a hinge focus of ours is that Southern block. We've talked about that in the past. If we have some success down there that tells us that that is part of our expanding core, we'll probably mobilize some additional one, or two, or more additional rigs down there. We do have some explorations that we're facing. We're in the process of handling that from a lease renewal situation. But if we had some encouraging results from drilling, we'd probably ramp it up a little there. I think we're at the right pace. We're still spending a lot of our energy debating the core science. And that's been to the credit of our team. They are very deliberate. They're very intellectually honest. We look at our data and we optimize. And I think that while we're still trying some things that we think have the potential to work, we need to be careful how fast we go. We have been there before, where we've learned some lessons in parallel and made mistakes simultaneously. We kind of like learning things serially.

F. Merelli

And not the least of which involved in all of this is our pilot to determine what the ultimate spacing in some of this area is going to be. It has big ramifications to production capital and everything that we're doing. And we don't know how that's going to impact us. So you've got a big potential swing out there and we're in a situation in Cana with almost in a lot of that area, we really full good about it. But we feel good about it on 160s. And if it turns into 80s, then that will just be that much better. But we're not planning on that but we realize that we have to determine early, as early as we can, what the ultimate spacing is going to be there. And hopefully, I don't know what's going to come out of that, if we did a nice definitive answer that it'll work on 80s or it won't, that'll be helpful to get it answered. But we don't know any of those things right now and so stay tuned, and we ought to something by mid-summer, or late-summer. That's what we're kind of planning on.

Operator

Your next question is from [ph]Sharma 71:22.

Unidentified Analyst

This is [ph] Ano Sharma 71:46] from Pritchard Capital. I had a question on your realized prices on gas. It looks like you guys had pretty impressive gas prices realization. Can you please just reflect upon that? I mean was it primarily driven by higher BTU content on your market gas stream? If so, what your average BTU would be in the marketed gas stream?

Mark Burford

Yes. Hi Sharma, this is Mark Burford. Yes, that's right. The premium into NYMEX that we did still raise in the first quarter it still resulted a high of liquids and a high BTU content gas. We had sort of broken out the NGLs in one play, the Cana as you saw in the press release but we still have a lot of liquids-rich gas in the Gulf Coast, Texas Panhandle, southern Oklahoma, Permian. So those areas are still -- the revenues from the NGLs are being booked into the gas revenues enhancing the realizations. So we expect due to the extent that we still have contracts for the volumes transfer [indiscernible 82:49] show the NGL volumes in gas and you had to tie. Oil to gas ratio will still be showing good realizations relative to NYMEX.

Unidentified Analyst

So you are a lot breaking out all the NGLs yet, only partial NGLs separately?

Mark Burford

That's right. Only in those cases where we actually have title trans occurring at a tailgate of the plant and that's the way the contract's written. Then at that point and those volumes we'll report the NGLs separately.

Unidentified Analyst

So it's the blended price of the NGL and gas in that case, okay.

Mark Burford

That's right.

Operator

Your next question is from Eric Hagen.

Eric Hagen - Lazard Capital Markets LLC

First, can you tell us how much acreage you have in the Avalon, are you willing to do that, or not?

Joseph Albi

Well, I don't know where the Avalon is. I mean I can tell you that we have a property a wide city in Eddy County, that's where we have about 40,000 acres. That's where we've drilled our Avalon horizontal. But we don't know where the play is going to be, Eric. I'm really not trying to be coy. I think we have good exposure. There's drilling around us but I would not encourage you to take that acreage and divide it by some spacing and call that our exposure to it. That's certainly not the way we do it. But we have a nice position and if the economics of that play looks strong to us, I think we'll have some good exposure to it.

Eric Hagen - Lazard Capital Markets LLC

Second question is on the Permian as well. What's the kind of constraint on ramping up rigs there? I think at one point, you had, I believe like 17 rigs running in the Permian. Where do you think the rig count could go in 2011?

Thomas Jorden

We haven't reported our 2011 plans yet. We're going to be careful. We certainly have the opportunities to get back to that level of drilling but we're committed to being careful on our cost containment. We want to do good science. We want to really study it and in 2008 when we had 17 rigs running, there was some economic waste there. If I had to do it over again, I probably would have let a couple of those rigs go and spend more attention optimizing our completions, focusing more on drilling costs, making sure that we weren't wasting some things. So in answer to your question, I would anticipate our 2011 rig count will be somewhere between our current eight to 10 and that 17. But I can't tell you where between those it's going to fall.

Eric Hagen - Lazard Capital Markets LLC

The final one was for Paul. It seems like with no bank debt and all this cash flow building, he's spending a lot of his time putting in hedges. I just wanted to see if I can get any thoughts on your hedge policy now, Paul, how you're thinking about next year? Do you have any target in terms of where you want to end up on that?

Paul Korus

Well, when we look at hedging, we put it a broader context of risk management and then of course, it's what does that mean. And we really view that as kind of a capital program for next year. So the tools we have to execute a capital program next year that's as large as this year's or is bigger, our cash that may be on hand at the end of the year and then depending on what price deck that you use, that can be anywhere from non to $300 million. So that's one tool we have. The other tool we have of course, is an undrawn credit facility. And then the last tool is of course, going into the hedging market. And then you have to factor in our appetite for risk on hedging. If you examine what we have done in the past and even the callers that we put on here recently during the first quarter for oil, we prefer white collars. We don't like to lose money if prices go up unexpectedly. We can debate the wisdom of that, but that is the way we view things and of course, we want a floor that we think is acceptable. So you see we put in some $65 floors with ceilings that are north of $105. We've done a total of 6,000 barrels. By the end of the year, we hope to add another 68,000 barrels, so that basically, we would have approximately half of our oil production hedged for next year. On the gas side, the swap market in the Gulf Coast is around 550, Mid-Continent, it's low-5s our preference has been for $5 floors with some ceiling. So basically all we can do is swap something around five, or little bit higher in Mid-Continent. And that just doesn't fit the risk profile that we like to have. Now I'll be quick to add, we change our mind, but that's where we are right now. So we have not added any hedges on the gas side yet, just because we don't like where the market is. And we have the other tools available to us to protect our sales for another robust capital program next year.

Operator

At this time, there are no questions. Do you have any closing remarks?

Mark Burford

Just thank you, everyone for joining us today and we apologize for the technical difficulties we had but that's the sticking with us on the call. And we look forward to keeping you posted our results in the future. Thanks, again for joining us today. Hope to see you soon.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Cimarex Energ Q1 2010 Earnings Call Transcript
This Transcript
All Transcripts