May 3, 2013
Executives
Steven L. Mueller - Chief Executive Officer, President and Director William J.
Way - Chief Operating Officer and Executive Vice President Robert Craig Owen - Chief Financial Officer and Senior Vice President
Analysts
David W. Kistler - Simmons & Company International, Research Division Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division Scott Hanold - RBC Capital Markets, LLC, Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Arun Jayaram - Crédit Suisse AG, Research Division Raymond J.
Deacon - Brean Capital LLC, Research Division Dan McSpirit - BMO Capital Markets U.S. Charles A.
Meade - Johnson Rice & Company, L.L.C., Research Division Biju Z. Perincheril - Jefferies & Company, Inc., Research Division Nicholas P.
Pope - Cowen Securities LLC, Research Division Hsulin Peng - Robert W. Baird & Co.
Incorporated, Research Division
Operator
Greetings, and welcome to the Southwestern Energy First Quarter 2013 Earnings Teleconference Call. [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.
Steven L. Mueller
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've not received a copy of yesterday's press release regarding the first quarter 2013 results, you can find a copy on our website, 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 detail 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 a first quarter of our company's history.
Since the end of the first quarter, gas prices have improved, and our production in 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 the acquisition of 162,000 additional acres in the Marcellus. Because it will take time to fully understand all 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 will 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.
William J. Way
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 PUD reserves begin to return to books -- up 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 troublesome in January where we only put -- were able to put 2 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 tests 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 placed 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 or 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 1 to 2 additional wells on this new acreage during the fourth quarter. We move on to the Fayetteville Shale, where we placed 102 operated horizontal wells on 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 new -- 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 5 days.
This brings our total of wells that we have drilled in less than 5 days to 296 wells in the Fayetteville. During the first quarter, the initial production rates from these -- the wells drilled was at 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 may -- and have already made meaningful impact to our overall well cost.
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 have a -- 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 8 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'll 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 7 unit filings have been approved for operators targeting the Brown Dense.
Now regarding our negotiations with a 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 to -- producing oil on the second day.
We will 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 and 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 opportunity 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.
Robert Craig Owen
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 costs, 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 of 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 will look for opportunities to add to our hedge position. Additionally, we added a new line item to our income statement entitled, commodity derivatives 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 cost 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 sort of prices. In summary, 2013 already looks like a record year for Southwestern Energy with strong cash flow generation and 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, and now we'll turn it back to the operator, who will explain the procedure for asking questions.
Operator
[Operator Instructions] And our first question comes from the line of Dave Kistler with Simmons & Company.
David W. Kistler - Simmons & Company International, Research Division
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 the 162,000 acres or some of the expiring rapidly? What portion -- you said you would 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 breakdown of that acreage?
Steven L. Mueller
Let me just kind of give you just a quick overview. Certainly, this is acreage that has between 4- and 5-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 4 to 5 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, it was in '13 and '14, we would not renew. In real life, it looks like of that 160,000 acreage, 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 half the acreage. But ultimately, we'll 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 PV-10 or a 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. It fits right where we're at.
We've been trying to get that Susquehanna acreage for the last 3 or 4 years to fill our positions in Susquehanna. We've got it and a lot more acreage along the way.
So it's a good overall acquisition for us.
David W. Kistler - Simmons & Company International, Research Division
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 re-lease, 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?
Steven L. Mueller
Almost all of this acreage is 100% operated. There's very little that is outside operated.
Just Chesapeake hasn't drilled much on it yet. And so in Susquehanna, I think almost everything there is -- for little bit to the north it kind of goes in where Williams is at, so I guess we have a little bit of partnership acreage on, but most of it's 100% there.
But it's really just a matter of they had not drilled much on the acreage. So the little bit of activity that was on the acreage, it was by other people putting in a little bit of acreage in units.
Operator
Our next question comes from the line of Amir Arif with Stifel.
Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division
I mean, 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?
Steven L. Mueller
Yes. I wouldn't say -- I wouldn't put it that we're still in discussions.
Bill and I have a little bit of difference anywhere 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, I guess, that we were the winner of the Chesapeake package. And getting some dollars in on the ground inside tied to 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 had budgeted as if we didn't have one, and we're on pace to do exactly we said we're going to do in that direction.
So it's just nothing more than somebody tried to change the terms on us, and we're just not going to do work that way.
Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division
Okay. Just asking a little more into the changing of the terms.
Was that after they went through the data room or sort of saw data? Or could you just provide some color on that?
Steven L. Mueller
No. Now about your question about was there more well control, there isn't any more well control at all.
What -- when we made the announcement, we had basically a term sheet with all 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 a geology or anything in that direction. And as I said, no new geological or no new information on any direction.
It was just saying we want to go back and start over on some of the terms.
Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division
Okay, I appreciate that color. The 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 in your balance sheet rather than just as bolt-ons?
Steven L. Mueller
We have a couple of areas that we target and are 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, but 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, we -- there just happens to be one right in our backyard in Marcellus.
Operator
Our next question comes from the line of Scott Hanold with RBC.
Scott Hanold - RBC Capital Markets, LLC, Research Division
Could I talk a little bit about the Marcellus firm that 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?
William J. Way
The data 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 our -- the transportation that we need through '15, '16 in terms of our growth plans.
But we are out in the -- we would be out in the market looking for some additional opportunities.
Steven L. Mueller
I think the market is basically the way it's been the last 6 months or so. There are operators who have firm that are not using it because they're not drilling right now.
And to the extent that we can buy 9 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.
So they're kind of 2-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 a 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 how fast we can go on that acreage.
Scott Hanold - RBC Capital Markets, LLC, Research Division
Okay. And then with respect to your comments, Steve, that obviously, gas prices are up here 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 in that in terms of like running the Fayetteville within sort of its cash flows?
Steven L. Mueller
Well, there really hasn't been any change in thought. Fayetteville shale, we'll keep it within cash flow, give or take a little bit.
If you look through the first 5 months of the year, I think the average NYMEX price is like $3.60. So we just need to see 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, you'd be looking at -- if 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 those.
Operator
Our next question comes from line of Brian Singer with Goldman Sachs.
Brian Singer - Goldman Sachs Group Inc., Research Division
On the Marcellus, would you mind just talking to the various firm transport compression and drilling constraints in each of your 4 main Marcellus areas? What is constraint today?
And what changes do you see between now and the end of the year?
William J. Way
We -- the -- 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 20 -- to 750 million a day. So today, we're able to move all of our gas.
There is -- there are no constrains 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 in -- 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 of 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.
Steven L. Mueller
And let me add. We talk about constraint.
When we do the economics in some cases just because these are such strong wells, we've decided that we don't need to turn on the compression and use that gas from a compression standpoint. And so I wouldn't put that as a constraint.
It's just pure economics and whatever you're getting for the gas price. We -- the big compression projects we have this year are in our Northeast Susquehanna area, and they're 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. But 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 all public information in Pennsylvania, and then compare that to Cabot. If you just 0 out when we started, when they started, put to time 0, take the number of stages of fracs that we've had to date and then the amount of production, both the stages and the amount of production are dead on top of each other for 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 that's showing that we're at 400 million a day, we're right 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 the 120-day rates on our chart, we've actually had a little bit of increase in production even at 120 days in all those quarters, but they're looking very comparable.
So we're excited about this acreage. And we're -- and then, if -- on top of it, especially in Susquehanna, we've added another 50,000 acres or so.
We're really excited about what's going to happen there later on in the year.
Brian Singer - Goldman Sachs Group Inc., Research Division
That's helpful. And to follow up on just a couple points on your response, is there -- what is the impact from the Bluestone connection to Millennium?
Is that a volumetric impact or a price impact or just allows for diversification? And then the compression that's 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?
Steven L. Mueller
I think the compression is in our guidance. You -- what I'll say is I think you'll never know until you put it on and see exactly what it does.
But it's -- certainly, we've factored it in as we go through. And then Millennium does 2 things for you.
It -- the Millennium tie -- number one, it's a little bit different price. You get a couple more cents if you go into Millennium.
So we'll send as much gas as we can in that direction. But the other part of it is in case either one of the lines are down, whether they're 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 2 main things.
Operator
Our next question comes from the line of Doug Leggate with Bank of America.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
I guess my first question is on capital spend [ph]. I get 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 the second half of this year but as you look into 2014?
Steven L. Mueller
Trying to predict 2014 is little difficult right now. I will say that we're drilling faster than we expected in the Marcellus.
And so if we would try to stay in the 90-well range on the acreage we have before the acquisition, rather than running 4 rigs, it's more like 3.25 rigs to do that. And so -- and we've got 4 rigs running today.
As we get towards the end of 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 11 days to drill a well, we're drilling closer to 100 or 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.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
Great. My only other one is really you made a convincing [ph] comment there about the assumption you had on the tight curves on the acquired acreage when you said a 5-Bcf curve.
But looking at the track records you've established up there 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 than the balance of your portfolio? Or are you just being conservative?
I'll leave it at that.
Steven L. Mueller
Well, I think certainly, part of our acreage is well under 3 Bcf, and there's a little bit of control for that. And we've talked about in our current acreage in Lycoming Country, much of that is less than the 5 Bcf numbers.
And as you swing into Wyoming, there'll be some of that, that's less than 5 Bcf with a little bit of well control that we've seen. In 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 those areas we don't have well control, we look at what the industry has done around as we risk those numbers and that 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.
Now 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 outside where Cabots 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'll just have to figure out how much higher.
In other cases, we're going to have to drill some wells and put in some infrastructure just to figure out the quality.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
Okay. And Steve, you've always been evolving your well design a little bit in your existing acreage.
Have you kind of figured out what your standard well is going to look like in the new acreage? Or is that going to be more of well you control as well?
In other words, what's your standard [indiscernible]...
Steven L. Mueller
The well design will be ongoing. And I'm going to jump to Fayetteville then come back to Marcellus.
But if you think about the Fayetteville, we're 3,500 wells into drilling. One of the reasons we had some low rates in January, well, we were trying to do some different -- little different fracs in an area, and those fracs didn't work the way we liked.
We learned some from those. One of the reasons that in April we had such higher rates that we announced was we went right back to the same area with a slightly different frac and got better wells, significantly better wells.
So even now, we're learning. In the case of Marcellus, we are understanding a couple of 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 of wells at high rates. They performed at high rates, well above 10 million a day.
When we look at how their pressure drops, they seem to more act like the Haynesville, where rather than having the high rates, you want to come in with a medium rate, maybe some at 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 a low or medium rate is better long term.
In our new acreage, to extent that in here 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 a -- just a formula in our stage spacing or on how hard you pull a 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, there's a 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.
Operator
Our next question comes from the line Arun Jayaram with Crédit Suisse.
Arun Jayaram - Crédit Suisse AG, Research Division
Steve, I wanted to talk to you a little bit about the development plans in the Fayetteville. You had obviously gone to wider spacing in order to help you meet the 1.3 PVI target in a 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 was tighter spacing? Do you plan to do that this year or will that wait?
Steven L. Mueller
It could happen in the fourth quarter. Again, we just need to see how price is working.
And it's not so much tighter spacing as we've talked about in the past. We're kind of drilling the better wells in the areas.
So we're just not drilling at hardly any spacing. We're just putting 1 or 2 wells near maybe a well that was drilled before.
And we'll get back to pad drilling once we're comfortable we're in a $4 world or near a $4 world. And certainly, the forward curve looks like that way.
As long as it holds in this shape, you'll see us towards the end of this year and going into next year going back to those pad-type drilling operations.
Arun Jayaram - Crédit Suisse AG, Research Division
That's helpful. Steve, you did provide a lot of...
Steven L. Mueller
And the other thing -- yes, let me just put on there this year, we're going to average a little over 2 wells per pad. So we're certainly not in a pad drilling situation right now.
Arun Jayaram - Crédit Suisse AG, Research Division
Okay. Steve, you gave us a lot of great detail in terms of the Marcellus in terms of 30-, 60- and 120-day rates and the average lateral length.
I see 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 some thoughts on, as you move forward, what you think the optimal lateral length could be.
Steven L. Mueller
Yes. Brad asked the same question.
Why are you putting that chart in there? It's got a bunch of junk on it.
And really, it's just bouncing around because it's -- 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 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 as much value, and we don't even get to the highest rate in Bradford, for instance, until at least 30 days out. And in Range, it's 45 to 60 days out before you see it.
So we've tried to use 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. In some of those quarters, you'll remember we're waiting on getting pipelines in, and we put a bunch of wells on them 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 low 4,000 -- I mean, high 4,000s 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.
Arun Jayaram - Crédit Suisse AG, Research Division
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 the benefit of the additional stage in terms of recoveries or IP rates?
Steven L. Mueller
I don't know that we're moving to 17 stage on average. We're trying to figure that out.
And in Bradford County, we think that at 250- to 300-foot range, and I think we averaged last year about 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's it going to be in Susquehanna, and I know some of our competitors have a tighter spacing there. It may end up to be that way.
We just have to find that out. So I think it'll just depend on each area exactly what that is, and that's why you see a lot of us talking about per stage numbers, because each area is going to be a little different on the total number of stages.
Operator
Our next question comes from the line of Ray Deacon with Brean Capital.
Raymond J. Deacon - Brean Capital LLC, Research Division
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?
Steven L. Mueller
What we've talked about in the past, well, 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 Marcellus has grown, we don't know what you're going to get on the interruptible or day market. And so we originally, and this is almost 2 years ago now, developed a program and developed a plan where we said, "What's the maximum rate that we can have and hold it flat for 8 to 10 years?"
And that number with the assumptions we had at that point in time, assuming around 5-Bcf wells and 5 -- a little over 5 million a day on average rates, said that we're some margins 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 are today, it came to be drilling around 100 wells a year at that 3,000, 4-rig program, and that's what we started doing last year and got us to this year. We're into that framework.
If the well performance is on average or a little bit higher, we'll tack on a little bit of firm that's out there, and it'll be roughly an 800 million-day range and we'll hold that flat for that period of time. If we saw, either on the new acreage something or in the acreage we have now where there are significantly better wells on average, then certainly we'd 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, have 100 million or 150 million a day more, you'd have to commit to some new pipe, and that's 2 years out. So that goes back to your comment about when you'd accelerate the capital.
You'd accelerated the capital as you were seeing the firm in place. So that'd be a little bit farther down the road.
Raymond J. Deacon - Brean Capital LLC, Research Division
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?
Steven L. Mueller
Not necessarily.
Raymond J. Deacon - Brean Capital LLC, Research Division
Not necessarily, all right.
Steven L. Mueller
But it depends on how you're getting it 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 really, it depends on the business you're growing, how many -- how big the line is and whether it's a new line or what's your -- how you're getting the capacity. So it doesn't have to change.
Raymond J. Deacon - Brean Capital LLC, Research Division
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. I mean, are you kind of in the fifth or sixth inning there?
And what's -- what would you say about Susquehanna?
Steven L. Mueller
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 is in a pad mode.
And while we're learning and we try this well we talked about in the press release, trying to learn how to do it a little bit better, we understand the geology and how it changes what's going on there. In Bradford, in the -- I mean, in Susquehanna, in the fourth quarter, we first -- 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 you get the best well out of that. That's something beyond this year, into next year or maybe a little later than that.
Operator
Our next question comes from the line of Dan McSpirit with BMO Capital Markets.
Dan McSpirit - BMO Capital Markets U.S.
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?
Steven L. Mueller
Yes, the -- let's comment. If you look at 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, it's a little less than 200.
For those who remember, we had just over 200 at the end of the year. So we doubled the PUD count in the Fayetteville Shale, and that's where he's talking about increase in count mainly.
Obviously, the $0.20 helps a little bit on the tailwind of wells. It helps a little bit in Marcellus but it's mainly in Fayetteville.
Dan McSpirit - BMO Capital Markets U.S.
Okay. And as a follow-up, on the Marcellus, and this is more a clarification here, on the Marcellus acquisition, you stated 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?
Steven L. Mueller
I think that's total acreage I was talking about from 160,000. And certainly, 40,000 of that is going to be gone here in the next 2 years.
Operator
Our next question comes from the line of Charles Meade with Johnson Rice.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
You guys have provided a lot of good detail on the Marcellus here, but I'd like to go in a fairly different direction and ask you about 2 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 5 stages and see how that went?
Or did the -- 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?
William J. Way
No, our original plan was to complete that lateral -- or fill that lateral and complete it in 2 phases where we would do the first 5 stages, let it flow for a while, 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.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
Got it. And do you have...
William J. Way
We're encouraged by what we're seeing so far. We're just -- it's early days.
We received -- we had oil come in the first 2 days, and then we're continuing to monitor it. It's still cleaning up.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
Got it, got it. And do you have a different completion design for those -- for the next 11 stages than you did for the first 5 here?
William J. Way
We're going to finalize that once we see what happens in these first 5 stages. And so -- and we've done this before in other wells.
We will split-complete it, look and see where we are, what the performance is on the recipe [ph] that we used, and then go back, make adjustments or not depending on what we see and then do the remainder of the completion.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
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.
William J. Way
That's correct. We've done the first 6 stages, and now we are -- we've pulled back.
We're evaluating the results of that. We're evaluating the -- combining that with the results of the other wells in the area that -- where we've learned from and then -- sorry, my voice is going.
And then we will optimize that frac and then move forward again.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
Got it, got it. And when might you think that you'll have something you want to share on either of those or on both of those wells?
William J. Way
I think it's going to be later in the year. We don't -- 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're ready to move forward.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
Got it, yes. But there's definitely a trade-off there.
Operator
Our next question comes from the line of Bob Christensen with Buckingham Research. Bob Christensen, you are now live.
Okay. Well, our next question comes from the line of Biju Perincheril with Jefferies & Company.
Biju Z. Perincheril - Jefferies & Company, Inc., Research Division
I had a question, going back to the well designs in Marcellus. And so you've talked about in Bradford County sort of what do you think is the ideal length for frac stages.
But 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?
Steven L. Mueller
We're going to -- 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 the stages is, is it 250, 275 or 300?
We're not in, is it 250 or 150? So we're still fine-tuning, but we're above 200 from the stages -- the space on the stages.
Biju Z. Perincheril - Jefferies & Company, Inc., Research Division
Okay. And then can you give us some data on your sort of average 30-day rates or 60-day rates in Susquehanna versus Bradford County and Lycoming?
Steven L. Mueller
Well, in Susquehanna and Lycoming, we barely have 60-day rates, I mean, we've got some 80s maybe or something in that range. Lycoming in general is, well, we have -- we drilled a couple of wells earlier with short laterals.
But if you take a 4,500-foot lateral, most 4,500-foot lateral wells are producing 7 -- between 7 million and 8 million a day-type numbers. And in Susquehanna, at around 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 are some that are much better than that, there are 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 in the 6 million to 6.5 million or 7 million a day-type range.
Biju Z. Perincheril - Jefferies & Company, Inc., Research Division
Got it. Okay.
And then one last question. Looking at the acreage that you recently acquired, especially in Susquehanna, it looks like there's not been a lot of permitting activity on that very eastern side of Susquehanna.
And can you talk about if there are any geological reasons for that? Or is that most -- is that -- those acreage had a longer expiry?
Steven L. Mueller
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 that just went in in December is the main way 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 and when you head 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 -- take this change across the whole interval geologic as you go there. So it's basically, you need to get the Bluestone line, and so you start hooking up some wells.
Operator
Our next question comes from the line of Nick Pope with Cowen Securities.
Nicholas P. Pope - Cowen Securities LLC, Research Division
A quick question on the acquisition. The -- what is the royalty running on kind of the acreage that you acquired?
And where is that relative to where you're at on kind of the heritage Marcellus asset?
William J. Way
It's very similar to the acreage that we have. It's about an 84% NRI.
Operator
Our next question comes from the line of with Hsulin Peng with Robert W. Baird.
Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division
So just a quick clarification question. On the New Venture sponsor [ph], I think that has assumed a JV partner.
And so, if you are not going down in the -- in Brown Dense, how would you -- where would you get the additional allocation dollar from?
Steven L. Mueller
Well, I don't think we ever said exactly how much we're 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 and top the ones we drilled now. But we can move money around within the joint venture budget to do that.
So it's done requiring more budget as we go through. And we still have...
Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division
Okay. So you found the -- well go ahead.
Steven L. Mueller
Well, this has to do with whether we might be drilling some place else or what acreage we might be picking up and how fast we pick up acreage.
Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division
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?
Steven L. Mueller
Both in our -- we've drilled 2 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, it would be in that, I'd say, mid-$10 million range, $10.5 million to $10.7 million range, somewhere in that range.
Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division
Okay. Well, that's good.
And then last question. I know I've only seen comment on Paradox, but I was just thinking.
So Fidelity [ph], we know Fidelity [ph] is drilling in the area as well, and I was wondering essentially, are you thinking about similar results to what they have been doing there?
Steven L. Mueller
Well, we will be -- our objective is the King Creek [ph] interval. And King Creek [ph] interval -- the King Creek [ph] interval is in a very large section.
But we'll be going for the King Creek [ph], which I believe is the same thing they're going for. And you'll us have some activity later this summer out there.
Operator
It seems there are no further questions at this time. I'd like to turn the floor back over for closing comments.
Steven L. Mueller
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, costs, cash flow, earnings, positive economics, production, activity. We 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 a glance of that in our discussion today for the first quarter. Our economics continue to improve in the Fayetteville Shale as we drive down the costs.
Lower costs allows us to have more activity. We talked about that in the Marcellus.
And we're also like to have more activity in the Fayetteville. But what's amazing about this is Fayetteville now is producing almost 8 years, and you're only barely 1/3 to the locations that we have to drill out there.
So we have a lot more to do in the Fayetteville Shale. When we think about the Marcellus, we've got exceptional results from the wells we have.
And as I said before, production per 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, ability to do more vertical integration and actually add more production and more value.
We've mentioned, just to the last question, about our New Ventures projects. We've got 4 of them that we've 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 in the Fayetteville Shale is $200 million less than last year. 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 costs.
And one of the reasons we have less costs 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 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.
Operator
This concludes today's teleconference. You may disconnect your lines at this time, and thank you for your participation.