西南能源 (SWN) 2013 Q1 法說會逐字稿

Greetings and welcome to the Southwestern Energy first-quarter 2013 earnings teleconference call. At this time all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation.

(Operator Instructions)

As a reminder this conference is being recorded. It is now my pleasure to introduce your host, Steve Mueller. Thank you, Mr. Mueller, you may begin.

Thank you and good morning to all of you and thank you for joining us. With me today are Bill Way, our Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, our Senior VP of Corporate Development; and Brad Sylvester, our VP of Investor Relations. If you have not received a copy of yesterday's press release regarding the first-quarter 2013 results, you can find a copy on our website at www.SWN.com.

Also I'd like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more details in the risk factors and the forward-looking statements section of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

Now let's get on with the call. It was a very good quarter. Our production grew year over year 11% and our costs continued to decrease, resulting in the strongest cash flow in the first quarter of our Company's history. Since the end of the first quarter, gas prices have improved and our production in the Marcellus has started to grow dramatically. As a result, we have raised our production guidance in the latter half of the year. Earlier this week we announced acquisition of 162,000 additional acres in the Marcellus. Because it will take time to fully understand all of the infrastructure needs, our acquisition analysis assumed little activity on the acreage in 2013. Be assured, we will quickly analyze how best to integrate this acreage into our current program and we'll update you later in the year regarding how we'll make changes to our Marcellus because of this acquisition.

Many have asked over the past several weeks if due to the recent run up in gas prices we would increase our capital program. We certainly are encouraged by the increasing better gas fundamentals but except for this acquisition, we do not currently plan to accelerate our activity levels. So while we're enjoying the recent increase in gas prices and the growing production, we will continue to be disciplined in our capital investments, focused on lowering our cost, focused on delivering more throughout the rest of the year. I will now turn the call over to Bill for more details on the operations and then to Craig for a recap of our financial results.

Thank you, Steve, and good morning, everyone. We achieved several key milestones in the first quarter, which I want to share with you this morning. As Steve said, we grew our production by 11% compared to the same period in 2012. In addition we continued to improve drilling times, lower our cost, and we're seeing some pud reserves begin to return to our books due to price. Our strong focus on health, safety, and the environment resulted in continued improvement in HSE performance.

We did experience some early challenges during the quarter, specifically due to the timing of getting wells online in our Marcellus area. Typical minor bottlenecks created by rapid activity are now behind us as a result of the efforts of our team in Pennsylvania, and our operational ramp is already showing results.

Since I mentioned Marcellus let me begin there. We got off to a slower start than we had planned due to various timing and logistical delays for getting wells connected to sales. This was especially trouble some in January where we only were able to put two wells on production; however, we adjusted and quickly resumed our ramp up of the business and brought on to sales 19 additional wells by the end of the quarter. We're hitting our full stride and we're back on pace in terms of production growth. Our gross operated production is continuing to ramp up and has already reached 400 million cubic feet per day. We are on plan to surpass 500 million cubic feet per day of gas by the end of the year.

Our Marcellus business will continue to grow in line with available gas transportation infrastructure, and we currently have agreements in place that increases our firm transportation capacity out of the area to 757 million cubic feet per day of gas by 2015. Back on the operations side, as we move into new areas, we continue to experiment with our stage counts and lateral lengths to optimize our wells. We've averaged 17 stages per well in the first quarter compared to an average of 12 stages in 2012.

We completed test on our Blaine Hoyd well in Southern Bradford County this quarter that included 32 stages in that completion. This well had a peak 24 hour rate of 23.9 million cubic feet of gas per day and compares to nearby wells that were replaced on production in 2013 with an average peak 24 hour rate of 10.1 million cubic feet of gas per day, average lateral length of 4,229 feet, and with 17 stages flowing up tubing only. We know some shale formations have experienced long-term effects producing with such high early drawdowns, so we'll continue to evaluate the technical and economic impacts of high-density, high-rate production in the Greenzweig area as well as Susquehanna and Lycoming Counties. While I realize that each area is different geologically we will continue to experiment with our fracture stimulations, lateral lengths, and flow techniques to optimize our wells throughout the rest of 2013. We have 18 more tests planned in this year.

I would also note that none of our Lycoming County or Northern Susquehanna wells are aided by compression at this point, so these wells are flowing against line pressures between 1,200 and 1,400 pounds per square inch. Once compression is installed in the summer, the wells in these areas will be able to flow against lower line pressure and produce at higher rates.

On the Midstream side, our owned and contracted gathering business in the Marcellus was gathering approximately 359 million cubic feet per day of gas from about 100 miles of gathering lines in the field at March 31. We're also very excited about our announcement earlier this week of 162,000 net acres we agreed to purchase near our existing position in Pennsylvania. We are beginning to plan the integration of these properties into our program and evaluating where we will begin drilling in some of the new areas later on this year. Our initial thought on this is that we would begin to drill one to two additional wells on this new acreage during the fourth quarter.

Let me move on to the Fayetteville Shale, where we placed 102 operated horizontal wells in production in the first quarter at an average completed well cost of $2.1 million per well. This is a record low well cost for us and is a testament to our strong team in Arkansas, the vertical services integration we have in the field, and our commitment to driving our costs lower. We also set a new record for average time to drill to total depth of just 5.4 days from reentry to reentry, and placed 53 wells on production during the quarter that were drilled in less than five days. This brings our total of wells that we have drilled in less than five days to 296 wells in the Fayetteville.

During the first quarter, the initial production rates from the wells drilled was an average of 3.3 million cubic feet of gas per day. While these rates were lower than previous quarters, in keeping with the rigor of our value adding investing, the resulting economic value of these wells more than exceeded our 1.3 PVI hurdle rates due to these lower average well costs. Our Company-operated frac services were up to speed faster and have already made meaningful impact to our overall well costs. Our continuing optimization and testing of the drilling program is working and continues to deliver strong results.

In April, we've already placed a number of strong wells on production in the Eastern side of the play, which had a peak initial production rate in excess of 3.5 million a day with several wells still climbing while cleaning up. On the Midstream side, our gas gathering business in Fayetteville continues to perform well, and at March 31 was gathering approximately 2.2 billion cubic feet of gas per day from 1,859 miles of gathering lines in the field.

Moving on to New Ventures, to date in the Brown Dense we've drilled eight wells. We remain encouraged after watching production flows from our BML and Doles wells over the past several months. We are currently completing 21 stages that are planned in our seventh well, the Dean Horizontal, and we will test several different frac techniques to try to unlock more hydrocarbons from the formation. Our eighth well, the Sharp vertical, is planned to be completed later this month. We've also seen industry activity pick up in the area as several operators have requested new drilling permits, and seven unit filings have been approved for operators targeting the Brown Dense.

Now regarding our negotiations with the potential joint venture partner in the Brown Dense, the period of exclusivity with our previously announced potential partner has lapsed, and while an agreement may be reached with that party we are also engaged in discussions with other interested parties on joining us to work on this promising opportunity. The lack of a joint venture partner will not slow our testing of the Brown Dense exploration program.

In our Denver-Julesburg Basin oil play in Eastern Colorado, we reentered and drilled a 2,000-foot lateral in our second well, the Staner 5-58. We're completing this lateral and have fracture stimulated 5 out of a total of 16 planned stages. The well started to flow back on April 13 and began producing oil on the second day. We'll watch performance on these stages and then complete the remaining 11 stages in June.

In our other New Ventures in Montana we plan to reenter an existing vertical well in Sheridan County to test the Bakken an Three Forks unconventional potential in the second quarter. We continue to lease our new ideas and hope to disclose at least one more of these by the end of the year.

So to close we remain sharply focused on innovating and adding value for each dollar we invest, and I'm highly encouraged by the opportunities we have ahead of us in 2013, and I look forward to discussing our progress with you in future quarters. I'll now turn the call over to Craig Owen who will discuss our financial results.

Thank you, Bill and good morning. As Steve has mentioned we had an exceptional quarter driven by higher production volumes and lower costs. Excluding the unrealized mark-to-market impact of derivative contracts, we reported net income of $146 million or $0.42 per share for the first quarter, compared to $106 million or $0.30 per share the prior year. Our cash flow from operations before changes in operating assets and liabilities was approximately $426 million, a record for discretionary cash flow generated in the first quarter, and up 15% compared to last year.

Operating income for our exploration and production segment was $176 million, up 53% compared to $115 million in the first quarter of 2012. Again, primarily due to higher production and lower cost partially offset by a slight decline in realized gas prices. We realized an average gas price of $3.43 per Mcf during the first quarter, which was down from $3.48 per Mcf in the first quarter 2012. We currently have 240 BCF, or approximately 50% of our remaining 2013 projected natural gas production hedged through fixed-price swaps at a weighted average price of $4.71 per MMBtu. We also have 233 BCF of natural gas swaps in 2014 at an average price of $4.41 per MMBtu. We continue to watch the gas markets and we'll look for opportunities to add to our hedge position. Additionally we added a new line item to our income statement entitled Commodity Derivative Income Loss, to capture the mark-to-market impact of our derivative contracts that have not been qualified as cash flow hedges, which includes our basis hedges, call options sold for 2015 production, and about 182 BCF of our 2014 fixed-price swaps that are associated with the call options.

Our cost structure continues to be one of the lowest in the industry with all-in cash operating costs of approximately $1.18 per Mcfe in the first quarter of 2013 compared to $1.28 per Mcfe last year, that includes our LOE, G&A, net interest expense, and taxes. Lease operating expenses for our E&P segment were $0.81 per Mcfe in the first quarter, down from $0.83 per Mcfe in the first quarter of 2012, primarily due to lower saltwater disposal costs associated with the Fayetteville Shale play.

Our G&A expenses were $0.21 per Mcfe, down from $0.30 per Mcfe a year ago due to decreased information systems costs and adjustments to employee related cost. These adjustments are not expected to be recurring and we anticipate our G&A costs will be in line with our previously issued guidance of $0.26 to $0.30 per Mcfe for the remainder of the year. Taxes other than income taxes were also lower at $0.12 per Mcfe, down from $0.13 a year ago, and our full cost pool amortization rate in our E&P segment fell to $1.09 per Mcfe compared to $1.33 last year.

Operating income from our Midstream Services segment rose 10% to $76 million during the quarter, primarily due to increase in gathering revenues from our Fayetteville and Marcellus Shale plays. At March 31, 2013 our debt to total book capitalization ratio was 36%, essentially flat when compared to the end of 2012, and our liquidity continues to be in great shape with only $35 million borrowed on our $1.5 billion revolving credit facility. We currently expect our debt to total book capitalization ratio at the end of 2013 to be approximately 31% to 33% at current [cer] prices.

In summary, 2013 already looks like a record year for Southwest Energy, with strong cash flow generation, an excellent balance sheet, and a low cost structure. We are ready to deliver even more value not only in 2013 but for many years to come. That concludes my comments so now we'll turn it back to the operator who will explain the procedure for asking questions.

(Operator Instructions)

Our first question comes from the line of Dave Kistler with Simmons & Company. Please proceed with your question.

Good morning guys.

Good morning.

Real quickly, maybe going to the announcement you made on Monday first about the acquisition in the Marcellus, can you walk us through maybe some of the lease terms associated with those 162,000 acres, are some expiring rapidly? I guess a better way to ask it what portion of that acreage will be acreage that you'll focus on for development in '14? And are there any kind of parameters you can give us around prospectivity for the break down of that acreage?

Let me just give you a quick overview. Certainly this is acreage that has between four and five year terms on it and then there are extensions. Those extensions are expensive. They are probably in the $3,000 to $4,000 type ranges to extend those for another four to five years, and there is some that will come up in 2013, 2014.

When we did our analysis we basically assumed that all of the acreage that was in '13 and '14 we would not renew. In real-life it looks like of that 160,000 acres, probably about 40,000 we would not renew at this point in time for '13 and '14 as we go through the overall process. As far as the general value, we think there's somewhere around 50% the acreage that ultimately will have wells better than 5 BCF on it and it takes a little bit of time to figure that out. But the real key for us was when we did the analysis, if we had $4 flat forever, it would take about 70 wells to get ourselves a PV10 or 10% return on the acquisition, and we're very comfortable we have a lot more than 70 wells.

So we're really excited about the acquisition, and it fits right in where we're at. We've been trying to get that Susquehanna acreage for the last three or four years to fill our position in Susquehanna. We've got it and a lot more acreage along the way, so it's a good overall acquisition for us.

Great, and maybe just one follow-up on the Susquehanna acreage. I'm assuming based on kind of the net well parameters that were as part of that release that it's non-operated acreage. Is that a fair assumption or is the way that it's set up, it allows you to exercise longer laterals on your existing leases because they fall into these other areas? Can you just kind of give us a little color on that?

Almost all this acreage is 100% operated. There's very little that is outside operated. Just Chesapeake hadn't drilled much on it yet, and so Susquehanna, I think almost everything there, there's a little bit to the North that kind of goes in where Williams is at that we have a little bit of partnership acreage on, but most of it is 100% there. But it's really a matter of they had not drilled much on the acreage, so the little bit of activity that was on the acreage was by other people putting a little bit of their acreage in the units.

Okay, great. I appreciate those clarification guys, thank you.

Our next question comes from the line of Amir Arif with Stifel Nicolaus. Please proceed with your question.

Good morning guys. I understand that you're still engaged in discussions in terms of the Brown Dense, but is there any color you can provide in terms of what issues are the sticking points, whether it's price, terms, or well results?

Yes, I wouldn't put it that we're still in discussions. Bill and I have a little bit of difference of opinion where this is at. We thought we had a deal with a group. They tried to renegotiate the terms. That's not the way I work and we're not in the deal anymore. Maybe we'll come back in the deal but it really was just simply that from that standpoint.

The other thing about it in general, we've had a lot of debates whether we should get a partner or not get a partner. Certainly we knew a few months ago that we are the winner of the Chesapeake package, and getting some dollars in on the Brown Dense side, being able to apply to the Marcellus was attractive to us. But overall, we're only going to do a deal if it's a good deal and we're only going to do a deal if it's with someone we want to work with.

So we're still looking at deals in the Brown Dense. Certainly if you can get a partner you can go a little bit faster, but as we said in our press release we budgeted it as if we didn't have one and we're on the pace to do exactly what we said we're going to do that direction. So it's just nothing more than somebody tried to change the terms on it and we're just not going to work that way.

Okay, just asking a little more into the changing of the terms, was that after they went through the data room or sought data or could you just provide some color on that?

Going back to your question about was there more well control. There isn't anymore well control at all. When we made the announcement, we had basically a term sheet with all of the agreed terms on it and the major thing they needed to do was do due diligence and that was more on the land side of it. It wasn't with the geology or anything in that direction. And as I said, no new geological or no new information on any directions, just say you want to go back and start over on some of the terms.

Okay, appreciate that color. Second question, looking at the acquisitions you did and the attractive acquisition price, any desire to look at maybe the acquisition market to get into some new areas, just given the attractive prices that are out there and your balance sheet rather than just as bolt ons?

We have a couple areas that we target and we're always looking at to get into and I'll just remind everyone, we look at our acquisition effort as an extension of our New Ventures, and we're not looking for significant production per se. What we're looking for is something that we can use our talents to. We can drill into, have a long running room on it, use our vertical integration. So to the extent there's any of those kinds of acquisitions in particular areas we're definitely looking for those and in this case, it just happens to be one of them is right in our backyard, the Marcellus.

Okay, thank you.

Our next question comes from the line of Scott Hanold with RBC. Please proceed with your question.

Yes, thanks. Could I talk a little bit about the Marcellus for a minute? You guys added, when did that additional firm kick in because it didn't look like Q2 production was increased at all, and generally, is there a line of sight on additional stuff out there?

The date of the additional 50,000 a day that we picked up comes in in the latter part of this year. We have, we're looking for additional transportation but we've secured the transportation that we need through '15, '16 in terms of our growth plans, but we are out, we would be out in the market looking for some additional opportunities.

I think the market is basically the way it's been the last six months or so. There are operators who have firm that are not using it because they are not drilling right now, and to the extent that we can buy nine months or a year of firm we're doing that. There's a couple of deals we're working on right now that are a little bit longer than that that are kind of two year type time frames on them, and that goes back to Bill's comment about working towards 2015, 2016 with some of the numbers, and of course you have our Constitution line that comes on in 2015.

From the standpoint of our new acreage, we had no firm on that new acreage, so part of what we're having to do right now is develop that budget, figure out what other firm we can add into the mix, and figure out how fast we can go on that acreage.

Okay, and then with respect to your comment, Steve, that obviously gas prices are up a little bit but you don't feel compelled I guess to increase activity. Now I think the plan was based on a $3.50 gas price and to the extent that obviously prices were better, it seemed like at least in the Fayetteville Shale, you'd add a rig I think it was every what, $0.35 you could add a rig and stay within cash flow. Has there been a change in thought of that in terms of running the Fayetteville within sort of its cash flows?

Well, there really hasn't been a change in thought. Fayetteville Shale we'll keep it within cash flow give or take a little bit. If you look through the first five months of the year, I think the average NYMEX price is like $3.60, so we just need to see it a little bit more to make sure that we have some more cash flow in the Fayetteville Shale to go faster on. We could decide maybe in the fourth quarter, but as we're looking at it right now and just looking at we build a budget around $3.50 and the average price that we have in hand today is about $3.60 we're not changing much.

Okay, understood, thanks.

Our next question comes from the line of Brian Singer with Goldman Sachs. Please proceed with your question.

Thank you, good morning.

Good morning.

On the Marcellus, would you mind just talking to the various firm transport compression and drilling constraints in each of your four main Marcellus areas, what is constrained today and what changes do you see between now and the end of the year?

I guess I would start by saying in terms of constraints, I think it's we really are looking at completing compression in the Susquehanna area, so it's not a constraint we're able to flow gas through that, so it's just ramping up infrastructure in the field in line with our drilling schedule. We have right now today through the end of the year about 600 million a day of firm transportation out of the area, and we hold that number through 2015 where we ramp up to 750 million a day, so today, we're able to move all of our gas. There are no constraints through the end of the year, and into next year, there are no constraints. We're actually slightly ahead and are utilizing other transportation that's being released in the area and then balancing that with incremental transportation if we need it.

The Bluestone line that we talked about at the end of last year will connect to Millennium within the next few days. We've been able to move all of our gas south while that activity has been happening and so now we'll split flow some gas north to Millennium and some gas south to Tennessee out of the Susquehanna area. All the infrastructure is in place in Lycoming for the growth that we have scheduled. And so really, the next sort of question mark becomes timing on longer-term projects, and we're doing some work around those to make sure that we have capacity in place to be able to move gas in the longer term.

And let me add when talking about constraint, when we do the economics, in some cases just because these are so strong wells, we've decided that we don't need to turn on the compression and use that gas from the compression standpoint, and so I wouldn't put that as a constraint. It's just pure economics in whatever we're getting for the gas price.

The big compression projects we have this year are in our Northeast Susquehanna area, and there to basically matching as we grow our production and as other wells start losing pressure from being put on earlier in the year, so from that standpoint, I think there really isn't a constraint as Bill said.

Let me also add we get all the questions all the time, how we compare to other companies and how we're doing, but one of the things that we did in the most recent data, we were able to take our production data and take the number of stages we have, and I think that's all public information in Pennsylvania, and then compare that to Cabot. If you just zero out when we started, when they started put the time zero, take the number of stages of fracs that we've had to date and the amount of production, both the stages and amount of production are dead on top of each other from where we're at, so I think from an infrastructure standpoint we're right on schedule. From what we're getting first stage, we're right on schedule, and the production is showing that we're at 400 million a day, we're on schedule so we're excited about that.

Another way to put that is our Range wells are coming on a little bit slower than the Bradford wells, but as we get to the peak rates and you see that on 120 day rates on our chart, we've actually got a little bit of increase in production in 120 days in all those quarters. But they are looking very comparable so we're excited about this acreage, and we're then on top of especially in Susquehanna we've added another 50,000 acres or so, we're really excited about what's going to happen later on in the year.

That's helpful. And to follow-up on just a couple points in your response, what is the impact from the Bluestone connection to Millennium? Is that a volumetric impact or price impact or just allows for diversification? And then the compressions coming on this summer, is that baked into your guidance or is there some avenue of upside if in fact that does come on on time.

I think the compressions in our guidance. And when I say I think, you never know until you put it on and see exactly what it does, but certainly we've factored it in as we go through. And then Millennium there's two things for you. The Millennium tie, number one it's a little bit different price, you get a couple more cents, so we'll send as much gas as we can that direction. But the other part of it is in case either one of the lines are down, whether it's down for maintenance or down for some other issues you've got an outlet you don't have to worry about, so that's your two main things.

Thank you.

Our next question comes from the line of Doug Leggett with Bank of America. Please proceed with your question.

Oh, thanks, good morning guys.

Good morning.

I guess my first question is on capital. Steve, I hear that you're not going to increase spending at least not in absolute terms. How about the allocation of capital now that you've got the Marcellus, the bigger position. How should we expect your relative capital within the portfolio to shift around? Maybe not so much second half of this year but as you look into 2014.

Trying to predict 2014 is a little difficult right now. I will say that we're drilling faster than we had expected in the Marcellus, and so if we would try to stay in the 90 well range on the acreage we had before the acquisition, or rather than running 4 rigs it's more like 3.25 rigs to do that, and so we've got 4 rigs running today. As we get towards the end of the year we'll either be drilling more wells on our current acreage or we'll have spread out into the new acreage is what we're doing. But right now, with the 11 days to drill the well we're drilling closer to a little over 100 well pace, and so we're trying to adjust that into the end of '13 actually and then we'll figure out what happens in 2014.

Great. My only other one is you made a pretty interesting comment there about the assumption you had on the type curves and the acquired acreage, I think you said a 5 BCF curve. But looking at the chart record that was published already, obviously that seems a little conservative. I'm just curious is that a starting point, or do you have reasons to think that these wells are going to be less productive in the balance of your portfolio or are you just being conservative? I'll leave it at that, thanks.

Well I think certainly part of our acreage is well under 3 BCF, and there's a little bit of control about that. We've talked about even our current acreage in Lycoming County, much of that's less than the 5 BCF numbers. And as you swing into Wyoming there will be some of that that's less than 5 BCF with a little bit of well control that we see.

And other areas frankly there's just not much well control, so we're just going to have to go figure it out, and obviously in any of those areas we don't have well control, we look at what industry has done around us, we've risked those numbers. And when we look at that risk kind of factor, we're thinking 50% or less is at 5 BCF. We'll have to figure it out.

The other side of that, we are offsetting some wells in Wyoming County for instance some of our acreage that are already proved to be 10 BCF wells or higher. Some of the new acreage we have is [right off studies], and what Cabot has recently announced in Susquehanna County, and they're talking about wells much better than 5 BCF there. And certainly some of our Tioga County acreage is sandwiched between what Shell has been doing and what we've been doing, and those almost certainly will have a lot of wells higher than 5 BCF. So some cases we've got it pretty much down, and we just have to figure out how much higher. In other cases we're going to have to drill some wells and put in infrastructure just to figure out the quality.

Steve you've always been evolving your well design a little bit in your existing acreage. Can you figure out what your standard well looks like in new acreage or is that going to be more of (inaudible) as well? In other words what's your (inaudible)?

Well design will be ongoing, and I'm going to jump to Fayetteville and come back to Marcellus, but if you think about the Fayetteville we're 3,500 wells in the drilling. One of the reasons we had some low rates in January where we were trying to do some little different fracs in an area and those fracs didn't work the way we liked.

We learned something from those, one of the reasons in April we have such higher rates that we announced, was when we went right back to the same area with a slightly different frac and got better wells, significantly better wells. So even there we're learning.

In the case of Marcellus, we are understanding a couple things. We think we know the rough spacing for the Bradford County. We spent most of last year trying to do that. In Lycoming County we tried to pull a well at a very high rate, a couple wells at high rates, they performed at high rates well above 10 million a day. But when we look at how their pressure drops they seem to more act like the Haynesville where rather than having a high rate you want to come in with a medium rate, maybe a 7 million to 8 million a day type well, and let that pressure stabilize as you go through it.

We're trying to understand in both Bradford and Susquehanna whether the high rate is better long term or the low rates or lower medium rate is better long term. And our new acreage to the extent it's near where we've done some work we can transfer that knowledge, but a lot of that we're just going to have to go in and start learning as we go through.

So I don't think there's going to be just a formula on stage spacing, or on how hard to pull the well across our whole acreage block. It's going to be individualized for each of the areas. And the reason it's going to do that is from Lycoming to Susquehanna there's over 2,000 foot depth difference across there, there's thickness differences across there, and there's pressure gradient differences across there. So all of that will affect how it produces and how you need to frac as you go through.

I appreciate the answer, thank you.

Our next question comes from of Arun Jayaram with Credit Suisse.

Good morning gentlemen. Steve, I wanted to talk to you a little bit about development plans in the Fayetteville. You had obviously gone to wider spacing in order to help you meet 1.3 PVI target in the lower gas price environment, yet with prices now moving up your well costs going down, what are the plans to shift back to your call it your more original plan which is tighter spacing. Do you plan to do that this year or will that wait?

It could happen in the fourth quarter, again we just need to see how prices working. And it's not so much tighter spacing, as we've talked about in the past we're kind of drilling better wells in the areas, so we're just not drilling at hardly any spacing, we're just putting one or two wells near maybe where a well was drilled before. We'll get back to pad drilling once we're comfortable, we're in a $4 world or near $4 world, and certainly the forward curve looks that way as long as it holds in this shape, you'll see us towards the end of this year going into next year, going back to those pad type drilling operations.

That's helpful. Steve, you did provide a lot of --

Let me just put in there. This year we're going to average a little over two wells per pad, so we're certainly not in a pad drilling situation right now.

Steve, you gave us a lot of great detail in terms of the Marcellus, in terms of 30, 60, 120 day rates and the average lateral length. Seen quite a bit of volatility in the data. I was wondering if you could maybe give us your thoughts on what you think the data suggests in terms of your Marcellus position, and also you have been moving around that lateral length a little bit. Just thoughts on as you move forward what you think the optimal lateral length could be.

Yes, Brad asked the same question. Why are you putting that chart in there, it's got a bunch of junk on it. And it's bouncing around because we're really new on the project area, so even if you look at well counts. Well counts bounce around, let alone the other parts of it.

One thing as I've said before that we've seen and one of the reasons we've put the chart together this way, an IP the initial high rate really doesn't do us much value and we don't even get to the highest rate. In Bradford for instance, say you're at least 30 days are out, and in Range it's 45 to 60 days out before we see it. So we try to get something where you could follow how it's going to happen over time, and I think a lot of this is just erratic nature of being early in the program. And some of those quarters you remember we were waiting on getting pipelines in, and we put a bunch of wells on at once and filled up the system, another quarter you did something else. So I think you just need to follow that through.

From an average lateral length though, it's probably less than 5,000 feet. It's probably high 4,000 and less than 5,000. For the most part, Lycoming probably will average a little longer than that, and certainly on our new acreage as we get to parts of that, there may be some of that that averages longer, but I don't think on average you'll see us much above 5,000 feet.

And then just one quick follow-up. In terms of the number of stages I think you mentioned that you're moving to maybe 17 stages on average. Are you seeing benefit of the additional stage in terms of recoveries or IP rates?

I don't know that we're moving to 17 stages on average. We're trying to figure that out. And in Bradford County, we think that a 250 to 300 foot range and I think we average last year like 280 or something, but we think that range is the right spacing on fracs. And so then it just goes back to what your average lateral length is and how many frac stages you have in a well. We're trying to learn what it's going to be in Susquehanna and I know some of our competitors have a tighter spacing there, and it may end up to be that way, we just have to find that out. So it'll just depend on each area exactly what that is and that's why you see a lot of us talk about per stage numbers because each area is going to be a little different on the total number of stages.

Very helpful. Thanks guys.

Our next question comes from the line of Ray Deacon with Brean Capital. You are now live.

I just had a question, I've heard you talk in the past about you being fine with your firm transportation situation if the wells were 5.5 BCF or less, and so I guess is the right way to think about that that if you do get numbers higher than that that is it so kind of beyond 2014 is when you feel like you would need to schedule in further firm transportation versus what you have now? Is that what you're saying?

What we've talked about in the past we believe that we want to have most of our production covered by firm, and we think that's important to get it to a liquid point especially as fast as the Marcellus has grown, we don't know what you're going to get on the interruptible or day market. And so we originally -- this is almost two years ago now, developed a program and developed a plan where we said what's the maximum rate that we could have and hold it flat for 8 to 10 years, and that number was the assumptions we had at that point in time assuming around 5 BCF wells and a little over 5 million a day on average rates, said that where just somewhere short of 800 million a day was that peak rate that we could have, and then we designed our current capital program just backing off of that and going back to where we're at today and it came to be drilling around 100 wells a year that we thought was a four rig program and that's what we started doing last year and got to this year where we're into that framework.

If the well performances on average are a little bit higher we'll tack on a little bit of firm that's out there and it will be roughly an 800 million a day range and we'll hold that flat for that period of time. If we saw either the new acreage something or on the acreage we have now where there's significantly better wells on average, then certainly we would have to go find some more capacity. And today, while we can buy little pieces of capacity from other operators, if we needed to for instance add 100 million or 150 million a day more you'd have to commit to some new pipe and that's two years out. So that goes back to your comment about when you'd accelerate the capital, you'd accelerate the capital as you were seeing the firm in place and that would be a little bit farther down the road.

Okay, got it. And is generally new sort of a second tranche of firm transportation, does it end up usually costing more than the early stuff that's put in or what would be your guess there?

Not necessarily. It depends on how you're getting and where you're getting it from. Certainly if it's just like Tennessee gas doing something to their line and adding compression that's usually less cost than putting in a brand new line, but it really depends on the distance you're going, how big the line is and whether it's a new line or how you're getting the capacity, so it doesn't have to change it.

Okay, got it and just one more quick follow-up. I guess in terms of looking at Bradford and Susquehanna County I guess where would you say you are kind of -- in Bradford it looks like you're getting much, much better results. Are you kind of in the fifth or sixth inning there and what would you say about Susquehanna?

Well Bradford, we've drilled on all corners of that block and we're feeling that we know it fairly comfortably, so it's really in a pad mode. And while we're learning and we tried this well we talked about in the press release, trying to learn how to do a little bit better, we understand the geology and how it changes and what's going on there. And in Bradford -- I mean in Susquehanna in the fourth quarter we put our first wells on and they were in the Northeast area but at the far south tip of that. During the first quarter we started to work along the Bluestone pipeline a little bit north, and by the end of the year we'll have wells all the way up almost to the New York border and have wells almost to the Eastern side of that northern block of acreage. So at that time, we'll at least understand the geology. To understand how you frac and how do you get the best well out of that, that's something beyond this year into next year and maybe a little later than that.

Okay, thank you very much.

Our next question comes from the line of Dan McSpirit with BMO Capital Markets.

Thank you folks, good morning. You spoke about pud reserves returning to books on price in your prepared comments. Can you elaborate on that statement and maybe speak to at what price and how much has returned. And as a follow-up to that, what should be expected with greater strength in price here going forward?

Yes, that comment if you look at the SEC rules you have to use a 12 month rolling average. The actual 12 month rolling average in price is something like $0.20 higher than it was at the end of the year, so you didn't have much increase in price. We added about 200 puds in the Fayetteville Shale, a little less than 200 and for those remember we had just over 200 to be in the year, so we doubled the pud count in the Fayetteville Shale and that's where he's talking about the increase in count mainly. Obviously that $0.20 helps a little bit on the tail end of the wells, it helps a little bit in the Marcellus, but it's mainly the Fayetteville.

Okay and as a follow-up on the Marcellus and this is more clarification here. On the Marcellus acquisition you stated that about 50% of the acreage will have wells with 5 BCF recoveries or greater. That's net of the 40,000 net acres that will be allowed to expire, correct?

I think that's total acreage I was talking about 160,000, and certainly 40,000 of that is going to be gone here in the next two years.

Got it. Thank you.

The next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question.

Good morning. Thanks for taking my question. You guys have provided a lot of good detail on the Marcellus here, but I'd like to go in a slightly different direction and ask you about two of your New Ventures plays. And specifically on the Staner reentry, did you always have the plan to just try one completion design on these first five stages, and see how that went? Or did you see something when you completed those stages that made you just want to let the well flow and see what it did?

No, our original plan was to complete that lateral or drill that lateral and then complete it in two phases, where we do the first five stages, let it flow for awhile, look at the cuts, look at the quality of the performance, and then go back into it and complete the remainder of that. So there's no change to our plan.

Got it and do you have more--

We're pretty encouraged by what we're seeing so far. It's early days. We received, we had oil cut come in the first two days and then we're continuing to monitor it. It's still cleaning up.

Got it, and do you have a different completion design for the next 11 stages than you did for the first 5 here?

We'll finalize that once we see what happens in these first five stages, and so we've done this before in other wells, we will split completed, look and see where we are, what the performance is on the recipe that we used, and then go back, make adjustments or not depending on what we see and then do the remainder of the completion.

Got it, and then that kind of gets to my next question. It sounds like you're going to take a similar approach for the Dean horizontal.

That's correct. We've done the first six stages and now we are, we pulled back, we're evaluating the results of that. We are evaluating the combining that with the results of the other wells in the area where we've learned from -- and then sorry my voice is going, and then we will optimize that frac and then move forward again.

Got it, and when might you think that you'll have something you'd want to share on either of those or on both of those wells?

I think it's going to be later in the year. I don't have an exact timing. We're really trying to incorporate the learnings. One of the things about drilling in these plays is trying to optimize our learning as we go and so we want to capture all the value of the data or the testing that we've done, and so I don't have a time for you yet, but we'll let you know as soon as we are ready to move forward.

Got it. There's definitely a tradeoff there. Thank you for the added detail.

Thank you.

Okay, well our next question comes from the line of Biju Perincheril with Jefferies & Company. Please proceed with your question.

Hi, good morning. I had a question going back to the well designs in the Marcellus, and Steve you talked about in Bradford County sort of what do you think is the ideal length for frac stages. But the latest well, the Blaine Hoyd well it looked like you're getting improved productivity with the shorter frac stages. Can you talk about the design going forward and what's the information you're still looking for there?

It's almost exactly what Bill said in the last question. We need to look at it. Certainly you're getting higher rates, but rates aren't the only part of it. You have to look at the pressure drawdown and the overall effects on the production. And if I had to guess today as we compare it to some of the other wells we've done where we've gone on a slower ramp up on rate, on just the pure rate part of it, the slower ramp up looks like it holds pressure longer than the higher rate. Now certainly part of that has to do with how close you put the stages together, but what we're in now adjusting on stages is a 250, 275 or 300, and we're not in is it 250 or 150, so we're still fine tuning but we're above 200 foot on putting the space on stages.

Okay, and then can you give us some bit on your sort of average 30 day rates or 60 day rates in Susquehanna versus Bradford County and Lycoming?

Well in Susquehanna and Lycoming, we barely have 60 day rates, and we've got some 80s maybe or something in that range. Lycoming in general is when we have, we drilled a couple wells earlier that were shorter laterals, but if you take a 4,500 foot lateral, those 4,500 foot lateral wells are producing between 7 million and 8 million a day type numbers. And in Susquehanna, at around the something beyond the 60 day mark, we're still -- a lot of those wells are still increasing on their maximum rates, but they're in the 6 plus million a day type average range for those wells, and there's some that are much better than that. There's some a little bit lower than that in Susquehanna. But that's kind of the general part of it, and then you can compare that to the Bradford. Bradford's mainly what's in that presentation material that we have there, but you can see those rates are in the 6 million to 6.5 million to 7 million a day type range.

Got it. Okay, and then one last question. Looking at the acreage that you recently acquired especially in Susquehanna, looks like there's not been a lot of permitting activity on that very East end side of Susquehanna, and can you talk about is there any geologic reason for that or is that mostly those acreage had a longer expiry?

In general, the Eastern side of Susquehanna hasn't had much permitting because you haven't had a way to get the gas out. That Bluestone line I just went in in December is the main way that all of the industry will get their gas out of that area.

Now from a geologic standpoint, the center of Susquehanna County is for the total Marcellus is thicker than when you go north towards New York or east towards New Jersey, so it is thinning a little bit, but from a general perspective you're talking about 30 or 40 foot thickness change across the whole interval geologically as you go through there. So it's basically you need to get the Bluestone line in so you can start hooking up some wells.

Thanks, that's helpful, thank you.

Our next question comes from the line of Nick Pope with Cowen Securities.

Good morning guys.

Good morning.

Quick question on the acquisition. What is the royalty run in on kind of the acreage that you acquired? Where is that relative to where you're at on kind of the heritage Marcellus asset?

It's very similar to the acreage that we have. It's about an 84% NRI.

Got it. I think everything else has been answered, so thanks guys, thanks for the time.

Our next question comes from the line of Hsulin Peng with Robert W Baird.

Good morning. So just a quick clarification question. On the New Ventures budget, I think that has assumed a JV partner, and so if you're not going down in Brown Dense, how would you, where would you get the additional allocation dollar from?

Well I don't think we ever said exactly how much we were investing in the Brown Dense, but we had originally in our budget about 2.5 net wells, and we may invest a little bit more in another well this year on top of the ones we have drilled now. But we can move money around within the joint venture budget to do that so it doesn't require more budget as you'll go through. But it just has to do with where we might be drilling someplace else or what acreage you might be picking up and how fast you pick up acreage.

Okay, got it. And then can you comment on the progress you are making toward the $10 million well cost target that you previously mentioned?

We drilled two wells since last quarter, both of those came on time and if we didn't have a lot of science to them on a 4,000-foot lateral would be in that I'd say mid $10 million range, $10.5 million to $10.7 million range somewhere in that range.

Okay that's good. And then last question, I know I don't think you can comment on (inaudible) paradox, but I was just thinking so Fidelity, we know Fidelity is drilling in the area as well and I was wondering if you can say are you thinking about similar results to what they have been doing there?

Our objective is the Cane Creek interval and Cane Creek interval, the section that Cane Creek is in is a very large section, but we'll be going for the Cane Creek, which I believe is the same thing they are going for, and you'll see us have some activity later this summer out there.

Okay, and my other questions have been asked, thanks.

Since there are no further questions at this time I'd like to turn the floor back over for closing comments.

Thank you. One of the questions everyone should ask about a Company is how do you measure yourself. Today, in this quarter we talked about a lot of things, revenue, cost, cash flow, earnings, project economics, production, activity, talked a lot about learning, and we'll continue to measure and talk about those things as we go forward in the future.

For us this year we've got a special measure in 2013 and that's to deliver more, and you saw a little bit of glance of that in our discussion today for the first quarter. Our economics continue improving in Fayetteville Shale, as we drive down the costs. Lower costs allows us to have more activity. We talked about that in the Marcellus. We're also could have more activity in the Fayetteville. But what's amazing about this is Fayetteville now has been producing almost eight years and you're only barely one-third through the locations that we have to drill out there, so we have a lot more to do in the Fayetteville Shale.

When you think about the Marcellus, we've got exceptional results from the wells we have. And as I said before, our production for frac stage is comparable to anyone in Northeast Pennsylvania, and we're still learning, we're still developing more and better wells. And then on top of that we've got some new acreage where we're going to create more options, more wells, be able to do more vertical integration, and actually have more production and more value.

We've mentioned just to the last question about our New Ventures projects. We've got four of them that we identified. We have 1.3 million acres, and we've got a lot more ideas, and you'll see at least one more come out this year. And then finally we're delivering more with less. When you think about our capital budget, our capital budget is $100 million than last year. The capital budget of the Fayetteville Shale is $200 million less than last year, and that's been our pride and joy, and yet we're growing production at 13%, giving you more production with less capital. Of course we've got less days, we've got less cost, and one of the reasons we have less cost is that we're using less water and we're working towards our goal that by 2016 we're net neutral as far as freshwater goes.

Again for us 2013 is a year of more, and the first quarter is just a start on what that more is. I thank you for the time you've taken from your busy schedules to listen to us today and have a great weekend.

This concludes today's teleconference. You may disconnect your lines at this time and thank you for your participation.