Harold Korell; Southwestern Energy Company; Chairman
Steve Mueller; Southwestern Energy Company; President, CEO
Greg Kerley; Southwestern Energy Company; EVP, CFO
Analysts
Michael Jacobs; Tudor, Pickering, Holt; Analyst
Robert Christensen; Buckingham Research Group; Analyst
Brian Singer; Goldman Sachs; Analyst
David Heikkinen; Tudor, Pickering, Holt; Analyst
Mike Scialla; Thomas Weisel Partners; Analyst
Jeff Hayden; Rodman and Renshaw; Analyst
Nicholas Pope; Dahlman Rose & Company; Analyst
Tom Gardner; Simmons & Company; Analyst
Jason Gammel; Macquarie Capital; Analyst
Vedula Murti; CDP US; Analyst
Scott Hanold; RBC Capital Markets; Analyst
Joe Allman; JPMorgan; Analyst
Dan McSpirit; BMO Capital Markets; Analyst
Presentation
Operator: Greetings, and welcome to the Southwestern Energy Company second quarter earnings conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. In the interests of time, please limit yourself to two questions. Afterward, you may feel free to re-queue for additional questions.
(Operator Instructions.)
As a reminder, this conference is being recorded.
It is now my pleasure to introduce your host, Harold Korell, Executive Chairman of the Board for Southwestern Energy Company.
Thank you, Mr. Korell. You may begin.
Harold Korell: Good morning and thank you for joining us. Steve Mueller and Greg Kerley, our Chief Executive Officer and Chief Financial Officer, are with me here today.
If you’ve not received a copy of yesterday’s press release regarding our second quarter results, you can call 281-618-4847 to have a copy faxed to you.
Also, I’d 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 section of our annual and quarterly filings with the Securities andExchange Commission.
Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.
Well, we’re here to report another very good quarter despite the low commodity price environment. Our gross operated production from the Fayetteville Shale reached a significant milestone of 1 Bcf per day in July, compared to approximately 500 Mcf per day at this time a year ago.
I mean, it’s truly amazing to think that it was only five years ago when we told the world about the Fayetteville Shale play and our gross production from that play alone is now over a billion a day. We’ve learned so much during that time, and we continue to do so, as the productivity of our wells continues to improve with each quarter.
While current gas prices remain low, we believe lower industry-growing activity will result in higher prices over the next 18 months. With our focus on value creation and a world-class resource to develop in the Fayetteville Shale, we are well positioned not only to weather the current low commodity price environment with our strong balance sheet and financial flexibility, but also to benefit greatly when prices return to more normalized levels.
I’d like to now turn the conference over to Steve for more detail 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.
Steve Mueller: Thank you, Harold. Good morning. During the second quarter of 2009, we produced 74.3 Bcfe, up 65% from the second quarter of 2008. Our Fayetteville Shale production was 60.6 Bcf, double the 29.6 we produced in the second quarter of 2008. Our remaining second quarter production came from East Texas, where we produced 7.8 Bcf and from the Arkoma properties, where we produced 5.8 Bcf.
In the first six months of 2009, we invested approximately $852.5 million in our exploration and production activities and participated in drilling 338 wells. Of this amount, approximately $694 -- $695 million or 82% was for drilling wells.
Additionally, we invested $102.5 million in our Midstream segment almost entirely in the Fayetteville Shale. In the first half of 2009, we invested approximately $793 million in our Fayetteville Shale play, including both our E&P and Midstream activities.
At June 30th, our gross operated production was approximately 990 Mcf per day, up from 850 Mcf at the end of March. We currently have 17 rigs drilling in the Fayetteville Shale, 13 that are capable of drilling horizontal wells and four smaller rigs that are used to drill the vertical portion of the wells. We expect to participate in approximately 575 gross wells in 2009.
As we discussed in our last teleconference, during 2008 the majority of our gas production from the Arkoma Basin was moved to markets in the Midwest. This included the Fayetteville Lateral phase one portion of the Texas Gas Transmission or Boardwalk Pipeline, which was placed in service on December 24th. On April 1st, the Fayetteville Lateral phase two and Greenville Lateralportions of the Boardwalk Pipeline were placed in service, and we began transporting a portion of our gas to Eastern markets.
As a result of recent inspections, repairs and maintenance on the Fayetteville Lateral, we have experienced curtailments that have impacted our ability to transport our production from our Fayetteville Shale. Beginning in April 2009, Boardwalk reduced the capacity on, or shut down, the Fayetteville Lateral on several occasions, due to various activities, including maintenance and pipeline inspection.
These activities, as well as similar repairs to the Greenville Lateral, are expected to continue, resulting in further curtailments. As an example, the Southwestern operated gross production exceeded 1 Bcf a day on Monday and Tuesday of this week. A line inspection was started on Wednesday and total production was reduced to 825 Mcf per day gross. And then this morning, the production is now restored to over a Bcf a day.
Currently, our transport capacity is sufficient for us to produce our operated wells at approximately 1 Bcf a day. Our net share of this, plus our outside operated production, is approximately 715 Mcf a day. Once repairs are started on the Fayetteville Lateral phase one facilities on the Boardwalk Pipeline, transport out of the producing areas will be limited to the existing Ozark and Center Point systems.
We estimate that our total operated production will be curtailed to approximately 600 Mcf per day gross or 450 Mcf per day net.
In anticipation of these continued pipeline curtailments, we have revised and widened our previous gas and oil production guidance range for 2009. Previously, it was 289 to 292 Bcfe and now it is 278 to 288 Bcfe. This revised production guidance is based on the portions of the Fayetteville Lateral phase one facilities being out of service for 45 to 60 days starting in September and assumes total curtailed volumes will be approximately 15 Bcf. At this lower production guidance, we will expect to have production growth of approximately 45% over 2008 levels.
Since 2007, the continuous improvements of our completion practices has resulted in quarter-over-quarter improvements in average initial production rates. The average initial production rate for wells put on production in the second quarter of 2009 was 3.6 Mcf per day per well. This is the highest average rate for any quarter since project inception, up over 7% per day from our previous high the fourth quarter of last year.
During the second quarter of 2009, our horizontal wells had an average completed well cost of $2.9 million per well. Average horizontal lateral length of 4,123 feet and average time to drill to total depth of 11 days from re-entry to re-entry. This compares to 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 the total depth of 12 days from re-entry to re-entry in the first quarter of 2009.
I’ll now move on to our Haynesville Shale activity where we see encouraging results. The first horizontal well in our 50/50 joint venture targeting the Haynesville/Bossier Shale in Shelby and St. Augustine counties, Texas, the Red River 877 number one, reached total depths in the fourth quarter of 2008.
This well, which had a completed horizontal lateral of 2,718 feet, wasproduction tested at a rate of 7.2 Mcf per day in the first quarter of 2009 and is currently producing approximately 1.8 Mcf per day.
The second horizontal well, the Red River 164 number one, was drilled approximately five miles to the southeast and reached a total measured depth of 17,124 feet with a 3,800 foot horizontal lateral. It was production tested at 13.4 Mcf per day in the second quarter and is currently producing approximately 7.8 Mcf per day.
We have completed drilling the third well, the Red River 619 number one, located in St. Augustine county, with a measured depth of 17,244 feet and a horizontal lateral of 4,000 feet.
Our fourth well, the Burrows Gas Unit 1H was recently spud.
These wells are being monitored very closely, and Southwestern Energy may participate in four additional Haynesville/Bossier Shale wells this year.
The capital for this drilling is included in our total 2009 capital guidance of $1.8 billion.
Finally, we participated in drilling 13 wells in the conventional Arkoma Basin and 23 wells in East Texas during the first six months of 2009. Twenty-one of the East Texas wells are James Lime horizontal wells.
Production from Arkoma and East Texas properties was 11.6 and 15.6 Bcfe respectively for the first half of 2009, compared to 11.9 and 16 Bcfe for the first six months of 2008. We currently have two operated rigs running in East Texas and none in the conventional Arkoma.
In summary, our E&P and Midstream businesses are expected to have continued strong results in the remainder of 2009 and beyond. We continue our focus on adding value. Significant value is created as we improve the operation and production performance of each well drilled in our world-class Fayetteville Shale resource.
In addition, we’re also excited about our future opportunities at the Haynesville, James Lime and Marcellus Shales.
I will now turn it over to Greg Kerley who will discuss our financial results.
Greg Kerley: Thank you, Steve, and good morning. As Harold and Steve have indicated, we had a very solid second quarter. We reported net income of $121.1 million or $0.35 a share for the quarter, down approximately 11% from a year ago, as our production growth almost completely offset the effects of significantly lower realized natural gas prices.
While our cash flow from operations before changes in operating assets and liabilities, it was actually up 13% over the prior year at $325.3 million. Our average realized gas price during the second quarter was $5.01 per Mcf, which was more than $3.00 per Mcf lower than our average realized price a year ago.
Our commodity hedge position increased our average realized gas price by $2.11 in the second quarter, and our locational market differentials or basisimproved from first quarter levels to approximately $0.60 an Mcf.
We currently have approximately 66 Bcf of our remaining 2009 projected natural gas production hedged through fixed-price swaps and collars at a weighted average floor price of $8.43 an Mcf.
We also have basis protected on approximately 50 Bcf in the third quarter and 30 Bcf in the fourth quarter of our expected gas production through hedging activities and sales arrangements at an average differential to the NYMEX gas price of approximately $0.35 per Mcf.
Our detailed hedge position is included in the Form 10Q that we filed this morning.
Operating income for our E&P segment was $174.4 million in the second quarter of 2009 compared to $215.1 million in the second quarter of 2008. The decrease was primarily due to lower realized natural gas prices and increased operating costs and expenses, which were partially offset by the 65% increase in our production volumes.
Our total cash operating costs continue to be some of the lowest in the industry. Our lease operating expenses for unit of production were $0.73 per Mcf in the second quarter of 2009 compared to $0.95 for the same period in 2008. The decrease primarily resulted from the impact that lowered natural gas prices had on the cost of compressor fuel.
General and administrative expenses for unit of production were $0.34 per Mcf in the second quarter of 2009 compared to $0.41 for the same period last year. The decrease was primarily due to the effects of our increased production volumes which more than offset increased compensation related costs associated with the expansion of our operations.
Taxes, other than income taxes, were $0.08 per Mcf in the second quarter, down from $0.16 for the same period in 2008, primarily due to lower commodity prices.
Our full cost pool amortization rate dropped to $1.46 per Mcf in the second quarter, down from $1.82 in the first quarter of 2009 and down from $2.01 in the prior year. The decline was primarily due to the non-cash ceiling test impairment we recorded in the first quarter of 2009.
Operating income from our Midstream Services segment grew to $27.8 million in the second quarter, up from $15 million for the same period in 2008. The increase was primarily due to higher gathering revenues resulting from the significant increase in our gathered volumes which were partially offset by increased operating costs and expenses.
As of June 30th, we had $196 million borrowed on our $1 billion revolving credit facility at an average interest rate of 1.2%. Our revolver balance included borrowings to pay off $60 million of senior notes during the second quarter.
For the first six months of the year, our debt outstanding increased by $135 million, resulting in total debt outstanding of approximately $871 million at June 30th and a debt to capitalization ratio of 28%.
We have a strong balance sheet with significant financial flexibility and are well positioned to weather the current commodity price environment.
That concludes my comments. So now we’ll turn back to the operator who will explain the procedure for asking questions.
Questions and Answers
Operator: Thank you. We'll now be conducting a question-and-answer session. (Operator instructions.)
Our first question, gentlemen, is from the line of Michael Jacobs with Tudor, Pickering, Holt. Please go ahead with your question, sir.
Michael Jacobs: Thank you, and good morning.
Unidentified Company Representative: Morning.
Unidentified Company Representative: Morning.
Michael Jacobs: Trying to reconcile average economics in the Fayetteville in the context of better IPs and EURs with respect to downspacing. Going forward, should we apply different spacing assumptions to areas with higher or lower EURs?
Steve Mueller: I don't know that there are necessarily areas with higher or lower EURs. If you look at what we've done in the last 12 months, there's 3 million a day-plus wells across entire acreages that we've been drilling on. There's certainly, though, scattering wells as you drill. I'm not going to say they're all 3 million a day. You get all kinds of scatter even near some of the better wells. So I'm not sure exactly what average you should use. I think that the key point is that we're continuing to learn, and as we learn, both the EUR and the rate's going up.
Michael Jacobs: Okay. And if I can move to East Texas, pretty impressive rates. Can you share the cost of the St. Augustine well and then put that in the context of targeted costs for East Texas and how you drive down costs over time?
Steve Mueller: And you're talking about the Haynesville there?
Michael Jacobs: Yes.
Steve Mueller: Yes. The first two wells had a lot of science with them. We drilled vertical first, cored them, did all kinds of other things. They're well past $10 million.
The third well that we just recently TD'd, we have got pipe run, it's a 4,000-foot lateral, and we're a little less than $5 million to date, so we think we're going to be getting that done somewhere between $9 and $10 million.
And that's the range, I think, that starts talking like some of these operators are doing on the Louisiana side. There'll be some more that we can take out of it, but we've already learned a lot, and we've taken a lot out in the first three wells.
Michael Jacobs: That's great. Thank you.
Operator: Our next question is coming from the line of Robert Christensen of Buckingham Research Group. Please state your question, sir.
Robert Christensen: Yes, thanks, guys. First question again is a Haynesville question. How are you selecting your positioning of these wildcat attempts? What goes into that decision making?
Steve Mueller: Well, we do have 3-D over most of our acreage that we're drilling on, so from a geological standpoint, we're looking hard at the 3-D.
The next three or four wells that you see drilled, we have picked with partners, and we're sharing some of the risk, so not all of those wells will be at 50% working interest for our company, so that's the other major thing we're doing. We're sharing some costs as we drill some of these wells and test them.
Robert Christensen: That isn't saying about location. You're drilling on the partner's acreage, or they have a decision in the wildcatting? I'm just trying to think are you seeking better rock somewhere? I mean the latest one - --
Steve Mueller: No, the Haynesville on our acreage, we've got enough control right now that we can comfortably say that Haynesville across our acreage is between 130 and 160-foot thick. We are -- the first two wells, as I said, were about five miles apart. They're on what we call our Jebel block, which is -- we have three big blocks of acreage. It's the central block. And for the immediate future, most of our drilling will be in that central block. All the wells in 2008 -- or 2009 will be in that block. And then as we look for 2010, you'll start to see us test on those other blocks.
Robert Christensen: My second question relates to -- this may be heresy in the energy patch -- limits to productivity in the Fayetteville Shale. We've been tracking it for years, quarterly, quarterly. I really appreciate the table that you guys put up quarterly; it's so useful. But at some point in time, is there some limits? Because this is just a great quarter, Steve.
Steve Mueller: We've got a long list of things we're still trying, and we've talked in the past about how many stages we've frac’d, and we've talked about how our perf intervals gotten lower. I will tell you that from a perf interval standpoint, we did our first 75-foot perf intervals late last year, we did some 50-foot, and preliminary information, we're not seeing much difference between those. That's very preliminary, and we've still got some more to do, but we may on the perf intervals be getting close to that part of it.
On the other side of it, as we've been putting more energy in the ground, more sand and more water, we're continuing to get better and better rates, and so -- and I think the whole industry's doing that. So, like I say, there's a whole list of things we're doing to continue and improve, and as long as we've got a long list to work on, I think we'll continue to improve.
Robert Christensen: Thank you.
Operator: Our next question is coming from the line of Brian Singer of Goldman Sachs. Please go ahead with your question, sir.
Brian Singer: Thank you. Good morning.
Steve Mueller: Good morning, Brian.
Brian Singer: How are you thinking about the trajectory of production once the curtailments in the pipelines end? Are you continuing to drill and not complete or just immediately shut -- or complete and immediately shut in and, therefore, be ready to be back to wherever you would've otherwise been in the late fourth quarter? Or do you see a more sustainable step-down in production in the next few months?
Steve Mueller: That sounds like a simple question. I don't know if I've got a simple answer. You know, the key is how long are they going to be down and how long is the spacing for being down? You know, are they going to be down in one or two-day chunks over a long period of time? Are they going to be down significantly for 30 days or 60 days and then you can put it back up? And we don't know the answers to that.
So we've tried -- and Harold mentioned flexibility earlier when he talked about his portion -- we tried to do this as flexible as possible. Today, we've got about 55 wells that are in some stage of completion or some kind of activity heading towards completion that they've TD'd the wells. That's not much more than normal. Normally, we'd have between 30 and 40 wells, so we're not backed up that much today.
Over time, if it takes five months, we will have wells that we'll have drilled and not be able to put on production, and we'll have to manage that. We will certainly frac some of them and have them ready to go on, and then some of them we may not frac.
The other thing we're doing, we own 11 rigs. Over the next -- really starting somewhere around September 1, we're going to take each one of those rigs down. We have not done maintenance on them -- or major maintenance on them in over two years, and we'll take each one down for a week to a week-and-a-half, and that will slow the drilling by about -- I think about between five and eight wells this year, and that's why if you notice our revision for total number of wells is down a little bit, that's doing maintenance while Boardwalk's doing their thing, as well.
So we're being as flexible as possible. If it takes five months, we're going to have a lot of wells backed up, and we may have to make some other revisions on whether we're drilling or not. If it only takes 60 days, we'll drill through it.
Brian Singer: That's really helpful. And when you layer that in but really more when you think about where gas prices are, your hedges, the strong well results you're seeing, any early look on how you're thinking about 2010 from a growth and then spending perspective?
Steve Mueller: We really haven't looked that far out. We're just trying to get through the Boardwalk thing right now.
Brian Singer: Great. And, lastly, any thoughts on decline rates from the couple wells that you're seeing in St. Augustine in the Haynesville? You mentioned where they are producing now. Are you seeing any hook in the decline curve where you think that we'll be at a lower decline rate after -- relative to the rates you mentioned earlier?
Steve Mueller: We haven't seen anything, no. If you -- I kind of gave youtwo data points. I gave you what the initial rate was and then what it was at various points in time.
On that second well, that 7.8 million a day, that's after about 60 days' worth of drilling, and if you put that on a type curve, you're going to see that's well over 6 Bcf. Now, you've only got 60 days, so who knows if it's going to fall off or what it's going to do in the future.
That first well, we're at just over 170 days with that 1.8 million a day that I have there. You put that on a type curve, and you're in a 3 Bcf type range. Neither of them had seen any kind of drops. They've been smooth through their production.
Brian Singer: Great. Thank you.
Operator: Our next question is from the line of David Heikkinen with Tudor, Pickering, Holt. Please state your question, sir.
David Heikkinen: Just a follow-up to Mike's line of questioning. Thinking about the downspacing as you move forward then, Steve, as you've tested, you would expect a similar spacing to be applied across your acreage position?
Steve Mueller: Boy, I don't know the answer to that yet. Like I say, we're seeing good wells across all of our acreage, but I don't have enough data to be able to tell you if one part of the acreage is going to be downspaced at one and another part's going to be downspaced at the other. We're still several months away from having that answer.
David Heikkinen: Okay. So, really don't expect the better area or work area. Just too soon to call on downspacing?
Steve Mueller: Yes, it's way too soon to call.
David Heikkinen: And then as you think about Boardwalk versus other lines and you've tapped into Center Point and Ozark, how should we think about cost for transportation as we go into third and fourth quarter if this lasts a little longer, and then your basis for realized prices?
Steve Mueller: Well, Greg had mentioned in his that we have put on significant basis hedges that are roughly $0.35 in the third, fourth, and we actually have some on first quarter of next year, and those are to the various hubs that we think we can get gas to.
David Heikkinen: Okay, so no change then?
Steve Mueller: I don't think there's any significant change. If anything, there may be of - -- the gas we're able to sell is actually going to be a little bit lower than this past quarter because we haven't put those basis hedges in.
David Heikkinen: Okay, good.
Steve Mueller: So --
David Heikkinen: Thank you.
Operator: Thank you. Our next question is from the line of Mike Scialla with Thomas Weisel Partners. Please state your question.
Mike Scialla: Hi. Good morning, guys. A follow-on to Bob's question on just how far you can take the improvements on the productivity side. You mentioned putting more energy into the ground. Is lengthening the lateral even further from here feasible? I mean is it possible to drive it across two sections at this depth, or is that technically not achievable?
Steve Mueller: It's technically achievable. We have done, and the industry has done, cross-section wells already. We've done several wells over 5,000. We've got a handful of wells over 6,000. And for a geologic reason, we actually have drilled a well about 7,300 feet lateral, so it's certainly technically feasible.
As you start looking at just the way the wells kind of space out over time, no matter what the spacing's going to be, it's much harder to, say, with a 10,000-foot average lateral, cover all what I'd call white space, make sure that you've got all your production covered and you've got all your reserves out of the ground than it is with something a little less than that. So I don't think 4,000's the right number, but it's not 10,000 either; it's somewhere in between those.
Mike Scialla: Okay. And then looking at your guidance, it looks like you've taken third quarter guidance down more than fourth quarter even though the maintenance is not set to begin until September. I would've thought it would've been the reverse. Can you help me understand what I'm missing there?
Steve Mueller: Our assumption is that they get out there in early September and work continually for 30 days basically in the third quarter. And then as you get into the fourth quarter, if they've -- if it goes to a scenario where it's the five-month scenario, they will go off. There will be issues where they're going to have to go away and production may come back for a while, and then they'll come back and work on it some more.
So in the fourth quarter, we've got more sporadic production or time that they're working than in the third quarter, but it's roughly the same number of days each quarter.
Mike Scialla: Thanks, Steve.
Operator: Thank you. Our next question is coming from the line of Jeff Hayden with Rodman and Renshaw. Please go ahead with your question, sir.
Jeff Hayden: Hi, guys. Just kind of want to start with the Haynesville. Looks like you guys talked about 32,800 net acres right now. I believe when you did the call last quarter, you said 50,000, so I'm assuming you let some stuff go. Could you give any color on what part -- you know, whereabouts you let the acreage go and maybe what were the reasons for that, what did you see, etcetera?
Steve Mueller: We have dropped some acreage. It was to the far west part of our overall acreage position, and it really is not in the Haynesville as we see it today, and it's much deeper.
If you kind of break our acreage into the acres we have today in the few sets, I said there's three major parts of it. The eastern two are roughly 12,500-foot deep. The western one is roughly 14,000 foot to get to the Haynesville. And the acreage we dropped was significantly deeper than that, and we just weren't going to get to it any time soon.
Jeff Hayden: Okay, appreciate that color. And then jumping back over to the Fayetteville; I believe last quarter you guys had talked about possibly taking the rig count down to about 15 or kind of 11 horizontal rigs running. Any updates on that; still expecting to lay off another couple of rigs or are you thinking about staying at kind of the 13 level?
Harold Korell: As it stands today, we’re still on the schedule that later this year drop 2 more rigs, get down to 11 big rigs running.
Operator: Your next question is from Nicholas Pope with Dahlman Rose.
Nicholas Pope: I know it’s a little early to tell anything on production response when you look at some of the downspacing tests you’ve seen, but have you seen anything with like pressure response or frac hit data on what that downspacing potential looks like right now?
Steve Mueller: We don’t have enough data to start putting trends together. We’ve got a lot of anomalies. And actually, if you look at the press release and look at the production curve for the 4,000-foot laterals, you’ll see that on the very end of that 4,000-foot lateral there’s a single well and it jumps up above the line. That was actually a well that we drilled a downspace well near and it took a frac hit and actually helped it.
Now let me tell you right off the bat that there’s only a handful of wells that took frac hits that helped them; most of them either come on the same or come on a little less than they were before. But there certainly are wells out there that have frac hits. What we have now is a bunch of data that we’re sorting through and so we’re just working our way through that.
Nicholas Pope: Appreciate that. Also, back to the pipeline; is there any recourse on that pipeline to recapture any money from what’s being lost from the pipeline being down or is this like force majeure kind of activity?
Steve Mueller: I’m sure if you talked to the pipeline company they would say force majeure. It never really got up to full operational, so they would say they’re still in the construction phase. And as long as it really takes a reasonable amount of time to get it fixed and we’re back in business and on a curve, there’s really no recourse that we’d want to do. If for some reason they can’t fix the pipe and it stays at a low rate, then we’ll just have to talk to them about what happens then.
Operator: Your next question is from Tom Gardner of Simmons & Company.
Tom Gardner: Just following up on your prepared comments on the Fayetteville production impact due to pipeline downtime, can you mitigate some of the impact through rerouting the gas or has that been fully considered in your guidance?
Steve Mueller: Any kind of backhaul, any kind of reroute that we could find or know about is considered in our guidance, including the fact that we’regoing to accelerate a project that really was planned for the end of next year, when we had higher production rates; we call it the East End Line. We’re actually going to lay a line that has about 200 million a day capacity, have it operational in late September. And we don’t have 200 million to put in the line; we’ve got about 100 million today to put in that line. But we’ll bypass Boardwalk and go straight to NGPL and we’ll get us a little more takeaway. And that goes back to an earlier question, why the production looks a little bit more in the fourth quarter. We are doing some things, rerouting and drilling in a little bit different areas to take advantage of every bit of pipeline we can take advantage of.
Tom Gardner: That makes sense and it’s a nice lead in to a follow-up question. Just given these transportation issues, can you walk us through the timing of future pipeline expansions and possible pinch points and how should we think about 2010 growth?
Steve Mueller: I think we’re all right once we get through the Boardwalk repairs. If you remember, we talked about phase one, phase two in the prepared remarks. There’s a phase three of the Boardwalk pipeline; there’s added compression and it’s supposed to be in at April of next year. They're on schedule to do that and that’s literally just delivering compressors out there and hooking them in, so I think that’s in good shape.
And then our other commitment is Fayetteville Express and while they’re in early stages of that, we don’t know of any reason why that would get delayed significantly. And with that third stage compression and Fayetteville Express, we think we’re fine going forward.
Operator: (Operator instructions.) Your next question is from Jason Gammel with Macquarie Capital.
Jason Gammel: I just want to follow-up on the question that was just asked. In the press release it said that gross production in the Fayetteville had reached a milestone of 1b a day in July and it says further in the press release that the transportation capacity for gross operator production was 1.05b per day. Does that mean that you essentially would have been up against some transportation constraints had it not been for the curtailments?
Steve Mueller: No. Let me explain a little bit about the pipeline. In April, the pipeline was dried up on basically 72% of its rating. Late in April, they ran their first inspection. When they ran that inspection they de-rated the line across the entire line, even though it had not been all inspected yet, to about 58% of its pressure. Once we get all this work done we’ll go back up to 72%, and we’ll be off and running from there. It’s really just all the work that’s going on with the pipeline that’s the effect today, but we’ve got the capacity once they get the repair work done.
Jason Gammel: Okay great, that’s very helpful. And then just a broader question. You guys had mentioned you’re turning to a more normal price environment over the coming weeks and months. Could you just give us your outlook on the macro environment, what you see just in terms of production in the US because of all the rigs way down, that sort of thing?
Steve Mueller: We’re all pointing at each other when you asked that question. This is one of those strange times, where because of the Boardwalk pipeline issues, you kind of hope the gas is a little bit lower here for the nextcouple of months, because you can’t take advantage of it as much. But I think in general, our general philosophy is that there are some forces in play, especially with the overall production and the low rig count, that should have gas price increase in the future.
We also think it’s going to be very volatile. We think it’s going to go up and it can come down as fast as it goes up and we think that will happen certainly for the next year or so. So we’re just watching it and as we can take some more hedges, we’ll take some more hedges and we’ll make decisions as it plays out. Again, the key to what we’re doing is flexibility. If prices look like they’re going to go up in 2010 later this year, we won’t drop those couple of rigs I mentioned in the Fayetteville. If they’re staying the way it is today and it looks like it’s going to stay that way for a while, we’ll make decisions then and go from there.
Operator: Your next question is from Vedula Murti with CDP US.
Vedula Murti: I’m kind of following up a little bit on Jason’s questions. If we look forward to 2010, can you talk a little bit about whether you’ll be matching up the capital program to projected cash flows or would you, given your strong balance sheet at this point, would you be willing to take on a little bit more leverage at this point? Can you talk a little bit about how you’re thinking about that?
Greg Kerley: We’re in the early stages of even starting to look at 2010 and build our program, so we’re several months away from knowing what that is going to look like exactly and obviously our price environment will have a big interplay with that. We planned our 2009 and 2010 overall program as we entered this year, where we could withstand a low price environment during that entire two-year period and in that scenario we’d be modest borrowers this year and potentially next year, but still have at least half of our billion-dollar credit facility still available to us as capacity. So we’re not uncomfortable in that situation, if that’s the price environment, but on the other side of that, it doesn’t take a very -- a $6.00 to $7.00 gas price environment we’d be cash flow positive here in 2009 or at least cash flow neutral.
Operator: Your next question is from Scott Hanold of RBC Capital Markets.
Scott Hanold: Steve, you talked a little bit about the downspacing test that you saw a few frac hits and I know you don’t want to give too much punch until you guys have a full opportunity to get a better handle on the data, but can you kind of give us some sense of how tight some of that spacing is getting and maybe relative to what has happened, say in other places in the Barnett where there’s been a lot tighter downspacing? Frac hits are pretty typical in some of the tighter spacing wells and really give us a sense of what that means.
Steve Mueller: Well, we are right now in the process of drilling about 400 wells at various downspace levels. Most of those are being drilled around a 56-acre spacing. If you remember, our pilot work we did was around 110-acres and we’re just kind of splitting that spacing. And then we have a smaller number of wells that we’re splitting again, going down to 28-acre spacing. And as you say, the closer you get, the more likelihood that you have a frac hit and there are all kinds of things you can do with simulfracs and things that they’ve done in the Barnett that actually enhanced production in certainparts of their field. We’re in the early stages of learning that.
As I said, frac hits are normal. We’re trying to figure out, as we get to those tighter spacings, is that helping, not helping and then how that works in overall plans as we go forward in the future. And again, I just don’t have enough information. It’s coming in, but we haven’t been able to sort it all out yet.
Scott Hanold: Okay. And in some of those wells that are in sort of that 50-60 acre spacing, have you seen any frac hits there or has it been much less in those wells?
Steve Mueller: I don’t know the exact percentage, but there is a fair number; it’s not 50% but there’s a fair number that you’re getting frac hits at 60-acres. And frankly, every once in a while at 110-acres you get a frac hit. It’s not normal, but it happens.
Scott Hanold: Okay. And then looking also at 2010, and I’m not going to push you for guidance there, but I think you all were looking at getting some specialized rigs for the Fayetteville to kind of move from once in development stages. Can you give us an update on what you’re thinking in terms of adding some specialized rigs for the play and when that could happen?
Steve Mueller: We’ve certainly looked at designs and from what we’ve learned in drilling wells, what we’d do different on rigs. But as you said, we really haven’t got thinking enough about 2010 or 2011 to figure out when we might do that.
Operator: (Operator instructions.) Your next question is from Joe Allman with JP Morgan.
Joe Allman: Steve, in terms of the Marcellus shale, could you give us an update of what’s going on there and when you might start talking some more details in the Marcellus?
Steve Mueller: There is not much update. We have picked up a little bit of acreage since the first quarter, but it’s not significant and the acreage we’ve picked up has been kind of blocking in where we’ll start drilling next year. We’re continuing to look at some other bigger acreage blocks, but haven’t done anything yet on that. What we’re doing on acreage in Marcellus today is permitting wells, getting the water rights in line and looking at pipeline right of ways, those kind of things, for a drilling program in 2010 and we’ll continue doing that the next couple of quarters and at the same time kind of opportunistically take down some acreage as we can do it.
Joe Allman: Okay that’s helpful. And then second question, on the Fayetteville Shale costs, they went down by about $100,000 from the previous release; what’s driving that and do you think that you could drive the costs lower and what might be a target for the company for the average Fayetteville Shale well cost?
Steve Mueller: There’s a couple of big pieces that are driving that. Steel cost has gone down significantly, so part of it is steel cost. Part of it is on the completion side, the pumping services have continued to go down from first quarter to second quarter. And then just taking that day out of thedrilling time has done it as well. With what we’re estimating today, we think we're going to exit the year another $100,000 down, roughly, in our costs.
Operator: Our next question is coming from the line of Dan McSpirit with BMO Capital Markets. Please state your question, sir.
Dan McSpirit: Gentlemen, good morning.
Steve Mueller: Good morning.
Dan McSpirit: Can you discuss the choke size applied on the first two Haynesville Shale wells and what you might apply going forward here to manage the decline rate going forward?
Steve Mueller: On the first well, I think I mentioned in the last conference call that we--soon after testing that first well, we put on a 1360 force and as far as I know it's still a 1360 force choke. So we haven't done anything to that one. And so, it's a little lower than you might have in some of the other areas, but frankly, that just has to do with takeaway capacity. On the second well, I don't know exactly what the choke is. It's about 3,900 pounds today, that's 7.8 million a day, so it's still got a lot of pressure there. And I know it's got 20 on it, but I don't know if it's 24 or 28, whatever the choke is.
Dan McSpirit: Okay. And what's the plan going forward here? Anything different than what was applied on the second well?
Steve Mueller: Not that I know of.
Dan McSpirit: Okay.
Steve Mueller: As you look at the other wells we're going to drill, they're all going to be roughly the same laterals, those same kind of frac stages. And I don't think we're planning to do anything to these wells. The key is keep them as constant as you can on choke size, so you can really see what they're going to do.
Dan McSpirit: Very good. Thank you.
Operator: Our next question is a follow-up from the line of Robert Christensen of Buckingham Research. Please state your question, sir.
Robert Christensen: Yes. Could you just tell us how in the field you would flex down your Fayetteville Shale production for the--sort of daily, weekly? I mean, do you do shut-in wells, do you choke them back, do you run the compressors less? Just give us a sense of how physically you would flex them.
Steve Mueller: And you're talking about when Boardwalk--.
Robert Christensen: --Yes--.
Steve Mueller: - --Does its work.
Robert Christensen: Yes.
Steve Mueller: There's a lot of ways that we can do it. When they completely shut-in all of their system, we're taking down a lot of wells. And we've got a list of wells that are easiest to take down. And there's also part of that list where you can get into other markets and where you can't get into markets. When they just take it down for a day or two, a lot of that we can do with just taking compressor stations down and letting the line pack a little bit. And so, we do a combination of things, depending on how long it's going to be down, how much it's going to be down.
Robert Christensen: The next question, a follow-up. Fayetteville wells, when they have been shut-in, let's say, for an extended period, how have they come back to life? Do you have any kind of--?
Steve Mueller: - --We really haven't seen any issues with them. Just like all wells, they have a little bit of a storage effect, so they'll pop up a little bit when they first come on. But, except for that, we're not seeing any kind of damage like you might have in some of the other areas of the country.
Robert Christensen: Thank you, Steve.
Operator: Our next question is from the line of--a follow-up from the line of Mike Scialla with Thomas Weisel. Please state your question, sir.
Mike Scialla: I just had one more on the pipeline. Could you tell us what the nature of these anomalies are that Boardwalk talked about? And then, do you think it's a potential for a widespread problem in the industry or is this you think just isolated to Boardwalk?
Steve Mueller: As far as a widespread problem, we don't have any idea whether it's a widespread problem. What has basically happened is that they run an inspection device down the well bore or down the pipeline. And the--that inspection device historically hasn't been as accurate as this very newest thing that's been run. And it's less than a year old. It can tell anomalies in the pipe of less than a quarter inch. And when I say anomalies, say the pipe is slightly deformed a quarter inch, it can pick that deformation up. The older tools couldn't pick up anything near that kind of resolution. So what's happening with the newer tool, you run it in these newer pipes and you're seeing a lot more anomalies than historically have been seen. And both the government and the pipelines don't know exactly what to do with that.
So part of what's been going on with the Boardwalk Pipeline in particular, is as they've run the inspection tool they've already gone back and part of this last quarter was them going back in and taking chunks of that pipe out, taking it to a lab and they're doing tests on it right now to know if a quarter inch is significant or not or three-eighths is significant or half inch is significant. And once they figure that out and go back to PHMSA, the government agency that is in charge of this, PHMSA will then say, here's the anomalies you need to take out and these other ones are okay. And that's why you're hearing one to five months. That's why you're seeing the large spread in our estimate for how much we're going to be down, because no one knows yet in any kind of clarity how much of the pipe is affected and how many of these things they're going to have to cut out.
Mike Scialla: That helps. Thanks.
Operator: Our next question is a follow-up question from the line of Joe Allman of JP Morgan. Please state your question, sir.
Joe Allman: Yes, thanks, again. Just separate from this Boardwalk Pipeline issue, were you bumping up against any kind of high line pressures or issues related to the high level of storage?
Steve Mueller: No, not really. As a matter of fact, in the second quarter the basis in general for the markets we go into closed up. And the reason for that was that south crossing and those other lines south of us coming out of the mid-continent and the Barnett took some back pressure off some of those mid kind of markets. So it actually has improved a little bit. Now, whether it will stay that way, I don't know, but we really haven't seen anything.
Joe Allman: Okay. Very helpful. Thanks, Steve.
Operator: Thank you. Ladies and gentlemen, we have reached the end of our allotted time for questions. I would like to turn the floor back over to Mr. Mueller for closing comments.
Steve Mueller: I want to thank everyone for being on the call. As you can--as we've talked about, the Boardwalk is going to be a little challenging here for the next couple of months. But we've got a really bright future ahead of us with what we're doing in the Fayetteville Shale. And we think we've got some exciting projects in James Lime, Marcellus, and Haynesville's got our interest peaked. So we think there's some bright things going for us as we go into the future.
So again, thank you, and if you've got any questions, give Brad or Greg a call and we can fill in some more questions.
Operator: This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation. Gentlemen, please standby. I'll transfer you to a post-conference.
Explanation and Reconciliation of Non-GAAP Financial Measures
We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods.
One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.
See the reconciliation below of GAAP financial measures to non-GAAP financial measures for the three months ended June 30, 2009 and 2008. Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.
3 Months Ended June 30,
2009
2008
(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities
$ 266,436
$ 291,165
Add back (deduct):
Change in operating assets and liabilities
58,860
(2,935)
Net cash provided by operating activities before changes
in operating assets and liabilities
$ 325,296
$ 288,230
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