Southwestern Energy Company Q2 2006 Earnings Teleconference Call
Officers
Harold Korell; Southwestern Energy; President, Chairman, CEO
Richard Lane; Southwestern Energy; President, E&P
Greg Kerley; Southwestern Energy; CFO, EVP
Analysts
Tom Gardner; Simmons & Company; Analyst
Shannon Nome; Deutsche Bank; Analyst
David Heikkinen; Pickering Energy Partners; Analyst
Robert Christensen; Buckingham Research Group; Analyst
Joe Allman; JP Morgan; Analyst
Brian Singer; Goldman Sachs; Analyst
Michael Scialla; AG Edwards; Analyst
Travis Anderson; Gilder, Gagnon, Howe & Company; Analyst
Amine Benali; John Hancock Advisors; Analyst
Ken Carroll; Johnson Rice; Analyst
Scott Hanold; RBC Capital Markets; Analyst
Richard Moorman; Capital One Southcoast; Analyst
John Gerdes; SunTrust Securities Group; Analyst
Presentation
Operator: Good day, and welcome to the Southwestern Energy Company's Second Quarter 2006 Earnings Conference.
At this time, I would like to turn the conference over to the President, Chairman, and CEO, Mr. Harold Korell. Please go ahead, sir.
Harold Korell: Good morning, and thank you for joining us. With me today are Richard Lane, the President of our E&P segment, and Greg Kerley, our Chief Financial Officer.
If you've not received a copy of the press release we announced yesterday regarding our second quarter financial results, you can call Annie at 281-618-4784, and she'll fax a copy to you. Also, I would like to point out that many of the comments during this teleconference may be regarded as forward-looking statements that involve risk factors and uncertainties that are detailed in our SEC filings. These forward-looking statements are subject to risks and uncertainties, many of which are beyond our control. 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.
During the second quarter, our development drilling programs in East Texas and the Arkoma Basin continued to deliver solid results, and we made significant progress in our Fayetteville Shale play. We increased the pace of our drilling in the Fayetteville Shale as additional rigs were placed in service, and we saw a marked improvement in well performance resulting from improvements in our fracture stimulation practices. As a result, our production volumes from the Fayetteville Shale have started to increase dramatically, with gross production from the play at approximately 50 million cubic feet per day, up from 20 million cubic feet of gas per day in early May.
At this time, we have 10 rigs running in the Fayetteville Shale play, including five of our Company-owned rigs, which are performing very well. We expect three more rigs to be delivered in August, with a total of 19 to 20 rigs drilling by year-end. We currently expect to spud 175 to 200 wells in this year, in 2006, as we accelerate development and assess undrilled areas of the play. Richard will give a full update on our E&P operations in a moment.
On the financial side, we again set new quarterly records for net income and cash flow, primarily due to higher production and higher realized commodity prices. As mentioned in our release, we also saw increases in our per-unit costs and expense, reflecting the significant upfront investment we've made in equipment and personnel related to our Fayetteville Shale play.
I'd like to now turn the conference over to Richard Lane, who will tell you more about our E&P activity, and then to Greg Kerley to discuss our financial results. And then at the end of that, we'll take questions.
Richard Lane: Thank you, and good morning.
Our total production for the second quarter was 16.4 Bcfe, up 9% from the 15.0 we produced in the second quarter of '05 and up 11% for the first six months over 2005. Our Fayetteville Shale production alone was 1.8 Bcfe in the second quarter, up substantially from the 0.7 we produced in the first quarter.
Through the second quarter, we have spudded a total of 170 wells, including 86 wells in our Fayetteville play, 43 wells in East Texas, 34 wells in the conventional Arkoma Basin, six wells in the Permian, and one in the Rockies. We invested a total of $344 million in our E&P program during the first half of 2006. We currently have 20 rigs running --10 in the Fayetteville Shale play, five in East Texas, three in our conventional Arkoma Basin, and two in the Permian Basin.
At the Fayetteville Shale play in the first six months of 2006, we invested approximately $119 million, including $88.6 million for drilling and completions and $17 million for leasehold. As of July 31, we have now drilled and completed 105 wells, including 51 vertical wells and 54 horizontal wells. 29 of our most recent horizontal wells have been completed with either slickwater or cross-linked fracture treatments, as we have moved away from earlier nitrogen foam completions.
The average initial production test rate for these 29 wells was 1.7 million cubic feet per day, 20 of which have been on production for more than one month, and the average rate for these 20 wells after 30 days was 1.6 million cubic feet per day.
In yesterday's earnings release, we included an update of the horizontal well production graph for wells which were stimulated using the slickwater or cross-linked fracture technique. This graph continues to show improved early production performance from these wells over our earlier completions.
We also have included a graph of gross production volumes from our Fayetteville Shale play, which show the effect of improved well performance and the project acceleration. Current total gross production from our Southwestern-operated wells is approximately 50 million cubic feet per day, up from 20 million cubic feet per day at May 1. We expect our gross 2006 exit rate to be near 100 million cubic feet per day.
Here are a few recent well examples.
In our Cove Creek field, located in Faulkner and Van Buren counties, the Edwards 2-36 well had an initial production test of 1.7 million per day and is currently producing 1.5 after being on production for 93 days.
In our Scotland field in Van Buren County, the Black 1-21 well initially tested at 2 million cubic feet per day and is currently producing 1.5 after being on production for 107 days.
Our Gravel Hill field in Van Buren and Conway counties is currently producing approximately 28 million cubic feet per day alone. We're expanding our gas-gathering capacity in the Gravel Hill and Scotland Field areas. As a result of the higher production rates from newer wells, increased gathering line pressure is temporarily restricting production from some of the older wells.
A few Gravel Hill wells of note are the Anadarko 1-11, the Evans 1-32, the Grills 2-31, the Guinn 2-6, and the Russell 1-33. These wells are currently producing at an average rate of 2.4 million cubic feet per day after being on production for an average of 47 days. The Anadarko 1-11 tested at 3.6 million per day and is still producing 2.7 million after being online for 80 days.
As of July 31, we held a total of approximately 883,000 net acres in the play. Of this, approximately 758,000 net acres were in the undeveloped play area, and the remaining 125,000 net acres in our traditional fairway area.
In the second quarter, we extended the play approximately 20 miles to the east with the drilling of the Hefly 1-12 located in our Sharkey pilot area of White County. The Hefly well was drilled and logged approximately 363 feet of gross Fayetteville Shale with pay comparable to what we are seeing in our Cove Creek field. We're also currently drilling the horizontal lateral sections in our first wells in the Caddis pilot area east of Cove Creek and the Goblin pilot area northwest of Sharkey, where the Hefly well is. By the end of 2006, we expect to have effectively tested a substantial portion of our Fayetteville Shale acreage.
As mentioned previously, we currently have 10 rigs running in the Fayetteville Shale play. Of these 10, two are shallow rigs, which we used to drill a vertical portion of our wells prior to moving in one of the larger rigs capable of drilling the horizontal section. Five of these are Company-owned build-for-purpose rigs that Harold mentioned, and we expect to have three or four shallow rigs and up to 16 deeper rigs in the play at the end of this year.
We're pleased with the progress we have made in the play to date and look forward to additional improvements throughout this year.
In the Arkoma Basin conventional area, we invested approximately $39.5 million and spudded 34 wells in the first six months of 2006. We currently have three rigs running in the conventional play. All these rigs are drilling at our Ranger Anticline project in Yell and Logan counties, Arkansas.
One second quarter well of note in the Ranger Anticline area is the SKK 1-13. This well is located between our main producing area and the eastern extension area we started developing in 2005. It's presenting producing 2.3 million cubic feet per day after being on production for 60 days. And we are currently completing offsets of the Smith 1-12, which had good gas shows in the Basham, Nichols, Turner, and the deeper Borum sands while drilling. We anticipate that we will have up to five rigs running at Ranger later this year and drill between 45 and 55 wells in 2006.
Since our last teleconference, we have established production from the Borum and Basham sandstones in our Midway prospect test, the one -- USA 1-24 last year. In the first quarter of 2006, we drilled an additional exploration test in the southern portion of our Midway block. This well, the USA 1-4, encountered 97 feet of potential pay in the Basham interval at about 5,000 feet and tested at a rate of 1.8 million cubic feet per day. We expect this well, which we operate with a 60% working interest, to be on production in September, and we expect to drill a third exploratory test on that block in the third quarter.
In East Texas, we continue to be active in our Overton Field and the Angelina River trend. In the first half of 2006, we invested approximately $113 million in East Texas and spud 43 wells, 38 at Overton and five at Angelina River. We currently have four rigs drilling at Overton, with an additional rig in the Angelina River trend.
In July, we released two third-party rigs that had been drilling in our Overton area. In our opinion, the day rates being charged for those rigs had become noncompetitive with other rigs available in the market. We have contracted with another drilling company to bring one of their rigs into Overton later this month. Additionally, we expect to bring two company-owned drilling rigs into East Texas by the end of 2006. Both these rigs and the newly contracted third-party rig are expected to result in lower overall drilling costs and higher returns on our investment. Due to the release of the two third-party rigs, we now expect to drill approximately 70 wells at Overton in 2006, as compared to our original plan of drilling approximately 83 wells. We continue to maintain a 100% success rate at Overton after drilling over 290 wells since we acquired a field in the year 2000.
Production from our Overton field was approximately 0.2 Bcf less than expected due to curtailment issues which were resolved late in the quarter. Delays in rig deliveries in our Fayetteville Shale play earlier in the year, along with these curtailment issues and changes in the drilling plan for East Texas I just discussed, have resulted in a slight decrease in our oil and gas production guidance to 73.0 to 75.0 Bcfe for the full year 2006.
In addition to Overton, we continue to expand our holdings at the Angelina River trend in Nacogdoches County. At December 31, 2005, we held approximately 14,000 gross acres. Since this time, we have leased an additional 31,000 gross acres, including 13,300 acres in the second quarter. In the second quarter, we completed the Isaacs #2 well, and this well had a peak rate of 2.2 million cubic feet per day from the Travis Peak, which is at approximately 11,500 feet. We're optimistic that our growing position here may provide significant drilling inventory next year and beyond.
Moving on to the Permian Basin, we discussed in our last teleconference that we have approximately 50,000 acres in the emerging Barnett Shale play in the Permian Basin. In the second quarter, we drilled and completed a well in our Popeye prospect and have spudded a well in our Coronado prospect, both of these blocks in Culberson County. The Popeye well, the State Street 701, is currently being tested, and the Dela Minerals State 701, our first well on the Coronado block, is at 7,000 feet, on its way to a total depth of 12,600 feet, and we expect to reach TD on that in early September.
In summary, we're very encouraged by our continued success in our Fayetteville Shale project. Gross production is up to 50 million cubic feet per day, and our recently completed wells continue to outperform. We currently have 10 rigs running and are ramping to 19 or 20 rigs by the end of the year. Overall, our programs in the Arkoma Basin, East Texas, and the Permian Basin are performing well, and we're looking forward to continued strong results in the remainder of 2006. We're on track to achieve 20 to 23% through organically driven production growth of 2006, and 2007 is shaping up as an exciting year for our E&P business.
I will now turn it over to Greg Kerley, who will discuss our financial results.
Greg Kerley: Thank you, Richard, and good morning.
As Harold indicated, we had another record quarter. Our earnings were up 38% to $0.22 per share, compared to $0.18 for the same period in 2005. Our reported earnings included approximately $0.03 a share of nonrecurring items, reflecting the gain on the sale of our interest in the NOARK pipeline system and a one-time adjustment to record additional deferred income tax expense related to recently enacted tax legislation in the state of Texas. Our net cash provided by operating activities before changes in operating assets and liabilities was $84.3 million during the second quarter, up 30% from the prior year.
Operating income for our E&P segment was $49.5 million for the quarter, up 2% from the prior year as the effects of increased production and higher commodity prices were largely offset by increases in our operating costs and expenses.
The average price realized for our gas production was $6.23 per Mcf for the quarter, up from $5.71 a year ago. Our hedging activities increased our average gas price by $0.07 during the second quarter, primarily due to Fayetteville basis hedges. Our current hedge position, which consists primarily of costless collars, provides us a solid level of cash flow protection, while still allowing us to retain considerable upside. We have hedged approximately 70% to 75% of our targeted 2006 gas production and 15% to 20% of our targeted oil production. We also have approximately 65% to 70% of our basis differentials for our gas production protected for the remainder of 2006 through financial basis hedges and gas sales arrangements. Assuming an average NYMEX commodity price of $7 an Mcf, we expect our average realized price to be approximately $0.45 to $0.55 lower than average NYMEX spot market prices for the remainder of 2006.
Lease operating expenses per unit of production was $0.64 per Mcf equivalent in the second quarter, up from $0.43 in the same period last year. The increase primarily results from higher gathering and compression costs related to our Fayetteville Shale play.
General and administrative expenses per unit of production were $0.60 in the second quarter, up from $0.39 during the prior year period. The increase was primarily due to higher compensation and other costs associated with our increased staffing levels to meet the demands of our expanding operations primarily related to developing our Fayetteville Shale play. Over the past year, we had made a significant investment in time and resources to meet our staffing needs and are pleased with the quality of people we have been able to recruit. We have hired 100 people in the first quarter of the year and another 144 during the second quarter. We expect to hire another 200 to 250 employees by year end. Approximately 250 to 275 of the total new hires are expected to be employed by our drilling company.
Our full cost amortization rate averaged $1.79 per Mcf in the second quarter compared to $1.38 in the same period last year. The higher rate resulted from an increase in our finding and development cost. Our finding and development costs during 2006 are expected to be heavily impacted by the timing and amount of our reserve bookings related to our Fayetteville Shale play.
Operating income from our midstream services segment was $800,000 in the second quarter, down slightly from $900,000 last year as increased staffing and operating costs for our gathering activities the Fayetteville Shale were largely offset by increase in margins and gas volumes marketed.
Our utility systems realized a seasonal operating loss of $2.1 million in the second quarter compared to a loss of $2.4 million for the same period last year. The increase in operating income was primarily due to the effects of delayed increase we implemented in October of 2005, partially offset by increased operating costs and warmer weather.
During the second quarter, we completed the sale of our 25% minority interest in the NOARK partnership for $69 million. We recorded a $10.9 million gain, or $6.7 million after tax, related to the sale and assume that $39 million of debt obligations in NOARK, which we previously guaranteed. The net proceeds from the sale will be used to help fund our 2006 capital investment program.
Our total capital investments in the second quarter were $207 million and were $374 million for the first half of the year.
Our balance sheet and financial position remained extremely strong. At June 30, our balance sheet debt-to-capitalization ratio was 10%, which is one of the lowest levels in our history. And we had approximately $176 million with a short-term cash investment, which exceeded our total debt outstanding by $38 million. We also have access to $500 million of unborrowed capacity under our current revolving credit facility. We are extremely well positioned to continue to accelerate our development of the Fayetteville Shale.
Despite the fact that we have been achieving the strongest operating results in our Company's history as well as establishing our best credit profile, our credit rating was downgraded by S&P to BB+ (stable outlook) from BBB- (negative outlook). The downgrade did not impact our current cost of borrowing under our credit facility. We are disappointed with the downgrade, especially at a time when we have over 60 times interest coverage and one of the lowest debt-to-total capital percentages of any publicly-rated E&P company. Unfortunately, it seems that our size and the potential for accelerated development over our Fayetteville Shale play factored heavily in this decision.
In our earnings release for the quarter, we also updated our guidance for the year, which included increasing some of our projected unit operating cost expenses and lowering our expected interest expense. As we continue to implement our drilling program, we expect our production levels to continue to ramp up significantly. Our targeted production for the third quarter of 2006 is 19 to 20 Bcf equivalent and our targeted production in the fourth quarter was 21.7 to 22.7 Bcf equivalent.
For the full year of 2006, as Richard indicated, we are targeting oil and gas production of 73 to 75 Bcf, which equates to growth of 20% to 23% from 2005. That concludes my comments and I will turn it back to the operator who will explain the procedure for asking questions.
Questions and Answers
Tom Gardner: With regards to the Hefly 1-12 well, my understanding is that it is logged but not tested. Have you encountered analogous shale in the play, that has not produced commercially? How does that 360 plus feet of gross pay compare with other wells in Van Buren and in Cleburne County?
Harold Korell: Richard, do you want to handle that?
Richard Lane: Yes, sure. This is Richard. I would say that you know, the log looks very encouraging and the straight up answer to that is we haven't had a well that we have logged in the Fayetteville Shale section that looks like that hasn't produced gas. So, very positive that way. It is analogous to some of the thicker parts of where we have been drilling and developing more like down in our Cove Creek area which is you know, one of the most southern pilots. So, I am very positive but we haven't tested yet.
Tom Gardner: What is your average net pay or net gross in the play?
Richard Lane: Well, you know it ranges, I don't know the exact average right now but you know we are ranging kind of 200 to 300 feet in the main undeveloped area.
Harold Korell: And back over in the fairway it tends to be 50 to 70 feet thick. So an average number is probably not very useful number in total, but over where we have been doing most of the drilling it is in excess of 200 feet.
Tom Gardner: Those are gross pay numbers?
Richard Lane: Yes.
Tom Gardner: Okay. Do you consider most of the gross pay contributing or is it some ratio of that?
Richard Lane: Well it is a hard thing to get a handle on, as you know. We do kind of net them down for what we see in resistivity and on our density curve, but we are fracture stimulating the whole interval, so it is all contributing probably some amount.
Shannon Nome: Hi, thanks. Good morning. I am curious with the Hefly well what percent in broad terms do you think of your whole 880,000 acre position do you think you have now validated?
Harold Korell: Well, Shannon that's probably a good question. It is not one that I know the answer to right now. You know the “ham” that we had drawn on our maps earlier represents about 35% and now we have stepped out 20 miles from that to kind of along pipeline again, if you will, following the pipeline route along there.
It would just be a question of, do we just loop it, you know -- it is hard question to answer. I think it is kind of a straight line over to the Hefly now and then we are drilling a well north and west of that, the Goblin is probably another 9 miles or 10 miles away from the Hefly but north, and as we get little more filled in I guess we could then talk about increasing the size of the ham. But definitely we have increased the area now.
Shannon Nome: So something between 35% and maybe 50%?
Harold Korell: And then the other data point is where Chesapeake is drilling south of us, you know they have drilled in White County, probably south of the Hefly at least 15 miles, Richard, I would guess and the Gentry well, they were reporting on the other day. It looks pretty good. So, you know these are kind of single data points as we step out and you know, I think we are looking to say what a another percentage is, but definitely a positive.
Shannon Nome: Okay. And then how even or uneven I guess has the pays in the IPs been across the various areas? In other words, do you have bunch of the wells that are below 1.3 EUR, and then a bunch that are above 1.5? Or are they more narrowly congregated within that range?
Harold Korell: Well, that question again presumes we know what to say, the EURs are for these wells, and I think it is too early to nail that down, real tightly. In the press release we put out actually all the data again, every one of the wells, and what its IP is in current rates, and then we put out that combined curve.
I think the important thing about all of it is that we have one well now that's about 300 days old of this new family of slick water fracs and cross-link gel fracs. So we have one well that is that old, and you could begin to nail it down but the remaining 20 some of them are a lot younger. So, I think in terms of -- we haven't nail down what the EUR is on each specific well. There is going to be somewhat of a range, but as you look at that table, you will see some wells whose IP is lower. But then they, after cleaning up some more they actually get a little better for a time before they start declining.
Using that short time production data to estimate or nail a real number for expected ultimate recoveries is just kind of hard to do. We know that are appearing to be above the 1.3 to 1.5 models but exactly what the numbers are, we are just not willing to put a number out there.
David Heikkinen: Hi, guys. Good morning. Just a question on the quarter, can you give us production per region for the second quarter and then any sort of thoughts on guidance for third and fourth quarter by each sector, Fayetteville, Arkoma, Permian, Gulf Coast, or do you have that?
Richard Lane: David, I can give you the breakout for the second quarter of this year. The Arkoma Basin conventional was 4.8 Bcf; Fayetteville Shale play was the 1.8 Bcf; East Texas, 7.7; Gulf Coast, 0.7; and the Permian, 1.4.
David Heikkinen: Okay. And any details on the third quarter and fourth quarter regionally?
Richard Lane: I don’t think by area, but we had our previous guidance for the Shale was I believe 11-13 Bcfe for the full year and then now we have just updated the full year Company-wide one.
David Heikkinen: With the drop off in rate count in East Texas, we would expect a little bit of a decline in production until you get it back up to 7 or 8 rigs running by year end. Was it 7 or 8 rigs in East Texas? I didn’t get the exact number. Trying to count them back up in East Texas at year end.
Richard Lane: I think that would be six when we get our Company-owned rigs. But I think it is a little lower well count, and we have seen that maintaining the wells that we drill per year as part of the quarter-on-quarter production growth, it would actually be seven rigs, David, at year end if we bring in that contracted rig as well.
David Heikkinen: Okay.
Richard Lane: But I think the quarter-over-quarter growth rate will flatten a little bit because we have less wells, but it will still be very strong contributor for us, and then as the Angelina River Trend matures, that can potentially be a nice supplement to that program.
David Heikkinen: And all of the acreage added in the Angelina River Trend is pretty contiguous, now it is up to 45,000 acres?
Richard Lane: No, I wish I could say it was. We have just straight blocks and some of those are not connected but it is the nice hardworking interest and decent nets, block of acreage for us.
David Heikkinen: Okay and then on the Fayetteville, with eight rigs running taking your production from 50 million a day now to 100 million a day on an exit rate, talking about going to 16 rigs running next year, obviously implies an accelerating trajectory for production; isn't directly linear, but can you give some sort of frame of reference of how we ought to model it in, that acceleration of drilling and what that means to production going into next year?
Richard Lane: Well, I don't think we will detail it quarterly, but I think the way to look at it is there are actually 10 rigs out there and eight of those are the deeper drilling rigs. Then we talked about the delivery schedules for going forward. Actually August would be a pretty active month for us, where we will have at least probably two being delivered. So that we have been on the -- three delivered in August, excuse me, and then back to kind of one for per month after that. So that is probably the best way to kind of describe that and how the associated drilling activity will follow.
Robert Christensen: Yes, do you think it is fair to say Overton now, at best today it is flat because of the interruption of the drilling schedule with the high decline rates?
Harold Korell: Well, Overton, by our plan, drilling was going to likely be over with in 2007 as far as the development plan, and Overton has been sort of peaking, I guess you would say. We have been at the 100 million a day, just a little over 100 million a day at times, rate. So Overton is nearing its mature part of its life, and there will be a point in 2007 where we will pretty much have it drilled up. We just, like you say, it is a matter of the math on it. Unless you keep adding rigs to those kinds of developments, they flatten.
Robert Christensen:Thanks, Harold. That brings me to the next question. Can you put a little more color on the Angelina River Trend? How many wells do you have down, and flow rates. I am counting on the Angelina River Trend to really start to replace Overton. Is that the direction I can hope for? And will you ever test Cotton Valley out there?
Harold Korell: Let me just say, Richard, respond to that. We have a number of things that we work on always as new project leads and seed money into, and Angelina River is one of those where we've been putting some seed money to hopefully establish another development area. That will only -- we will only know the answer to that as we drill more. Up to this point, we have drilled some pretty good wells in there and the plan is to continue assessing that acreage and see what comes out of that.
The primary target for us there right now is the Travis Peak and I think Richard has given in his comments and if not in the press release also some producing rates out of wells. Angelina has the opportunity to become an interesting area for us. Is it like the Overton Field, specifically? Maybe, maybe not it's a different pay. But Overton fortunately for us and we're done drilling there we have already suffered the early decline on the bulk of the wells. We're going to have a nice production base left from it. Our hope is that Angelina River can turn into a good project area for us and beyond that we have other things, chances of growing our production as well. To say nothing of the Desoto Play and the Fayetteville Shale and some other things.
Richard Lane: I think Bob, just for some numbers, I think we're at about 14 wells there now that we've done, so we're pretty encouraged by the results on average, somewhere a little less than a 1.5 Bcfe per well, we think. And they have been testing 2 to 2.5 million cubic feet per day. So, definitely we're looking for that to be something that we can supplement our East Texas Program with. If you look at the spacing and the acreage there's a lot of wells to drill if we can prove some more of it up. I mean, that's part of what we've shown that we are good at here is that our ability to create new ideas and we will be continuously doing that. That is just an example of that.
Joe Allman: Harold or Richard, in the Fayetteville Shale play, when we see the variability amongst wells and even some wells that are pretty close together, what do we attribute that to, or is that just sort of the nature of things and that's what we should expect going forward in this play?
Richard Lane: Well, I think if you look at these types of plays in general, Joe--it's Richard--I think you can expect that variability. Everybody would like to focus in on the average well and have that consistency in the macro sense and also even in the small areas within a pilot. But the reality of these kind of places, it's hard to get that. If you look at plays where thousands and thousands of wells have been drilled and look at the distribution of that, you see that even after years and years of development. So, you know, what's driving that, I think are some of the things that you can't see when you're looking at a gauge reading what the well's producing or when you're looking at a log and trying to understand petrophysical properties.
It has to do with, I think to me, the big variable and unknown is how effective that fracture stimulation is that you attempt to create and what kind of network of fractures you create and how much of just the natural stuff that you intersect, and I think that's a big variable. And also the effectiveness of the stages that you do. If you're doing a five-stage job, you know, do all five go off real well in one well and maybe less in the next well? That's a variable. One thing we've seen though, is we've gotten a lot of consistency here in the quarter on effectively treating all the stages of our horizontal wells.
Harold Korell: One thing to add to that, Joe, it doesn't seem that there's one area that is tremendously better than another. We have very good wells, ranging all the way from Scotland, all the way down to Cove Creek. So, across this broad area, we're appearing to get some very good results.
Joe Allman: That's very helpful. And then, in some of the curtailments that you're seeing in the Arkoma Basin, do you think any of that is due to any Barnett Shale production moving eastward? And do you think you'll have some issues in the Arkoma with the ramp-up in Barnett Shale production?
Richard Lane: Are you talking about the curtailment that we just reported on in East Texas or are you talking about some of the line pressure things in the Arkoma Basin?
Joe Allman: Yes, I guess I'm--if you could address both, that would be great. I was talking about in the Arkoma Basin in particular.
Richard Lane: Well, the East Texas issue has gone away and that had to do more with Btu content and getting a little too richer of gas into the pipeline. So that's been corrected with some separation facilities work. In the Arkoma Basin, it's not an interstate thing. It's really our local gathering around our pilots. We're drilling awfully fast and bringing on good wells and in some areas, better wells than what the model would have had, so it's ramping up that gathering infrastructure to meet that. So that's a temporary thing--.
Joe Allman: And then just moving over to West Texas, I know you folks are drilling out there and testing out there. Have you seen anything from your drilling or from the industry that gives you more encouragement or discouragement out there?
Richard Lane: Well, we've just drilled and logged our well, so we'll know what we have there. And basically, we've seen what we had hoped to see and we're testing, so we don't have the answer. The industry is pretty quiet on the whole thing. Everybody's holding their cards pretty close to their chest there and we probably will too here for a while. But, it's hard to say how to read that.
Brian Singer: I had a couple of questions on the completion side in the Fayetteville. First, if you could just talk a little bit more about some of the new things you've been trying, relative to slick water and gel frac stimulations? And then secondly, what kind of cost pressures are you seeing on the pressure pumping side and is there anything you can do to mitigate that going forward as more players move into the play?
Richard Lane: On the cost side, what we're doing is just operationally attacking that and we're seeing some efficiencies there that might be able, as we keep working on those, may be able to translate to lower costs. In terms of just our relationship with vendors, we have some purchasing power there with the level of activity we have. And so we have some negotiated discounts there that we think will mitigate that. And then talking to a couple of other contractors, that will bring some competition into that area of our costs. So that's kind of from a cost standpoint.
Harold Korell: Richard, before you go on, operator, we're hearing some echo-back feedback here from what we're saying here. Is there a possibility somebody's on a speakerphone on the other end? I don't want it to degrade the quality of what other people can hear.
Operator: Mr. Singer may be on a speakerphone. I'm not hearing an echo on my end.
Brian Singer: I'm actually not.
Harold Korell: Okay. We're hearing our echo here, which is kind of--it just started up.
Richard Lane: Okay, and then the other part of your question, Brian, I think was what are we doing on the completion side, new things? A lot of new things. You know, obviously, going to the slick water and the cross links is a big departure from our nitrogen techniques and we're very encouraged that's the way to go. You know, some of the things we're doing there is more stages in a given section of horizontal well, maybe more closely spaced together, so when you look at the total net fluid volumes and sands pumped, maybe per stage they're a little lower, but there's more of them. So we're seeing some things there.
We've experimented with using acid soluble cement, when we have a cemented production string in place and that has, we think, provided some pretty positive things in terms of treating pressure and then ultimately getting that stage pumped away. Some real positive things there. The cross-linked-gel on some of our pilots has been very effective in terms of getting our early frac started and also lowering our treating pressures. So those are all real positive things we've been experimenting with.
We have done, I think about 5 wells now where we've used uncemented liners, a technology that's out there. And the benefit we're seeing on that is that we can complete a multistage well quite a bit faster than what we were doing before and we have the freedom to really do as many stages almost as we would like there. And then I think the uncemented liner technology we've been using also has helped us with creating those early fracs and lowering treating pressure.
Brian Singer: Does that then lead to any downside to the $2.1 million that you now talk about in terms of drilling and completion cost or does that just mitigate upside?
Richard Lane: Well, the uncemented liner technology, there's more absolute cost in the hardware, if you will, and then there's reduction in the time you spend out there. So, right now, that's kind of neutral. But I think overall, just to categorize which way we would think that all that would head is two-part. How efficient can we get when we land on a recipe that we want to do? And then what's happening with inflation on the service side? If the inflation costs hold, then we're confident that we can get evermore efficient and drive them down.
Michael Scialla: I'm wondering on your completions in the Fayetteville, with the slick water cross-link gels, have you done any microseismic surveys on any of those wells that would suggest they're draining a different size area than the nitrogen foam fracs? I know you've done some on the early wells that suggested you were draining less than 80 acres. I just wondered if the improved results with those wells suggest that you're draining a larger area or not?
Richard Lane: I think so. I think you kind of hit on it there. We have indeed investigated that while we're using the slick water and we're pretty confident that we're seeing larger half-lengths per stage. So we're reaching out further, perhaps double what we were doing in the nitrogen jobs. So maybe going from 400 or 500 feet to 800 feet or 1,000 feet of half-lengths. So that's a good thing. And then how much of that gets propped and is effective is also a key thing. That's a little harder to get your arms around. But we're definitely contacting more rock.
Michael Scialla: Okay. And then, I think Chesapeake said on their call that they were seeing significant water costs on their first couple of wells, maybe as much a $0.5 million. Could you give us an indication on the $2.1 million completed well cost, what kind of cost for water you're seeing and are you seeing any problems in the play with sources of water?
Richard Lane: We've included all those costs and all the completed well cost estimates we've ever put out there. And I think how much that cost is for a given well depends on where you are and how many wells you're doing. If you're out in a greenfield area and you're starting from scratch, then you know, one well is going to burden a lot of costs.
We've done a lot of things there to mitigate that. We have, in fact, done some surface impoundments ourselves and a lot of things to lower the cost of hauling water in and hauling water out. That's the worst scenario. We've looked at and tested some water source wells. And I think if you look at the whole picture, we're probably including in our AFE, somewhere around $100,000 per well. So we're sharing. You know, when we put in a frac pond or a frac lake, we're allocating that out to all the wells that would use it, so there is no stranded cost there. But I think on average, I think that's what an AFE would be averaging for us right now.
And we have a whole group--you know, your question about, is water an issue going forward? Certainly it is, but we have a whole team of people working on that and a lot of good ideas of how to deliver that to the wells and how to dispose of it in an economic way.
Travis Anderson: I was wondering if, with all the vertical wells that you kind of have waiting for the rigs to complete, if you've seen this rise in production that's been so rapid here in the last six weeks or so is really the result of having the rigs to actually take advantage of the vertical holes you have waiting? And also, wondering how many more vertical rigs you're going to be adding? It sounds like 2 more later this year. And if you have any idea of what you might be adding next year, both vertical and horizontal rigs?
Richard Lane: I think the ramp-up in production is twofold. Obviously, our rig count is rising, so our completed well count is rising. The slope of how many wells we're getting completed in a month is going up. And then also the latest wells, as we reported here, are really some of the best wells. So it's really twofold why that production is rising. And given the deliveries continue to come in, which we think they will, on the equipment and what our team can do in terms of competing these wells, we feel good about estimating that year-end.
Harold Korell: Travis, just in terms of the plans, you can imagine we have a lot of schedules around here that try to time out the deeper rigs delivery and then how that ties to how many vertical holes we need to have in front of the deeper rigs to have a logical schedule. So you see us building an inventory of the shallow holes, the vertical holes that will fit with our rig deliveries on the deeper rigs. And of course, as Richard said, the production buildup is going to occur, because there are more wells being drilled and completed and because of the performance of them.
One other thing that Richard mentioned a while ago that can be important here--can be very important actually, is a couple of major differences in techniques we're using to frac these wells. And one is, we cement the liner in the hole and then perforate, do a frac job, set a bridge plug, perforate, do a frac job, set a bridge plug, getting monotonous, but up to four or five times along that horizontal section and maybe at most we can do two frac jobs a day on that scenario, and sometimes we can't do two a day.
So a completion can string out over four or five days and then at the end of that you have to drill out all those bridge plugs and then start flowing the well back. That's kind of one conventional sense of how you do this. The other is, Richard talked about uncemented liners, we've used a company's technique called Packers-Plus. Some of you have asked questions about that. In which you have isolation packers on the liner that isolate the frac jobs as you do them.
But in that technique, you are able to basically frac an entire hole, which may mean six or seven frac jobs - separate entry points into the formation, if you will - and do that in one day. Well, I mean, being able to complete a well in one day versus four or five days, and then actually turn the well around and begin to flow it back immediately, can affect the results of the well, both the cleanup--it certainly affects the scheduling and it affects the acceleration of the project. If we can get convinced that that's the way to do that--and I think we've done five or six of those. Occasionally, we'll encounter some mechanical difficulties with some of the equipment. But if that can be mastered, it has a pretty big impact on a project like this.
Travis Anderson: Okay. So in terms of vertical wells, you're managing to keep the inventory flat to rising, versus where it was in your last update?
Richard Lane: Yes, that's correct.
Travis Anderson: Okay.
Richard Lane: And it's--using those--what we're calling these spudder rigs or shallow rigs, it's been a nice benefit to us. We're actually lowering the whole well cost by utilizing that. But we're also getting a nice inventory of wells that we can move to, so that we're never caught without a place to go. So I think it's--there's two good benefits from that.
Harold Korell: If you think about use of iron or use of equipment, the shallow--the rigs we're using to drill the vertical parts of the hole are designed to drill shallow wells and in the Arkoma basin, we can generally always drill the vertical part of the hole with an air package on the rig. We don't have to have a mud system. So those little rigs can move around, drill the vertical part in three or four days, put mud in the hole, move off. And then, when the big rig comes, which we have to have mud in the hole anyway to drill the lateral, then they can move in and drill the lateral part. So basically, you're using the equipment for what it's designed to do. And so, I mean, if you're not doing this, then you're not going to have the lowest well costs in the area.
Amine Benali: Yes. Hi. Thanks. My question was on the cost to complete the wells. In your update, you provided a number - $2.1 million per well. And I was wondering how that compared to six months ago. And I think the number we have been given was $1.5 million - maybe that was not realistic. But if that were the number, is the increase explained by the change to the new frac techniques? Or if you could separate on how much was inflation? And is the number likely to drop lower or are you looking at higher and higher numbers?
Richard Lane: Oh, I think we--the previous guidance we had was $1.4 to $1.8 million. And now, our guidance is $2.1. And the increase there is a combination of things. It's the--certainly some inflation kicking in there, day rates going up, and the cost of the--all of the supporting services with the rig going up. And then, part of it being the increase in just the completed side, the change in technology of what we're doing. So, of course, but on that one, we--we're seeing what we think is a well performance that justifies that part of it. So going forward it's--that's hard to predict. But we do know that a growing part of the fleet we'll be using will be our own and we know what that will cost.
Amine Benali: All right. And I have just another question on the Angelina River trend. I was curious if you could confirm what your total acreage is, and if you have drilled any wells to date.
Richard Lane: Right now, our acreage is 45,000 acres. And I believe the number that we have drilled and completed is about 14 wells right now.
Amine Benali: 14 wells. And what was the total acreage six months ago?
Richard Lane: 14,000 or 15,000 acres.
Amine Benali:Okay. All right. Thank you very much.
Richard Lane: That was year-end.
Ken Carroll: Hey, guys. Just a couple of quick housekeeping. In terms of the wells in the Arkoma, where they've been dumped offline due to line pressure. Any--can you give us a feel for kind of the volume impact? And I assume it's on the small side, but--.
Richard Lane: Yes, it's pretty negligible. I think for the quarter it's less--under a tenth of a Bcf.
Ken Carroll: Okay.
Richard Lane: But it's--we want to maximize the production there and the well performance, so we're addressing that.
Ken Carroll: Got you. And that would just be upgrading compression and gathering systems to get those online?
Richard Lane: Correct.
Ken Carroll: And in terms of looking at LOE for the quarter, obviously, up with the Fayetteville becoming a bigger piece of the pie. That continues to ramp through the year Company-wide as the Fayetteville grows. Kind of what is your LOE run rate in the Fayetteville, as that becomes a bigger piece for you guys?
Richard Lane: Well, it's--right now, it's running about $0.60 per Mcfe, with the bulk of that being obviously gathering and compression. And so, there's a lot of cost weighted for that. Harold described in his opening remarks about some of the expenses. We have a lot of equipment out there and cost on the ground to build towards higher production. And so, it's kind of front-loaded I think is how he described it. So as we build more production per dollar of equipment we have out there, we have a chance to do better.
Harold Korell: The other thing on operating cost and on capital efficiency as well is that we have kind of two objectives here in the Fayetteville Shale right now and they are opposing each other. One of those objectives is to build our production volumes and become the most efficient operator that we can - lowest cost, and therefore, highest margins. If we were to do that, we would go into one of these fields and just start drilling there and drill nowhere else.
And the second objective is to assess the acreage across this whole spread. We have a lot of acreage here. We have decisions to make down the road here in the not too distant future about how do we move all of this gas away from here. How do we effectively and efficiently gather it? And so, we need to understand the extent--what percent of and what area of this large acreage position is productive such that we can design the ultimate gathering system.
But to the extent that we are drilling wells in separate pilot areas, and we've drilled now in 21 separate areas, if we've got one--the next well we stretch out, when we put it on production, believe me, the operating costs there are not the most efficient because you've got one well producing into one compressor and--I hope you get the build up of that. That you shouldn't look at what our costs are today as kind of this is the picture of the Fayetteville Shale operating cost.
Ken Carroll: Got you. No, I was just looking to see--kind of get a feel for where that flattening would occur. All right, guys. Appreciate it.
Scott Hanold: Could you give a little bit more color on--you obviously are going to have a nice ramp through this year and you've indicated that there was some--I guess some of your older wells in the Fayetteville Shale have been sort of restricted because of the newer, stronger wells coming online. Is there any point this time this year where you'll maybe come under a little bit of a constraint, and what event could alleviate that? And could you kind of look forward over the next one to two years? What type of events of adding capacity would alleviate any potential issues there?
Harold Korell:Well, generally speaking, we will be able to keep up with our gathering and compression to where we don't have major restrictions in the field this year. I think we have in Gravel Hill right at this point in time--some of those wells have come on at higher rates than what we had anticipated. And so, it creates kind of like an immediate traffic jam when you have an accident on the freeway. And when you can get that--get enough lanes open to get it going through there, then you--then that's alleviated.
As far as the long-term being--long-term being next year, we'll be drilling a lot more wells next year. Of course, we're building plans to be sure that we can take that gas away. I think about two months ago or something like that, Greg, we did a release on the firm transportation that we have spoken up for and paid for on the Ozark pipeline, which is 175 million a day. And we're continuing to look at alternatives here for moving gas easterly out of here. And some of that is dependent upon understanding how much of this acreage is productive, so as we build a ramp-up in production that we're able to take it--move it out of here.
I don't see a restriction happening--a major restriction here happening to us this year or next year or at all, hopefully. Probably the main constraint we're going to feel in this play is frac equipment--is pressure pumping equipment. We're continuing to work to push the limits on how much acceleration we can put into this play. And as we look forward, it's probably frac equipment right now.
Scott Hanold:Okay, good. Thanks. And just one quick question. You guys, obviously, have bumped up the number of rigs you project by year-end over the last couple of updates. And is that increase in--just to clarify--getting some of your new rigs quicker into the end of this year, or would you be just, say, holding onto a rig you would've previously thought you would've dropped off?
Richard Lane: Well, the actual Company-owned rigs has not changed. We have some additional third-party rigs in there. So I don't think--it's not dropping ones that we had in that first forecast. It's the addition of rigs.
Scott Hanold: Okay, fair enough. Good quarter. Thanks.
Richard Moorman: Good morning, gentlemen, and congratulations on the progress in the Fayetteville. Just I have a few questions, if I can. I guess starting with the Angelina trend. The success of the play sounds very good. We've got other operators doing well in the area, too. I'm just wondering at this stage could you give a rough idea of the gross thickness you're encountering in the Travis Peak?
Richard Lane: This is Richard, Richard. I don't have that number in my head. It's variable per well. And the net to gross is fairly extreme. We have a big thick interval at Travis Peak and we're netting out small intervals throughout the whole section. But I'm thinking it's 50 to 100 feet is kind of what we've been seeing of net-net pay.
Richard Moorman: Okay. Super. Now, Travis Peak is normally a little cleaner than Cotton Valley out there. Just wondering, do you think an 80-acre spacing is reasonable here, if all goes well as you've seen so far?
Richard Lane: Oh, it's in the ballpark. There's an awful lot that goes into that calculation, as I know you know. But somewhere maybe 100 acres--80 to 100.
Richard Moorman: Okay. Super. And then, moving to Delaware Basin in West Texas. Been some commentary from EOG that the facilities are not--in the area not keeping up. Do you have any thoughts on how facilities are going or going to evolve for you there?
Richard Lane: Well, we--are you talking about service facilities or--?
Richard Moorman: --Yes, gathering, I guess. Yes, takeaway.
Richard Lane: Well, we--on our acreage, we've looked at that before we purchased it and we have some capacity there. In our Coronado block, we have a line that's very close to that block. Getting tapped into it is--will take a little doing and some of the costs of those taps we've been quoted seem too high. But there is--the pure pipeline capacity is there. I don't really know what EOG has been experiencing on their acreage.
Richard Moorman: Basically, they just commented non-existent facilities. I think it's maybe they didn't pick the right place overall. Just next thought, I guess, on--maybe more for Greg here. You're getting quite a number of your own rigs now. And wondering--it's a case of the left hand paying the right hand. I'm just wondering how you're accounting for it. You say $2.1 million a well. That's probably with the full day rates for the rigs. So I'm just wondering how you would characterize the money you are saving by owning your own rigs and how you would account for that.
Greg Kerley: Well, the $2.1 million includes some amount of our savings that we're actually realizing on the rigs because what we've got in there is our actual operating cost of those rigs being charged and capitalized, along with a depreciation of half the rigs. So we're realizing the savings right now. Obviously, as we get more of our rigs in the field, that--as a percentage of the total rigs running, that will be a good benefit for the Company. But that is included in our $2.1 million average right now.
Richard Moorman: Okay. And that's because, like you say, about half of them are operated rigs. And so, as you go to a larger percentage, hopefully, that would improve that slightly.
Greg Kerley: Well, it could do that. Right now, I think we're seeing about $100,000 benefit that those rigs are giving us right now.
Richard Moorman: Okay. Super. And then, I guess the last kind of thought for the day for me. It seems like there's been just continued progress in the slick water techniques, and obviously, the cementing or non-cementing technique sounds great. We've seen you go from initial first month rates of about 1.3 million on the slick water fracs to now about 1.6 after a month. And obviously, that's very impressive and bodes well for the future.
The decline curve looks better to me, too. I agree, I know you don't want to be pinned down on reserve numbers here. But I guess I wanted to say it looks to me like when I extrapolate what you're seeing to be about a 64% decline rate in the first year, and that would be better than the nitrogens. And it looks to me like that extrapolates over 2 Bcf a well. Obviously, a lot of that comes over a long period of time.
But I guess I'm wondering, you know, looking at the way these kind of plays perform, do you see any reason why the existing wells' decline curves would suddenly change? You know, right now, they're 64% in the first year. Say is there any reason that in the second year they would radically shift or come off of that gradual slope into something more steep?
Richard Lane: Well, you know, the first year of decline rate is, we don't have one year of production, so that's a number that is not firm in that. I appreciate you modeling it to get to where you are. You know, the out years, is there any reason to believe that it would radically change? I think it's safe to say we don't think it would be any kind of radical change. But when you're trying to get to the estimated ultimate recovery of a well, you know, we're talking about decades of production here. And, you know, the devil is in the details. It's in all the shaping of that curve and all those out years and very minor changes in percent of those declines affects the EUR. So it's hard to say right now. I think the way Harold characterized it.
Richard Moorman: Great. Well, I appreciate the comments. Thank you, guys.
John Gerdes: Good morning, gentlemen. Interesting this curve you painted on page 4 of your release, it looks like very little in the way of hyperbolic decline in the population of these slick water wells. What would you attribute that to? I notice that the number does drop-down a little bit after the 120-day mark. And I think that that may just be the population of wells?
Richard Lane: Yes, I think you have to look at the whole data set, John. And that, the number of wells in the data set is across the top there. So you see that one well makes up half the data, and if you think of the world from the oldest, the end of the oldest well backwards, you know, you realize as you come back along that curve the production actually steps up, which says that the oldest well wasn't the best well. See what I'm saying?
John Gerdes: I do. And the interesting thing, as it relates to that curve is that, again, that curve looks almost linear versus your typical hyperbolic profile. What would you contribute that to? Attribute that to – I take it part of it probably has to do with the fact that in these multi-stage fracs you are accessing more rock, you're gaining more well bore cross-sectional area, would that be the driver behind the demonstration of that curve?
Richard Lane: Well, this is Richard. I think we would definitely characterize those wells, the old ones and the new ones, as hyperbolic decline reservoirs. You know, it's hard to see the forest from the trees here. We're looking at such a short time that the reality of it is, and you're looking at a Cartesian plot versus a semi-log plot. But looking at it the way we would, we would definitely think there'd be hyperbolic reservoirs.
John Gerdes: Okay.
Richard Lane: Maybe less hyperbolic than the nitrogen foam, but indeed hyperbolic.
John Gerdes: Richard, you mentioned these liner packers you're using for isolation as you do stimulations. You also mentioned, or Harold may have mentioned, the mechanical, you know, challenges at times in using this new technology. Can you speak to that just real briefly?
Richard Lane: Could you repeat that question? I'm sorry.
John Gerdes: Yes, you mentioned the liner packers you've been using on, I guess, a recent five wells. And you said there was the degree of challenges, mechanical challenges associated with that. Could you speak to that briefly? And is that where you think you're headed in terms of selective stimulation of these laterals?
Richard Lane: Well, I think, you know, we're headed for the most optimal from a well performance and from a cost performance. I mean there are some challenges with running it, and it all hasn't been perfect for sure. You know, you're running a liner and you have the typical, maybe a little bit less whole tolerance when we're running that, so you want a well that's, you know, these horizontal wells, you want one without a lot of twists and turns in it. But and then also running any kind of liners you always have the challenges of the liner top and having that deal against your intermediate strength. So that's where the challenges have been. But where are we headed? Yes, we'd like to be able to do all the stimulations, we're going to do…
John Gerdes: With that technology?
Richard Lane: Something like that. And the – it's not the only technology out there. There's lots of interesting breaking things. But the direction would be towards, you know, getting more done in a single day.
John Gerdes: Richard, you're at $2.1 million per your, you know, your new disclosure the last day or so. Where do you think maybe ultimately you could go in terms of it? And I know there's also, obviously it's very predicated on the stimulation, where would you, where do you think you can go on the cost side? And how far up the learning curve do you think you are at this stage?
Richard Lane: Well, you know, I don't think I'll speculate as to how well we can hit the number. It's two parts. It's where is service cost and inflation, and where is – and how good can we be at being efficient? Well, just the pure cost side of it. But, you know, I think we've shown that when we can have a lot of wells to drill in the same area that are similar in nature that we've been very good at driving those costs down. So, you know, does that come in the second half of this year? Does it come next year? It's a little bit hard to say. But, you know, we've definitely done that at Overton pretty dramatically. So I think when we fix on the recipe we want for one of these and get all of our company owned rigs in, that we'll see some operating efficiency.
John Gerdes: Percentage wise, where do you think you are in the experience curve? I know that's not an easy, it's a subjective question, but?
Richard Lane: It's not an easy one, and so I don't have an answer for you. But we're far from the end of it.
John Gerdes: Okay. Thanks so much.
Harold Korell:Operator, I'm going to have to leave this conference call. This is Harold. I've got a plane that I am scheduled to catch, that I've got to do. But Richard and Greg are still here. But I just wanted to let everyone know I'm going to sign-off. And thanks for being here with us today.
Tom Gardner: Thank you. With regard to the Permian Basin, I'd be interested in hearing kind of a characterization of the up side potential and then success case for the Popeye Prospect? And that also applies for the Coronado Prospect? A success case, kind of up side kind of scenario, just trying to gauge the, characterize the general potential?
Richard Lane: Well, you know, I think it's too early really to say. What I would generally characterize it is like this, particularly in our Coronado block, we think that with the data we have which is limited and the data that industry has is pretty limited, that, you know, in some of those deeper areas like that where the well cost might be significantly higher than say what we're doing in the Fayetteville or in the Ft. Worth Basin, or what you have there is the added benefit I think is the potential of having a lot of gas in place per section, if you will. You know, dramatically more gas in place than in some of these shallower, lower pressured shale play. So, you know, but we just don't have enough data to really say that right now, okay?
Tom Gardner: One last question. I'm just intrigued by your process improvements to bring down costs. Can you kind of characterize the savings you're seeing as a result of using these spudder rigs? And how many spudder rigs or horizontal capable rigs do you need for spudder rig in the field?
Richard Lane: Well, I think, you know, the way we have the distribution of that planned for yearend, you know, with about maybe three of those for another 16 of the deeper ones. You know, what we've seen is that that will keep us prepared for the deep rigs to come on and enter those wells, and have some inventory of those shallow holes ready for us. So we'll be able to keep up and do what we want there.
The cost savings on the spudder rigs is a range, and that depends on the, you know, what rig is, what rig are you replacing with the shallow spudder rig? Are you replacing a more efficient company owned rig, or are you replacing one that is not? And like Greg said we've seen as much as $100,000 of benefit when we utilize that spudder rig.
Tom Gardner: Thank you, gentlemen. Solid quarter.
Robert Christensen: Yes, how far are you on compression? And have you ordered a major amount of horsepower for the Fayetteville shale play?
Richard Lane: We have, Bob. This is Richard. It's obviously been a key part of the resources we need out there from inception, so I think we got ahead of it right from the start. And have the horsepower out there that we need right now. And a lot more of it planned and ordered, to come, to stay ahead of what we need, and if anything we'll be erring on the side of having excess capacity.
Robert Christensen: How much horsepower, and what, how is it phased in?
Richard Lane: I don't have those numbers here.
Robert Christensen: The next question, I guess, is you say you're spending seismic on the Fayetteville. Is that all micro seismic work, you know, with Pinnacle?
Richard Lane: Well, we have seismic capital expenditures and seismic related to monitoring the fracs, and then we have the 2D and 3D seismic that we've been shooting. And this year I think we have four small pilot shoots planned, so that is some of the capital seismic related capital, as well.
Robert Christensen: Would you ever consider using ceramic proppant in these holes?
Richard Lane: Ceramic proppant?
Robert Christensen: Yes. The lightweight stuff?
Richard Lane: Yes. Well, you know, I don't think we're seeing the need for that. I think the costs are actually greater and, you know, why would you do it? We're not, we don't know of any big compressive strength issues. I think, you know, what we're pumping in the hole is doing the job here cheaper than what that would be, so probably not.
Robert Christensen: Thank you.
Travis Anderson: Hi. Looking out, you know, four or five years with the potential size of the prospect, you're going to need a gathering system that's, I guess, you know, taking a swag at it, it's going to be north of half a billion cubic feet a day in capacity. And was wondering, you know, are you planning on doing something that big yourselves? Or are you going to try and partner up with somebody, or am I just way out of the ballpark on those numbers?
Greg Kerley: Well, I think you're – this is Greg Kerley. I think you're correct in that obviously we have, there's a significant amount of gathering that will be built. And, you know, from our standpoint we're looking at a lot of different ways. We're considering a lot of alternatives, including, that includes both partnering with other companies who build that. We have a lot of different companies that have come to us with proposals.
So from the gathering standpoint we're set-up, in the beginning of this as we talked about kind of the front-end of our project, it makes the most sense for us to own and to put that in the ground as we're staying ahead of everything. And sometime down the road it makes, it doesn't necessarily make the same sense that we own that pipe, so we'll definitely be flexible in how we look at that going forward.
But we really don't think that we're going to have any problems getting it in the ground, and getting it in the ground in a timely fashion. We definitely, the few problems that we've seen so far have really related to the fact that the wells continue to outperform kind of expectations. And so we've had a little bit of bottlenecks in some areas. But, you know, when you really look at the acreage position we have it could be one of the largest contiguous gathering systems in the country by the time this play is developed.
Travis Anderson: And related to that, I was just trying to think of why S&P is so on tender hooks? And, you know, given that they're still seeking to like $400 million of debt or so by yearend? I was wondering if this was something that you've shared with them about, maybe some of the spending you might be looking at next year, and that? Because that's got them all bothered?
Greg Kerley: Well, it's hard for us to understand their action, also, especially with the current strength of the company's balance sheet and our credit profile. I think that one of the things that they've, if you look back even a year-and-a-half ago, there's only eight companies that they have investment grade ratings on, that being about that. They kept appraising us is I think we were anomalous to all of those eight for several different things, both our size and the fact that our investment level was, exceeded our cash flow, and most of those other investment grade peers were investing significantly less than their cash flow. Obviously, our opportunities there, it's just been really, really great. And so we are a different anomaly, but can't really speak to exactly why they have done what they've done. And it doesn't make a lot of sense to us.
Travis Anderson: Yes, of course, a lot of it has to do with what forecast they're using for gas prices. We don't know what that is either. Okay, thanks.
Greg Kerley: Well, this is Greg Kerley. Thank you for joining us today. We're obviously very pleased with the progress we've made in the second quarter, and look forward to the balance of the year. And that concludes our teleconference.
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SWN Q2 2006 - August 2, 2006