西南能源 (SWN) 2008 Q4 法說會逐字稿

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

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

It's actually only CEO and chairman. Mr. Mueller, our President, is here with us. That all is going to change down the road in a few months. Good morning and thank you for joining us. Steve is here with me and Greg Kerley is also here. If you have not received a copy of yesterday's press release regarding our fourth quarter and year-end 2008 results, you can call 281-618-4847 to have a copy faxed to you.

Also, I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control, and are discussed in more details in the risk factors and forward-looking statement section of our annual and quarterly filings with the SEC. 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, 2008 was a tremendous year for Southwestern Energy. We recorded exceptional production and reserve growth as we continued to move up the learning curve in the Fayetteville shale. We also reported record results in earnings and cash flow, and the proactive management of our balance sheet has placed us in great financial condition with a debt to total capitalization ratio of 23% and nearly $200 million cash on hand at year end, and nothing borrowed on our $1 billion unsecured credit facility. However the key accomplishment for us in 2008 was clearly the progress we made in our Fayetteville shale play. Steve will give more details on all of our operating areas in a moment, but overall I could not be any more pleased with our accomplishments in 2008.

As we enter 2009, we will continue to focus on organic growth and the value added for each dollar we invest. As a result of the low commodity price environment, we currently have a planned capital program of $1.9 billion for 2009 compared to $2 billion plan that we announced in December. Our current plan includes releasing four rigs during 2009. We will actively manage our capital program, and have the flexibility to make further reductions if we find ourselves in this low natural gas price environment for an extended period of time. So while there is a lot of uncertainty in today's markets we feel confident that when our industry comes out the other side of this commodity price cycle that Southwestern Energy will be extremely well positioned financially healthy and growing significantly at low cost levels.

On a more personal note, yesterday we announced my planned retirement and the planned promotion of Steve Mueller to CEO. We are extremely fortunate to have Steve and our strong management team to guide Southwestern Energy into the future. Being here at Southwestern Energy has been a fabulous experience for me over the past 12 years, and I've been so fortunate to be a part of this value creation story.

I'd now like to turn the teleconference over to Steve for more details on our E&P and midstream activities, and then to Greg for an update on our financial results. Then we will be available for questions.

Thank you Harold. I want to personally thank you for your mentorship to me for so many years, and for your leadership here at Southwestern energy the past 12 years. As anyone who has met you knows, you are the right person doing the right things, and all of us at Southwestern look forward to your continued leadership in the future.

Now let me get back on script and talk about 2008. In 2008 our gas and oil production totaled almost 195 Bcfe, up 71% from 2007 primarily as a result of increased production from our Fayetteville shale play where our production was 135 Bcf in 2008. This is more than double the 53.5 Bcf we produced from the shale in 2007. We produced 31.6 Bcfe from East Texas and 24.4 Bcf from our traditional Arkoma Basin area in 2008. Production from both of these areas was also higher than in 2007. Up from 29.9 Bcf in East Texas and 23.8 Bcf in the Arkoma Basin. We produced an additional 4.1 Bcf in 2008 from our other areas combined including from our Gulf Coast and Permian Basin properties we sold during the year.

In 2008 we increased our year-end proved reserves by 51% to 2.2 Tcfe. The 2.2 Tcf or proved reserves were located approximately 71% in the Fayetteville Shale, 16% in East Texas, and 13% in the conventional Arkoma Basin. In 2008 we added 920 Bcf of proved reserves and had net upward revisions of 98 Bcfe. Both the additions and the revisions were primarily driven by the performance of wells in our Fayetteville play.

During 2008 we sold all of our remaining assets in the Gulf coast and Permian Basin areas, and approximately 55,600 acres in our Fayetteville Shale play. In aggregate, these divestitures of proved reserves of approximately 90 Bcfe. Including both our additions and revisions, we replaced 523% over 2008 production at a F&D cost of $1.53 per Mcfe. Excluding revisions, we replaced 473% of our 2008 production at a finding and developing cost that was $1.70 per Mcfe. Proved developed reserves accounted for approximately 62% of our total reserves at year-end 2008.

In 2008, we invested a total of $1.6 billion in our E&P business and participated in drilling 750 wells, 479 of those were successful, 11 were dry, and 260 were in progress at year end. Of the $1.6 billion invested, approximately 81% or $1.3 billion, was in exploratory and development drilling and workovers, $83 million for leasehold acquisitions, $66 million for seismic expenditures, and $118 million in capitalized interest and expenses and other technology related expenditures.

Moving on to the Fayetteville play, gross production from our operated wells in the Fayetteville Shale play increased from approximately 325 million cubic feet per day at the beginning of 2008 to approximately 720 million cubic feet per day at year end to its current level of approximately 750 million cubic feet per day. We estimate that our 2009 production from the Fayetteville Shale will range between 229 and 232 Bcf, up approximately 70% from 2008. We invested approximately $1.2billion in our Fayetteville Shale drilling program during 2008, added 984 Bcf of new reserves at an F&D cost of $1.21 per Mcf. This includes upward revisions of approximately 159 Bcfe due primarily to the improved well performance. The finding and development costs excluding those revisions was $1.44 per Mcf.

Total proved net gas reserves booked in the Fayetteville Shale at year-end 2008 was 1.5 Tcf compared to 716 Bcf of reserves booked at the end of 2007. The average gross proved reserves for each of the proved undeveloped wells is approximately 1.9 Bcf, up from 1.5 per well at the end of 2007. A gross proved reserves for wells that were placed on production in the second half of 2008 averaged 2.2 Bcf per well.

During 2008 we continued to improve our drilling practices in the Fayetteville Shale. Our horizontal wells had a completed average well cost of $3 million per well, average horizontal length of just over 3,600 feet and average time to drill to total depth of 14 days from re-entry to re-entry. This compares to an average completed well cost of $2.9 million per well, average horizontal lateral length of 2,650 feet, and average time to drill to total depth of 17 days during 2007. Our initial producing rates also continued to improve, as wells placed on production during 2008 averaged initial production rates of nearly 2.8 million cubic feet per day compared to average initial rate of approximately 1.7 million cubic feet per day in 2007.

During the fourth quarter of 2008, our horizontal wells had an average completed cost of $3.1 million per well, average horizontal lateral length of 3,850 feet, and average time to drill to total depth to drill wells of 13 days. This compares to an average completed well cost of $3 million per well, average horizontal lateral length of 3,736 feet, and average time to drill to total depth of 12 days in the third quarter of 2008.

We currently are running 22 rigs in the Fayetteville Shale play, 15 that are capable of drilling horizontal wells, and seven smaller rigs that are used to drill a vertical section of the holes. Expected lateral length should average approximately 4,000 feet in 2009, and completed well costs are expected to decline slightly in 2009 to approximately $2.9 million per well. This lower cost is a result of lower oilfield service cost that are projected to be more than offset by higher costs associated with the evolving completion techniques and longer laterals.

Since 2007 the continuous improvement of the company's completion practices have consistently resulted in quarter over quarter improvements in average initial production rates of operated wells placed on production. The approximately 16% increase in the average initial production rates for the fourth quarter of 2008 also reflect the impact of delay in a boardwalk pipeline. Initial rates were higher in all of the delayed wells because wells were shut in for a longer period of time before being placed on production. In addition, the company generally placed wells with highest initial rates on production first during the quarter. As a result, the remaining backlog of shut-in wells that were placed on production in the first quarter of 2009 were generally at lower rates. These lower rates are expected result in lower average initial production rate for the first quarter of 2009 as compared to the fourth quarter of 2008. Results through the first six weeks of 2009 indicate that the company's operated wells have an average initial production rate of approximately 2.9 million cubic feet per day.

At year end we held approximately 875,000 net acres in the play, down from approximately 906,700 acres at year-end 2007 due to the sale of acreage in May 2008 to XTO Energy. Approximately 26% of our leasehold acreage is held by production excluding 125,000 acres in the traditional fairway portion of the Arkoma Basin, and 35% to 40% of the total 2009 wells of plan to hold acreage. We have approximately 961 square miles of 3D seismic data in the play and plan to acquire approximately 139 square miles more in 2009. This will bring our total seismic coverage so approximately 41% of the net position in the Fayetteville Shale excluding our fairway acreage.

In the conventional Arkoma, we have approximately 281 Bcf in 2008 compared to 307,304 Bcf at year-end 2007. In 2008 we invested approximately $135 million and participated in 81 wells, 67 were successful and eight were in progress at year end. It resulted in a 92% success rate. Net production from the conventional Arkoma properties was 24.4 Bcf in 2008 compared to 23.8 Bcf in 2007.

In 2009 we plan to invest approximately $60 million in the conventional Arkoma program and drill approximately 25 wells. We have approximately 351 Bcf of reserves in East Texas compared to 353 Bcf at year-end 2007. In 2008 we invested approximately $160 million and participated in 50 wells in East Texas, of which 42 were successful and eight were in progress at year end resulting in a 100% success rate. Net production from East Texas was 31.6 Bcf in 2008 compared to 29.9 in 2007. Our 2008 drilling program was primarily focused on drilling the James Line Formation in our Angelina River Trend area.

During 2008 we participated in a total of 32 wells targeting James Line horizontal. The average gross initial rates for the 15 operated wells we placed on production in 2008 was 9.1 million cubic foot per day. At year-end 2008, we had just over 100,000 total gross acres, approximately 86,000 were undeveloped and approximately 17,000 gross acres developed in the Angelina Trend.

In the second quarter of 2008 we signed a 50/50 joint venture agreement with a private company to drill two wells targeting the Haynesville Bossier Shale interval in Shelby, Nacogdoches and St. Augustine counties Texas. The first horizontal well, Red River 877, #1, located in Shelby County, reached total major depth of 16,144 feet in the fourth quarter of 2008 with a 2,718 foot lateral length. It was completed in the first quarter of 2009 and is currently being tested. We plan to start drilling the horizontal lateral of the second well, the Red River 164 #1, within the week. It is expected to be completed and tested in the second quarter of 2009.

We're encouraged by our results to date and may invest more capital in 2009 than currently planned in the Haynesville Bossierville Shale play. In 2009, the current plan is to invest up to $110 million in East Texas to participate in approximately 40 wells, 34 of which are planned to be horizontal wells targeting the James Line Formation.

At year-end 2008 we had approximately 138,600 net undeveloped acres in the United States outside of our core operating areas. We invested approximately $73 million in new ventures programs in 2008 including $58 million in the Marcellus Shale play in Pennsylvania. At year-end 2008, we had approximately 115,000 net acres in Pennsylvania, under which we believe the Marcellus Shale is prospective, at a total cost of about $530 per acre. During 2008 we drilled our first four wells, including our first horizontal well, on the acreage in Bradford, in Susquehanna County, three of which have been production tested.

In the first quarter of 2009, we increased our acreage position in the Marcellus with the purchase of approximately 22,000 net acres in Lycoming county, Pennsylvania for approximately $8.2 million. As a result, we currently have approximately 137,000 net undeveloped acres in Pennsylvania. We plan to invest approximately $80 million in various new venture products in 2009 including the Marcellus Shale play.

In summary, as Harold mentioned, we are very pleased with the results of 2008. Our planned capital investment plan for 2009 of approximately $1.9 billion continues to build on that success. It includes approximately 86% or $1.6 billion for E&P, and $220 million from midstream services. Managing through any significant drop in product prices is always challenging, but with our focused approach and our concentration on adding value we're looking forward to continued strong results in 2009. We expect to meet or exceed our PVI target, have approximately 45% production growth and significant increases in proved reserves.

I will now turn it over to Greg Kerley who will discuss financial results.

Thank you, Steve, and good morning. As you have seen from our press release, our production growth drove significant increases during 2008 in both our earnings and cash flow and we ended the year with one of the strongest balance sheets in our history. For the calendar year we reported net income of $568 million, or $1.64 a share, more than double our prior year record results. And our cash flow from operating activities before changes in operating assets and liabilities increased over $500 million to almost $1.2 billion for the year. For the fourth quarter we reported earnings of $104 million, or $0.30 per share, a 46% increase over the prior year as a significant growth in our production volumes substantially outweighed a 14% decline in our average realized gas price and higher operating cost and expenses.

Our commodity hedge position increased our average realized gas price by $0.79 in the fourth quarter which helped us offset some of the effects of lower spot market prices and widening locational marketing differentials or basis that occurred during the quarter primarily as a result of delay in construction of the Fayetteville lateral portion of the boardwalk pipeline. Phase one of the Fayetteville lateral was placed in service on December 24th and we are currently moving a little over 400 million cubic feet of gas per day through the pipeline. We currently have close to 48% of our 2009 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.48 per Mcf. Our detailed hedge position is included in our Form 10-K filed yesterday afternoon.

Our annual results for our E&P segment were truly exceptional. Operating income for this segment was $813 million in 2008, up from $358 million in 2007. We grew our production by 71% to 194.6 Bcf equivalent and realized an average gas price of $7.52 Mcf which was up approximately 11% from the prior year. Our lease operating expenses per unit of production were $0.89 per Mcf in 2008, up from $0.73 in 2007. The increase was due primarily to increases in gathering and compression costs related to our operations in the Fayetteville Shale play including the impact of higher natural gas prices on the cost of compression fuel.

General and administrative expenses per unit of production were $0.41 per Mcf in 2008 compared to $0.48 in 2007. The decrease was primarily due to the effects of our increased production volumes which more than offset increased compensation and related costs primarily associated with expansion of our E&P operations. We added a total of 219 new employees during 2008 most of which were in our E&P segment. Taxes other than income tax were $0.13 per Mcf in 2008 down from $0.16 cents in the prior year due to changes in severance and ad valorem factors that primarily result in a mix of our production volumes.

Our full cost full pool amortization rate dropped to $1.87 per Mcf in the first quarter and averaged $1.99 in 2008, down from $2.41 in the prior year. The decline was due to the combined effects of our sales of oil and gas properties during the year, the proceeds of which were credited to the full cost pool, and our low 2008 finding and development cost of $1.53 per Mcf.

Operating income from our midstream services segment also grew significantly in 2008 to $62.3 million, up from $13.2 million in 2007. The increase was primarily due to higher gathering revenues and an increase in the margin from our marketing activities partially offset by increased operating costs and expenses. At February 15th we were gathering approximately 830 million cubic feet of gas per day through 864 miles of gathering lines in the Fayetteville Shale play area, up from approximately 405 million cubic feet a year ago.

We worked very hard during 2008 on strengthening our balance sheet and improving our liquidity. In early 2008 we issued $600 million of ten-year 7.5% senior notes and used the proceeds to pay down our $1 billion revolving credit facility. We believe our credit facility will provide us with a significant source of liquidity throughout its maturity in October of 2012, and it is not secured by any assets, and our ability to borrow is not tied to our reserves.

We ended the year with almost $200 million of cash on hand, nothing borrowed on our $1 billion revolving credit facility, and had reduced our debt to capitalization ratio during the year from 37% down to 23%, or 19% net debt, and had total debt outstanding of $735 million at year end. We are well positioned to weather the current low commodity price environment with a strong balance sheet, excellent liquidity and one of the lowest cost structures in our industry.

That concludes my comments. So now we will turn back to the Operator who will explain the procedure for asking questions.

Thank you, sir. The question and answer session will be conducted electronically. (Operator Instructions) Our first question comes from Tom Gardner with Simmons Company. Please go ahead, your mike is open.

Good morning everyone. Harold, I'd like to congratulate you on your retirement plans. You leave quite a legacy at Southwestern and I have great respect and admiration for your accomplishments. And Steve, congratulations on your promotion. And I know you and your team will have great success going forward. Guys impressive reserve additions this year. Can you give me some help here peeling the onion with respect to your reserve revisions. Essentially you had about a hundred Bcfe net additions. Can you give me an idea of upward performance revisions versus negative price related revisions embedded in that number.

For the total company we had about 22 Bcfe negative price revisions. And those were split pretty much evenly between Arkoma and East Texas, very little was in DeSoto. Then total performance revisions 120 Bcfe, total that direction.

With respect to individual average uplift in bookings there on the Fayetteville wells, were those performance revisions primarily related to increasing or decreasing the terminal decline rate assumptions? Just trying to get an idea.

Not really, we haven't done anything to the terminal decline. What really happened, if you think about any given year, and 2008 is a perfect example, we started the year with one kind of completion technique, we ended the year with another kind of completion technique. That's why we gave the numbers where we went. We talked about the last quarter, those wells are 2.2 Bcfe. When you start booking your PUDs they do look at each highlight area, but they take the average in those pilot areas and really you're averaging the wells that have the most production. So you're really seeing the weighted average for the first half of 2008 in your PUDs and 2007 was the same kind of case. So I think for the near future as long as we keep our PUDs EUR and IPs increasing you will see positive revisions down the road, as well.

And our next question comes from Jeff Hayden with Rodman and Renshaw. Please go ahead sir, your mike is open.

Hi guys, congratulations on the great quarter. A couple quick questions. One I may have missed, just wondering if you could give us a little color on how to think about expenses going forward into 2009. And then also wondering time in the budget how many Marcellus wells do you have planned.

Are you talking about overall drilling expenses or operating expenses, Jeff?

Just kind of a modeling number, how should we think about lifting costs per unit, G&A going forward into 2009.

Okay. Well, our guidance we put out in December is still we think pretty solid. We're going to end up trailing down on G&A, we ended the year averaging $0.41 cents, so we expect that to decline a little bit as our unit rates continue to increase. Our taxes other than income taxes are going to be up a little bit from last year with a new severance tax in the state of Arkansas pushing that up a little bit. Our amortization rate on that side of those, the financial cost, is actually continuing to trend down. We were $1.87 in the fourth quarter, with our finding cost at $1.53. That's going to help us and we expect to have some pretty good finding costs in 2009. On our operating expenses we still believe that around the $0.90 to $0.95 range is a good number for us going forward.

As far as the Marcellus goes, we will probably participate in a couple wells in Marcellus, but we do not plan an active drilling program this year. That will be more 2010. This year we'l concentrate on trying to pick up some more acreage, basically continue to lock up the position we have.

I appreciate it guys.

And our next question comes from David Heikkinen with Tudor Pickering Holt. Please go ahead sir, your mike is open.

Thank you. Good morning. Question on current strip in each one of your areas of operation. Can you walk us through what your PVI metrics would be looking forward in the Fayetteville wells, 3 Bcf wells at 2.5, and then what you're doing in the James Line, where you're allocating capital.

I'll start taking a little bit of a stab at that, David. We mentioned in our press release that we're dropping four rigs, both East Texas and Arkoma. The drilling we're going to be doing there, at least for the foreseeable future, is for the most part holding acreage. Those numbers going for 1.3 are challenged right now. They're still making us good money, but they're not getting that 1.3 PVI.

In the case of the Fayetteville Shale, we're comfortable with today's prices that we can still average 1.3 PVI in the Fayetteville shale. So what we plan to do is drop four total rigs. We will move one rig out of East Texas, and one rig out of Arkoma and put that back into Fayetteville. So while we have 15 big rigs running today, we will exit the year with 13 rigs in the Fayetteville.

Okay. Then intrigued by your comments of putting more capital into the Haynesville Bossierville. How do you make that decision as far as more capital, less capital? Driven by your partners wanting to commit more capital to it? Or how does that kind of overall joint venture work.

I think the real thing is, as we said, we're testing one well now, we have one well drilling. We need to see the results of those wells and just figure out how economic they might be. And then we can figure out if we're going to put more capital into it.

Okay. So just stay tuned on that.

In reality, it's a continuing story, because we're turning over cards and we have certain positions, we have partners, we have capital allocation sorting on projects and we have an eye on our balance sheet, as well.

Our next question comes from Joe Allman with JPMorgan. Please go ahead sir, your mike is open.

Yes, thank you, good morning everybody. Congratulations to both you guys. In terms of the Marcellus Shale you mentioned you have three wells you production tested. Can you talk about results there?

The only thing we will say is we're happy with the results. The reason we're not giving out any data is that in Pennsylvania it's very difficult to get production data. Some states, within a month you have production data, and in Pennsylvania that's a little more difficult. So part of the reason for drilling those wells besides just testing our acreage was to give us some trade material that we could trade logs, production data, et cetera. And we're doing that. As long as that has value you probably won't see us say much about the actual production.

Okay, got you. And then in the Fayetteville Shale, is it safe to say some areas of the Fayetteville Shale probably have average EURs at 3 Bcfe or above?

I guess the way to answer that question is in our PDP reserve base we have wells significantly above 3 Bcfe, yes, already.

And our next question comes from Brian Singer with Goldman Sachs. Please go ahead sir, your mike is open.

Thank you good morning. Just wanted to check in on the commodity price environment here. You did tweak down your budget slightly. Can you talk to what commodity price environment that's based on and to the extent that natural gas prices stay at current or lower levels what that would mean, and regionally what the impact could be.

I think I'll take the initial stab at this. Remember, we are hedged, we have got about half our 2009 production hedged at basically an 844 so that helps us, especially in today's price environment. And we have done a lot of changes to the budget since we first announced in December. I fully expect as the year goes through and you start watching the numbers, and get a better feel for what's going to happen, we will make more changes. The whole idea behind what we're doing is to keep as flexible as possible and we're still targeting that 1.3 PVI. We think with what we're seeing today we can still do that with where we have our capital being allocated.

I think as addition to that, Steve, Brian, I would say that the thing to kind of keep in mind is that the wells we're drilling in the Fayetteville Shale hit our PVI targets below $5 NYMEX price. We're fortunate to be in the position we're in in the maturity of this play to understood how to make it work and what makes it work and have our costs in line. And I want to differentiate that from what Steve said. We have hedges, the hedges help us with our cash flow to help us keep from moving our debt level higher since we are investing at a level above our cash flow.

But on the fundamental decision making part of it, the PVIs of these Fayetteville Shale wells we're drilling, one could push those possibly down to the $4 NYMEX prices. So, we find ourselves in a very enviable position, and I don't want to brag that we're the best and greatest, but we actually are positioned and probably the most economic in today's market and with our cost structure probably the most economic shale play around.

And our next question comes from Scott Hanold with RBC Capital Markets. Please go ahead sir, your mike is open.

Thanks, good morning guys. Steve, you had mentioned that the well that you plan to drill, I think you said could average around 4,000 feet lateral length. I just want to clarify that because it was kind of interesting, on your chart where you show the performance and type curve reference points, wells that are above 4,000 foot lateral lengths appear to be following that 3 Bcf type curve. Can you talk about what the expectation on average lateral length and what kind of ranges you're looking at for 2009?

As we said, we're going to average around 4,000 foot laterals. I think the longest lateral we have drilled to date is something over 5,500 foot. And we have drilled a dozen or so wells in the 5,000 foot lateral range. Where we can do that, where the geology is set up that way where we can do units and we get the exceptions you will see us drilling some longer laterals. But in general there's some other areas. For instance, when you get shallower physically drilling a longer lateral just isn't part of it. So part of it's just a mix when you start talking about the 4,000 foot laterals. We will get them out as long as we can where we can.

Okay. So then if we look at that 78 well reference that you have over 4,000 feet, that's a pretty reasonable way to look at your 2009 drilling program, is that a fair statement?

I would think so.

Okay. Good. And quick follow up, as well, for Greg. On severance taxes can you just talk to, I know it looked like the fourth quarter severance tax dipped quite a bit. How do you think that's going to look like going into 2009, what's the progression? I know the rate goes up as of 1/1, but will we see a pretty steep increase in the first quarter or is it going to gradually roll in?

Well, it will gradually grow, and a portion will be affected by commodity price. Some of the mix last year in the drop in the fourth quarter was also due to some severance tax refunds we received in that helped lower a few pennies on that average. And going forward you have about, a graduated rate in Arkansas that I think we figured it will be between 2% and 3% on average, a long term going forward for a period of time. But it will be reflected against whatever the commodity price environment is.

And our next question comes from Gil Yang with Citi. Please go ahead sir, your mike is open.

Good morning, gentlemen. Could you tell us how many wells were actually delayed from the fourth quarter to the first quarter? And how many of those wells in the first six weeks, what percentage of the wells that came on were actually those old wells?

There is just over 50 wells that were delayed into 2009. It will take us well probably into the summer before those 50 wells or the equivalent of those 50 wells are all caught up. The reason for that is we drill TD about 10 wells a week, we're trying right now to complete about 11 to 12 wells a week. So it just takes 25 to 30 weeks to catch up. So we're in the process of doing that right now.

Our next question comes from Mike Scialla with Thomas Weisel Company. Please go ahead sir, your mike is open.

Hi guys, I wanted to echo the previous congrats to both Harold and Steve. Most of my questions have been asked, but just have one more for Greg. On the basis hedges, what could you hedge right now for Mid-Continent and do you have any plans to add to those?

We have about the same amount that are pretty well tied to our commodity hedges right now, basis protection also about close to 50%. I think we're estimating that on average they're about $0.55 to $0.60 on average differential. On a specific hub, if you wanted -- each hub is a little different that you go to, but the worst fill, the center point, and if you were going to try and do a basis, say, for the second quarter, right now it would above something above $1.40. Then it decreases from there depending which hub and which direction you're going.

So really no plans to try and add.

One of the things you need to remember is somewhere around April 1st the second phase of the boardwalk pipeline will be completed, and we will be able to send gas across the Mississippi River, and our basis will actually drop then. So we have been actively doing basis hedges, actually more the eastern markets than the center point market, because we're planning to send as much gas as we can that way.

Our next question comes from Marshall Carver with Capital One. Please go ahead sir, your mike is open.

Thank you, and congratulations to both Harold and Steve. A couple quick questions. Do you have any preliminary data on any down spacing test in the Fayetteville?

We really don't. We have put together just around a 200 well program and we're well into drilling it, but we're just now starting to see production results from that. It's probably at least two quarters away before we will be able to get enough data to start sorting it out.

Okay, thank you. And on the Haynesville, could you give your most recent tally on acreage in the area, and have there been any nearby wells that also get you encouraged?

Our acreage is roughly 50,000 acres net that we have as Haynesville potential, as what we're seeing right now. There are some drilling wells around us that have TDs very comparable timeframes to what we have done. We haven't seen any results, we have seen a couple of them are completing right now, we haven't seen results. Just the fact that people are completing wells gives you a little bit of benefit, but we haven't seen anything.

Our next question comes from Robert Christensen with Buckingham Research Group. Please go ahead sir, your mike is open.

Yeah, congratulations Steve and Harold for the years of success. The Fayetteville, you still have some leases that have five years to hold them. Will you get that done? I mean it looks like about 229,000 acres. Shouldn't be too tough with five years. But what do you think there?

Yes, of our drilling that we're doing right now, about 40% of it is holding acreage, and the other part of it is really for the most part the down spacing testing we're doing. And this year we think we're going to hold quite a bit of acreage. We will hold those basically 180 to 200 wells. Then we're also putting together a unit on some of the federal acreage and we will drill some wells there that should hold a big chunk of the federal acreage. This year will be a big year for us. We do have a plan over the next two to three years where we think we can hold all the acreage we want to hold.

Overton, South Overton, are there any rigs running there this year?

We're actually completing right now a well in Overton area. And that will be one of the rigs that's going to move in the Fayetteville Shale play, as we drop one of the rigs out of Fayetteville. For the most part we will participate in a couple outside operating wells. We don't plan to operate much more in Overton this year.

Thank you Steve.

Once again press star one to ask a question. (Operator Instructions) Our next question comes from Jo Allman with JPMorgan. Please go ahead sir, your mike is open.

Thanks again. I'm going to throw out several questions. So maybe you have a pen or pencil there. So Steve in response to an earlier question, I asked about 3 Bcfe EUR and you said there are several wells booked well above that. Could you just address whether or not those are, is it spread out in your acreage or is it in concentrated locations? And then could you talk about your gas? Break out the gas and which hubs the gas is going to and what kind of throughput fees you pay. And then in terms of your reserve revisions, could you break out the approved developed versus the PUD reserve revisions? That's all I got.

As far as the 3 Bcfe wells, they are, anywhere where you have seen some fairly high IP on wells that we have got, those are going to be where the EURs are, as well, and they do go across the entire acreage we have out there.

As far as gas on hubs, I'm not sure we need to go into a whole bunch of detail about that. I'd say over the near future, a good average number for us is in that $0.50 to $0.60 range. We're working on, whenever we can put basis on that gets affected. As Greg said, we have about 400 million a day that's going into the boardwalk pipeline and that's an NGPL type marker. It is a little better basis, it's a little less than $1.00 center point basis, but it's still going Mid-Continent. Once that second phase gets turned around on April 1st, we should be able to scale up over 500 million a day of production going east, that basis collapse. Right now it's roughly neutral, $0.01 or $0.02 positive right now. So that's the big swing for us, is getting that 500 million a day around April 1st to go into the eastern markets.

And then on the PDP versus the PUD revisions I'll have to give you that, we don't have that right here.

And our next question comes from David Heikkinen with Tudor Pickering and Holt. Please go ahead sir your mike is open.

Actually, question's already been asked, thank you.

And it appears there are no further questions in the queue. I'd like to turn the conference back over to Mr. Korell for closing remarks.

Okay. Well, thank you all for joining us today and I look forward to seeing some or all of you on various conferences around the country in the next year. That concludes our comments, thanks.

This concludes today's conference. Thank you for your participation, you may now disconnect your line.