Southwestern Energy Company Q4 2005 Earnings Teleconference Call
Wednesday, March 1, 2006
Company Officers
Harold Korell; Southwestern Energy; President, Chairman, CEO
Richard Lane; Southwestern Energy; EVP, E&P
Greg Kerley; Southwestern Energy; CFO, EVP
Analysts
Brian Singer; Goldman Sachs; Analyst
Joe Allman; RBC Capital Markets; Analyst
Amir Arif; Friedman, Billings, Ramsey; Analyst
David Heikkinen; Pickering Energy Partners; Analyst
Robert Christensen; Buckingham Research; Analyst
Travis Anderson; Gilder Gagnon Howe; Portfolio Manager
Joe Allman; RBC Capital Markets; Analyst
Robert Christensen; Buckingham Research; Analyst
Presentation
Operator: Good day, and welcome to the Southwestern Energy Company Fourth Quarter 2005 Earnings Conference Call.
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 2005 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. We also would warn you 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.
Well, 2005 was an outstanding year for the Company. For the third consecutive year, we set records for annual production volumes, reserve replacement, and year-end reserve levels. And as a result, our financial results were outstanding as we delivered new records for earnings and cash flow, and our balance sheet is as strong as it’s ever been.
In addition, and importantly, we have positioned the Company well for the future with our Fayetteville Shale play in Arkansas and exposure to the emerging Barnett play in the Permian Basin.
On the operating side of our E&P business, we’re continuing to move forward with our plan to evaluate our large acreage position in the Fayetteville Shale play. Our first Company-owned rig began drilling in January with success, and we will be increasing our activity as the year goes forward. As time goes by, we’re accumulating the production data that will be the key to understanding and for projecting the estimated ultimate recoveries for our Fayetteville Shale wells.
Up to now, the focus of our play in Arkansas has been the Fayetteville Shale, and it’s likely that that will continue. However, in addition within the last three months, we’ve produced gas from the slightly deeper Moorefield and Chattanooga Shales. So as the year unfolds, we will be continuing to increase our knowledge about the different aspects of the unconventional play in Arkansas, and we’ll begin to gather data on our position in the Permian.
I’d like to now turn the teleconference over to Richard Lane, who will tell you more about our E&P activities, and then to Greg Kerley to discuss our financial results, and then we’ll take questions.
Richard Lane: Thank you, and good morning.
In 2005, we set new records for our annual production and reserve additions.
Gas and oil production totaled 61.0 Bcfe, up 13% from 54.1 in 2004. The increase in 2005 production resulted primarily from the continued development of our Overton Field in East Texas and from increased production from our Fayetteville Shale play in Arkansas.
Production for the fourth quarter of 2005 was 15.7 Bcfe, up from the 15.1 we produced in the fourth quarter of 2004. Our production during the quarter was lower than originally expected due to delays in the Company’s drilling programs, mostly caused by rig problems. Of the 15.7 fourth quarter production, 8.1 was from East Texas, 4.9 from our conventional Arkoma Basin properties, 1.4 from the Permian Basin, 0.8 from the Gulf Coast region, and 0.6 from the Fayetteville Shale. We estimate that our first quarter 2006 production will be between 15.7 and 16.1 Bcfe and that full-year 2006 production will be 74 to 76 Bcfe.
We ended 2005 with 826.8 Bcfe of total proved oil and gas reserves. That’s up 28% from 645.5 at year-end ’04. In 2005, we added 243.1 Bcfe of proved reserves, including revisions. Of the 826.8 Bcfe of year-end reserves, 368.7 were in East Texas, 271.0 in the Arkoma Basin, 101 in the Fayetteville Shale, 58.6 in the Permian, and 27.5 in the Gulf Coast region.
We replaced 399% of our 2005 production at a finding and development cost of $1.71 per Mcfe, including revisions and excluding the capital invested in our drilling rigs. Excluding revisions, our finding and development cost was $1.51 per Mcfe. Proved developed reserves accounted for approximately 73% of the total, and our reserve life index was 13.6 years.
In 2005, we invested 451.3 million in our Exploration and Production program and participated in drilling 247 wells. Of the 247 wells, 197 were successful, 8 were dry, and 42 were in progress at year-end. Of the $451.3 million invested in 2005, approximately $323 million was for drilling wells, $60.6 million was for leasehold and seismic, and $35.1 million was for the purchase of drilling rigs; $32.5 million was for other capitalized costs. Excluding the capital we invested in new drilling rigs, approximately 78% of our 2005 investments were in drilling.
In our Fayetteville Shale play in 2005, we invested approximately $154.5 million, including $67 million to spud 67 wells; $40.7 million for leasehold acquisitions; $35.1 million toward the fabrication of 10 new drilling rigs to be utilized in the play; $4.3 million per seismic; and $7 million in capitalized costs. We continue to increase our significant leasehold in the play, and as of February 27, we held a total of approximately 875,000 net acres in the play area. Of this, approximately 750,000 net acres were in the undeveloped play area, and the remaining 125,000 net acres are in our traditional fairway area of the Basin.
From the beginning of our drilling program in the Fayetteville Shale in 2004 through February of 2006, we have spud a total of 117 wells in the play, 112 of which were operated by us and 5 of which are outside operated. The wells are located in 17 separate pilot areas located in 7 counties in Arkansas, and as of Monday, 60 were producing, 17 were in some stage of completion or waiting on pipeline hookup, and 6 were shut in due to marginal performance or temporarily abandoned. The remaining 34 wells are in the drilling process.
We estimate that the wells drilled to date have demonstrated that the Fayetteville Shale is gas productive over an area of approximately 100 miles by 20 miles. Sixty-three (63) of the 117 wells spud are horizontal wells. As of February 27, 17 of these were producing, 11 were completing, 4 were drilling, and 2 were temporarily abandoned, and 29 wells have been drilled through the vertical section, preparing to be drilled horizontally.
The average initial test rate for 16 of the 17 completed horizontal wells is 2.2 million cubic feet per day. The well costs of the most recent horizontal wells have ranged from $1.4 million to $1.8 million per well, excluding non-reoccurring costs. The horizontal wells drilled through December 31 of 2005 have had an average vertical depth of 3,200 feet and an average lateral length of 2,000 feet and have taken approximately 15 to 20 days, on average, to reach total depth. And during 2006, we plan to test longer lateral lengths to determine the optimal well-bore design.
In yesterday’s earning release, we included an average well production plot compared to our 1.3 Bcf and 1.5 Bcf-type curves. While there is a wide range of performance from individual horizontal wells, in aggregate, the average well production data plots roughly between the 1.3 and 1.5 Bcf-type curves. Two of our most recently completed horizontal wells, the McNew 4-2 in our Gravel Hill Field and the Church 1-27 in our Griffin Mountain Field, are only included in the production data for 125 and 95 days, respectively. The McNew 4-2 was our first horizontal well to be stimulated with the slick water frac, and the Church 1-27 utilized the hybrid slick water and nitrogen foam fracture stimulation. Both of these wells are producing at rates exceeding the average horizontal well and are tracking above our type curves. To further test these stimulation techniques, we plan on using either slick water or hybrid stimulations in several horizontal wells here as we go forward.
Net gas production from the Fayetteville Shale play during 2005 was 1.8 Bcf, compared to 0.1 during 2004. Proved gas reserves booked in the play as of year-end 2005 were 101 Bcf from 177 locations, of which 54 were proved developed producing, 6 were proved developed non-producing, and 117 were proved undeveloped. Of the 177 locations, 131 were designated as horizontal wells. Our estimated average ultimate recovery from these wells is 1.3 to 1.5 Bcfe per horizontal well. The average proved reserves for each of the horizontal undeveloped locations included in our audited year-end reserves was approximately 0.95 Bcfe gross per well, or 63 to 73% of our estimated ultimate recovery, and this is a reasonable and prudent percentage given the relatively short production histories of these wells. And following best practices for proved reserve estimating, we fully expect our book reserve estimates to increase over ti me.
As you know, we have an audit done of our reserves each year by an outside reserve engineering firm. For the past four years, we have used Netherland, Sewell & Associates to do this audit. Again, this year, NSA audited our reserves and gave us their audit opinion, which states, “The estimates of total proved reserves and future revenue are, in the aggregate, reasonable and have been prepared in accordance with Generally Accepted Petroleum Engineering and Evaluation Principles.”
In doing their audit work, NSA expresses their findings in aggregate regarding the Company’s reserve bookings and does not give a specific analysis and report form for each of our fields. This year, because of the importance, however, we did inquire of NSA what their value was for our horizontal wells in the Fayetteville Shale play. And in discussions with us, they have indicated that their current estimate of average proved reserves for the horizontal wells is 700 million cubic feet equivalent. Although they generally believe that their reserve estimates for these wells will increase over time, we continue to believe, based on our modeling and early production data, that horizontal wells in the play will have an estimated ultimate recovery of 1.3 to 1.5 Bcfe per well.
We currently have four rigs running in our Fayetteville Shale play. Of these four rigs, one is a shallow rig, which we use to drill the vertical portion of our wells prior to moving in one of three larger rigs capable of drilling the horizontal section. By utilizing shallow rigs, we have built an inventory of 29 wells ready to be deepened. Additionally, we currently have 14 pre-built locations on to which we’ll be moving these rigs.
As we announced last year, we have entered into sales agreements with a private company to build a total of 10 new land drilling rigs capable of drilling the horizontal wells in the Shale play. We took delivery of our first rig in late January. The DeSoto Drilling, Inc. rig #1 has already successfully drilled its first two horizontal wells, and we expect to take delivery of the second rig in early March and have all 10 of the rigs drilling in the fourth quarter of 2006. Combining these with rigs with additional contracted drilling rigs, we expect to have three shallow rigs and up to 14 deeper rigs in the play at the end of the year. In conjunction with ramping up the number of rigs in the Shale play, we also now have access to a second set of completion equipment and crews dedicated to the play. We anticipate further increases in dedicated completion services as we progress throughout the year.
In addition to our Fayetteville Shale potential, as Harold mentioned, we have tested gas production from the deeper Moorefield and Chattanooga Shales that are also found in our play area. Our Carter 1-35 well, a vertical well, located in our East Cutthroat pilot area in Cleburne County, was completed at the Moorefield Shale and tested at 710 Mcf per day. Based on our preliminary work in some areas, the Moorefield Shale, which underlies the Fayetteville, has similar reservoir characteristics. We currently hold approximately 130,000 net acres that we believe may be prospective for that Moorefield Shale, and we expect to put the Carter well on production in early March. The Carter well had 220 feet of gross Fayetteville Shale and 85 feet of gross Moorefield Shale.
Additionally, we are currently testing the Chattanooga Shale and the Eschbach 1-12 well after fracture stimulating it. The Eschbach well is located in our traditional Fairway HBP area. The Chattanooga Shale occurs below both the Fayetteville and the Moorefield, and the Eschbach penetrated approximately 100 feet of gross Fayetteville Shale and 50 feet of gross Chattanooga Shale.
In 2006, we expect to invest $338.3 million in the Fayetteville Shale play, which would include drilling between 175 to 200 wells. Of those wells, nearly all will be horizontal wells. In 2006, we will focus on increasing our production through development drilling, while also determining the extent of the Fayetteville Shale by testing the undrilled portion of our acreage in an additional 25 to 30 pilot areas.
Now, moving to our conventional Arkoma Basin assets. In 2005, we invested approximately $64.5 million in our conventional properties, drilling 71 wells, of which 61 were successful and five were in progress at year-end. We added 51.7 Bcfe of proved reserves, including revisions, in the Arkoma Basin. Our 2005 production from the Arkoma Basin was 20.2 Bcf, relatively flat compared to 2004’s production of 20.1.
In 2005, we further increased our drilling activity at our Ranger Anticline project area in Yell and Logan Counties. During 2005, we successfully completed 34 out of 37 wells, which added 19.3 Bcf of new reserves at a finding and development cost of $2.19 per Mcfe, including downward revisions of 4 Bcf. Excluding reserve revisions, our finding and development cost at Ranger was $1.81 per Mcfe. Net Ranger production in 2005 was 5.6 Bcfe, approximately 60% higher than 3.5 in 2004. Our wells at Ranger have primarily targeted the upper and lower Borum tight gas sands between 5,000 and 8,000 feet.
In 2005, wells completed in the Borum had average ultimate gross reserves of 1.2 Bcf per well. In 2005, we extended the field boundaries to the east approximately nine miles by completing four successful wells in shallower sands. These shallower sands are between 3,500 and 4,500 feet in depth and had average estimated ultimate reserves of .5 Bcf per well. The average cost to drill and complete these shallower wells has been approximately $700,000.
Late in the third quarter of 2005, we drilled the initial exploratory well on our Midway prospect, targeting the Pennsylvanian and Ordovician sections. The USA #1-24 well encountered approximately 230 feet of net play by electric log calculation in the Pennsylvanian aged Borum sands, which are the main producing horizons in the Ranger Anticline area. We are currently testing these sands and will determine the development potential based on those results. We have approximately 20,000 gross undeveloped acres in our Midway prospect area.
In 2006, we plan to invest approximately $89.6 million in the conventional Arkoma program, and drill 100 to 110 wells, including 50 to 60 wells at the Ranger Anticline. We also plan to have a significantly increased workover program, particularly in the traditional Fairway area of the Arkoma Basin, targeting the recompletion of behind-pipe productive intervals.
In 2005, we invested approximately $183.6 million in East Texas, drilling 89 wells. Of this, $158 million was invested in our Overton field, where we drilled and completed 80 wells of which 52 were 40-acre space wells. We added 91.2 Bcf of proved reserves, including revisions, in East Texas. Our 2005 production of 28.2 Bcfe from East Texas was 27% greater than the 22.2 we produced in 2004.
We continue to maintain a 100% success rate at Overton after drilling 253 wells since we acquired the field in 2000. Daily gross production at the Overton field increased to approximately 109 million cubic feet equivalent at year-end 2005, resulting in net production of 26.7 Bcf during 2005, compared to 21.8 in 2004. New wells drilled in the field during 2005 averaged approximately $1.8 million to drill and complete, had average initial production rates of approximately 3 million cubic feet per day, and had average estimated ultimate gross reserves of 1.8 Bcf per well. In 2006, we plan to invest approximately $161.5 million at Overton and drill approximately 83 wells.
In addition to Overton, we continue to expand our holdings at the Angelina River Trend in Nacogdoches County, Texas. At December 31, 2005, we held approximately 11,000 gross undeveloped acres and 3,000 gross developed acres. Since this time, we have signed a Letter of Intent to acquire an additional 9,600 gross acres. Through December 31, 2005, we had drilled nine wells with 100% success in this trend, primarily targeting the Travis Peak formation. Net production from the area was .9 Bcf in 2005. Gross initial production rates from wells drilled during 2005 ranged from 1.7 to 4.4 million cubic feet equivalent per day. The average estimated recovery from the wells completed in 2005 is expected to be approximately 1.6 gross Bcfe per well, with an average drill and complete cost of $2.5 million per well. In 2005, we invested $18.7 million in the Angelina River Trend. And during 2006, we intend to invest $34.5 million to drill a total of 16 wells in the area.
Moving to exploration and new ventures. Along with our Fayetteville Shale play and our ongoing East Texas and Arkoma Basin programs, we continue to develop new prospects for future development. At the end of 2005, we held approximately 116,600 net undeveloped acres, primarily in the Rocky Mountain areas and the Permian Basin, associated with other conventional and unconventional natural gas and oil plays. Of this, approximately 50,000 acres are located in Culberson County, Texas in the emerging Barnett Shale play in the Permian Basin. We anticipate spudding our first test well there during the second quarter. In 2006, we plan to invest approximately $28.9 million in exploration projects and $14.5 million in new venture projects, including drilling up to 18 wells within the continental U.S.
In summary, we’re very pleased with our record results in 2005. Our program is performing well, delivering significant growth in production and reserves, while achieving our investment return target of 1.3 PVI or greater. In 2005, we developed a better understanding of the individual well potential of our shale play. And in 2006, we expect to develop a fuller understanding of the play’s potential size.
I’ll now turn it over to Greg Kerley, who will discuss our financial results.
Greg Kerley: Thank you, Richard, and good morning. As Harold indicated, 2005 was an excellent year for Southwestern. We ended the year with record fourth quarter earnings of $48.9 million, or $0.29 a share, compared to $32.9 million, or $0.22 a share, for the same period in 2004. Our net cash provided by operating activities before changes in operating assets and liabilities was $102.8 million during the fourth quarter of 2005, up 42% from $72.4 million in the fourth quarter of 2004. Strong commodity prices and higher production led to the improved financial results.
For the full year of 2005, we reported record net income of $147.8 million, or $0.95 per share, up 43% from $103.6 million, or $0.70 per share, in 2004. Net cash provided by operating activities before changes in operating assets and liabilities also set a new record in 2005 at $321.8 million, up 35% from $237.7 million in 2004. Operating income for our E&P segment was $234.8 million in 2005, compared to $164.6 million for the same period in 2004. The average price realized for our gas production, including the effects of hedges, was $6.51 per Mcf in 2005, up from $5.21 a year ago.
Our current hedge position, which consists primarily of costless collars, provides us with significant support for a strong level of cash flow in 2006. The average floor price of our collars is approximately $5.50 per Mcf and provides a solid base for our projects, while the average ceiling price of approximately $10 still allows us to retain considerable upside. Approximately 70 to 75% of our targeted gas production and 15 to 20% of our targeted oil production is hedged in 2006.
Disregarding the impact of our commodity price hedges, the average price received for the Company’s gas production during 2005 was approximately $0.90 per Mcf lower than average NYMEX spot prices, due to locational market differentials, compared to an average of $0.34 per Mcf during 2004. We have approximately 75% of our basis differentials protected for 2006. Assuming an $8 average NYMEX price, and including the effects of our current basis hedges, we expect our average realized market differentials to be approximately $0.60 to $0.70 per Mcf lower than average NYMEX spot market prices for 2006.
Our average realized oil price in 2005 was $42.62 per barrel, compared to an average price of $31.47 per barrel in 2004. We expect the average price received for our oil production to be approximately $1.50 per barrel lower than the average spot market prices.
Our lease operating expenses per unit of production were $0.48 per Mcfe in 2005, up from $0.38 in 2004. The increase is 2005 was due primarily to increases in compression, salt water disposal, and gas processing costs, as well as generally higher oil build service costs.
Taxes, other than income taxes, per unit of production were $0.37 in 2005, compared to $0.28 in 2004. The increase in 2005 was due to increased severance and ad valorem taxes that primarily resulted from higher commodity prices. General and administrative expenses per unit of production were $0.46 in 2005, compared to $0.36 in 2004. The increase was due primarily to increased payroll costs due to the expansion of our oil and gas operations related to the Fayetteville Shale play and increased incentive compensation costs. The number of employees in our E&P segment increased to 280 at the end of 2005, up from 147 at the end of 2004. Our full cost full amortization rate averaged $1.42 for Mcfe in 2005, compared to $1.20 in 2004.
Operating income for the utility was $4.9 million in 2005, down from $8.5 million last year. The decrease resulted from increased operating costs and expenses and reduced usage per customer, due to customer conservation brought about by high gas prices and warmer weather. Effective October 31, 2005, the Arkansas Public Service Commission approved a rate increase for our gas utility that will increase future revenue and operating income by approximately $4.6 million annually.
Operating income for our Midstream Services segment was $5.7 million in 2005, up from $3.2 million in 2004. The increase in 2005 was due primarily to higher marketing margins on natural gas sales, caused in large part by the increased volatility of locational market differentials in our core operating areas.
Midstream Services also had gathering revenues of $1 million in 2005, related to gathering systems it owns in Arkansas. Gathering revenues for this segment are expected to continue to grow in the future, as gathering systems for the Company’s Fayetteville Shale play are constructed to support the development of this play.
We also earned interest income of $3.4 million, related to our cash investments in 2005.
Our financial position, simply put, is the best in the Company's history. Our strong earnings, along with our equity offering in September of 2005, in which we raised approximately $580 million, helped us to decrease our balance sheet debt-to-capitalization ratio to 8% at year-end 2005, down from 42% at December 31, 2004. And more importantly, we have positioned the Company to allow to aggressively pursue the development of our Fayetteville Shale play.
Our planned capital investments for 2006 are $830 million, consisting of $770 million for expiration of production; $37.5 million for Midstream Services; approximately $12 million for gas distribution system improvements; and $10 million for general purposes.
Our 2006 capital program is expected to be funded through cash flow from operations. The remaining net proceeds from our equity offering and borrowings under our revolving credit facility. From this capital program, we are targeting 2006 oil and gas production of 74 to 76 Bcf equivalent. Our targeted production in the first quarter of this year is 15.7 to 16.1 Bcf equivalent, up slightly from our fourth quarter production. However, as we continue to implement our drilling program, we expect our production levels to ramp up significantly in the last half of the year.
That concludes my comments. We’ll now turn back to the Operator, who will explain the procedure for asking questions.
Brian Singer: Could you talk a little bit more about the history of when you started to look at the Chattanooga and Moorefield Shales, and also how you would plan or think about planning to produce that in the context of horizontal drilling in the Fayetteville Shale with the expected, or it’s obviously early, but what the additional well costs might be and so forth?
Richard Lane: This is Richard, Brian. Obviously, when we started studying the area, we looked at the whole section, including the Fayetteville and the deeper horizons. So I would say, to try to date stamp, it would be back when we first started looking at the play to try to understand all those intervals. Now these tests are, obviously, most recent. And we don’t have a lot of control on that. I think we have a little better feel for the Moorefield than the Chattanooga. But I think what we’ll be doing here to try to address, go forward, we have a number of new pilots that we’ll be drilling and we’ll take some of those wells down through that full section and be evaluating it with those wells.
Brian Singer: Would you ultimately produce the Fayetteville where they co-mingle and the different shales? Or how would you produce that on the context of horizontal drilling with the Fayetteville?
Richard Lane: Well, I think the first thing to answer is it going to be a widespread target and what really will it do? That’s really the most important thing first. And then if it is, then we’ll kind of address how do we commercially extract it. Would you be looking at individual wells? Would you be looking at co-mingling? All those things we would look at.
Brian Singer: Okay. Separately, could you characterize the nature of the conversations that you had with Netherland, Sewell regarding the Fayetteville horizontal well reserve bookings? I mean, what did they say they needed to see to take it above 700 million cubic feet? Did they believe you were being conservative in other areas to ultimately give you the clean bill of health?
Richard Lane: I think that’s generally accurate. As I said in my comments, it is a reserve audit, so they are looking at in the aggregate ‘Are the reserves reasonable’ and ‘Have we used correct techniques in estimating them?’ Relative to the Fayetteville Shale, they have their number and what would it take for it go up for them, and I think both for us, as well, is more production history. And I think we both feel like it’s most likely that they will go up.
Harold Korell: Brian, just to address that a little bit further. I’m assuming you’ve had an opportunity to look at the press release, which has some graphs in it. The primary one, of course, that’s of interest is what is the average of all of the horizontal wells that we have production histories on, and, very clearly, we’ve shown in that graph the number of wells on production and the average daily rate.
One of the questions we’ve had to deal with here internally and, of course, that Netherland, Sewell deals with when they do their work, is -- and the conclusion one comes to is, you can search, and Richard said this the other day, you can look long and hard at the production graph versus various ultimate recovery models of this, the real answer lies in what’s ahead of us. The answer doesn’t -- I mean, you can see by the data where the actual performance tracks various modeled outcomes for the time period up through the history that we have. But that is 270-plus days for the longest well we have on production.
The real question here is what happens from here forward. And, naturally, we, and the reserve engineers that do this auditing work for us on the outside, are going to take a rather conservative approach to the reserve bookings themselves. And people need to understand the difference between reserve bookings and ultimate recoveries, because it’s a matter of how conservative is each person in estimating those numbers.
Now, relative to overall reserves, we’ve booked I think on average 2 proven undeveloped locations, offsetting each one of our producing horizontal wells and/or some of the vertical wells where we’ve definitely established production. So have we been conservative overall? Definitely. Because there is the opportunity you could book more PUDs to each location in which you’ve established the fact that there is production there.
Joe Allman: If the Chattanooga Shale test is positive, how much acreage do you think you’ve got that would be prospective for the Chattanooga?
Richard Lane: Well, it’s, as we see it right now, it’s pretty darned widespread, Joe, and it’s going to exist over the majority of the area that we have. It’s thinner in places, and that may limit it being a target, and it’s thicker in others. I think, generally, down there near the Eschbach well, we’re more in the thicker part of it. But it’s very widespread and that’s probably all I can characterize it right now.
Joe Allman: Okay. And then, Richard, while I’ve got you on the Midway, was the Borum the primary target there? I mean, could you just talk about that a little bit, what your plan is going forward, assuming that you get a pretty good sized rate there?
Richard Lane: Yeah, sure. We had Borum targets, which like I said, are good zones we have at Ranger. And then we had a deeper Arbuckle target. And the Arbuckle, we had some gas in there, not a whole lot, and when we tested it we didn’t think we had anything commercial. But we’re pretty pleased with what we saw in the Borum section. And we have to see that test rate. Those can be kind of tricky rocks, but calculate that as pay and looks good and we just need to test it. And if it tests like we think it will then we’ll kind of determine that development plan. We’ve got nice block acreage there and if that goes we’ll, we’ll get after following that up.
Amir Arif: First question. In terms of the new rigs that you’re getting in the Fayetteville Shale, the person was delayed and the next one is coming in March. What’s your comfort level with you’ll get all 10 by the third quarter or early fourth quarter?
Richard Lane: Amir, this is Richard. I think we’re looking at all the factors that go into that ultimately getting those delivered, and that’s why we’re forecasting what we have here, so we feel pretty comfortable with it. There are some things that are not totally in our control, but I think we’ve mitigated most of those by trying to preorder equipment and things. But, in general, we feel -- I think the real question there is, generally, we feel good about drilling the 175 to 200 wells that we have forecasted.
Amir Arif: Okay. And so your drills at 175 to 200 wells, do you need 10 rigs by that time or is that something you could deal with 6, 7, 8 rigs?
Richard Lane: No, we, generally, would need the count that we have forecasted there.
Amir Arif: Okay. And just a final question on the production shortfall for the quarter, I mean, the Fayetteville shale, I understand there was a rig delay. Can you just talk about the drilling delays you had in the Ranger Anticline?
Richard Lane: Yeah, we were challenged with equipment. We’ve talked mostly about the Fayetteville Shale, the challenges there. And we could have continued at a higher rig count rate, but we felt like we were not being efficient with our capital, so it was a hard decision, but I think the right thing. But also at Ranger, we were affected there because some of those rigs we were moving back and forth and we had problems at Ranger as well, so the same thing goes there, the same kind of decision, and it affected the production that we would have gotten out of that area.
David Heikkinen: I just had a quick question on the economics of the Fayetteville regarding commodity price. If you could just go into some details regarding the Fayetteville Shale and the natural gas prices where you would see any sensitivity. What commodity price you’d have any sensitivity for slowing down activity.
Richard Lane: Well, I mean, the way we’ve been looking at it, with the kind of reserve estimates that we’ve talked about, and using about a $1.5 million completed well cost, we reach our return thresholds at significantly lower prices than where we are right now.
David Heikkinen: Is that $5 gas? $4? Just wanted to get a little more specific.
Harold Korell: No, I don’t think that to try to put a specific number out there, I don’t think we’re going to be doing that today, David. Our actual plans will depend upon what our costs are at any point in time. And it will depend upon the results we’re achieving. We’re not going to make our decisions simply upon the basis of the wells we’ve drilled to this point. We’re continuing to learn and improve results. And so we know that we have a large gas resource here. And our objective is to sort it out and figure it out and make the most of it. And I know you guys would sort of like to get a picture that says, “Well, at this price there won’t be activity.” But this is not like drilling a conditional exploration play there that has 5 wells behind it. And so this is the type of thing that I think you’ll see us continue be very active in throughout this year, unless we see gas prices at $3, if we see gas prices at $4.
But I don’t know, I may be zeroing in on it for you, but this is not like the oil business of old. This is the where -- this is the type of thing that we’ve got a large resource here, we know that because we’ve drilled enough wells to know that we have production coming from a large are in the Fayetteville Shale. We’ve seen some encouraging things in a couple of the other shales. We’ve got a lot of production hedged, so our cash flow is pretty well protected. Our view over the longer term is gas prices aren’t going to stay low for a long time, so I doubt you’ll see us in a sort of what I would call a knee-jerk reaction that if prices fall to $5 you are going to see us contract our payable shale activities. And so I don’t know, that’s probably the best way to answer it. I don’t think there’s a single point there.
David Heikkinen: No, there was some market commentary that at $7 gas you’d slow down, Harold. And I think you pretty clearly answered that you’re sensitive in the $4 range, but below $5 you wouldn’t really -- you are still chugging forward for the long term thinking commodity prices will be above $5.
Harold Korell: Well, that’s right. And I think that’s the prudent thing to be doing for our shareholders.
Robert Christensen: The West Texas play, can you give us any industry results? I mean, what’s going on around you? I mean, you basically said that you felt you were a little late to the play, that’s fine, but what’s happened, let’s say, in the last 6 months in the barn at West by industry?
Harold Korell: Bob, there is a lot of activity out there in leasing. Lease costs have gone up. There’s, I don’t know, there’s probably 10 wells drilled, and I don’t know, 5 or 6 being drilled. It’s hard to get a lot of information on those. You probably have every bit that we have almost in terms of what people have announced. EOG announced something I think a while back on 1 horizontal well that they drilled. We weren’t the first ones there. We weren’t 3 years late or 4 years late, though. But we do have 2 nice blocks of acreage that we’ll drill our first well on, probably in the second quarter, and begin to learn about the rocks. It’s certainly, when we say the word emerging, it is emerging in that we don’t know a lot about it. We think it’s prospective and a number of other companies do as well. And all that is just going to unfold over time. It’s going to be interesting in this case that we’ll be hearing the results of some of the other companies as time goes along and then we’ll begin to get our own data points there. That’s really about all we can say about it, except you can put a lot of gas out there.
Robert Christensen: And the only data point you have is the EOG? I mean, what are the several other wells?
Harold Korell: We don’t really know anything that companies haven’t made public about their results, so I can’t address things I don’t know about.
Robert Christensen: Fair. Fair. Coming back to the Chattanooga Shale, my records indicate that the Eschbach is a horizontal well. Are you drilling that Chattanooga section horizontally? Was it drilled horizontally? From the press release, it sounds like you’re on test now.
Richard Lane: Yeah, it’s a vertical test. It started out, I think, initially designated as that way, Bob, but we are talking about a vertical well and the testing would be in the vertical section in the Chattanooga.
Travis Anderson: I want to go back to something Richard Lane said. I want to make sure I got this down right, because I tried to write it as accurately as I could. Quote, “We estimate the wells drilled to date in the Fayetteville have demonstrated that the Fayetteville is gas productive over an area of approximately 100 miles by 20 miles.” Is that correct?
Richard Lane: Yes. That’s correct. Now that, it’s a vast area and it’s exciting to see it over such a big area. You also have to understand that that’s not continuously tested within that block. We’re just saying if you loop around wells on the perimeter as far out as we’ve drilled, that we’re looking at that kind of distance.
Travis Anderson: Based on 17 pilots so far, you mean.
Richard Lane: Right.
Harold Korell: Yes and Travis, you and everyone else have seen the map that we’ve had out in the world for a long time. And what Richard basically is saying is we’ve tested and produced gas from over in the Fairway area where the original Nixon and Crockett vertical wells are, all the way across to the East some 100 miles. And so it’s a fair statement.
Travis Anderson: Right. Okay.
Harold Korell: It needs to be sampled more heavily and I mean we’re early on in this. But you don’t go very many places in the world and drill wells 100 miles apart and have production from the same zone.
Travis Anderson: Right. So now the issue is, is it economical over that entire area?
Harold Korell: That’s correct. I don’t think it’s a question of economics. It’ll be a question of what are the economics of it.
Travis Anderson: Right. Okay, thank you.
Joe Allman: Hi, everybody. Harold could you update us on the constraints that you’ve got for developing the Fayetteville? Could you talk about staffing and getting the crews to man the rigs and pipelines and just getting rigs and just the various constraints you’ve got?
Harold Korell: Well, I think that if you saw within Southwestern Energy, it’s sort of like the Chinese army marching forward on a lot of fronts. We’ve had the press on, trying to get the drilling rigs out here and I think we’ve solved that to the point of getting up to be able to perform the plan that we have in front of us to drill, as Richard said, 175 to 200 wells. We’ve done very well at recruiting people. I think 130 or so people added in 2005. We’ve got a lot of things happening there, moving people into new space in the building we’re in here in Houston. We’re in temporary facilities in Conway, trying to locate ourselves with a permanent office there. So there’s a lot going on in regard to the people side of it.
The fracing side, the well stimulation side of it, as Richard said, we’ve got another crew dedicated by the service company to do our stimulation there. So that’s seems to be moving in a positive direction. On the pipeline side, we have a very capable group of people now working on the gathering and the midstream and the marketing.
So I don’t know how to orchestrate it much better than we’re doing. Surely we’re going to run into some delay, but I don’t think there’s something that’s going to really take our feet out from under us, unless it would be $4.00 gas price. And we believed we’d see $4.00 gas price for a long time and I don’t really believe that. So I think we’re doing pretty darn well on, to tell you the truth.
Joe Allman: Sure, and then another question, separate issue. Overton, I mean, it looks like the Overton development may be through this year. Do you have hopes that the development of Overton may continue beyond this year?
Harold Korell: Well, it appears to us we’ll have some drilling in 2007 and the question will be how much and it will depend upon service costs, which are increasing. The drilling company has continued to push that up and I’d say there could be some point where, I mean, that will be a factor. Service cost and then gas price will be a factor in deciding how far that goes into the future.
We think we’ll be reasonably well developed there probably some time in 2007 and that’s assuming that part of the field is developed at 40-acre spacing and then that would leave some of it 80-acre spacing. And the question would be can we drill some of the 80’s to 40’s and right now we haven’t made that decision. But there will be the incremental well out there that we’ll be making a judgment on when we get closer to that point.
Robert Christensen: You said you’ve brought in another set of, I guess, completion services. Is that, what, another company besides Schlumberger?
Richard Lane: No. It is a Schlumberger crew and a group of equipment to do the cementing and stimulating and all that, so they’re building their presence down in that part of the world with us, which is good, and ramping up. So we’re happy to have that other unit available, which is right in with what our plans were and then to continue to kind of grow that.
Robert Christensen: Have you drilled any wells in White County yet? I saw that there is one, two, three, four wells permitted horizontally in White County, toward the end of the year you permitted them. Are you going out that far to do any wells out there yet?
Richard Lane: Yes, I think some of our easternmost wells that we’ve been drilling are in White County. Some of the ones that may have hit the permit stuff that you’ve seen, we had a Frowd well. Of course the Chesapeake-operated stuff is in White County. Those are those Ronnie wells. But yes, we’re out there in White County, Bob.
Robert Christensen: Okay, but no production results yet. You’ve drilled them but just no results yet?
Richard Lane: I don’t --
Robert Christensen: I haven’t seen a completion yet.
Richard Lane: I think that’s right. I don’t think we have. I think that’s correct.
Robert Christensen: Yes, okay, but could we, I mean, they’re probably sitting on pipelines, so I imagine you’re going to -- I don’t know. I’ll just, I guess, wait of the Arkansas Oil and Gas Commission to give us results.
Richard Lane: Yes, well there’ll be a combination of ones closer to it and then some as we’re trying to do those pilots and understand the distribution also.
Robert Christensen:: Got you. Well, thanks, guys.
Joe Allman: Yes, sorry about that. I know a couple of horizontal wells have been temporarily abandoned. Could you address that issue?
Richard Lane: Well, we’ve talked about, I guess a total of six. We had four, I guess, maybe last time we talked and we had a well. I think for the ones that are new to that are probably the Crowden. We had to -- actually, one of them is an outside operator well that we’ve called the Parish, that we really were not the operator or completing it, obviously, and that is one of them as well.
Joe Allman: Okay. Any particular issues with just maybe the shale wasn’t present or not commercial or was it operations involved?
Richard Lane: Yes. Well, the Parish was a vertical and it was operated by a small independent out there and not performing really up to snuff. No, it was nothing in particular I could point to, other than mechanical things of it, but we weren’t the operator of that Parish well.
Joe Allman: Okay. All right. Thank you.
Operator: And gentlemen, there are no further questions. I’d like to turn the conference back to you for any additional or closing remarks.
Harold Korell: Well, I appreciate all of you joining us today and amazingly, we finished in less than an hour. I thought our prepared comments went pretty long. But we thank you for joining us and we look forward to another exciting year.
Operator: That concludes today’s conference. We’d like to thank you for your participation.