SM Energy Company (SM) Q2 2008 Earnings Report, Transcript and Summary

Good morning my name is Michael, and I will be your conference operator today. At this time, I would like to welcome everyone to the St. Mary Land & Exploration Second Quarter 2008 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions]. Thank you. I would now like to turn the call over to Mr. Brent Collins.

Thank you, Michael. Good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's second quarter of 2008 earnings conference call. Before we start, I would like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance. These statements involve risks, which may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For discussion of these risks, you should refer to our... to the information about forward-looking statements in our press release from yesterday and the risk factor section of our 2007 form 10-K/A. We'll also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliations of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release yesterday. Additionally, we may use the terms probable, possible and 3P reserves and estimated ultimate recovery or EUR in this call. Probable reserves are unproved reserved, which are more likely than not to be recoverable. Possible reserves are less likely to be recoverable than probably reserves. Estimates of probable and possible reserves, which may potentially be recoverable through additional drilling for recovery techniques are by their nature more uncertain than estimates of proved reserves, and accordingly are subject to substantially greater risks of not actually being realized by the company. EUR means those quantities of petroleum, which are estimated to be potentially recoverable from an accumulation plus those quantities produced there from. The company officials on call the call this morning are Tony Best, President and Chief Executive Officer; Jay Ottoson, Executive Vice President and Chief Operating Officer; Dennis Zubieta, Manager of Reservoir Engineering; Mark Solomon, Controller, Mark Brennan [ph] Senior Attorney, Matthew Purchase, Budget and Planning Director; and Brent Collins, Director of Investor Relations. I will now turn the call over to Tony.

Good morning. Thank you for joining us this morning for our second quarter earnings conference call. Yesterday we released our quarterly earnings press release and financial highlights. I will provide an overview of our year-to-date performance as well as a few thoughts on St. Mary's transition efforts and direction followed by comments on our second quarter financial results. Jay Ottoson, our COO will then provide some comments on our current operations, and then I will wrap up with some concluding remarks. Looking back at the first six months of 2008, we've had a very strong first half. We are executing on our number of goals we set out on our business plan at the beginning of the year. Production is exceeding our plan and cash flows are strong due to the better than anticipated production growth and higher commodity prices. We have made great strides in hiring and getting our organization staff for growth. Most importantly, we have been working to improve our portfolio so that we can grow faster and more efficiently. Divesting in non-core assets and then still in a culture of operational excellence have been and will continue to be key factors in helping us move towards that goal. Moving to the financials, I am going to focus my remarks on the second quarter's results. Production for the second quarter 2008 was 28.6 Bcf equivalent, which beat our guidance for 26.0 to 27.0 BCFE. Production was up 10% year-over-year, and if you adjust for the significant divestiture, which closed in the first quarter of 2008, our production actually grew 15% year-over-year on our retained properties. Reported net income for the second quarter was $33.6 million. Diluted earnings per share for the quarter was $0.53 per share. Adjusted net income, which adjust for nonrecurring and significant non-cash items was $80.8 million or $1.29 per share, which is inline with the First Call estimate. There are two significant adjustments this quarter: the non-cash charge related to the change in the net profits plan liability and bad debt expense resulting from the bankruptcy of SemGroup, a company which purchased a portion of our crude oil production. The after-tax adjustment related to the NPP liability was $43.3 million or $0.69 per share and was the result of an increase in forecasted prices for oil and gas as of June 30th. The after-tax adjustment related to the SemGroup bad debt expense was $6.3 million or $0.10 per share. I'll discuss the SemGroup issue in a more detail in a moment. Discretionary cash flow for the quarter was $211.9 million or $3.38 per diluted share, which is $0.30 higher than the First Call estimate. Lease operating expense including transportation was $1.63 per Mcf equivalent compared to $1.37 year ago, and was higher than we had guided for this quarter. In the second quarter, we have several unplanned major well workovers, one at the Judge Digby Field in the Gulf Coast and a couple at the Constitution Field in Southeast Texas; that drove LOE up for the quarter. Like others in the A&P sector, we are also seeing increases in recurring LOE that we believe are being driven by strong commodity prices, high levels of activity and some limitations of services and by supply firms to keep up with demand. Production taxes for the quarter were $0.95 per Mcf equivalent and were driven up by the strong commodity prices that we saw in the quarter. DD&A increased year-over-year to $2.67 per Mcf equivalent from $2.10 per Mcf last year. Directionally as higher F&D properties have become a larger portion of our production base, DD&A has gone up. G&A for the second quarter of 2008 was $0.77 per Mcf equivalent, which was slightly below guidance for the quarter. G&A increased from $0.62 per Mcf equivalent in the second quarter of 2007 due primarily to cost associated with higher headcount and higher cash payments from the net profits plan year-over-year. We noted in our press release that we had two exploratory drive holes in the quarter. These were non-operated wells in the Floyd Shale in Mississippi. We had an impairment on proved properties in the quarter related to two wells, targeting the Glen Rose formation in East Texas. After promising initial results both wells began producing large amounts of water and became non-commercial. The non-cash charge related to the increase in net profit plan liability is the result of the significant increase in forecasted oil and gas prices between the first quarter and second quarter of 2008. The value of this liability is significantly impacted by commodity prices. However, I would note that oil and gas prices have fall back meaningfully since the end of the quarter. We recognize $9.9 million before tax in bad debt expense in order to reserve the receivable from SemGroup for June 2008 production. Our maximum additional exposure is $6.8 million before taxes for amounts related to oil volumes sold after the quarter end. These amounts are not material to our liquidity or our overall financial position. That said just because we have established reserves for these receivables, does not mean that we won't be paid or that we have stopped pursuing our claims or payments. We are continuously monitoring the bankruptcy process, which has been very dynamic and are determining the best course of action for the company. Clearly the SemGroup bankruptcy is a very unusual situation, and one that we feel is highly unlikely to recur with that was appropriate to make this adjustment to our adjusted net income. In summary, we had a solid second quarter, and we will be certainly happy to answer any specific questions you may have related to our financial results in the Q&A segment of the call or you may get with Brent offline afterwards. I'll now turn the call over to Jay for his overview of operations. Jay?

Thank you, Tony. Company wide, we are currently running 16 rigs. I'll briefly cover the areas where we are focused and making most of our capital investments. First in the Woodford shale, we continue to see positive results. The average EUR for our last ten wells with meaningful production history is approximately 3 BCFE, which is an improvement from the 2.7 BCFE average we've been disclosing recently, and fairly better than the results we saw on our ten wells. We have two operating drilling rigs running there reached currently and we'll be adding a third rig in mid-August. We also continue to be a leader in drilling efficiency in the play. In East Texas and North Louisiana, we have two operating rigs running that are focusing on a horizontal program consisting of James Lime and Cotton Valley wells. Necessarily, the country is also where our Haynesville shale acreage is located. We disclosed 50,000 net acres that have potential roughly 10,000 of which is in the Louisiana, and the balance of which is in East Texas. We are in a process of building location for our first horizontal Haynesville well in Louisiana. And we'll begin drilling there by early September. The Haynesville is an exciting play, and we are happy to be in it. I should point out that we are already growing production 35% a year year-over-year in the ArkLaTex with just our Cotton Valley and James Lime programs. So that Haynesville is another adder. On the North Dakota side of the Williston Basin, we are currently drilling our second horizontal Bakken well in Burke County. Our first horizontal well in Northern Mountrail is currently completing. The pilot hole for that well was drilled through the Bakken and our logs confirmed the presence of perspective Three Forks formation in that area, which is additional upside for the company. We are also completing our first horizontal Bakken re-entry well in McKenzie County. We recently entered into an agreement to purchase roughly 6,000 net acres in Eastern McKenzie County, and 18,500 net acres in northern Divide County. We believe this acreage has significant potential for the Bakken and the Three Forks. Williston is an active place right now, and we have a lot of exposure there; more than a 150,000 net acres between our legacy owned Helm Cooly Bar Trend [ph] acreage and the new acreage positions that we've been building over the last year in North Dakota. I'll note that the Williston Basin is the region, where we have had the most exposure to SemGroup as they were a marketer for a portion of our crude production there. Clearly there are number of things to be worked out through the bankruptcy process and we continue to monitor those cases clearly... closely. While our financial exposure SemGroup isn't material, there are scenarios, where we could see curtailment of our production ... of a portion of our production in the Williston Basin. Currently, we are moving all our production, but there could be some temporary production impacts for some producers related to the bankruptcy. In the Wolfberry tight oil program, we have four operated rigs running at Sweetie Peck and our partner's operating two rigs at Halff East. We are continuing to drill and evaluate 40 acre locations in three pilot areas at Sweetie Peck. The program is working great. We probably don't talk about this often as we should. It's an oil project, has very good economics in the current environment and there is additional upside potential. In the Maverick Basin, we have two rigs running in our Omo shale [ph] gas project. As many of you know, we are also participating with the partner in a program to test the Pearsall and Eagle Ford shales in the Maverick Basin in South Texas. We are currently in the process of drilling several horizontal reentries prior to starting on some grass roots horizontal well tests. We don't have any completion results yet. If this program is successful that exposes us to a large acres position, potentially 75,000 net acres at a very cost of entry. On the capital and guidance front, I appreciate that many of you want to know what we are forecasting and guiding for the second half of the year. We have a regularly scheduled Board meeting this Thursday, where we'll be discussing our capital investments for the remainder of 2008. Unfortunately earnings season and the Board meeting didn't line up this quarter and we won't be in a position to provide capital and financial guidance for the remainder of this year until after that Board meeting. We plan to update you on that by the end of next week. With that I'll turn it back to Tony.

Thank you, Jay. A couple of closing remarks before we turn the call over for questions. As many of you probably saw yesterday morning, we have announced that we have hired Wade Pursell as Executive Vice President and Chief Operating Officer. Wade was previously CFO at Helix Energy Solutions in Houston. He brings a lot of transactional experience, as well as the deep financial and accounting knowledge to the table, and he will be a key contributor in moving St. Mary to next level. He'll be joining the company in early September. St. Mary has been quietly, but effectively transforming over the past 18 months, becoming a more resource play focus company with increased growth potential, higher efficiencies and a deeper inventory of repeatable projects. In fact, we are now active in three of the top six resource plays in the country: the Woodford, the Bakken, and now the Haynesville. I believe we don't get enough credit for that or valuation. And currently, we have had a great success recruiting new leadership and talent to both our management team and our technical and professional staffs. Our management team is focused on delivering value for the stockholder. And the new compensation plan recently approved by stockholders in May clearly aligns our management and employees with the stockholder. I am excited about where we are and a lot of work to ramp up our growth fly wheel has now has been completed, and we will continue our efforts to grow the company while optimizing our portfolio. With that, I will turn the call over for questions. Question And Answer

[Operator Instructions]. Our first question comes from Stephen Beck with Jefferies & Company. Subash Chandra - Jefferies & Company, Inc.: Yes, hi, actually this is Subash. Question on the Williston Basin; have you sort of got a sense of percentage your Three Forks potential on the Montana side of the border? And well, I think you have substantial legacy and if there are any attempts near term to try to drill a well out there?

Subash, I have to say I don't know enough about that really comment and tell us when they were going to Williston at the end of this week, we'll be talking about a lot of issues up there. And I may know more but, right now I don't have a sense for what the Three Forks potentially is on the Montana side. Subash Chandra - Jefferies & Company, Inc.: Okay. And in the Haynesville, I guess you sort of leapfrog the vertical part of the R&D process into the strain to the horizontal. A, I guess I suspect this because your neighbors have had the cost doing it, so why not, but I am trying to figure out may be in '09 are we still in the R&D process or do you think if things prove out as the last half dozen wells you've seen that you might be in development mode next year.

Well, these first couple of wells we are going in drill I think, we will get some core, we will do some power holes. We are going do some science, I guess our thinking was that we are going to be near production or near some other completions. And if we are going to be in there spending a bunch of money, we might as well go horizontal and see what we can make. And I think it was just an issue of trying to get in there and make a completion, it was real economic. Most of the vertical completions don't like they are that great. And the horizontals have lot more potential. So, I think we are kind of accelerating our process to try to get meaningful production results earlier. As far as moving into development, I think we will have to drill some initial wells in several different areas. We announced this well were about to spud, we have plans to drill another East Texas, probably after the first one. And then we're going to... we'll to try to move through our acreage position and make sure we have enough data to feel like we can go forward. I am very optimistic, I think we have a lot perspective acreage. We like our East Texas acreage quite a bit. The stuff we have in Louisiana that is we are going to drill this first well and to sort of perish. I think it's in a good area. It's been an area, where there are a lot of leasing activities. So we are very optimistic about it. And we will be devoting significant resources to it in our 2009 programs, I think. Subash Chandra - Jefferies & Company, Inc.: Okay.And one final one for me: any plans to sort of get in this line grab on the East Texas side?

Well, the land grab on East Texas side, if you look at the issues on East Texas side, most of acreage over there is HPP. So it's a deal-based land grab from that standpoint. As you may remember, we bought acreage in Panola County in a deal in January before the big hype started. We've looked at lot of packages since, and haven't really seen anything that worked for us. But we look at deals all the time. And I can assure you we are looking at them now. Subash Chandra - Jefferies & Company, Inc.: Okay, thank you.

Thanks.

Your next question comes from John Healy with Forest Investment Management.

Hi, good morning.

Good morning, John.

Couple of questions; so if you were... is your availability on your revolver just simply $500 million minus $295 million, so it's $205 million available to you at the end of the quarter?

Yes, that's true. Of course that number, that $500 million number could be adjusted as well.

Yes, yes. I mean would your bank group allow you to adjust that. I mean how easy could you if you wanted to take that up from $500 million to whatever between $500 million and $1.2 billion. That's pretty easy do with your bank group?

Currently borrowing basis is $1.4 billion, and yes, we have the capability to ramp that up.

Terrific. And then regarding this SemGroup bankruptcy, it looks like you wrote off just under $10 million, and you said... in your press release there is another just under $7 million of exposure. What are you writing that down to? I mean are you making some assumption about recovery or are you just writing your receivable from them down to zero?

We are writing it down to zero.

Okay, so being conservative, good. Okay, thank you, good quarter.

All right. Thanks, John.

Your next question comes from Ronny Iceman [ph] with JPMorgan.

Good morning, I had a question in term of the Williston Basin, where you are seeing for joining completion for the Bakken?

Well, I think your numbers are going to be... it depends on where you are and what your completion technique is. For the multi stage packer completion to replace... I think you're probably looking in the $5 million to $6 million range. If you look at a lot of the completions we've been around or the longer lateral, say 12.80s and I think the potential there is, you can get those down into $4 millions. In our program right now, we've only got one or two wells down, we did a lot of science on them. I'm not really sure exactly where that's going to end up. I think long-term our objective is to get them into the $4 millions. I will say though that rig rates are going up, steel prices are going up and a lot of the stuff you hear from people about cost coming down-down-down in some of these large plays right now, I think you have to be kind of skeptical about it. We've just seen a tremendous uptick in, for example, in steel prices, a lot of shortages, rig rates are going up. So a lot of these forecasts that show, okay, well the costs are going to continue to be reduced in some of these plays, I think we're a little skeptical about. But in general, I think, if you're in the 4, somewhere for the typical Bakken well that would be a pretty good number. And for the more complicated multi stage packer jobs, I think $5 million to $6 million is probably not an unreasonable number.

And then a similar question, in the Woodford, where you are seeing for recent cost there?

Low $4 millions; now as we go east on our acreage, it gets deeper; and you are going to see a fees in $5 million to $5.5 million range.

Okay, great thank you.

All right, thanks Ron.

Your next question comes from Eric Hagen with Merrill Lynch.

Hey, good morning.

Good morning, Eric.

Just a quick question on the divestures. Any update on CVM play hanging with Basin play?

At present time, we continue to evaluate and continue the completion of wells of the large program that we had going last year. So I mean we continue to focus on that play and we'll continue in the foreseeable future.

Okay. So no plans to divest it then at this time?

Not at this time.

Okay, great, thanks. And then the second question I had was on the Woodford; just an idea of... how long it takes to drill the wells spud to spud and also just the spud to sales?

Sure, well a typical well spud to TD is probably 30 to 32 days for us somewhere in there. We drilled them as fast as 25 and we've had some as more like 40, 45; as you go deeper, it's going to take a little longer than that. Now, spud to sales is probably is more like two months. And a lot of that is just getting frac dates lined up, you got all flow back period. So it takes a while to get that going.

Okay, thanks a lot. Great quarter.

Thank you.

Your next question comes from Larry Busnardo with Tristone Capital.

Hey, Good morning.

Good morning, Larry.

First in the Bakken play, I know it's early, but do you have any plans for three or four test at this time. I know it's again you've just got a couple wells that are down right now, but given what are you seeing, any plans for a test?

We're going to talk to Board this next, just a few next days. I think we definitely are interested in Three Forks. We have potential, we are actually participating in an non-op Three Forks well right now, so we're getting data. And we are excited about the potential. A lot of the acreage we bought in Divide County... that's a Sanish play out there. So we are into play. I think we've been buying acreage to be in the play. We need to get with the Board talk about capital and rig count in the Bakken. And I think we'll be able to give you some more color on that next week.

Okay.And would that be potentially this year or would that be when you talk about program, would that be the '09 program or is that...

I think we certainly have potential to drill well or do some completion work in Sanish/Three Forks this year. In terms of the major-to-major program, we only have one rig running out now in North Dakota. And we've got a lot of Bakken activity to do as well as Sanish. So really for us I think to get significantly into the Sanish, we've got to up our rig count and that we expect to talking to the Board about CapEx.

Okay.

Larry, clearly that's the play where we get additional running room as we continue to learn more about Three Forks/Sanish as well as obviously the completing the Bakken testing.

When do you think you have results in that first well, is that something that may come out... when you come out with the updated guidance or would it be further along next-to-next quarter?

You are talking about the first Bakken where we do?

Yes

I think its going to be few weeks. I want to make sure the expectations are appropriate for the well. We screened out when we fraced it. It's well... it's in an area that that there has been couple of 100 barrel wells. I mean I don't think that first well is going to really... it's not going to be a partial type completion, okay? So, I think it will be a good economic well, but I don't... it's going to be 1,500 barrels a day kind of numbers. At the same time, what we are trying to prove up, up there is that we could develop a large area at lower costs, and that is what we are focused on. That will... we won't have results on that well here for a little while, but it was flowing back, making a bunch of fluid here. And we going have to write it up and get a pump on it. So it's going to be little while before you see an IP number.

Okay. And then on the acreage side that you acquired, can you give us a sense of what the cost was?

Well, we paid about 20 million bucks for the total package, and we actually... obviously we allocated that between the Divide Acreage and Barridon... [ph] what we call Barridon, which is in the McKenzie, North Dakota.

Okay, thanks. And then just shifting over to the Woodford that three rig program or are you going to be adding a third rig? Are you going to maintain a three rig program for the reminder of the year?

Yes.

Okay. And then just in regards those last 10 wells, can you just give us a sense of where those wells were located? Were those groups together, how did they match up with where the initial 10 wells were drilled? Were they in this first or in different areas?

Well, they are actually in a sort of the same area, probably a little bit to the east, more easterly than some of the initial wells we drilled. I think the big difference between the wells we are drilling now and those are really completion technique. We've put a lot more horsepower into the completion than we did for more whole size on bottom. I think it's a more aggressive completion. Generally though, a lot of these wells are within a section or given in the same section or some of the wells we drilled the headquarter results. So I do think it's a more an issue of improved completion in drilling technique than it is so much the location of the wells.

Okay, great. Thanks a lot.

Thanks, Larry.

[Operator Instructions]. Actually we have a question from David Tameron with Wachovia.

Hi, good morning everyone, and congrats on the nice quarter.

Thanks, Dave.

Tony, I apologize, I have been struggling [ph] conference call, so I apologize if you cover this, but I know your guidance are going to be for coming... you have a Board meeting. Can you talk about the way you structured the portfolio, what type of growth do you think is achievable kind of on a longer terms two to three year outlook?

Yes, David our focus going forward is to be able to deliver double-digit organic growth on the year-to-year basis. And so obviously that's part of the transformation we are making is continuing to deepen and optimize and strengthen the portfolio. So we're excited about where we are. We've got a lot of running room and we're going to be focused on double-digit organic growth every year.

Okay. And do you have that portfolio constructed today or do you need to add, obviously everyone's always looking to upgrade the portfolio and high grade it, but do you need to do anything or are you in position today what you've said?

I think we're in great position today. We are in three of the top six resource plays. Those resource plays will continue to be a focus for us. And certainly, we will be looking to add to that inventory with other resource plays and opportunities that we see and some of that we are pursuing as we speak. So to me that's how you continue to grow and deepen your portfolio and pursue that double digit growth.

Okay, and drilling down one more... one more level... you guys are running I think about 15 or 16 rigs?

Right, 16 rigs.

Is that a good run rate over the next 12 months you need to accelerate, decelerate or what's your feeling on that?

Well, David, I think we are going to be picking up rigs... my general sense is we are going to be picking up rigs. And I say that in some trepidation known the rig markets is tied across going up. But nearly all of my competitors are telling they are going to pick up rigs too. But generally I think if you look at our portfolio right now, especially with the addition of Haynesville. Honestly Haynesville by itself could be three drilling inventory for us as a company if you think about how big it could be to us. So clearly we have free cash flow, we have tons of great places to invest money. I think we're only really constrained about how fast we can go and really be one of the folks as... Tony is absolutely right. We are really focused on having a very efficient spend and improving the efficiency of our growth rate. And we're going to grow faster, but we're going to be more efficient about it too. So you're right, we're optimizing the portfolio. We are going to be... we'll dump some low end stuff and as we add more really exciting up higher and lower finding cost stuff, we just continue to high grade the program. But generally, I think you can see we have more growth in front of us in terms of higher rig rates, higher CapEx going forward.

Okay and then the rig market, the tightness, are you talking primarily over 1,000 horsepower type rigs 15,00 those type rigs?

Yes, we've seen 12% to 15 % increases in rig rates just in the last two or three months.

Okay.

We're starting to see a lot of people talking about rigs moving to East Texas, we had comments from people in West Texas about when pull rigs to move to East Texas. So you see rig rates increasing pretty much across the board; the Bakken rig... very tight in the Bakken as well. So, I continue to be... I am very optimistic about the plays we're in and I really like the portfolio we are building. I think this is going to be a really interesting time with everybody saying they're going to increase CapEx.

But directionally yes, we would intend to be adding rigs with these resource plays.

All right thanks. Appreciate it.

Your next question comes from Jack Aydin with Keybanc Capital Markets.

Hi, Tony.

Good morning, Jack.

Good morning. A few questions, the Floyd shale you had two driver; are you giving up on that area? And how much acreage do you have there?

Jack we've got 22,000 acres there, we have an earning arrangement, where we can earn a lot more. We participate in a couple corner wells, if I'd mentioned who drilled them, you'd know them, as part of that earning arrangement. In fact, those wells were pretty experimental and really weren't that surprised with the results we've got. But if you look well bores now, they don't have a lot of utility. So we decide to go ahead and dry hole them. We haven't given up on the play.

Okay.

It's a big area and I think there are some opportunities in other places and we may very well spend a little more money there. At the same time, I think everybody understands that Floyd is not the premier shale play, potentially; it's some of the other ones are. And I think there is some more research frankly that needs to go into making it commercial. So...

Okay. In the Maverick basin, you've got 75,000 acres in East Texas area. Did you drill the well or you're drilling... you're planning to drill that well and what you're trying accomplish there?

Well, I think what we've said repeatedly is that we are earning into a potential 75,000 acres through drilling wells. And that's a three year program, which we'll spend about $8 million a year. And then I think, the third year is about $10 million. So it's a long-term drilling arrangement. At this point in time, we don't have... we don't own the acreage and we don't get it unless we drill.

So, are you in your first year or second year?

We are in the first year.

First year, okay. The second question, you have legacy production in the Bakken, nothing... in the Williston Basin before. What is that production is running at now and is there opportunity to go re into some of those wells for the Bakken or Three Forks or Sanish?

Well, in terms of potential entries, yes there is... there are potential re-entry opportunities and I think if you, HTO [ph] just bought acreage, if you look Headington purchase what they bought was a lot of what we own. And on truly trend and if you've read their press release and talk about it, they are talking about a lot of down spacing and in fill completion, we agree with all that. And we have about an 111,000 acres I believe in that Helm Cooly Bar trend area. In terms of total production, we can get back to you on that.

Final question for me in the Divide County in North Dakota, did you hear anything; have you heard anything anybody else drilled any wells that they have Sanish and Three Forks potential if somebody else drill?

Yes.

Could you name them, if you don't mind?

I'm not sure I have the data here. We can get back to you on that too, Jack. But there are Sanish wells producing in Divide County.

Okay, thank you.

Jack, before you leave, one comment on the Floyd shale and also in the Maverick Basin with Pearsall and Eagle Ford shale. I think what you are seeing there is a significant change for St. Mary. I think those are excellent examples of where we are looking to get into some of these plays earlier rather than later, rather than waiting for the plays come to us, we are going in and exposing some minimal capital, but allowing us to detest exposure to significant acreage positions. And with success, certainly that's one way to continue to grow our portfolio. And obviously the key there is once you're done your testing to make through that you decision those wells, and if its not working then you get out promptly, if it is you have an opportunity to ramp up your development in those plays. But those are two key examples of what we're trying to do to get in earlier in some of these key resource place.

You're transforming the company, Tony.

That's the plan.

Yes, thanks.

Jack, thank you.

Your next question comes from David Epstein with Advent [ph].

Hi, I just wanted to get your thoughts on supply growth coming on and then your view of gas prices and how it influences your CapEx program.

Well, basically each year certainly we stay tuned to what's happening in commodity markets, but we don't try to forecast pricing. That's not what we do. When we build our capital programs, we focus on minimal pricing correct to make sure that all of our projects are able to achieve those minimal hurdles on pricing; and then we build our capital program using that as kind of a floor.

I think what the minimum pricing is that you assume.

Yes, right now basically we've used the 70 and 74 for our current program. And uncertainly we adjust that as we see changes in the market.

Thank you.

You bet. Thank you.

There are no further questions at this time gentlemen. Are there any closing remarks?

Just a couple of comments: first of all I would like to thank those who are listening in this morning, and those with questions. We appreciate your feedback and input. As I've mentioned earlier we are excited about the state of our portfolio at this point. We have some key resource plays that we are very active in and continue to grow on those plays. Also we are excited to have our new CFO coming on board in a month or so. And a part of our job early on is to have Wade get out on the road, have a chance to meet many of you. If you get a chance and you are coming towards Denver, we certainly invite you into meet with Wade and have a chance to get to know him. Generally, it's very strong for first half of the year we are excited about where we are and our job now is to executive, continue to execute on our business plans through the rest of the year. With that, we appreciate you calling in and we'll talk to you next quarter.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.