西南能源 (SWN) 2009 Q1 法說會逐字稿

Good day and welcome to the Southwestern Energy company first quarter earnings teleconference.

At this time I would like to turn the conference over to Chairman and Chief Executive Officer, Mr. Harold Korell. Please go ahead, sir.

Good morning. Thank you for joining us. With me today are Steve Mueller, President of Southwestern Energy; and Greg Kerley, our Chief Financial Officer.

If you have not received 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 teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and 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're not guarantees of future performance and actual results or developments may differ materially.

To begin with on this report we had a very productive first quarter despite the efforts or the effects of the recent decline in natural gas prices. Our production from the Fayetteville Shale continues to climb as we move up the learning curve in the play. Our gross operated production from the play reached approximately 850 million cubic feet per day at the end of the first quarter compared to approximately 400 million cubic feet per day around this time last year. While we feel confident that natural gas prices will be higher for the longer term, the price of gas has fallen approximately 35% from year end 2008 thus causing a noncash impairment of our oil and gas properties.

As a result of the continuing low commodity price environment we are reducing our planned capital program for 2009 by an additional $100 million down to $1.8 billion which is approximately flat with our 2008 capital investments. The important thing to know is that commodity prices move in cycles and with the decreased drilling activity in our industry we are now positioned for an up turn in commodity prices. With our growing production volumes and financial flexibility, Southwestern is well-positioned to benefit. I will now turn the teleconference over to Steve for more details on our E&P and midstream activities, and then to Greg for an update on our financial results, and then we'll be available for questions.

Thank you, Harold. Good morning. During the first quarter of 2009 we produced 63.9 Bcfe, up 64% from first quarter of 2008. Our Fayetteville Shale production was 50.2 Bcf, more than double the 23.6 we produced in the first quarter of 2008. We produced 7.8 Bcfe from East Texas and 5.8 Bcfe from our conventional Arkoma properties. As we announced yesterday we're reducing our expected 2009 capital investment by approximately $100 million to $1.8 billion due to the continued low natural gas prices.

To achieve this capital reduction we are now planning to exit 2009 down 6 rigs, 4 in our Fayetteville Shale play and 2 in other producing areas. Due to our continued strong production performance partially offset by reduced capital budget, we now estimate that our full year 2009 production will range from 289 to 292 Bcfe up from 280 to 284 Bcfe.

In the first three months of 2009 we invested approximately $450 million in our exploration and production business activities and participated in drilling 190 wells. Of this amount approximately $366 million or 81% was for the drilling wells. Additionally, we invested $51 million in our midstream segment almost entirely in the Fayetteville Shale. In the first quarter of 2009 we invested approximately $416 million in our Fayetteville Shale play including both our E&P and midstream activities. At March 31, our gross operating production rate was approximately 850 million cubic feet per day up from 750 million cubic feet per day in mid February. During 2008 the majority of our gas from the Arkoma basin was moved to markets in the Midwest including through the Fayetteville lateral portion of the Texas gas transmission or Boardwalk pipeline which was placed in service on December 24. On April 1, the Greenville lateral portion of that Boardwalk pipeline was placed in service and we began transporting a portion of our gas to Eastern markets.

On March 31, our midstream segment was gathering approximately 920 million cubic feet per day through 890 miles of gathering lines in the Fayetteville Shale up from approximately 470 million cubic foot per day a year ago. In April 2009 Texas gas announced that there would be a temporary reduction on the Fayetteville lateral due to various activities including maintenance and pipeline inspections. The exact completion dates on these activities are unknown but is expected to be complete by the end of the third quarter. As a result, transportation of Fayetteville lateral as of April 24, 2009, was approximately 700 million cubic feet per day -- or BTU per day. Our capacity was approximately 500 million BTU per day to Bald Knob, Arkansas, including 365 million BTU per day to Lulu, Mississippi. We expect that the remainder of our Fayetteville Shale production will continue to be transported in other pipelines to Midwest markets until these issues are resolved.

We currently have 19 rigs running in the Fayetteville play, 15 that are capable of drilling horizontal wells and four smaller rigs used to drill the vertical portion of the wells. As I mentioned previously, we're currently planning on releasing four rigs in the Fayetteville Shale play area this year. This decrease in rig count means that we now expect to participate in approximately 600 gross wells in 2009 rather than our original plan of 650 wells. This is approximately the same number of wells that we drilled during 2008. Since 2007 the continuous improvement of our completion practices have resulted in a fairly steady quarter over quarter improvement in average initial production rates of operated wells placed in production.

The significant increase in average initial production rates for the fourth quarter of 2008 and subsequent decrease for the first quarter of 2009 primarily reflected the impact of the delay in the Boardwalk pipeline. Initial rates were higher in all of the delayed wells because wells were shut in for a longer period of time before being placed on production. In addition, we generally place wells with the highest initial rates on production first throughout the fourth quarter of 2008. As a result, the remaining backlog of delayed wells that were placed on production in the first quarter of 2009 generally had lower rates, particularly during January and February. Wells that were placed on production in January and February of 2009 had average initial production rates of 2.806 million Mcf per day and 2.749 million Mcf per day respectively. The wells placed on during March 2009 had average initial production rates of 3.375 million Mcf per day for the lump of April through April 15. We had placed 25 wells on production and the average initial rate of 3.763 million Mcf per day.

We expect that our average completed well costs in 2009 will be approximately $2.9 million per well as lower oilfield services costs are projected to more than offset the higher costs associated with the larger completions and longer laterals. Our first quarter wells had an average completed well cost of $3.1 million per well, average horizontal lateral length of 3,874 feet, and average time to drill to total depth of twelve days from reentry to reentry. Because of the continuing outperformance in our front end loading of our drilling, our Fayetteville Shale play, we expect production here to be between 238 and 240 Bcfe in 2009. This is up from our previous guidance of 229 to 232 Bcfe.

I will now move onto our two newer areas, the Haynesville Shale and the Marcellus Shale. The first horizontal well in our 50/50 joint venture was a private company targeting the Haynesville, Bossier Shale and Shelby and (inaudible) County, Texas, the Red River, 877 number 1, reached total depth in the fourth quarter of 2008. This well which had a completed lateral length of 2,718 feet was production tested at a rate of 7.2 million cubic feet per day in the first quarter of 2009 and is currently producing approximately 3 million cubic foot per day. The second horizontal well, the Red River 164 number 1 has reached total depth for the 3,818-foot lateral, and is expected to be completed and tested in the second quarter. Pending further results from these wells, we may invest more capital in the Haynesville Bossier shale play than previously planned. We currently hold approximately 17,350 net acres in the Texas joint venture and a total of 50,110 net acres that we believe may be prospective in the Haynesville Bossier shale.

In the Marcellus shale we currently have approximately 138,600 net acres in Northeast Pennsylvania, where we believe the shale's prospective. During 2008 we drilled our first four wells here including our first horizontal well on our acreage in Bradford in Susquehanna County. During the first quarter we increased our position in the Marcellus by approximately 23,900 acres.

Finally, we participated in drilling nine wells in the conventional Arkoma Basin and 11 wells in East Texas during the first three months of 2009. None of these Texas wells are James land horizontals, production from Arkoma and East Texas properties were 5.8 and 7.8 Bcfe respectively for the first three months of 2009 compared to 5.9 and 8.1 Bcfe for the first three months of 2008.

In summary, we continue to have solid results in our E&P and midstream businesses and expect continued strong results in the remainder of 2009 as demonstrated by our increase in production guidance. We decided to reduce our capital budget by approximately $100 million as we continue to focus on adding value during this period of reduced product prices. As Harold mentioned, when commodity prices rebound we will be well-positioned both financially and operationally as a growing low cost leader. I will now turn it over to Greg Kerley who will discuss our financial results.

Thank you, Steve. Good morning. As you have seen from our press release we had a very good first quarter despite the significant drop we have experienced in natural gas prices. For the first quarter of 2009 we reported a net loss of $432.8 million or $1.26 a share including $558 million after tax given test impairment of our oil and gas properties. The significant decline in gas prices from $5.71 per Mmbtu at December 31, 2008, for Henry Hub natural gas down to $3.63 at March 31, led to the ceiling test impairment. Excluding the noncash impairment, we recorded earnings of $125.5 million or $0.36 a share which was 15% increase over the prior year period.

Cash flow from operations before changes in operating assets and liabilities was up 31% to $372.6 million as our production growth more than offset lower realized natural gas prices. Our average realized gas price during the first quarter was $5.94 per Mcf, 23% lower than our average price a year ago. Our commodity hedge position increased our average realized gas price by $2.13 per Mcf in the first quarter which helped us offset some of the effects of lower spot market prices and widening location market differentials or bases that occurred during a quarter. We currently have approximately 47% of our 2009 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.48 per Mcf. We also have basis protected on approximately 131 Bcf of our remaining 2009 expected gas production through hedging activities and sales arrangements at a differential to NYMEX gas price of approximately $0.25 per Mcf. Our detailed hedge position is included in our Form 10-Q that was filed this morning.

Operating income for our E&P segment was $179.9 million in the first quarter of 2009, excluding the impairment charge, up from $165.7 million in the first quarter of 2008. The increase was driven primarily by the 64% growth in our production volumes which more than offset the decline in our average realized gas price and higher operating costs and expenses. Our lease operating expenses per unit of production were $0.78 per Mcf in the first quarter of 2009 compared to $0.77 for the same period in 2008. A modest increase was a result of higher per unit operating costs associated with the Company's Fayetteville Shale operations partially offset by the impact that lower natural gas prices had on the costs of compressor fuel in the first quarter of 2009.

General and administrative expenses per unit of production were $0.31 per Mcf in the first quarter of 2009, down from $0.42 for the same period in 2008. The decrease was primarily due to the effects of our increased production volumes which more than offset increased compensation and related costs associated with expansion of our E&P operations. Taxes other than income taxes were $0.13 per Mcf in the first quarter of 2009 down from $0.16 for the same period in 2008 due to changes in severance and ad valorem taxes that primarily resulted from the mix of our production volumes and lower commodity prices. In total our per unit cash operating cost and expenses declined 10% compared to the prior year period.

Our full cost pool amortization rate dropped to $1.82 in the first quarter down from $2.30 per Mcf in the prior year. The decline was due to the combined effects of our sales of oil and gas properties during 2008, the proceeds of which were credited to the full cost pool and our low funding and development costs. As a result of the ceiling test impairment charge in the first quarter, we expect that our amortization rate going forward with all other factors remaining constant will be reduced by between $0.30 and $0.40 per Mcf.

Operating income for the midstream servicing segment grew significantly in the first quarter of 2009 to $27.4 million, up from $10.2 million in the same period in 2008. The increase was primarily due to the higher gathering revenues and an increase in the margin from our marketing activities partially offset by increased operating costs and expenses. We ended the first quarter with approximately $80 million of cash on hand, nothing borrowed on our $1 billion revolving credit facility, and our debt to capitalization ratio was 25% even after the ceiling test impairment charge.

Continuing low gas prices have impacted our projected cash flows for 2009, and as a result we reduced our planned capital investments by approximately $100 million to end the year with approximately the same debt level as we originally planned. We believe we are very well-positioned to weather the current low commodity price environment with our strong balance sheet and financial flexibility. That concludes my comments so now we'll turn back to the operator and he'll explain the procedure for asking questions.

Thank you. (Operator Instructions) We'll go to Scott Hanold of RBC Capital Markets.

Good morning.

Good morning.

If we look at that impairment of $900 million, could you give a little bit of color on that, talk about was it some of the PUDs that were impaired or was it more of a tail?

On just a general comment, it is part of the full cost pool, but your PUDs are always going to have because they have capital against them are always going to have worse economics than PDPs, so on the reserve side any kind of cuts that were there would have been on the PUD part of it, but really, remember the impairments at full cost pull so there is a lot of things that go into it.

Thanks. Appreciate the color. I guess for my second question you guys obviously trimmed the CapEx budget, but they're showing just tremendous growth, and it looks like productivity is a key driver here. How do you kind of think about production growth in gases hanging around the $3 to $4 level? I notice some of your peers have curtailed productive rates on individual wells. Is that something you all would consider kind of how do you think about it?

Well, one first place to begin on that is how do we feel about producing at higher rates and lower prices. It feels like producing more and enjoying it less. We like to see prices higher. On the other hand we are fortunate that we're experiencing the improvements we are in our activities in the Fayetteville Shale, so the growth is a good thing. Steve, you may want to make more--?

I think there is two parts to that. Part of it is what about curtailing or something to do that way with production. We've kind of come to the conclusion working through our economics that if you're going to drill the well, need to put on production, so it is really a decision about drilling wells or not, and that was part of the reason that we cut the $100 million out of our capital budget. The other part of this is just remind everyone a lot of what we're doing still just like it has been from day one Fayetteville is learning, and we have got a lot to learn this year, and so when we put our budget together, it wasn't about growth rates. It was what did we need to learn to set ourselves up for the future, and that's really what we're trying to do.

Appreciate that. Thanks, guys.

We'll go next to David Heikkinen of Tudor Pickering Holt.

Good morning, guys.

David.

Wanted to walk through pipeline capacity and just kind of deciphering what's in your 10-Q and current capacity and how the Boardwalk line steps forward over the next three years and then also the firm commitments that you have beyond Boardwalk? Could you do that for us?

I will run through some top side things, and then we can go wherever you want to go with that from there. Today, as we said, we've got in the high 300s going all the way across Mississippi River and Eastern markets, and that's really right on schedule with what the original Boardwalk pipeline was supposed to do. Both Boardwalk and the various companies that we are involved in that pipeline have been trying to do some things to accelerate that overall production, and part of this maintenance and testing and things that we're talking about was to try and get a waiver that would give you a little bit higher operating pressure and by giving a little higher operating pressure, be able to get an acceleration on the amount of gas you could get across the Mississippi River. That's what's going on right now. They have run tests on the pipeline. There are some spots they need to repair on the pipeline, they'll work on that, and then we'll apply for this waiver. But as far as our actual production, we're producing about what we were supposed to under the contract through the Boardwalk pipeline.

Now, if we get the waiver which would be later this year, third to fourth quarter type things, we'll get a little acceleration, but assuming there is no acceleration, and towards the end of the first quarter 2010 the third phase of Boardwalk will become effective, and at that time the Boardwalk pipeline will be approximately 1.2 Bcf a day total. We'll have about 800 million a day capacity on that line, and then the other big pipeline that we've got firm on is what we call the Fayetteville Express. Fayetteville Express is in its early stages, but it's still on schedule looks like for an early 2011 timeframe for first sales, and then there is really three steps in that contract also, and in 2012 we have got about 1.2 Bcf a day on a 2.2 I think Bcf a day total pipeline.

Thanks.

One other thing. We do have firm capacity still that goes in the Midwestern markets through Ozark and some of these other lines as well.

That was about 400 million a day.

Somewhere in that range. It varies a little bit month to month. That's somewhere in that range. So we're probably as they're fixing and repairing some of these spots and the Boardwalk pipeline we'll see some days there where we may be a little curtailed, but overall we can get our gas out. It is just the big thing is get as much as you can across the Mississippi River, and that's what all of us are trying to do.

As you think about your basis hedges and kind of where your non-hedge gas realized prices are kind of tied to all the pipeline moves, can you think about -- I guess you're in the 300 million, 400 millionish a day that's going to high 300 millions that goes to Eastern markets. Everything else goes Center Point and Ozark. How should we think about differentials over the kind of next couple quarters?

Well, we've said in the press release that we have purchased basis on 130 Bcf of about $0.25, so we have already locked that in. Now, the real trick is as you take gas out of the Mid-Continent across the Mississippi River, that changes the basis on what the Mid-Continent gas, is so I don't know how to tell you how to predict that because a lot depends on how much is going which direction.

Okay. That's the deciphering. I guess we know what your locked in volumes are, we can just make some assumptions of Center Point and Texas, Oklahoma gas prices and get a blend. I will try that.

That's basically what we do.

The other side of kind of improving operations and pilot tests and the Fayetteville, I think, is continued to see well quality step up. You talk about the average rates and kind of how that continues to get better and then also thoughts around pilots you want more data always, so how that's progressing? And that's it.

We're trying to learn several different things is what we're doing right now. We're continuing to tweak and work with our completions, and the biggest thing we're doing in that side if you remember in the fourth quarter we had done a couple of wells at 50-foot first spacing hedge, started doing 75-foot per spacing, and the first and second quarters of this year was to test both of those. We're continuing to do that. 75 is looking really good. 50 we don't have enough information yet to tell you much about that, but so far the first spacing is reduced -- is continuing to add to that productivity.

The other thing we're doing was just learning about spacing, and we don't have enough information yet as we've talked about in the past. It is somewhere between 400 and 500 wells that we have got set to learn about that spacing. Those are all getting drilled now, and it is, all that far needs about six months production before we can tell much.

I guess with two-thirds to the majority of your drilling program going towards spacing, it really isn't piloting, it is just optimizing how much down spacing you're going to have? Is that a--?

Just trying to figure out what spacing might be in various situations, both geological across the play and in relationship to older wells that have already been drilled.

Thanks, Steve.

We'll go next to Rehan Rashid of FBR Capital Markets.

My questions have been answered. Thank you.

We'll go next to Joe Allman of JPMorgan.

Thank you. Good morning, everybody.

Good morning.

Could you help with us the non-Fayetteville production? I know in the fourth quarter the non-Fayetteville production was down and it bumped up in the first quarter. Can you explain that and then just give us some sense of the direction of that?

I think the direction is kind of easy to give you a sense on. Like a lot of companies where we haven't been doing that much learning, we have cut our capital considerably, and so we just don't have that much activity either first quarter or going in for the rest of the year, so I would expect that in general you're going to see our production go down not up in those areas.

Steve, was the main driver for the increase in the first quarter the James Lime horizontal wells?

The little that was there was James Lime, yes, all there. We're only drilling, other than those couple of wells we talked about in the Haynesville, the only thing we're drilling outside Fayetteville, we have one rig working in Midway, Arkansas, and then we have got James Lime wells going down, and some of that is timing. For instance, right now we have got seven wells that we have to complete that are James Lime wells that completions will start this week, and they got backed up a little bit because of pipeline issue, so it is going to bounce around from quarter to quarter, but in general you're not going see an increase in production.

Got you. And then could you just help us with the thinking behind just dropping the rigs in the Fayetteville, I guess, and how that fits into the overall plan of development there? Are you increasing efficiency so much that you just actually just don't need as many rigs and as you drop down to 11 horizontals and 4 verticals by the end of the year, what's the thinking about in the next year and obviously commodity prices are a big factor? Can you just help us with the thinking behind the move here?

Yes. There is two things behind the move. We're trying to figure out how many wells we need to learn, and that's a certain minimum number, and we have to get to those numbers, and then we're looking at the overall market out there and how much we're making cash flow wise, wanting to be as flexible as possible as we go out into the future. It was a combination of those two that were the drop in the overall capital budget. We think we can get enough wells drilled and we'll get those drilled as quickly as we can and those rigs will drop off in the second part of the year. If the commodity prices come around, I would fully expect you'll see us reevaluate. If they go down we'll reevaluate, and if they go up we'll reevaluate. Certainly we have got a lot of wells to drill, so long-term 11 rigs or even 15 rigs aren't the right answer.

I think to add to that the discussions that we have had in the past have been that we want to stay true to our concepts about present value created per dollar invested, and when we look at prices now and use the forward curve, the economics of what we're drilling in the Fayetteville Shale are still fine in terms of a present value created per dollar invested. If one just looks at today's price and keeps it flat, then those are in a little bit of a pinch, so the other thing that we'e talked about in the past is we want to keep an eye on our debt levels, and we want to maintain flexibility and not incur an inordinate amount of debt.

The current move is, I would say it's a compromised position of what price should you really use to do the economics? Well, I don't think you should use today's price flat, but still it has a bearing on how we feel about it. It also has a bearing on our borrowing, so the step back of about $100 million continues to give us more options in the future as to which things that we can do and pursue by not drilling the wells today, by cutting $100 million of capital out, it is just $100 million we still have in the war chest available in our borrowing capacity, so I would say it is a conservative approach to it. At a time when our production volumes are growing tremendously anyway.

Okay. That's helpful. Thank you very much.

We'll go next to Tom Gardner of Simmons & Company.

Good morning, guys. A question about your hedging strategy going forward, specifically looking towards 2010. Can you talk about perhaps what gas price would you consider too low to lock in as you look to hedge out 2010?

Well, current prices are obviously too low for us to lock in. For us we've got a really good hedge position for what we've got hedged right now for the remainder of the year, close to mid 8s, and if you look at long-term data, it looks like historically somewhere between $6 and $8 is what the industry needs to break even for which shale plays maybe that's a lower number than it has been obviously with conventional drilling so what is that long-term rend going to be, is that 6 to 8, is it going to be 6 to 7, but we think that the marginally prices have got to get above 6 before we start really looking at the screen very hard, and we think that we're going to have opportunities to hedge when we do see that intersection of a supply curve start hitting closer to the demand curve. We'll be watching it very closely, but there is nothing in the near term that we expect to be doing.

I got you. That's helpful. And a more specific question related to drilling costs, specifically cost savings from pad drilling, you're estimating I guess the average well cost to go down to 2.9. Can you give us an idea of what your pad drilling savings is and what the percentage of I guess second well on a pad drilling might look like from 2009 going into 2010?

As you know, we're building pads everywhere, and in 2009 and as well as 2010. We'll be drilling about 200 wells that are just single wells holding sections, and in some cases tha may be two wells off a pad. You don't get a lot of cost savings there. You get a little bit of rig time skidding 10 feet versus moving a mile or something to a pad which is about a day's worth of rig time. The real cost savings when we do development and get into full development phase. I don't know exactly when that is. It is not 2009. It is probably not in 2010 for much of it.

When we get to that point, we should start seeing some significant savings, and to give you a feel for that, one of the recent projects we did trying to do some down spacing, we drilled four wells off a single pad, and it took us 28 days total to drill those four wells, so that's 7.25 days of well, and so we know that the twelve we're doing right now is not the right number when we do get to the development phase, in addition to that when you're fracking on the location where you have several wells, we do use same techniques they use in the Barnett where you use the dippers and move back and forth between. There is quite a bit of savings in both time and amount of effort plus hopefully even better fracs when you get done with that again, except for just a little bit of the down spacing work we got wells close together, we got two or three on a pad, you haven't seen any of that savings yet.

Thanks, guys.

We'll go next to Gil Yang of Citi.

Good morning. Could you clarify the amortization benefit of $0.30 to $0.40, was that seen in the first quarter or was that only second quarter and going forward?

Gill, this is Greg Kerley. That will be seen going forward. The impairment charges made at the end of the period and the amortization rate of $1.82 is what we average for the first quarter going forward that we would expect that to be $1.40 to $1.50 an Mcf equivalent with all other things being equal.

Okay. Great. Question I have is can you talk a little bit about the Haynesville in terms of the well in Shelby that IP that 7.2 million a day is that a 24 hour test, is it a 30-day test, and currently producing at 3 million? Is it being curtailed in any way, and how many fracs were there and how closely spaced were they?

Just remind you it is 2,700-foot lateral. I think it was six stages of fracs in it which from a stage per foot of lateral is about equivalent to what you would see in other Haynesville wells, just laterals considerably shorter than the ones you normally see rates on. That test was the test that we gave to the state after we put on the well on production, and it was not an IP or some kind of test rate that was immediately after the well first was tested, so there was a little bit of timeframe on that. Those states are -- the state testing is 24-hour testing. As far as are we choking it back or is anything from that standpoint, 1364 choke i what it's been flowing out for considerable period of time, so I don't know if you want to call it choke back or not, but that's what we've been flowing it at. Wells holding up strong, you're seeing very little pressure drop, 1364, so that's kind of what the well is.

Thank you.

We'll go next to Brian Singer of Goldman Sachs.

Thank you. Good morning. Sorry about that. Wanted to follow-up on, I believe it was Scott, David and Joe's questions with regards to CapEx versus learning versus growth. When you considered whether to drill even less and say keep production guidance flat versus increasing, can you speak to the gas price break even and discount rate in your present value calculations and also how much flexibility exists for further budget reductions until you may begin to give up acreage in the Fayetteville or other areas?

I can start with giving up acreage part of that. The drilling, the rigs we have left in our conventional areas basically are there holding acreage. There isn't much other than that going on in that direction. In the Fayetteville as I said of the 600 wells roughly 200 of those will hold acreage this year, and we need to drill out that pace for the next couple of years to hold all the acreage, but we shouldn't have any issues in doing that. From the standpoint of holding, having less production and economics, for our, going back to Harold's comment about our PVI goals, for our PVI goals you need to have a flat price of somewhere in the mid-4's to hit our PVI goals, and that's what he said before, if you start just a flat price going out, you're challenged right now in economics. If you have some kind of escalator in the future, we still are going to have decent economics than what we're doing, so that's part of the debate that's been going on internally, how much do you slow down, when do you slow down, and how do you keep that flexibility?

Steve, and those mid-4s are with today's well costs. They're not with the development scenario maybe that would occur as we're drilling multiple wells on pads and so on down the road.

Thanks.

I think that answered everything you had there.

I think so. I can follow-up a little on the discount rate question. But secondly it seemed like operating expenses that were not related to internal transfer costs have fallen significantly on a per unit basis in the last couple quarters, and wondering if there is any color, first of all, if that is the right interpretation and if there is any color on what's driving that?

We're very sensitive on our LOE costs to the gas price because about half of that total LOE is compression, and almost all of that is the gas price, so as you have seen that gas price go down over the last couple of quarters, you're seeing our LOE go down. The actual what I call fixed LOE has actually gone up a little bit, it's almost flat but it's gone up a little bit, so really you're just seeing the gas price move up and down is what's happening.

Thank you.

We'll go next to David Snow of Energy Equities Inc.

Hi. I was hoping everybody would have dropped off before I asked this, but do you have to do your ceiling test on a quarterly basis or is it optional as to whether to do it annual or quarter?

No. You have to do it at the end of each quarter. There is certain rules that would change, or that are scheduled to change at the end of the year about what pricing you use that you use more of an average price, and if we were in that time period with those rules, we would, it looks like we probably would have been fine, but right now as we go through this year on a quarterly basis the rules are what prices in effect at the end of each period and the second and third quarter also. End o f the year will be different rules.

Does that enter into your any of your covenants indirectly or is it not an issue?

No. It is not an issue at all with our covenants. We have those kind of noncash, any noncash adjustments to our earnings or equity are excluded. But again, even if it was included we're 25% debt-to-cap, and we do have a financial covenant that our debt can't exceed 60%, so we have significant room in our covenants, but it is not considered one of the effects of it.

Okay. I was wondering if you can translate your formula for PV needs to just what the straight ROI is at 450 flat?

On an internal rate of return type thing, compound rate of return, roughly the 20% range. It depends on the shape of the wells and the way it works, but it is roughly that number.

On that 75 -- changing your spacing to first, to 75 feet, what type of improvement do you get versus what you have been doing?

I think if you just look at the chart and look at the IP changes as you went from I take the average of the first and fourth quarter and then look at that compared to the third quarter, that's really when we put the 75 foot in effect so that's probably the best way to answer that one.

How much more does it cost?

I think we're trying to limit this to two questions per person if we could.

All right.

We'll go next to Robert Christensen of Buckingham Research.

Good morning, guys. Question for you. What's your next decision point on a Haynesville Wildcat? I guess you drilled two wells, but what comes up next in the joint venture and who makes that decision? You or your private party?

We are carried completely for the first two wells through the pipeline. The second well will be completed here in the next 45 to 60 days, and you'll obviously, the next big thing is get that completed, see who it looks like, compare it to your first well, and then the other big thing is that there are some wells drilled around us by other companies, and get a little information on what they've got and hen you can decide how good it is and what other drilling you want to do.

Is there take away capacity in the area?

Yes.

And a final off subject, the Marcellus, you just leased land there? I guess in the quarter. What were you paying on average in other terms related to the 23,900-acres, please?

I think we said in the last conference call that we paid a little over $8 million for about 21,000 acre, and we did some cleanup work out there to get the last couple thousand acres.

Thank you.

We'll go next to Mike Scialla of Thomas Weisel Partners.

Hi, guys, just a couple follow-ups to Bob's questions on the Haynesville. Based on what you have seen on the first well and maybe some of the results that you have seen from other operators, how far away do you think from making that economic right now and what did that first well cost you?

The first well had a lot of science on it, so it is not really representative on its overall cost. We think we need to have something less than $10 million between 8 million and $10 million total costs on the well, and we need a little more encouragement probably on the production rate and what we have seen to date to just put on the able and say this is a great play, but it is very intriguing.

Maybe with a longer lateral and some cost savings to you--?

Once you start a little longer lateral and take out the fact that we drilled the vertical and cored both of these wells and get into really where you're drilling wells for production, it is interesting that point.

Same on the Marcellus, what's encouraged you to have the acreage that you have?

Well, there has just been a lot of wells. In 2008 there was almost 300,000 drilled in the Marcellus. There were several in and around our acreage besides the ones we drilled, and we really like what we're seeing from a lot of different perspectives there. Technically, probably the thing we like best is there is more free gas in the Marcellus versus absorbed gas than a lot of the shales out there, and you're seeing some pretty good initial rates because of that.

Thank you.

Next to Ray Deacon of Pritchard Capital.

I was wondering if you could comment on the $1.8 million budget. If you do get more reason for optimism and increased spending on the Bossier Haynesville, would you take rigs away or would you add to the $1.8 billion in CapEx?

We're going to have to wait and see. I don't think we're prepared to answer that question right now.

Got you. Kind of a little bit tied to that, you're going to be adding a lot of PDPs between now and November, there's a lot of concern about what the banks might do to credit lines. I guess do you feel like you could be slightly more constrained at the end of this year in terms of availability to you on your borrowing base, six, seven months from now or do you think the PDPs will offset that?

Ray, this is Greg Kerley. You might not recall, our credit facility is somewhat of an anomaly compared to a lot of our peers is we do not have a borrowing base facility. It is an unsecured line, and so it wouldn't have any impact and have any impact with the swings in prices.

Thanks very much.

We'll go next to Brian Kuzma of [Weiss Multistrategy].

Good morning, guys.

Good morning.

When you look at your April IP rates, around hat 3.7 million a day, I mean, does that mean you guys are seeing like 6 million and 7 million a day IP rates your goodwill?

We haven't seen any?

Okay.

There has been a 6 reported by another company out there, but we haven't seen 6 and 7.

Okay. And then just to clarify on the hedging and the take away, when you talk about having those quantities basis hedged in the second half of the year, that's in addition to the 365 you've got to Lula, Mississippi?

What we have, we've got gas hedged at a certain price, and that total for the year was about 130 Bcf, it was like 134 Bcf, and then basis hedging is just a difference between NYMEX and whatever you have at a certain delivery point, and that's a different kind of hedge. You're just hedging that little bit of basis. It happens that for the next three quarters we have roughly 130 Bcf of basis hedge, but those are two different kinds of hedges.

I got it. So you guys are -- when you combine your FT with our basis hedges, I should look at that as you guys being 90% hedged out of the Fayetteville, then?

No.

No, that's not right?

No. You have to hedge basis to certain points. There is certain aggregating points in the country. For instance, some of our gas that's going into Ozark pipeline, for instance, has an aggregation point that's in the central part of the U.S. other parts southeast or you could be true NYMEX in Louisiana, and so your basis is just the difference between NYMEX and whatever that aggregation point is, and it is not a physical hedge like our other hedges are on price.

Okay.

We'll go next to Jack Aydin of KeyBanc Capital Markets.

Hi, guys, most of my questions were answered, but I have one. Looking at your acreage on the 105,000 acres in the Angelina trend, did you test the Haynesville formation in this acreage this year at all or last year?

The test we talked about that Haynesville well is in kind of the middle of that acreage position, that's where that is at.

Okay. Thank you.

We'll go next to Marshall Carver of Capital One Southcoast.

Yes, a couple quick questions. When you talk about needing wells to cost 8 million to $10 million in Texas, Haynesville Bossier were you indicating that the first well was more than $10 million but you think you can get the 8 million to 10 million longer term or how should we think about longer term costs there?

I think you can certainly make an AFE that would show that we can drill a well for 8 million to $8.5 million. I can tell you that the first two wells we drilled as I said we took whole cores, we ran a bunch of different logs that you normally wouldn't run, and we've taken those whole cores you actually drill a vertical well first and then backed up and did the horizontal part of the well, so, yes, it was considerably higher than the 8 million to $10 million range.

That's helpful. The April wells that you drilled so far in the Fayetteville, are those reflective of what you think the Q2 wells will be like for IP rates or is there anything special about April that you probably won't get in May?

I have no idea. There is nothing different about where we drilled wells really for the last 2.5 quarters. We're drilling across the entire play. We're drilling a lot of different areas that we're targeting, and there is nothing different about the third quarter, second quarter, first quarter, in that respect. Now, statistically all kinds of weird things happen, and as you're learning that just goes with it, so I can't even kind of guess what's going to happen.

Okay. That's helpful. Thanks. Good quarter.

Thanks.

We'll go next to Jeff Hayden of Rodman and Renshaw.

Hey, guys. Just a quick follow-up to Brian Singer's question from earlier. When you're talking about the wells, the well counts you need to hold your acreage, was that the 200 wells you referred to that you have to keep doing to kind of be able to hold all your acreage?

Yes.

Okay. And then assuming you're just kind of stay at the 11 horizontal rigs, about how many gross wells do you think you would drill next year?

Well, we're averaging about 11 days a well. I would have to -- it's 540, 500 and something, whatever that number is.

And then out of that about how many are the kind of outside operating wells versus how many of those are the ones you guys would operate?

Well, this year roughly 100 of the 600 wells are outside operating.

Okay. I appreciate it, guys.

We'll go next to Omar Jama of Owl Creek.

Good morning. I had a question on your type curve chart, that you have seen a notable improvement over the last few quarters and years, and two questions really. One, just eyeballing the chart, it appears that the declines have become steeper, and so I am just wondering if you're not just pulling forward production as opposed to increasing the overall EUR from some of these wells? That's the first question.

I think you need to be a little careful calling them type curves at least from the production data. We put type curves on there, but you've got to remember that what's happening here is you're rolling through the increases in IP 30 and 60-day rates, so as you follow this over time, those curves have kind of pulled themselves up over same, so we just have to watch as we go into the future, but I don't know that there is anything there that we see that says we're accelerating versus some other time.

Okay. And the other question I had is seemed like a couple of years ago you were doing a lot more drilling and just seeing what you had as opposed to now where you seem to be getting a little more aggressive in the development. I know you still have a huge amount of running room. I am curious if you could just talk us -- you say you're drilling across the play, but seems like you might be, actually might have found a better area within the play that you're more focused on recently, so I am just curious if you could share your thoughts on what we can infer from some of the data you're presenting here about the potential longer term for the kind of results that you will see across the whole play as opposed to perhaps the sweet spots that you're drilling now?

I am not sure, if you saw a map where we're drilling I don't know that you'd say we were drilling any sweet spots. We literally, on 800,000 acres, the only place we haven't been drilling and we will be drilling later this year is a little over 100,000 acres in the far Northwest corner that's federal, and we've got the federal unit almost together, and then we'll drill on it this year, but other than that we drilled across the entire play. Probably the other way to kind of answer your question, of the roughly just under 1,000 wells that we have drilled and completed, about 290 of those wells were 3 million a day or better, and if you looked at a map where that's at, they're across that entire acreage plot. There is just an obvious sweet spot where they're all sitting there and then drops off from that, so I don't know that we found the best spot or the worst spot. Certainly there is geologic differences as you go through, there's faulting, and all kinds of things of thickness and that, but our intent has not been to drill just one little sweet spot.

But do you think the data you're presenting is an accurate sampling or is it a large note sample to have a feel or do you think it is still too early to be able to infer what the longer term EURs will be from the data we have?

I think if you look at whether it is the table where we've got the number of completions per quarter, we're consistently doing between 70 and 100 completions per quarter. Certainly if you start talking about 70 you might talk about statistics being off a little bit, but if you're off 100, you start getting enough for statistics there. When you look at the actual production graph, we do have the data there on how many wells, and obviously the early part of that has a lot wells than the later part, so the far end of that has less statistical value than the front end, but we're learning. From day one we've been learning, we're still learning a lot. Development is still a ways out because we tried to move some of these major things.

That's helpful. Thank you very much.

(Operator Instructions) We'll take a follow-up from Scott Hanold of RBC Capital Markets.

Thanks. One real quick follow-up. You gave some of the info away but of the 600 wells you have planned for 2009 in the Fayetteville, I think you indicated 100 of those were nonoperated wells. What was that number at when you were originally targeting 650 wells and do you expect there could be some risk as other operators pull back CapEx a little bit?

We've actually in our revised capital budget, we've actually added about $10 million to the outside operated. We have seen more AFEs than we originally planned, and that's not that many more wells, but we're not seeing any slack there.

Okay. So how--?

Let me put it this way. We're seeing it two different ways. The number of AFEs have actually increased a little bit here recently. The other thing that's happened is that our working interest in those AFEs has gone up since our original budget and what we assumed in the original budget also.

And how correlated are AFEs to, against those outside operator's ability to actually go and out drill those wells?

It is a fair correlation.

Okay. Thank you.

Some of those wells don't get drilled. Usually they drill them.

Thank you.

We'll take a follow-up question from Rehan Rashid of FBR Capital Markets.

Not to beat a dead horse here, but the improving IPs then sequentially is simplistically the more tighter fracking, is that the driver?

A combination of longer laterals, the perforation clusters, and the frac jobs we're doing, yes.

Okay. The $2.9 million per well, does that reflect most of the service costs deflation we have seen or should we expect all else being equal that cost to come down because of cost reductions?

That has our estimate for what reductions will be, yes.

Last one, on free gas and absorb gas have you kind of begun to notice when does absorb gas kick in and how could that help the longer term decline rates?

We really have not -- I assume you're talking about Fayetteville Shale. We have not got a good feel for that yet. That's one of the things we've been trying to monitor but don't have a good answer yet.

Okay. Thank you.

We'll go next to David Snow of Energy Equities Inc.

I was just trying to pull up a map of your drilling, and I was astounded when you said that it has been pretty constant over the whole play. I was thinking that the, just the thickness alone and the depth varies considerably. Am I right that you have gotten away from the whale and the various sections of identifying the play and it is all pretty much giving you comparable results?

I won't say it is giving us completely comparable results. You still have in the shallow section lower pressures and in general you're going to have a little shorter laterals than you are in the middle or deeper parts of the play, and there are certain parts of it that have more or less faulting as you go through it, but consistently across the play we have seen 3 plus million a day wells.

Terrific. Okay. The 75-foot intervals, are they costing you a lot more per well or just about a little bit more?

Kind of the way to think about it, a year ago 60% of the we will cost was drilling. 40% of the well cost was completion. Today it is almost flip flopped, about 40% of it's drilling because we've taken the days out of drilling curve but because we're putting more energy in the ground and about 60% is completions.

Of the 2.9, how many is it like another 50 million to go to 75-foot intervals?

That 2.9 has reflected both 50, the percent that we think will be 50-foot spacing, 35-foot spacing and any other spacing, so that's kind of a combination of everything.

Thank you very much.

At this time we have no further questions. I would like to turn the conference back over to Mr. Harold Korell for my additional comments.

Thank you. Thank all of you for joining us today. I wanted to end with just sort of the big picture. For those of who you have had an opportunity to see our annual report, there is one bird that seems to be leaving the flock in a positive direction, and we have done that as we have said before through a real tight focus on value creation, and idea generation, and we're continuing that today. We are walking through a period of some stress in our industry very clearly, and, but where I see this going is out the other end of this there is a blue sky ahead. Thanks for joining us, and have a good day.

That concludes today's Southwestern Energy Company conference. Thank you for your participation.