西南能源 (SWN) 2010 Q1 法說會逐字稿

Greetings and welcome to the Southwestern Energy first quarter earnings teleconference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation.

(Operator Instructions)

As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Mr. Steve Mueller, President and CEO for Southwestern Energy. Thank you, Mr. Mueller, you may now begin.

Thank you for joining us. With me are Greg Kerley, our CFO, and Brad Sylvester, SWN's VP of Investor Relations.

If you did not receive a copy of yesterday's press release regarding our first quarter results, you can call 281-618-4847 to have a copy faxed to you.

Also I would like to point out that many of the comments during this conference -- teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control, and are discussed in more details in the Risk Factors in the forward-looking statements section of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

We had a good -- very good quarter financially. Our earnings and cash flow growth were outstanding, which highlight the value of our industry-leading low cost structure. However, while our production grew by 41% during the first quarter, we experienced operational and weather-related field issues in our Fayetteville shale play which impacted our production volumes. As a result, 26 fewer wells were placed on production than originally scheduled at March 31st, impacting our production first quarter by approximately three Bcf. We have adjusted our production guidance for the second and third quarters, and remain optimistic that our fourth quarter production guidance is still achievable at this time.

Now to talk a bit about each of the operating areas. Earlier this week, our gross operator production from the Fayetteville shale reached approximately 1.3 Bcf per day, up from about 850 million cubic foot per day a year-ago. While it now seems that most of the issues are behind us, we did have operational and weather-related field issues which affected our results during the quarter. Approximately 47% of the wells placed on production during the quarter were the very first well in a section, and 65% of the wells were along the shallower, northern and far eastern borders of the project. Both of the first section -- both the first section wells and shallow well locations were the highest of any quarter in the Company's history by at least 13% and 20%, respectively.

As might be expected, the initial rates from the wells on the edges of our producing area are less than central and deeper areas, but we continue to improve, and achieved initial production results that were better than previous quarter averages for all of these border areas. Weather and challenges encountered in the more remote locations with the first wells in the sections, resulting in placing a total of 26 fewer wells on production than what we had originally anticipated, impacting our production by about three Bcf for the quarter.

As we discussed in the last call, we have added two additional horizontal drilling rigs during the first quarter, and expect to catch up to our original operator well count by the third quarter of 2010. We're currently running 24 drilling rigs in the Fayetteville shale, 16 that are capable of drilling horizontal wells, and eight smaller rigs that are used to drill the vertical sections of the wells. During the first quarter, our horizontal wells had an average completed well cost of $2.8 million per well, average horizontal length of 4,348 feet, and average time to drill to total depth of 12 days from reentry to reentry. This compares to an average completed well cost of $3 million per well, average horizontal length of 4,303 feet, and average time to drill to total depth of 12 days from reentry to reentry in the fourth quarter of 2009. Wells placed on production to the first -- during the first quarter of 2010 averaged initial production rates of 3.197 million cubic foot per day, down 14% from the average initial production rates of 3.727 million foot per day in the fourth quarter of 2009.

When looking at our results through April, we have already placed nearly [60] wells on production at an average initial production rate of approximately 3.6 million cubic foot per day. The quarterly decrease in production had one additional factor than the drilling mix or the number of wells in the section -- in the first [well] section. Beginning in late 2009, we began what sometimes is called green completions, whereby wells are placed directly on production very early in the flowback period, so that incremental gas volumes are captured.

As a result of the wells being placed on production earlier, the initial pressure the well is flowing against is higher, and the recovery of the completions fluids is slower. This will capture more gas, but we estimate initial production rates could be reduced by approximately 5% to 10%, depending on the quality of the well. We continue to test tighter well spacing, and on March 31 we had placed over 375 wells on production that have spacing of 700 feet or less, representing approximately 65-acre spacing or less, and have previously concluded that 10 to 12 wells per section is the minimum number of wells needed to officially drain the reserves. The most recent information from this larger group of wells indicates interference of less than 10%, compared to earlier estimates of 10% to 15% from the smaller well set. We continue to focus on optimizing the well spacing for the play, and plan to test over 44 different pilots with well spacings that will range from 200 to 450 feet apart as part of our 2010 drilling program.

To wrap up our discussion on the Fayetteville shale, we are now providing new production data on our zero time production plot of wells with drilled lateral lengths over 5,000 feet, as shown in our press release. With over 60 wells included in the sample, we're encouraged by what we're seeing thus far.

In our east Texas operating area production was 9.6 Bcfe, up from 7.8 Bcfe a year-ago. We participated in drilling 11 wells in east Texas during the first quarter, six of which were James Lime, three of which were Haynesville horizontal wells, and two of which were Pettet horizontal oil wells. Initial production rates from the James Lime that were placed on production during the first quarter averaged 6.6 million cubic foot per day, and we placed one well in production from the Haynesville shale during the quarter at an initial production rate of 22.1 million cubic foot per day. Initial production rates from the four Pettet oil wells that were on production during the quarter averaged 292 barrels of oil with 2.6 million cubic foot of gas -- million cubic foot of associated gas per day.

In our conventional Arkoma program, we participate in three wells, and our production from the area was 4.9 Bcf compared to 5.8 Bcf last year. In Pennsylvania, we have approximately 151,000 net acres in Pennsylvania, prospective for the Marcellus shale. We're currently drilling our second well for 2010, the Ferguson [Kingsley] 1H in Bradford County. We plan to complete both wells drill to date during the second quarter, and they should be on production as early as June. At least 15 wells are expected to be drilled by Southwestern in 2010.

In our new ventures program, we announced in March that we had granted -- we have been granted exclusive licenses to search and conduct an exploration program covering over 2.5 million acres in a province of New Brunswick, Canada, to test new hydrocarbon basins. As the winner of the bids, our financial commitment over the next three years is approximately $47 million. More than 80% of the work commitment is gathering and processing of geochemical, gravity, magnetic and seismic data. The initial phase of the data gathering is planned to start before the end of 2010.

In closing, natural gas continues to underperform the rest of the commodities, and like all of you, we're carefully watching both the imbalance of supply and demand and the industry's reaction to that imbalance. We have already made some adjustments to our capital allocations to emphasize our best projects. We also remain confident that our low-cost operations, financial strength and flexibility to pursue our drilling program in the Fayetteville shale, give us staying power through the tough times, and the ability to add significant value for our shareholders, even in the current low gas price environment.

I will now turn it over to Greg Kerley, our Chief Financial Officer, who will discuss our financial results.

Thank you, Steve, and good morning.

As Steve noted ,our financial results for the quarter were excellent, with earnings up 37% and cash flow up 12%. Our improved results were driven by our strong production growth, and continue to highlight the high quality of our assets and our industry-leading low cost structure. We reported earnings for the first quarter of $172 million or $0.49 a share, compared to adjusted earnings in the first quarter of 2009 of $125 million or $0.36 per share, which for comparative purposes exclude a noncash ceiling test impairment test recorded in 2009. We also report discretionary cash flow of $418 million, up 12% from last year, and we were nearly cash-flow neutral for the period, as our cash generated from our operating activities funded 94% of the cash requirements for our capital investments. Our production totaled 90 Bcf in the first quarter, up 41% from the prior year, and we realized and average gas price of $5.42 in Mcf, down $0.50 per Mcf for the same period last year.

Operating income of our E&P segment was $250 million during the quarter, up 39% from the same period last year excluding the noncash ceiling test impairment, as the significant growth in our production volumes more than offset the decline in our average realized gas price. Our commodity hedge position increased our average realized gas price by approximately $0.55 in Mcf in the first quarter. We have approximately 48 Bcf of our remaining 2010 projected natural gas production hedge in fixed price swaps and collars, at a weighted average for a price of a little over $8 per Mcf. We recently increased our hedge position in 2011, and also added some hedges in 2012. We hedged an additional 55 Bcf of our 2011 forecasted gas production through costless collars at a floor price of $5 per Mcf, and average ceiling price of $6.42; and approximately 29 Bcf of our 2012 forecasted gas production at a floor price of $5.50 per Mcf and an average ceiling price of $6.54.

We have one of the lowest cost structures in our industry, and we continued that trend in the first quarter of this year, as our lease operating expenses per unit of production were $0.78 per Mcf during the quarter, unchanged from last year. Our general and administrative suspension expenses per unit of production declined at $0.29 per Mcf in the first quarter, down from $0.31 last year, due to our increased production volumes. Taxes, other than income taxes, were $0.14 per Mcf in the quarter, compared to $0.13 in the prior year. Our full cost amortization rate also declined, dropping to $1.41 per Mcf in the quarter from $1.82 in the prior year. The decline was due to a combination of our ceiling test impairment recorded in the first quarter of 2009, and our lower trending finding and development costs. Operating income from our midstream services segment increased by 37% in the first quarter to $38 million.

The increase was primarily due to increased gathering revenues related to production growth in the Fayetteville shale play, partially offset by increased operating costs and expenses. At April 25th, our midstream segment was gathering almost 1.5 billion cubic feet of gas a day, over -- through over 12,000 miles of gathering lines in the Fayetteville shale play, compared to gathering approximately 900 million cubic feet per day a year ago.

We invested $474 million during the first quarter of 2010, compared to a little over $500 million in the first quarter of 2009, and drew down our revolver balance by only $20 million during the quarter. At March 31st, we had $345 million borrowed on our $1 billion credit facility, at an average interest rate of 1.3%, and had total debt outstanding of a little more than $1 billion. This leaves with us a debt to book capital ratio of 29%, and a debt to market capital ratio of only 7%, which is one of the lowest in our industry.

That concludes my comments. Now we will turn back to the Operator, and he will explain the procedure for asking questions.

(Operator Instructions)

Thank you. Our first question is coming from Jeff Hayden of Rodman & Renshaw.

Good morning, guys. A couple of quick ones. One, it looks like the performance of the Fayetteville wells had a nice bump up in April versus what it was in Q1; just wondering what were the differences there? Was there a difference geographic mix, higher percentage of longer lateral wells, anything like that going which kind of influenced the performance?

Before I answer that let me make one comment. I think Greg said we had 12,000 miles of pipe out there. We actually have 1,200 miles of pipeline. If anyone ask that question, we don't really have 12,000.

But -- as far as the April wells, there is a little bit different mix in April. We've had some rigs drilling on the southern end of our acreage, again, kind of peripheral, but whereas northern and far east are in the 2,500 to 3,000-foot depth range, when you go to the far south you're at a 6,500-foot depth range. Two things happen there; you will get a little better rates down there, but it is going to take you a little longer to drill it. So while we averaged 12 days to drill wells in the first quarter, in April it was something like 14 days to drill a well, because there are --- some of those wells are a little deeper.

So there is a little bit of a mix issue, and that just brings up how things will kind of develop over the next few quarters. Both first quarter and second quarter, we will have a significant number of our wells capturing first wells on the section and so there is going to be a different mix from first to second, and then there will be a different mix compared to last year, the previous quarters we had also. We're just going to have to work through that and that you can through it as we go through those mixes.

Okay. And just in kind of looking at the potential locations you guys have in the play, how much of it do you think is in, you know, kind of a central area and other kind of deeper areas of the play versus, you know, how many of your locations are in the shallower part of the play right now?

I don't know about the actual mix. I think the best way to do it is to go look at our website. Look at our presentation. There is a page in there that shows where our midstream is at. That will tell what you we have tested to date, just where that midstream infrastructure shows on that map. And you can get a feel for what has been tested today, and then you can kind of look at what needs still to be tested. There is a significant amount of new capture that we're going to have to do in the middle of our acreage on the eastern side, and then we have got some of those peripheral captures we will do as well.

Probably the best way to give you a feel for the overall mix, our northern acreage is very similar to what Petrohawk has done, they have a lot of things on the north end. If you look what their performance has been, you can think about that if it was what our acreage would be there. On the far east, that is where Chesapeake has a lot of their production. You can look at their performance, and get a feel for what those wells might do.

Okay. Then one more and I will jump off. I may have missed it, but did you guys give any updated expense guidance?

As far as LOE or those kinds of things? No.

Okay. Thanks guys.

Thank you. Our next question is coming from Brian Singer of Goldman Sachs.

Thank you. Good morning. A couple questions. First on the down spacing, can you add any color more specifically on what is giving you more confidence in the less than 10% communication versus your higher levels previously, and talk a little bit about the aerial extent of, you know, where you see potential tighter spacing?

It really has to do with the number of days we have had the wells on production. You know, the -- when we first made kind of the -- we needed 10 to 12 wells per section called back last -- in the third quarter of last year, I think the longest we had any wells on were basically 90 to 120 days. Now we have got several months more production, so we have a better shape on those curves, and so it doesn't look like there is as much interference as we first thought.

Okay, is that the result then of a much flatter production profile, or do you just feel like you were being conservative earlier and wanted to see more before kind of putting out a 10% or less kind of number?

Well, we actually saw in that early part of the performance, that 10%-plus, so that -- we did see that. That wasn't being conservative, that was just data. And it is data, again, today, in -- part of that, again, that initial mix that we talked about, had just over 100 wells in it. We're talking about 375 wells now. So you're covering a bigger area with those number of wells, and getting more information on them. And it looks like you're going to have a higher EOR.

In general, at -- when you're talking about the spacing unless you're very, very close together on the wells, the IP shouldn't change much. It is all on your EUR estimate. So when we were talking about the fact that we had something greater than 10% and now we're less than 10%, it is that EUR, and it is that back end of the curve that you're projecting off of that initial production.

Geographically are you definitively ruling in any more areas of your acreage for tighter spacing? I think you focused a little bit more on the southern -- south-central portion previously?

You mean as far as tighter than the 10 to 12 wells per section?

Yes, that's right. Or even the 10 to 12 wells per section, that or tighter.

We're comfortable on average, that 10 to 12 will work just about across our entire acreage. We haven't tested everything yet, but what we have tested we're comfortable with that. With this 44 pilots that we're doing, that will also be spread across the empire acreage, and let me emphasize we're trying to get 44 improvements done. To actually do the pilots, you need to get 100% participation by all of the partners in the well, and so it may end up to be 40, maybe couple more than that, but we're doing that right now to get that project.

In those cases we will be testing that tighter spacing, and I fully expect that ultimately you're not just going to do 10 to 12 wells across the entire area, you will have some areas that are tighter and some that will be the 10 to 12.

Great, thanks. Lastly, can you just comment any more on the operational side of the issues that delayed some of the wells, and is there any risk that continues over the next couple of quarters?

Well, the simple answer to the first part, or second part of your question is risk of it happening, once you run across the kinds of issues we had, and I will describe a little bit of them here in a second, once you run across those issues you pretty much design a system that you won't get those again.

But the real thing, and the reason that I put in the letter, or put in the press release and put in my comments that I was disappointed is that we're trying to build a system that is robust enough that what we say we can do, we can actually do, and we missed last quarter. I'm disappointed in that. So we have to continue to work on building a robust enough system.

Now having said that, the kinds of things that happened too us last quarter, some of them were decisions by us, and one of the things that happened if you remember back in the third quarter, we had boardwalk pipeline issues. We took some of the rigs that we operated, did maintenance on those. We also took some of those sputter rigs that doing the vertical portion of the wells, and laid those down. And then whenever the boardwalk pipeline issue was resolved, we were going to pick those up. Well, we went to pick them up; it took about 30 days longer to pick them up than we thought. Some of that was them, some of that was us; just took a little longer.

In some cases it is our pipeline. The reason we put 50 wells already on in April, which is a record for any month, is we had to lay a 20-mile pipeline. We thought that 20-mile pipeline would be in in mid-February. If it is in in mid-February, we hit our target. We got delayed about 15, 20 days on that pipeline. Part of that was weather, but most before it was the number of crossings and various things we had to do from a surface permeating standpoint, both with the owners of the surface and with the State and the various agencies, and we lost 20 days. In those kinds of cases, both those ones I described, those are behind us. Those aren't going to happen, but again it just tells you we're not quite as robust in our system and how we're predicting, and we will get that fixed.

Thank you very much.

Our next question is from Joe Allman of JPMorgan.

This is actually Ronny Eisemann. I had a question, going forward for the next couple of quarters, do you have a rough estimate of what the mix will be for the percentage of wells drilled in the northern and eastern area?

I really don't at this point. And the reason we don't, we're always trying to work seven or eight months in advance, but for instance some of these wells have to go to hearings. If you don't get the well in the hearing, it doesn't just effect the one well but effects everything that hooks up with those rigs, so you're always changing the mix and exactly where they are going.

So probably the best I can say is, during the second quarter we will be doing a significant number of acreage [caps]. It looks like we will even do more than we did in the first quarter. But where exactly those are at, I can't tell you the exact mix on that. There will still be some up in the north and some in the far east, but as I said, we're also drilling some wells on the very southern end of our acreage also.

Great, thanks. And the green completions, of the 106 wells brought on in the first quarter, how many of them were green completions?

Most of those. And let me just talk quickly about the green completion. Some people call it green completion because you're not releasing some of the gas in the atmosphere or flaring some of the gas, so there is an environmental component to it. I think of a green completion, and that's why I said some people call it green. it is just economically green for us to do that. We capture about 15 million cubic foot of gas by going directly or very early into the system; that 15 million cubic foot of gas is about $2 an M to capture that gas. And if you put in perspective we will drill 500 wells this year, and while 15 million cubic foot doesn't sound like much, that is 7.5Bcf this year alone of gas that we would have flared that we're going to capture, and that's a significant amount.

So the idea was capture that gas, and you might ask why we were not capturing it, why we didn't capture it before? That goes back to the robustness of the system. You have to put a special team in place, you have to move a lot of equipment around to do this, and we're just at that stage where we can start doing that part of the process.

Of the 22 wells in the fourth quarter, how many of those were green completions?

Very few.

Yes.

We started doing this in December.

And then, again, the 106 wells brought on in Q1, versus the 50 brought on in April, did the weather delays delay within the quarter, the -- when those wells were brought on? Were they more back-end loaded within the quarter?

Yes, yes. And, I mean, that -- that basically is why we missed our guidance.

And with the additional rigs running this year to catch up, is there an effect on CapEx?

Well, I mentioned that we reallocated capital a little bit. We have decisions that we can make about our Fayetteville drilling later in the year. Four of the rigs, actually five of the big rigs of the 16 that are running, we will be able make decisions whether we want to keep those running through the year or not, starting in late June and going through November we can lay down those rigs on various contracts.

But what we have done on the capital budget, we have reallocated dollars to Fayetteville shale. It is economic on any kind of forward curve you're looking at or anything we have got, and we're planning right now to run those rigs through the year. In Pennsylvania, we were a little slow getting the rig to work there. We wanted to get the rig out there the 1st of January. Didn't get out there until the middle of February. So we reallocated some of that Pennsylvania money that is not going to get invested to that Fayetteville shale, and then we've also backed down on a little bit of our new venture dollars, so we can run those rigs through the year in the Fayetteville.

So we have done some minor changes. Overall, that is a total of $50 million to $60 million out of $2.1 billion that we have moved around. But the whole idea was, get the money where you've got the best projects at this gas environment.

Thank you. Our next question is coming from Michael Scialla of Thomas Weisel Partners.

Good morning, guys. Want to ask you about the 5,000-foot laterals. How much are those costing, and what percentage of your acreage do you think you can drill 5,000 feet or more on, and maybe how the economics of those compare to the shorter laterals?

5,000 for the laterals, probably are in about the $3.5 million to $3.6 million range today, and that's drilling at basically one well in a section type number. As you -- I fully and that is going to go down a little bit. And let let me just also put that in comparison. In the shallow, where we're drilling 4,000 or 3,500-foot laterals and it's only 2,000-foot deep, those are $2.5 million wells. That is really the range that you have got.

On the you numbers of 5,000-foot laterals we have, in a very shallow portion of the area, probably not going to do 5,000-foot. Probably in the 4,000-foot range. In the far east, you have got a lot of more faulting. I don't know if we can quite average 12,000-foot laterals in the far east, but as we who into the future and look at the geometries, it looks like we're going to have to average better than 5,000, somewhere between 5,000 and 6,000-foot on average across most of our play to optimally invest the dollars to get the most gas out of the ground.

So I think a large part of it will be 5,000-plus. On the other hand, and you didn't ask the question, but what's the odds of having bunch of them at 6,000 or what is the odds of a bunch of 8,000 or 10,000? The real average is somewhere in that 5,000 to 6,000-foot range. We will drill some wells, especially where there skinny fault blocks, that will be longer than that, and we have already drilled a couple wells over 8,000 feet.

Sounds like from an economic standpoint though, the optimal -- you're kind of zeroing in on this 5,000 to 6,000-foot range?

That's what it looks like today.

Okay.

Let me add, the reason it looks that way, if you try to lay out a grid of say 10,000-foot laterals, you could put a bunch of 10,000-foot laterals out there but then there is a bunch what we call white space. There's spots on the map that you can't get to with 10,000-foot laterals. What you need is a bunch of 2,000 or 2,500-foot laterals to do that, and you end up averaging at 5,000-foot anyway.

So when we start looking at it, it looks like that 5,000 to 6,000-foot is the range for that laterals.

Any additional acreage you will need to drill these longer laterals?

Well, we have permission -- there are two things the States worked with worked with us on recently. We got permission in December to basically do wells at cross sections, so that you can drill and hold sections and do the various things under -- there's some details with the State rules, but we can do that administratively now. When we were doing it last year up until December timeframe, we would have to take those wells to the Commission and get their approval, and now we can just do that with the regular administrative process.

The other thing that the States have done for us recently, as we started doing these green completions we realized that the peak production may not be in the first ten days. The States' rules were you have to give the top production rate in the first ten days. top 24 hours in the first ten days. We now have that. I think it is 45 days we have to get the top rate, and they changed that back in early January. So those are the two most recent changes in that direction.

Thank you, our next question is from Scott Hanold of RBC Capital Markets.

Thanks, good morning. So, I think you guys kind of covered most of the stuff but, you know, in terms of looking at your spending plans, specifically on the Fayetteville shale going forward, and I guess what the gas curve looks like right now, you obviously made the case that the wells that you're drilling are economic, even at these stripped prices, how do you think about if full development mode of the Fayetteville, and how you hedge that sort of on a go-forward basis?

Well, it looks like today that we could have an extended period with relatively low gas prices. When I say relatively low, is that a high 4 or a low 5, or mid 4, but it's probably not 6s and 7s. We are very economic in what we're doing in both Fayetteville shale and Pennsylvania, and the real thing that is keeping us from going faster or doing something different is more the cash flow side of the overall equation. First quarter, we only borrowed an additional $20 million, so we're real close to cash flow neutral, even with the prices we had in the first quarter. And so as we start -- get cash flow neutral and get some extra dollars, we will put those to work. We're not going to try by ourselves to solve the gas problems that the nation's got. So if we have economic projects to do at whatever price is out there, and we have the dollars to do it, and we can do it within a strong financial situation, we're going to go do it.

Okay. When you think of that longer-term picture, is there any consideration of eventually going out there and, you know, building your own fit-for-purpose rigs in the Fayetteville, based on what you know now, that would be much more optimal than maybe what you're running at this point?

Whether we build them or someone else builds them, that will definitely happen. The next rigs we'll add will be built for purpose. We've actually got two of them operating. The reason we picked up two of those right now, [walk], they are AC-powered, and we're using them on the downspacing work where we're drilling more wells than one on a pad, and the most advanced of those rigs are right now averaging less than seven days per well to drill wells on pad works.

So there is a big difference between the 12 we're doing now and that seven, and we'll add rigs; as we add rigs, that's exactly the way we will work it. Now whether we're buying those rigs or someone else is building them and owning them, and supplying them to us, we will make those decisions as the market goes forward in the future.

Okay. And one last question, I should have asked this before I asked the last one, but back to the hedging aspect, what is your plans in terms of what you do on a go-forward basis with hedges? Where do you feel comfortable at layering these in? And the preference for swaps versus collars, how should we think about your policies going forward?

I don't know if there is a swaps versus collar preference, but we just in the last week put on some hedges, as Greg said. There are $5 to $5.50 floors in 2011 and 2012. We make a lot of money at $5 or above. And so you will see us putting on hedges when we can, and we won't hedge obviously our entire production in those years but we will hedge enough so we know can make good money and head on down the road.

Excellent, thanks guys.

Thank you our next question is coming from Jason Gammel of Macquarie.

I wanted to come back and ask a couple more questions about the green completions, to make sure I understand the overall effect on the performance of a well. I understand producing into a higher pressure early on is going to have a negative effect on the IP rate, but when we're thinking about ultimate recovery of the well, I understand you're capturing incremental gas at the beginning; are you really doing anything to the ultimate recovery of the well? Is it lowering the decline rate that you see, say, 30 and 60 days out? Any help you can provide on that would be useful.

I might -- we're still trying to gather all the data. It might on a 30-day number, for instance, flatten it out a little bit. I would guess by 60 days, as I said in that -- one of the reasons the state changed the rule to 45 days, somewhere between 15 and 30 days you pretty much have got all these wells cleaned up the way they should clean up. At that point, it is no different than when you originally did the well and put it into the same kind of system. It has the same back pressure on it from there, so it performs the same. So EUR is going to be bigger by 15 million cubic foot, is basically the answer. It's spread out a little bit different in that first 30 to 45 days. That's about all there is to it.

So just as a follow-up then, is a lot of this just essentially the reporting requirements of the State? I mean, it seems to me that the effectiveness of the well is actually improving a little bit, even though the stated IP is worse?

Yes, we're making money, so yes, for those who follow the IP, it is going to be a little bit down, and that's all we want to tell people. It shouldn't effect hardly our 30-day at all. Like I say, you might see a little effect -- it shouldn't affect 60 for sure. So that's one of the reasons we have all three columns on the table.

Okay great that's useful. One more if I could. Just from a tactical standpoint, and I think you partially answered this, but having such a high percentage of the wells in shallower areas of the play coming on during the quarter, was that simply a function of where you could get the rigs at specific points in time, where you had permits? And I think you've already answered this, but what sort of mix would you expect to see moving forward in the shallow sections versus the deeper sections?

Yes, I did answer the question with about the mix. We really don't have a good handle, because that is kind of dynamic, of exactly how much. Certainly in the second quarter you will see more in the shallow and far east than did you last year at any point in time. But how that compares to first quarter, it will be down a little bit; but is it down 10% or 20%? I don't know. But there is a little bit of difference between the quarters.

Now I forgot the other part of your question.

Just from a tactical standpoint, what led you to bring on so many wells in those lower productivity areas?

Oh, it really had -- we started moving rigs that direction late last year because number one, we had to capture some acreage. And number two, we wanted to learn more about how we've applied some of our current production fracking techniques, and see how much better wells we could get. And consistently in the shallow and far east areas, we're getting better wells than we had in previous quarters or previous times we have been out there.

That was key to us, to learn that now, and also then set us up so we can go out there and do some of this down spacing test. You have to have some wells out there that have a history on them that are your type wells that you compare against. We needed to get a recent type well in those areas, and then we will move out there and do some of that testing. So part of it had to do with getting ready to do down spacing. Part of it had to do with making sure our techniques we're using could actually get better wells, and part of it had to do with acreage capture.

That's very helpful. Thanks Steve.

Thank you. Our next question is from Brian Kuzma with George Weiss.

I just wanted to make sure I understood -- so the difference on the 30-day rates from fourth quarter to first quarter, that's mostly due to the mix; that's not due to the green completions?

There is a little bit of green completions in the IP. But the biggest -- biggest portion of the IP is mix, yes.

Okay. And I know you don't know exactly what you guys are going to drill this year. But like of your 900,000 acres, you say 125,000 are kind of in the Arkoma fairway, how does the rest split out between you know like core, northern and eastern, roughly?

And on the far western side we have got about 150,000 acres, it is a Federal unit. That Federal unit, there is a couple wells we drilled a few years ago. There is a private piece of land in the Federal unit that we could get on to, but there is only a couple wells that are in that Federal unit. We will drill a couple more wells this year, but there is 156,000 acres there.

When you look off to the far east, there is -- I am trying to think about how many sections, but there is a -- couple hundred sections that we need to give first well in a section on ,and each section is 640 acres. So that is what will be happening over really the next two-and-a-half to four years in far east and some of the southern acreage portions of it.

And then as you mentioned, there that is 125,000 acres that is already held by production with our conventional Arkoma. That 125,000 acres has only a couple of Fayetteville shale wells on it, and we will get to that once we get all the acreage captured and we can start working that direction.

Okay. And then like how much acreage do you think is up north, the Petrohawk type wells?

Well, if you just look at our map it is across the whole map, you know, the -- if you look at our map, it -- the structure runs basically east-west, and gets deeper as you go to southern side. So the southern side of our acreage is about 6,500 feet. The northern side is about 2,000 feet. And so, it will just grade from that 2,000 all the way down to 6,500. The dead central portion is 3,500 to 4,000 feet.

Okay, I got it.

I will say that if you look at any of our maps and any of our presentations, there is -- on the eastern side there are a couple of lakes. We don't have a whole lot of acreage up north of those lakes. That's why we have got a little cut out in our little shaded area we have got on that map there.

Okay. And then, like when I look at your [zero] time plots that you guys charted here, you guys said that you had 375 wells thats are less than 500-foot spacing; is it fair then to say that there is like 375 wells in the zero time plot which are -- have production rates which are 10% lower? Do you see what I'm saying there?

That would be -- yes, that would be true. It -- yes, in general. I mean, I --

And those wells were drilled in the past year?

Yes, for the most part. You know, the thing about 2009, we had about 200 acreage [caps] of wells, and we had about 400 wells that were doing the 600 -- 500 to 600-foot spacing, so yes, you're seeing a reflection, and you'll see it really in the last -- when you looking at any of those, whether it's 3,000-foot or 4,000-foot plots, you'll see those in that first 365 days or 180 days, depending on each well.

Okay. And then when I compare the 4,000-foot curve to the 5,000-foot curve, it doesn't like appear to be linear; and I was just curious, it looks like there is some sort relief decreasing marginal returns?

You mean, as far as the -- are you talking about linear because at the end of there where you have fewer wells it jumps up, or linear -- how do you say linear?

I was referring to like the first 100 days, it looks like there is more recovery per lateral foot on the 4,000-foot. But I didn't know if --

They are pretty parallel once you get past the very beginning there, so I would have to see if there actually is more recovery per lateral foot. I haven't looked at that.

But help me understand, the 5,000-foot laterals were drilled in the deeper areas, so they may have been a little different geologically?

Not necessarily deeper areas. They wouldn't be drilled in the very shallowest portions, that's basically a couple miles across the north end of that. But from 3,000-foot or so down to 6,500-foot, they could be drilled anywhere in there.

Okay.

Thank you. Our next question is coming from David Heikkinen of Tudor, Pickering, Holt & Co.

The new venture there, obviously you have talked about Canada and have been continuing to allocate some capital away from there; is that allocating capital away from leasing or drilling, or how should we think about any of the -- how you allocate capital to new ventures?

We didn't have any drilling allocated this year for new ventures. What we had this year was leasing and buying data, seismic, gravity, magnetics, those kind of things. What we have done basically is delayed some of the information gathering part of it, some of the seismic depth that we're going to get, and some of our leasing, and until somebody figures out exactly where we're at and what we're leasing, we can delay some of that, too. So both of those things are going on.

So it is not that things are getting more competitive and values are going up, it is just that -- that isn't changing your leasing plan?

No, it is not a competitive issue.

Okay. On the Fayetteville, just trying to dissect this a little more, and thinking about the Petrohawk-type curve in the northern acreage, can you talk about what you think across your 889,000 acres what an average EUR will be for -- you're talking more 5,000-foot laterals now than you used to, so where do you think things are going from an average EUR in the Fayetteville?

You kind of mixed metaphors there, you had 5,000-foot laterals and average EURs and those kind of things. What is on our reserve report today is 2.4Bcf on our PUDs. We have about 1,200 PUDs in the reserve report. Certainly you look at the plot, if we average 5,000-foot laterals it will be higher than that. And in general, our our best wells -- as an industry we have drilled I think over ten wells now at 6 million a day IPs. All of those had very high 4s in the 5,000-foot range. So, I think it is just -- not a perfect extrapolation but I want does -- -- those 5,000-foot laterals, as you get a longer lateral you are going to contact more rock; as long as as long as you frac it the same way, your EURs are going to go up.

Thank you. Our next question is from Bob Christenson of Buckingham Research.

Did you guys express any kind of interest in the Common Resources sale? Did you bid, look? And what are your impressions of that sale?

No comment about whether we bid, looked or did those kinds of things. As far as impression, my understanding is the closing's in May. One of the things -- one of the reasons we did not change any capital, when I talk about a little capital changes we didn't really change any capital in east Texas, is we just needed to get the thing closed.

For those who don't know, Common has sold their east Texas portion of their assets; those east Texas portion, we have 50% of part of that. I think they sold 29,000 acres. We have 50% of about 20,000 acres. A little less than 20,000. So whenever they have the closing, we need to talk to the new operator, and the operator and us need to get together and figure out how we're going to develop going forward, and figure out their plans. So that's about as much as I know about Common right now.

So you're saying the drilling capital could be there with new participants, perhaps?

I just don't know. We just got -- got to get to closing let them, get to closing and then we can find out really what they are going to do.

My follow-up is, what is your reaction, and maybe Greg answers as well, to some of the joint ventures, alliances struck in the Marcellus shale of Pennsylvania as of late?

Since you asked for Greg, we will let Greg react.

Okay.

Well, I think there are some interesting numbers that we have seen that continues to kind of climb up there, and it definitely gets everyone's interest. We like our acreage we have in the northeast portion of the play, it is where the shale is, some of the thickest areas, and we think we have at least that kind of value and probably a lot more value in our acreage up there, what we believe we have, as we continue to develop it.

Let me add that of ways that we would finance or bring in some dollars, JV probably in the Marcellus isn't real high on our list. JV almost anywhere is not real high on our list. There is a lot of operational and a lot of people issues that go with all of that. So, while we kind of are interested in what is going on, and prices keep going up, which values our acreage higher, we're not really looking for JVs at this point in time.

The other side of it, we're not buyers at those prices either. While we like what we have, we think we can put our dollars to work better some place else.

Thank you.

Thank you. Our next question is coming from Dan McSpirit of BMO Capital Markets.

Gentlemen, good morning, and thank you for taking my questions. Turning to New Brunswick, can you speak to well control in that part of the part of the world, and really what drew you to that part of Canada? Maybe some history of drilling in New Brunswick?

And then, secondly, can you speak to how it is you plan to dissect the opportunity, given your massive, massive land position, of course recognizing that it is very, very early innings?

Right. Well, in New Brunswick, there is a lot of shallow wells drilled many, many years ago. But there is actually two fields there in the southern part of what is generally called the Maritime Basin that goes off shore and then comes on shore in New Brunswick. Those two fields, there is one gas field, with what they know about it today it is about 250Bcf, but it's being drilled now so it could get bigger. It's conventional field. There's another small oil field that was found in the early 1900s. And really those two fields tell you that there is gas and oil in the system.

And I need to back up and talk a little bit about how we got into it. We started working on New Brunswick almost a year-ago, after looking at several different shales in a lot of different places in the US and in Canada. Thought that the there might be in the Maritime Basin a chance for a deeper shale called a Frederick shale, and start doing some work. As we looked at the southern basin that had the oil and gas in it, we reprocessed a bunch of magnetic data. And as we look north, it looked to us like there were some basins that could be there, that had the depth to basically cook the Frederick shale, both for an oil objective, conventionally, maybe, oil objective for the shale, maybe, gas objectives, conventionally, and gas objectives for the shale.

And the industry really hadn't seen that in the past. The industry's general interpretation was as you went north from these producing feel fields and where this producing field area was, that the basin shale was [way up] and would be 5,000-foot or less in depth. We're seeing things on the magnetics that make us indicate maybe as deep as 20 or deeper, 20,000-foot or deeper depths. That is what kind of keyed us into it, and that also they will you a little bit about what we're going to do in the future.

What we have to do is confirm that there really are deep enough basins there that we could have the right thermal dynamics to really cook the rock the way we want it cooked. And so what we will be doing is doing some more gravity and magnetic work; that tells you the shape of the basin, and gives you feel for depth of basin. We will be doing surface geocam work on the entire area. I think they were talking about 2,500 stations or something like that over the next year-and-a-half. And then we will layout a seismic program, that once we figure out where the deeper portions are we can shoot some seismic and you can see what the rock looks like in those areas. Towards the end of that three-year term, we have one well as a commitment to drill.

So over that three-year period of time we're just going to be delineating what we think is a basin and learn as much as we can about it, and then drill some wells and figure out how it goes from there.

Thank you.

Thank you our next question is coming from Nicholas Pope of JPMorgan Securities.

It's actually Dahlman Rose. Good morning, guys.

Good morning.

Real quick, just curious, you said 15 wells being drilled at -- in Marcellus this year; how many of those do you all think you will be bringing on line during the year?

Well, except for the very last ones drilled, you know, in December, we should get most of those on line during the year. We are currently [fermenting] and laying a short lateral to get to where we're going today, all the drilling in a few miles of the point we're at today, so once that line gets there, we'll be drilling and fracking and putting in that line and going from there.

All right. And then just in terms of capacity, you will have capacity to get the gas out of the area, the -- you all have plenty of capacity right now?

Yes, we have been -- we had committed in the past about $20 million a day firm, and then we're committing to other gas right now for the end of this year and then into 2011. We're comfortable we can get the gas out, certainly at the pace we're drilling now.

Okay. That's really all I had, thanks guys.

Thank you.

Thank you. Your next question is coming from Daniel Guffey of Thomas Weisel Partners.

You mentioned previously you drilled some 8,000-foot laterals; I was wondering if you could provide any 30 and 60-day rates? And then also if you guys have given an EUR, or have an internal estimate for EUR for these wells?

Well, first off, as I said that when have done the 8,000-foot laterals, they have been unique situations where we have drilled in a fault block that you couldn't do two 5,000, or there was some characteristic of the fault block that 8,000 made sense. Because of that, they are going to be somewhat limited.

From an IP standpoint, those are fairly high IPs. Those will be the 5 million a day type plus IPs. EURs though, depends on the fault block and how small the fault block is, and those kind of things, as to whether the EUR matches with that initial rate that you have. So I don't know that those are representative themselves of what you could do, if you were just out in an open area and drilled an 8,000-foot lateral.

Okay so, I mean, you mentioned I guess there are special situations. So how many 8,000-foot or more laterals do you expect that you will have -- I mean, can you even say right now?

I don't even know if I can guess that. You know we have done three or four -- I think we have three that are in the 8,000-foot range, 7,500 to 8,200, right now, and depending on where you're at, if you're over in kind of the eastern area, you may do one a quarter or something over there; if you're over farther to the west or central area, you're not going to do very many of them.

Great, thanks guys.

(Operator Instructions)

Thank you, there are no further questions at this time. I would like to hand the floor back over to Mr. Steve Mueller for any closing comments.

Thank you, Operator, and thank all of you for listening on the conference call.

There is just two last things I want to say. We are disappointed as a Company in the quarter, because we missed a guidance. And as I said, that tells you something about the robustness of the operation, and we're working on that. We're not at all disappointed in that table. And I will tell you, every once in awhile something will come up and say, well ,should we do the green completions because it may affect the table? That lasts about 30 seconds because we look at the economics and say, of course we do that. We will explain the table as we go through.

And if you look at that -- the table, while at surface, yes, we had less IP than we had last quarter, that average of 3 million a day IP in the areas we're drilling compared to what we would have averaged a year ago in those areas is tremendous, and we're excited about that. And I just want to make sure that all of you know that we are excited, even though the table looks a little different.

And then you come back to, did we ever discussions whether we should have that table in there or not in there? As I said in the past, that table is a learning curve not just for our Company but for the entire industry to follow the kind of things that happen as you drill these kind of plays out, and it will be there forever. We will be happy to explain it as it comes up, whether it is up on one of those numbers or down on one of those numbers as we go through.

So like I say, there is some disappointment. It's a little bit of disappointment. When you think about it, a 41% production increase, across the board better financials than we have had, only borrowed $20 million, and had over $3 million a day production rates for the quarter in Fayetteville; we had a great quarter.

And with that I thank you, and look forward to the next several quarters.

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you all for your participation.