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Southwestern Energy Company (NYSE:SWN)

Q1 2009 Earnings Call

April 28, 2009 10:00 AM ET

Executives

Harold M. Korell - Chairman and Chief Executive Officer

Steven L. Mueller - President and Chief Operating Officer

Greg D. Kerley - Executive Vice President and Chief Financial Officer

Analysts

Scott Hanold - RBC Capital Markets

David Heikkinen - Tudor, Pickering & Co.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Joe Allman - JPMorgan Securities, Inc.

Thomas Gardner - Simmons & Company

Gil Yang - Citigroup

Brian Singer - Goldman Sachs

David Snow - Energy Equities Incorporated

Robert Christensen - Buckingham Research

Michael Scialla - Thomas Weisel Partners

Raymond Deacon - Pritchard Capital Partner

Jack Aydin - KeyBanc Capital Markets

Marshall Carver - Capital One Southcoast

Jeff Hayden - Rodman & Renshaw

Operator

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.

Harold M. Korell

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 and 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 Statement sections of our annual and quarterly filings with the Securities and Exchange Commission.

Although we believe the expectations expressed are based on reasonable assumptions and are 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 affects 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 is falling approximately 35% in year-end 2008, thus causing a non-cash 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 decreased drilling activity in our industry, we are now positioned for an upturn 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.

Steven L. Mueller

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 are 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 to six rigs; four in our Fayetteville Shale play and two in other producing areas.

Due to our continued strong production performance partially offset by a 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 well. 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 operated production rate was approximately 850 million cubic foot per day, up from 750 million cubic foot per day in mid-February.

During 2008, the majority of our gas from the Arkoma Basin was moved to market from the Midwest, including drilling (ph) of 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 it began transporting a portion of our gas to Eastern markets.

On March 31, our midstream segment was gathering approximately 920 million cubic foot 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 inspection. The exact completion dates for these activities are unknown but is expected to be complete by the end of the third quarter. As a result, transportation at Fayetteville Lateral as of April 24, 2009, was approximately 700 million cubic foot per day or Btu per day. Our capacity was approximately 500 million Btu per day through Bald Knob, Arkansas including 365 million Btu per day to Lula, Mississippi.

We expect that the remainder of the Fayetteville Shale production will continue to be transported on other pipelines to Midwest markets until these issues are resolved.

We currently have 19 rigs running in the Fayetteville play; 15 are capable of drilling horizontal wells and four smaller rigs are used to drill the vertical portion of the well. As I mentioned previously, we're currently planning on releasing four rigs in Fayetteville Shale play earlier 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 operating wells based on production.

The significant increase in average initial production rate for the fourth quarter of 2008 and subsequent decrease for the first quarter of 2009 primarily reflected the impacts of the delay in the Boardwalk Pipeline. Initial rates were higher in all the delayed wells because wells were shut-in for 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 Mcf per day and 2,749 Mcf per day, respectively, for wells placed on during March 2009 had average initial production rates of 3,375 Mcf per day for the month of April through April 15. We have placed 25 wells on production and average initial rates of 3,763 Mcf per day.

We expected our average completed well cost in 2009 will be approximately $2.9 million per well as lower oilfield services costs are projected to more than offset higher costs associated with 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 the total depth of 12 days from re-entry to re-entry. Because of the continuing out performance in our front end load we're drilling in 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 on to 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 in Shelby and San Augustine Counties, Texas, the Red River 877 number one, 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 the rate of 7.2 million cubic feet per day in the first quarter of 2009 and it's currently producing approximately three million cubic foot per day.

The second horizontal well, the Red River 164 number one has reached total depth for the 3,818 foot lateral and is expected to be completed and tested in second quarter. Pending further results from these wells, we may invest more capital in Haynesville/Bossier Shale play than previously planned. We currently hold approximately 17,350 net acres in the sector joint-venture and total 50,110 million acres that we really made perspective in the Haynesville/Bossier Shale.

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

Finally, we participated in drilling nine wells and conventional Arkoma basin and 11 wells in East Texas during the first three months of 2009. Nine of these Texas wells are James Lime horizontals. Production from our Arkoma and East Texas properties were 5.8 and 7.8 Bcfe respectively for the first three months 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 Haynesville (ph) Midstream businesses, and we expect continued strong results the remainder of 2009, as demonstrated by our increase in production guidance. We've 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'll 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.

Greg D. Kerley

Thank you, Steve and good morning. As you've seen from our press release, we had a very good first quarter despite the significant drop we'd 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 even test impairment of our oil and gas properties.

The significant decline in gas prices from $5.71 per MMBtu at December 31, 2008, or Henry Hub natural gas down to $3.63 at March 31, led to the seasonal test impairment.

Excluding the non-cash impairment, we recorded earnings of 125.5 million, or $0.36 a share, which was 15% increased 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 basis that occurred during the quarter.

We currently have approximately 47% of our 2009 projected natural gas production hedge through fixed price swaps and collars at a weighted average core 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 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 a 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 leased 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. The modest increase was a result of higher per unit operating cost associated with the company's Fayetteville Shale operations, partially offset by the impact that lower natural gas prices had on the cost 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 cost, associated with the expansion of EMP 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 have 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 fuel amortization rate dropped to $1.82 in the first quarter, down from $2.38 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 fuel, and our low funding and development cost.

As a result of the season test impairment charge in the first quarter, we expect that our amortization rate going forward, with all other package remaining constant, will be reduced by between 30 and $0.40 per Mcf.

Operating income for our Midstream Services segment grew significantly in the first quarter of 2009 to 27.4 million, up from 10.2 million in the same period of 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 cost and expenses.

We ended the first quarter with approximately 80 million of cash-on-hand, nothing borrowed on our one billion revolving credit facility and our debt-to-capitalization ratio was 25%, even after the season test impairment charge.

Continuing low gas prices that impacted our projected cash-flows for 2009 and as a result we've 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 financial flexibility.

That concludes my comments. So now we'll turn back to the operator, who'll explain the procedure for asking questions.

Question-and-Answer Session

Operator

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

Scott Hanold - RBC Capital Markets

Good morning.

Harold Korell

Good morning, Han.

Scott Hanold - RBC Capital Markets

When -- 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 parts that were impaired or was it more of a tail?

Harold Korell

Just a general comment, its part of the forecast pool. But, your part joy (ph) is going to have, because they have capital against them, or else going to have worse economics than CEPs. So on the reserve side, abd kind of cuts over there have been our first part of (inaudible) remember the impairments have full-cost pools so there's a lot of things to go and do.

Scott Hanold - RBC Capital Markets

Okay, okay, thanks. I appreciate the color. And I guess for my second question, you guys obviously trimmed the CapEx budget. But it's showing just tremendous growth and it looks like productivity is a key driver here. How do you kind of think about production growth and gas is staying around the three to $4 level; I know some of your peers have curtailed productive rates in individual wells, is that something else would consider kind of how do you think about it?

Harold Korell

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

Steven Mueller

Yeah, I think there is two parts of that. A part was, what about curtailing or something to so with production. We've kind of come to the conclusion working through our economics tat if you are going to drill a well you need to put on production. So, it's really a decision about drilling wells or not. And that was part of the reason that we cut $100 million out of our capital budget.

The other part of this, just to remind everyone, a lot of what we're doing is still just like it has been from day one Fayetteville is learning (ph) and we've got a lot to learn this year. And so, when we put our budget together, it wasn't about growth rate. It was what did we need to learn the sales goes up for the future. And that's really what we're trying to do.

Scott Hanold - RBC Capital Markets

Okay. I appreciate that. Thanks guys.

Operator

And we'll go next to a David Heikkinen of Tudor, Pickering & Co.

David Heikkinen - Tudor, Pickering & Co.

Good morning, guys.

Steven Mueller

Hi, Dave.

David Heikkinen - Tudor, Pickering & Co.

I wanting to walk through pipeline capacity and just kind of decide for what's in your 10-Q and kind of 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?

Greg Kerley

I'll run through some cost side things. And we can go was where we want to go with that from here.

David Heikkinen - Tudor, Pickering & Co.

Yeah.

Greg Kerley

Today as we've said, we've got in the high 300s going all the way across the Mississippi River in the Eastern markets. And that's really right on schedule of what the original Boardwalk pipeline was supposed to do. Both, Boardwalk and the various companies that 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 higher operating pressure that will get an acceleration on the amount of gas you can get across Mississippi River.

That's what's going on right now. They've run tests on the pipeline. There are some spots they need to be repaired on the pipeline and 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 the under the contract treaty with Boardwalk Pipeline.

Now, if we get the waiver, which would be later this year, third to fourth quarter type thing, we'll get a little acceleration. But assuming there is no acceleration and towards the end of the first quarter of 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 is still on schedule looks for a early 2011 timeframe for first sales and then there is really three steps in that contract also and in 2012 we've got about 1.2 Bcf a day on a -- I think two Bcf a day total pipeline.

David Heikkinen - Tudor, Pickering & Co.

Thanks.

Greg Kerley

Well, one other things, we do have firm capacity still that goes into those Midwestern markets through Ozark and some of these other lines as well.

David Heikkinen - Tudor, Pickering & Co.

And that was about 400 million a day?

Steven Mueller

Yeah, somewhere in that range. It varies a little bit month-to-month but that's somewhere in that range. So we've probably they are fixing and repairing some of these spots in the Boardwalk Pipeline we'll see some day there where we maybe a little bit curtailed but overall, we can get our gas out, just the big thing is get as much you can across the Mississippi river and that's what all of us are trying to do.

David Heikkinen - Tudor, Pickering & Co.

Yeah. So as you think about you 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 percentage I guess you are in the three -- $400 million yesterday that's going to high 300s that goes to Eastern markets. Everything else goes in center point and Ozark how should we think about differentials over kind of the next couple of quarters?

Steven Mueller

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

David Heikkinen - Tudor, Pickering & Co.

Okay. That's kind of a, the side frame. I guess, we know that you are locked in volumes are just kind of make some assumptions of Center Point in Texas, Okalahoma gas prices and get a plan to outside of that?

Steven Mueller

That's basically what we do.

David Heikkinen - Tudor, Pickering & Co.

The other side of kind of improving operations and power tests in the Fayetteville I think, continued to see well quality step up. Can you talk about the average rates and kind of how that continues to get better and then also thoughts around no pilots you want more data always, so how that's progressing?

Steven Mueller

We're trying to learn several different things and so what we're doing right now. We're continuing to tweak and work with our completions. And the biggest thing we're doing on that side if you remember in the fourth quarter, we had done a couple of wells at 50 foot per spacing, had started doing 75 foot per spacing and the first and second quarters this year was to test both of those. We are 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 per 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's somewhere between 400 and 500 wells that we've got set to learn about that spacing. Those are all getting drilled now and it's -- all that needs about six months production before we can tell them to watch.

David Heikkinen - Tudor, Pickering & Co.

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

Steven Mueller

Yeah, just trying to figure out what spacing might be in various situations both geological across the play and in relation just all the wells that have already been drilled.

David Heikkinen - Tudor, Pickering & Co.

Thanks Steve.

Operator

And we'll go next to Rehan Rashind of FBR Capital Markets.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

My questions have been answered. Thank you.

Operator

And we'll go next to Joe Allman of JPMorgan.

Joe Allman - JPMorgan Securities, Inc.

Yes, thank you. Good morning, everybody.

Harold Korell

Good morning.

Joe Allman - JPMorgan Securities, Inc.

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

Steven Mueller

Well, I think, the directions kind of easily to give you a sense on; like a lot of companies where we haven't been doing that much learning we've cut our capital considerably and so we just don't have much activity either first quarter or going in for the rest of the year. So I would expect that in general, you are going to see our production go down not helping those areas.

Joe Allman - JPMorgan Securities, Inc.

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

Steven Mueller

The little bit over there was a James Lime, yes, is all there. Really, we're only drilling other than those couple of wells we talked about the Haynesville, the only thing we're drilling outside Fayetteville, we have one rig working in midway in Arkansas, And then we've got James Lime wells going down and some of that's timing. For instance right now we've got seven wells that we have to complete, they are James Lime wells. The completions will start this week and I got backed up a little bit because of pipeline issue.

So it's going to bounce around from quarter-to-quarter, but in general you're not going see an increase in production.

Joe Allman - JPMorgan Securities, Inc.

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

Steven Mueller

Yeah. There's 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. We have to get to those numbers and then we are looking at the overall market out there and how much we're making cash flow wise one end it will be as flexible as possible as we go out in the future. It is a combination of those two that was a drop in 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 which kind of drop-off in the second part of the year.

If the commodity prices come around I would fully expect you'll see us re-evaluate. If they go down, no, we'll re-evaluate as -- we'll re-evaluate. Certainly, we've got a lot of wells to drill. So long-term 11 rigs, 15 rigs is the right answer.

Harold Korell

Yeah, I think to add that, the discussions that we've 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 dealing in Fayetteville Shale are still fine in terms of a present value created per dollar invested.

But 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 we talked about in the past is we want to keep an eye on our debt levels. We want to maintain flexibility and not incur an inordinate amount of debt. So the current move as of, I'd say is 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 and how we feel about it. It also has a bearing on our borrowing.

So, to 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 $100 million out of capital, at just $100 we still have in the floor chest (ph) available in our borrowing capacity. So, I'd say it's a conservative approach to it on at time when our production volumes are growing tremendously anyway.

Joe Allman - JPMorgan Securities, Inc.

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

Operator

And we'll go next Tom Gardner of Simmons & Company

Thomas Gardner - 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 to note a lock in as you look to hedge out 2010?

Steven Mueller

Well, current prices are obviously too low for us walk in. For us, I mean, 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 six and $8 is what the industry needs to breakeven for but with shale plays, maybe that's a lower number than it has been obviously with conventional drilling.

So, what is that long-term trend going to be is that six to eight? Is it going to be six to seven? But we think that marginally, if prices have got to give above six before we start really looking at the screen very hard and we think that we are going to have opportunities to hedge, when we do see the intersection of supply curve start getting closer to the demand curve. So, we'll be watching it very closely, but there is nothing in the near-term that we expect to be doing.

Thomas Gardner - Simmons & Company

I got you. That's helpful. And a more specific question related to drilling cost, specifically cost savings from pad drilling. You are 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?

Harold Korell

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, there maybe two wells off a pad. You don't get a lot of cost savings there, you get the little bit of rig time skitting 10 feet (ph) versus moving a mile or something to a pad which is about a days worth of rig time.

The real cost savings comes when we do development and get into full form development phase. I don't know exactly when that is, its not 2009, it's probably not in 2010 for much of it. When we get to that point, we should start seeing some significant savings and at to give you kind a feel for that, one of the recent projects we did trying to do some down space and we drilled four wells off a single pad and it took us 28 days total to drill this four wells with seven core days of well.

And so, we know that the 12 we are drilling right now, is not the right number. We do get the development phase. In addition to that, when you're tracking on the location we have several wells, we do you same contingencies in the Barnett, we do the dippers (ph) and we move back and forth between. There is quite a bit of saving in both time and amount of effort plus hopefully even better fracs when we get done with that.

Again, except for just a little bit of down spacing work we've got wells close together. We've got two or three on a pad. You haven't seen any of that yet.

Thomas Gardner - Simmons & Company

Thanks guys

Operator

And we'll go next Gil Yang of Citi.

Gil Yang - Citigroup

Hi, good morning. Could you clarify the amortization benefit of 30 to $0.40, was that seen in the first quarter or was that only second quarter as going forward?

Greg Kerley

Gil, this Greg Kerley. That will be seen going forward. I mean, if 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 what we would expect that to be $1.42 to the $1.50 and Mcf equivalent with all other things being equal.

Gil Yang - Citigroup

Great. The question I have is could you talk a little bit about the Haynesville in terms of the well and Shelby, that IP that 7.2 million a day; is that a 24-hour test? Is it a 30-day test? And kind of (inaudible) $3 million is it being curtailed in any way and how many fracs were there? And how close will you stage with it?

Steven Mueller

Just to remind you, it is 2,700 foot lateral. I think it had, I think were six stages of fracs in it which from a stage per foot laterals about equivalent to what you had seen on Haynesville wells or just the 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 a well on production. It was not an IP or some kind of test rate that was immediately after the well first was tested. So there's a little bit of timeframe on that. Those states are -- the state test unit 24-hour testing. As far as, are we chocking it back or is anything from that standpoint 1,364 chokes was flowing at for a considerable period of time. So I don't know if you want to call it chock back or not, but that that's what we pointed out.

Well is holding up strong. You are seeing a very little pressure drop at 1,364. So that's kind of what the well is.

Gil Yang - Citigroup

Thank you.

Operator

And we'll go next to Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you. Good morning, sorry about that. Wanted to follow up on I believe it was Scott, David and Gil's questions with regards to CapEx versus learning versus growth. When you considered whether to drill even less than say key production guidance flat versus increasing, can you speak to the gas price breakeven and discount rates 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?

Steven Mueller

I can start with the giving up acreage part of that. The drilling -- the rigs we have left in our conventional areas basically they're holding acreage. There isn't much other than that going on in that direction. In Fayetteville, as I said of that 600 wells, roughly 200 of those, will hold acreage this year and we need to drill out that pace for the next couple years to hold all the acreage. We shouldn't have any issues doing that.

From the standpoint of holding, having less production and economics for our going back to Harold's comment is that our PBI goals, for our PBI goals you need to have a flat price someone in the mid-fours to hit a PBI goal. And that's what he said before at the start just a five price going out, you challenge right now in the economic if you have some kind of escalator in the future we still have decent economics on what we're doing.

So that's part of the debate that's been going on internally on you how much you slowdown, when do you slowdown and how do you keep that flexibility.

Harold Korell

And then Steve, I think and those mid-fours are with today's well cost they are not with the development scenario maybe they are with curve as we're drilling multiple wells on Fayetteville and so on down growth.

Brian Singer - Goldman Sachs

Thanks.

Steven Mueller

I think that answered everything you have there.

Brian Singer - Goldman Sachs

I think we could follow-up a little on the discount rate question but secondly, it seems like operating expenses that they were not really internal transfer cost falling significantly on a per unit basis in the last couple of quarters and wondering if there is any color refers to out that the right interpretation and if there is any color on what's driving that?

Steven Mueller

We are very sensitive on our LOE cost 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 see in that gas price goes down over the last couple of quarters, you're seeing on our LOE go down. The actual what I'd call fixed LOE is actually going up a little bit. It's almost flat. It's gone up a little bit and so really you're just seeing the gas price move up and down is what's happening.

Brian Singer - Goldman Sachs

Great, thank you.

Operator

And we'll go next to David Snow of Energy Equities Incorporated.

David Snow - Energy Equities Incorporated

Yeah, hi. I was hoping you may would have dropped off before I asked this, but do you have to do your ceiling customer on a quarterly basis or is it optional as to whether do it annual or quarter.

Steven Mueller

No, you have to do it at the end of each quarter. There are certain rules that would change our schedule to change at the end of the year about what pricing views that reaching these 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 intersect at the end of each period in the second, third quarter also. In the year, will be different rules.

David Snow - Energy Equities Incorporated

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

Harold Korell

No it is not an issue at all with our covenants. We have those kinds of non-cash, any non-cash adjustments to our earnings or our equity are excluded. But again, we're 25%, even if it was included, we're 25% debt-to-cap and our -- we do have financial covenants 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.

David Snow - Energy Equities Incorporated

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

Greg Kerley

On an internal rate of return type thing, compound rate of return, roughly in the 20% range. It depends on the shape of the well and the way it works. But it's roughly that number.

David Snow - Energy Equities Incorporated

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

Steven Mueller

I think if you just look at our, that chart, and look at the IP changes is one from I take the average as percent in fourth quarter. And then look at that compared to the third quarter. That's really when we put the 75, when the effects so that's really where we can get. That's probably the best to answer that.

David Snow - Energy Equities Incorporated

How much more does it cost?

Harold Korell

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

David Snow - Energy Equities Incorporated

All right.

Operator

And we'll go next to Robert Christensen of Buckingham Research.

Robert Christensen - Buckingham Research

Good morning, guys. A Question for you; what's your next decision on the Haynesville well cut? I guess you've drilled two wells, what comes up next in the joint venture, and who makes that decision, you or your private party?

Steven Mueller

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 obviously, the next big thing is to get that completed. It did look like compared to your first well. And then the other big thing is that there are some wells drilled around this by other companies. And get a little information on what they've got. And then you can decide how good it is and what are the drilling you want to do.

Robert Christensen - Buckingham Research

Is there takeaway capacity in the area?

Steven Mueller

Yes.

Robert Christensen - Buckingham Research

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

Steven Mueller

Well, I think we've said in the last conference call that we pay a little over $8 million for about 21,000 acres. And we did some cleanup work out there to get the last couple of thousand in to.

Robert Christensen - Buckingham Research

Thank you.

Operator

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

Michael Scialla - Thomas Weisel Partners

Hi, guys, just a couple of follow-ups to Bob's questions on the Haynesville. Based on what you've seen on that first well and then maybe some of the results that you've seen from other operators. How far away do you think you are from making that economic write-down? What did that first well cost you?

Steven Mueller

The first well had a lot of signs on it. So, it's not really representative on its overall cost. We think we need to have something less than $10 million, between and eight and $10 million total cost on the well. And we need a little more encouragement probably on the production rate and what we're seeing to-date to just pound the table for you (ph) this is great play. But it's very intriguing.

Michael Scialla - Thomas Weisel Partners

To maybe with the longer lateral and cost savings?

Steven Mueller

Yeah, once you start down the little longer lateral and take out the fact that we drilled the vertical and chord both of these wells and get in there really where it is drilling the wells for the production. Its starts (inaudible) that point.

Michael Scialla - Thomas Weisel Partners

And then same on the Marcellus, what encouraged you to add the acreage that you have?

Steven Mueller

Well there has just been a lot of wells. In 2008 there was almost 300 wells drilled in the Marcellus. There were several in and around our acreage besides the ones we drilled.

And we really like what we are seeing from a larger perspective there. Technically, probably the things we like best is there is more free gas in the Marcellus versus absorbed gas in a lot of the Shales out there and you're seeing some pretty good unusual rates because of that.

Michael Scialla - Thomas Weisel Partners

Thank you.

Operator

We'll go next to Ray Deacon of Pritchard Capita.

Raymond Deacon - Pritchard Capital Partner

Yeah, hi. Good morning. I was wondering if you could comment on the $1.8 billion budget if you do get more reason for optimism and increase spending on the closure of Haynesville, would you take rigs away or would you add to the 1.8 billion of CapEx?

Harold Korell

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

Raymond Deacon - Pritchard Capital Partner

Okay, I got you. And I guess kind of a little bit tied to that is there -- you're going to be adding a lot of PDPs between now and November, there is a lot of concern about what the banks may 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?

Greg Kerley

Ray this is Greg Kerley. You might not recall our credit facility is somewhat of an anomaly compared to all of our peers as we do not have a borrowing base facility,

Raymond Deacon - Pritchard Capital Partner

Okay.

Greg Kerley

It feels the unsecured line and so wouldn't have any impact -- impact with the swings in prices.

Raymond Deacon - Pritchard Capital Partner

Great, thanks very much.

Operator

And we'll go next to Brian Tuisma (ph)

Unidentified Analyst

Good morning, guys.

Steven Mueller

Good morning.

Unidentified Analyst

When you look at your April IP rates, around like 3.7 million a day. I mean, does that mean you guys are seeing like six and seven million a day IP rates on your goodwill?

Steven Mueller

We aren't seeing any.

Unidentified Analyst

Okay.

Steven Mueller

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

Unidentified Analyst

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

Steven Mueller

Well, we have. We've got gas hedged at a certain price and that total for the year was about a 130 Bcf, was like a 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.

Unidentified Analyst

I got it. So you guys are -- for the one you combine our ST (ph) with your basis hedges I should look at that as you guys being 90% hedged out of the Fayetteville?

Steven Mueller

No.

Unidentified Analyst

No, that's not right?

Steven Mueller

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

Unidentified Analyst

Okay.

Operator

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

Jack Aydin - KeyBanc Capital Markets

Hi, guys. Most of my questions were answered but I have. Looking that 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?

Steven Mueller

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

Jack Aydin - KeyBanc Capital Markets

Okay, thank you.

Operator

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

Marshall Carver - Capital One Southcoast

Yes, a couple of quick questions. When you talk about needing wells to cost eight to 10 million in the East Texas Haynesville/Bossier, was that -- were you indicating that the first well was more than 10 million, but you're thinking you can get the eight to 10 longer-term or how should we think about longer term cost there?

Steven Mueller

Well, I think you can certainly make an AFE that would show that we can drill well for eight, $8.5 million. I can tell you that the first two wells we driller as I said, we with our cold quarters, we ran a bunch of different valves that you know we wouldn't run. And we're taking those whole core to actually drill a vertical well first then backed up and drill the horizontal part of the well. So, yes, it was considerably higher than the eight to $10 million range.

Marshall Carver - Capital One Southcoast

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

Greg Kerley

Yeah, I don't -- I have no idea. There's nothing different about where we drilled wells really to last 2.5 quarters. We're drilling across the entire play. We are drilling in a lot of different areas that were targeted. And there's nothing different about the third quarter or second quarter first quarter in that respect.

Now statistically, all kinds of worse things happen. And as you're learning that just goes where it's like, I can't even kind of guess what's going to happen.

Marshall Carver - Capital One Southcoast

Okay. That's helpful. Thank you. Good quarter.

Steven Mueller

Thanks.

Operator

And we'll go next to Jeff Hayden of Rodman & Renshaw

Jeff Hayden - Rodman & Renshaw

Hey, guys, just a quick follow-up to Brian Singer's question from earlier. When you were talking about the wells, the well counts need to hold your acreage. Was that the 200 wells you referred to that you have to keep drilling or kind of drilled the hold of your acreage?

Steven Mueller

Yes.

Jeff Hayden - Rodman & Renshaw

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

Steven Mueller

We're averaging about 11 days a well perhaps its 540,000 or something or whatever that number is.

Jeff Hayden - Rodman & Renshaw

Okay. And that's then out of that about how many of the kind of outside operate well versus how many of those that once you guys would operate?

Steven Mueller

This year, roughly honored (ph) over 600 wells of outside operators.

Jeff Hayden - Rodman & Renshaw

Okay. I appreciate it guys.

Operator

And we'll go next to Art Jemma of Alcreek (ph).

Unidentified Analyst

Good morning. I had a question on your type curve chart. You've 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 are not just pulling forward production as opposed to increasing the overall from some of these wells. That's the first question.

Steven Mueller

Thank you. You need to be a little careful calling them type curves at least from the production data. We put some type curves on there, you got to remember there what's happening here as you're rolling through those increases in IP 36 day (ph) rates.

So as you follow this overtime those curves have kind of pulled themselves up overtime, we just have watch as we go out in future, but I don't know that there is anything that we see that say's we're accelerating versus something like.

Unidentified Analyst

Okay. And the other question I had is it seems like a couple years ago you were doing a lot more drilling and just kind of 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. But I'm curious if you could just talk as say you're drilling across the play. But it seems like you might be actually, might have found a better area within the play that you're more focused on recently.

So I'm 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'll see across the whole play as opposed to perhaps the sweet spots that you're drilling now?

Steven Mueller

Yes, I'm not sure if you saw a map where we're drilling. I don't know what you say we 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 this federal unit almost together, now we're drilling at this year. But other than that, we drill 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 300 million a day or better. And if you looked in map where that's at, they are across that entire acreage block. There isn't, it's just an obvious sweet spot where they are all certain there and drops off from that. So, I don't know that we found the best part or the worst part.

Certainly there is geologic differences as you go through this whole thing and all kinds of things that takes from it (ph) Our intent has not been to drill just one little sweet spot.

Unidentified Analyst

Okay. But if you think it's the data you are presenting is an acreage sampling or is there a large amount of sample to have a feel or do you think its still too early to be able to infer what the longer term EURs will be from the data we have?

Steven Mueller

I think if you look at whether it's the table where we've got the number of completion per quarter. We're consistently drilling between 70 and 100 completions per quarter. Certainly, to start on that 70, you might talk about statistics being up a little bit. But he gear up to 100 and you're starting to get enough of statistics there. When you look at actual production graph, we do have the data there on how many wells. And obviously, the early part of that, it's got a lot more wells in the later part.

So, the far end of that has less statistical values than the front end has but, we're learning. I mean, from day one, we've been learning, we're still learning a lot. Development is still always up as we try to learn some of these major things.

Unidentified Analyst

Okay, that's helpful. Thank you very much.

Operator

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

Scott Hanold - RBC Capital Markets

Hey, thanks, one real quick follow-up and that you gave some of the info away but of this 600 wells that you've planed for on 2009 in the Fayetteville. I think you indicated a 100 of those for non-operated well. What was that number at when you're originally targeting 650 wells? And do you expect there could be some risk as other operator pull back CapEx a little bit?

Steven Mueller

We've actually, in our revised capital budget, we've actually added about $10 million to the outside operated. We've seen more of these than we originally planned. And that's not that many more wells, but we are not seeing any flat there.

Scott Hanold - RBC Capital Markets

Okay. So, how

Steven Mueller

Let me put this way, we're seeing two different ways. The number of AFEs have actually increased a little bit here recently. The other things that's happened is that our working interest on those AFEs has gone up since our original budget and when we (inaudible) budget also.

Scott Hanold - RBC Capital Markets

Okay. And how correlate did are AFEs to I guess results of that operator's ability to actually gotten drilled those wells?

Steven Mueller

There was a fair correlation.

Scott Hanold - RBC Capital Markets

Okay, thank you.

Steven Mueller

And there are some of those wells don't get drilled, but usually they get drilled.

Scott Hanold - RBC Capital Markets

Thank you.

Operator

Now I'll take a follow up question from Rehan Rashid of FBR Capital Markets.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Not to be the dead horse here, but the improving IPs than sequentially is simplistically the more tighter fracking, is that the driver?

Harold Korell

Combination of longer laterals, the perforation clusters and the back jobs we're doing, yeah.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

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

Harold Korell

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

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Last one on free gas and absorbed gas; have you -- have you began to notice when does absorbed gas kick in and how could that help the longer term decline rates?

Harold Korell

We really have not I assume we are talking about Fayetteville Shale.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Yeah.

Harold Korell

We have not got a good feel for that yet. That's one thing we've been trying to monitor but we don't have a good answer yet.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Okay. Thank you.

Operator

And we'll go next to David Snow of Energy Equities Incorporated.

David Snow - Energy Equities Incorporated

I was just trying to pull up a map of your drilling and I was astounded when you said that it's 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've gotten away from the well and the various sections of identifying the play and it's all pretty much giving a comparable results?

Steven Mueller

I won't say that it's giving us comparable results. You still have in the shallow section lower pressures and general you're going to have little shorter laterals and you are in the middle of deeper parts of play and certain parts of that have more or less faulting as you go through it. But consistently across the play we're seeing three plus million wells.

David Snow - Energy Equities Incorporated

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

Steven Mueller

Kind of the way to think about it a year ago 60% of well cost was drilling, 40% of well cost was completion. Today it's almost flip flop. It's about 40% of drilling because we taken days our drilling curve but because of putting more energy in the ground about 60% completion.

David Snow - Energy Equities Incorporated

So the 2.9 how many is like another 50 million it's go to 75 foot intervals?

Harold Korell

Well that 2.9 has reflected both 50% that we think will be 50 foot space and 35 foot space in near kind of space first so, that's kind of a combination of everything.

David Snow - Energy Equities Incorporated

Thank you very much.

Operator

And at this time, we no have further questions. I would like to turn the conference back over to Mr. Harold Korell for any additional comments.

Harold Korell

Thank you. Thank you all of you for joining us today. I wanted to end with just sort of a big picture for those of you who 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've done that as we've said before, through a real type focus on value creation and idea generation. And we are 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.

Operator

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

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Source: Southwestern Energy Q1 2009 Earnings Call Transcript
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