Southwestern Energy Management Discusses Q2 2013 Results - Earnings Call Transcript

Aug. 2.13 | About: Southwestern Energy (SWN)

Southwestern Energy (NYSE:SWN)

Q2 2013 Earnings Call

August 02, 2013 10:00 am ET

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

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

David W. Kistler - Simmons & Company International, Research Division

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

David Heikkinen

Biju Z. Perincheril - Jefferies LLC, Research Division

Daniel Harris - Fitch Ratings Ltd.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Operator

Greetings, and welcome to the Southwestern Energy Second 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, President and CEO of Southwestern Energy. Thank you, Mr. Mueller. You may begin.

Steven L. Mueller

Thank you, and good morning, and thank all of you for joining us today. With me are Bill Way, our Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, 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 our second quarter 2013 results, you could find a copy of all of this on our website at swn.com.

Also I'd like to point out that many of the comments during this conference -- 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.

I'm excited to begin this call today. And for those of you who know me, the word excited isn't often used. And we just had an excellent quarter. A combination of high production and high realized gas prices, or higher realized gas prices, resulted in records for adjusted earnings, EBITDA and cash flow in the second quarter.

Our production growth of 17% was primarily fueled by the strong oil performance from our Marcellus Shale properties combined with more overall wells placed on production. As a result, we've increased our production guidance for the second time this year. Additionally, our well counts and capital investments for the year have also been increased due to our recent acquisition and planned drilling on it, as well as faster drilling times and more efficiency.

I want to stop there for a second and remind you little bit about our overall philosophy. In the Marcellus, it's obviously the best economics we have in the company. And we try, as best we could, to put as much capital in that direction. And we announced last quarter the acquisition and didn't think we could spend much capital there this year. We've worked hard and build on more and more details about what we're doing there. But of that increase, there's about $140 million total, $93 million of acquisition and the rest in some activity we can do in that acreage.

And then when we talk about the Fayetteville Shale, we've always said that we wanted to keep it within cash flow, and we've been trying to do that for the last 2 or 3 years. And frankly, they have been so efficient. Rather than drop a rig in the drilled wells we said we were going to, we're going to keep one of the rig running, and with that one rig running, be able to drill faster this year and guarantee significant growth next year. Now that's all just part of our theme that we have for delivering more. As I said, we'll keep more -- 8 rigs running in the Fayetteville all year due to the increased capital budget. The one thing I didn't mention was when we started the year, we built our capital budget in Fayetteville to basically balanced. Running the 8 rigs for the whole year and adding wells, we'll actually have $100 million of cash flow from the Fayetteville come back to our company. That's a great example of adding more for Southwestern Energy.

In the Marcellus, we've learned a lot about productivity in our wells in northern Susquehanna County. And our production ramp out of that area has been tremendous, growing from 0 to over 100 million -- 180 million a day in just 7 months. And we've just looked at the wells drilled and the acreage that they are actually developing. It's less than 5% of that northeast corner of Range Trust area. But because of the geographic extent, and we'll continue drilling farther north through the rest of the year, we already think we derisked approximately 50% of our total position in Susquehanna north area. There's more to learn, obviously, and more to come from this area and the other counties as we start exploring some of the new acreage we've purchased earlier this year. But the Marcellus has obviously given us more.

I mentioned before that we're going to have higher cash flow from Fayetteville and we're going to increase our capital budget. I've talked in several calls and talked with many of you about the fact that before we raised our capital budget, we'd have to feel better about gas price. And obviously, we feel better about gas price, too. It's always a discussion point this time of the year. And especially in the heat of the summer, there is always the debate raging about what the gas price is going to be in the future.

we believe the most of the numbers point to the fact that this gap between supply and demand is continuing to narrow. And we remain encouraged that we'll be in a $4-world long-term, and we think that could happen late this year or early next year. Now I want everyone to keep in mind, the gas prices don't drive our success. As we've proved in 2012, our business model can generate returns in a much lower gas price environment. And you can be sure we'll always be focused on disciplined learning -- disciplined investing, continued learning, keeping our costs low and delivering more value for the business.

And now I want to turn call over to Bill. He'll give you details on both our capital budget and our production, as well as some of the other great things going on. And then Craig will recap with the financial results.

William J. Way

Thank you, Steve. Good morning, everyone. The execution of our drilling and completion programs in our Marcellus and Fayetteville areas has resulted in record productions this quarter and has set the stage for very good year for Southwestern Energy in 2013.

The production performance from both areas has been truly outstanding, and I want to personally thank our Fayetteville and Pennsylvania integrated teams for a truly terrific job. Overall, our production in the second quarter grew by 17% over the last year, fueled largely by faster drilling times in the Fayetteville and strong well results and increased activity in Pennsylvania, as Steve mentioned. As a result of this success, we've increased our production guidance for the remainder of the year. And further, we have increased our capital budget, which includes our acreage acquisition in Pennsylvania, which was closed in the second quarter; address additional drilling activity due to faster drilling times and increased efficiencies; and capital for our E&P services group. As a result, our planned well counts will increase by 70 wells in the Fayetteville and approximately 15 wells in the Marcellus.

Let me begin with the Marcellus. We placed 37 wells on production this quarter compared to 21 wells in the first quarter. As a result, our gross operated production that had reached 400 million cubic feet of gas per day in mid-April further increased to 500 million cubic feet of gas per day by mid-June. Net production for the quarter was 3x greater when compared to a year ago, rising from 34 Bcf, up from 10 Bcf in the second quarter of 2012. Our Marcellus production will continue to grow in line with available gas transportation infrastructure. At this time, we currently have agreements in place to allow us to transport over 800 million cubic feet of gas per day out of the area by 2015. We are pursuing opportunities for long-term access to additional firm takeaway capacity out of the basin, and we'll keep you updated as things progress for us in that area.

In keeping with our plans for the area, we announced yesterday that we've entered into agreements with subsidiaries of DTE Pipeline Company, which provide for additional firm capacity to both Millennium and Tennessee Gas Pipelines on the Bluestone gathering system in Susquehanna County. This additional capacity further strengthens our ability to move Marcellus gas to liquid markets from the area. We also added 103 million cubic feet per day of additional firm transportation capacity on various long-haul pipes, comprised of a mixture of firm transport and short- and long-term sales.

The delineation of our Range Trust area in northern Susquehanna County continues to provide us with strong results since we first put wells on in the area in late November. 18 wells were brought on production in the area during the second quarter, helping to further delineate the acreage to the east and north. In just 7 months, gross operated production has increased from 0 in the Range area to approximately 184 million cubic feet per day as of July 1 from a total of 40 wells.

As a follow-up to our Blaine-Hoyd well in southern Bradford County that we announced last quarter, the production from this well continues to be very strong. And I'll remind you, this well had 32 stages in completion, a longer sea lat [ph] of over 6,500 feet, and after 90 days, this well was producing approximately 16 million cubic feet per day and had cumulative production of 1.5 Bcf for the second quarter. Earlier this week, the well is still producing approximately 15 million a day.

We continue to experiment with our fracture stimulations, lateral lengths, flow techniques, further optimizing our well performance and believe we're getting closer to conclusions on how to best stimulate these wells. Wells placed to sail in the first 6 months of 2013 have averaged 17 stages per well compared to 12 stages in 2012, while average lateral lengths have been approximately 4,700 feet this year compared to roughly 4,100 feet last year. Meanwhile, completed well costs have declined to $6.6 million per well in the second quarter compared to a little over $7 million per well in the first quarter.

On the midstream side, total gathered volume in the Marcellus was approximately 503 million cubic feet per day from 167 miles of gathering lines in the field as of June 30, half of which are Southwestern Energy-owned and are gathering 300 million cubic feet per day. We also added first compression to the Range area in late June, with another phase of compression scheduled to be placed in service in October. Additional compression was placed in service in Greenzweig yesterday, and first compression at Lycoming is planned to come on later this year. As more compression is installed in these wells, our wells will not have to compete as much against high line pressure and can then produce at high rates.

We have closed on the previously announced acquisition of approximately 162,000 net acres near our existing acreage position in Pennsylvania in May, and we've included $50 million in our revised capital budget for drilling, lease renewals, participation in wells operated by others, seismic and other expenses on the new acreage.

Let me shift to Fayetteville now, where we placed 126 operated wells on production in the first quarter at an average completed well cost of $2.3 million per well. Our completed well costs were up from $2.1 million in the first quarter due to longer laterals and deeper average vertical depths. This, however, marks the first quarter that our laterals have averaged over 5,000 feet since the inception of the play. We continue to drill wells across the play and the resulting economic value from our wells in the second quarter continued to be enhanced by our vertically integrated services. And further efficiencies continue to be a significant benefit in driving down our costs.

Initial production rates from the wells during the second quarter returned to trend and averaged 3.6 million cubic feet of gas per day. For wells already brought online in July, we've had an average peak initial production rates in excess of 4 million cubic feet of gas per day, with several high rate wells still climbing while cleaning up.

As Steve noted, with our current capital program of $900 million in the Fayetteville and the resulting additional well count, we project the division will now generate free cash flow of roughly $100 million this year, using prices to date and strip prices going forward.

And on the midstream side, our gas gathering business in the Fayetteville Shale continues to perform very well and at June 30, was gathering approximately 2.3 billion cubic fee of natural gas per day from 1,886 miles of gathering lines in the field.

Let me switch to new ventures and update you on our progress there. To date, in the Brown Dense, we have drilled 8 wells. We remain very encouraged after watching flattening production profiles from both our BML horizontal well and the Dean vertical well over the last several months. We've seen further encouragement in the completion of our eighth well, the Sharp vertical well. The first stage we stimulated in the Sharp wells is lowest part of the Brown Dense and it is an interval that we had not previously tested in any of our previous wells. This interval seems to be more highly fractured, and we've seen -- than we've seen in previous sections. This interval well has been testing just over a week and is continuing to increase in rate and flowing pressures, with rates over 125 barrels a day at 48-degree gravity oil, 326,000 Mcf of 1,275 Btu gas. We will likely simulate and test the remaining 3 wells, or intervals of this well in the next few weeks.

We've also seen industry activity pick up in the area, as both public and private operators have requested drilling permits, and 2 of 5 planned wells have actually been spud, with the remainder planned for later this year or early next. Overall, we remain excited about the Brown Dense, and we're going to continue to work to unlock the commerciality of this play.

In our Brown -- in our Denver-Julesburg Basin oil play in Eastern Colorado, we've begun flowback on our 15-stage Staner well on July 18, and we'll watch performance of this well over the next 90 days. In the Bakken, we have concluded our testing on our second well. We are disappointed with the results that we've seen and will move on to other opportunities in our New Ventures portfolio. In New Brunswick, we've successfully acquired 2 lines of 2D seismic and look to acquire 2 more lines of 2D this quarter. We remain on track with our goal of first drilling in late 2014.

To close, we're delivering more to our shareholders, and we believe in the future of Southwestern and we believe that future is very bright, driven not only by the produceable assets we have in hand, but also because of the potential of the early-stage New Ventures projects that we're working on. We will continue to update everyone on these over time, including some that are undisclosed for now.

In the meantime, we remain vigilant in continuing to drive the process of innovation, keeping our costs as low as possible and adding significant value for each dollar we invest. And I look forward to talking to you more about the progress of these in the future quarters.

Let me now turn it over to Craig Owen, who will discuss our financial results.

Robert Craig Owen

Thank you, Bill, and good morning. As Steve mentioned, our results in the second quarter were outstanding, driven by higher production volumes and higher gas prices. Excluding noncash items, we reported net income of approximately $190 million or $0.54 per share for the second quarter, more than doubling prior year net income of $91 million or $0.27 per share. Cash flow from operations, before changes in operating assets and liabilities, was a record $493 million. This was 16% higher than the first quarter and up 39% compared to the same time last year. Operating income for our exploration and production segment was $253 million, over 3x higher than the $82 million we recorded in the second quarter of 2012, again primarily due to the higher production and higher realized gas prices, partially offset by the higher expenses due to the increased activity.

We realized an average gas price of $3.85 per Mcf during the second quarter compared to $3.12 per Mcf in the second quarter of last year and have 169 Bcf of our remaining 2013 projected natural gas productions hedged through fixed price swaps at a weighted average price of $4.68 per MMBtu. We also have 233 Bcf of natural gas swaps in 2014 at an average price of $4.41 per MMBtu.

As for field differentials. We have projected approximately 128 Bcf of our remaining 2013 projected natural gas production from the potential widening basis differentials through hedging activities and sales arrangements at an average basis differentials to NYMEX gas prices of approximately $0.06 per Mcf. This includes approximately 50% of our expected Marcellus volumes that are protected through year end. Although both NYMEX and field prices have declined from levels seen earlier in the year, we continue to watch the gas markets closely and will look for opportunities to add to our hedged position.

One of the softer basis points that the northeast market has seen this summer is Dominion, which has the potential to impact approximately 15% of our Marcellus production through the shoulder season. One thing to remember is that when the new pipeline projects go in service this fall and winter -- and excuse me, and winter demand arrives, these differential should improve. And this is all reflected in our expectation of a $0.55 discount to NYMEX for the balance of 2013.

Our cash operating cost of approximately $1.24 per Mcfe in the second quarter continue to be very low relative to rest of the industry. Lease operating expenses for our E&P segment were $0.85 per Mcfe in the second quarter, up from $0.79 per Mcfe in the second quarter of 2012, primarily due to higher compression and gathering costs in the Marcellus Shale, partially offset by lower saltwater disposal costs in the Fayetteville Shale.

Our G&A expenses were $0.24 per Mcfe, down from $0.27 a year ago and were lower due to decreased employee-related and information system costs.

Taxes and other income taxes were $0.11 per Mcfe compared to $0.08 a year ago. Our full cost pool amortization rate in our E&P segment fell to $1.05 per Mcfe compared to $1.38 last year.

Operating income from our midstream services segment was relatively flat with last year at approximately $73 million during the quarter.

At June 30, 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 excellent shape. We currently expect our debt to total book capitalization ratio at end of 2013 to be approximately 34% to 36% at current strip prices.

With our outlook for increased natural gas production, coupled with higher gas prices being budgeted and a low-cost structure, we believe we have not only a record year ahead of us in 2013, but also the ability to create significant value 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.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So when we look at that Marcellus EUR or I guess type curve charts in the some of these recent wells that you've got roughly 18 stages on seem to be performing the 16 Bcf EUR, is pretty impressive. I mean, when you step back look at your acreage, now that you've done a little bit more drilling, how much of your acreage do you think could be that good? And if you have a general well location count that could be applicable, that will be appreciated.

Steven L. Mueller

Just kind of a general comment. Certainly, the Chesapeake acquisition, which was 162,000 acres, we don't have a whole lot of new information on that. That's one of the reasons we're trying to accelerate our capital budget. But I think it's safe to say -- we talked in the past that we were -- had 1,000 wells on the acreage we had before Chesapeake. In the Chesapeake, we had at least 300. And it's safe to say, whether it's the size of the well for the number of well count, there's probably at least 20% additional in all those categories.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. Great. And then my follow-up is in the Fayetteville. The IP rates in the second quarter were pretty solid. It looks like the 30th- and 60th-day rates were a little bit lower than some of your prior groupings of wells. Was there anything specific to that?

William J. Way

Yes, the IP rates are higher and it just represents geographic mix. We are drilling and completing wells across the play. And depending on -- and as we mentioned last time, our focus is on value. And so, with our low well cost, the opportunity to drill in some of the shallower areas and capture our 1.3 or greater PVI benefit is our objective. And so the well mix from the previous quarter and into this quarter is impacted by drilling in some of those areas. The really important piece of it is, is that in our current drilling inventory for this entire year, we are in excess of our financial metrics in terms of drilling going forward.

Steven L. Mueller

And I think Scott, a kind of easy way to think about it, it'll roll through just like the low IP did last quarter. And I think you'll see 60-day -- 30-day to 60-day up this next quarter. So it's just one of those bubbles, as far as I'm concerned, in the curve.

Operator

Our next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

One of the key debates is how the wells in the Range Trust in northeast Susquehanna County compare with some of the higher-profile wells we've seen in southern Susquehanna County. Beyond the 50% of Susquehanna overall as perspective, can you add some more granularity on how far north and northeast you've tested within -- particularly the Range area and how the well performance is varying, if at all?

Steven L. Mueller

We'll kind of a tag team this between Bill and myself. We're -- from a distance, across Range Trust, and to kind of remind everybody, we've got about 120,000 acres total in Susquehanna County, about 23,000, 24,000 in the southern corner, then the rest is up in the northeast corner of the county. And we've been concentrating on the northeast corner in the last several months. We're about just over halfway north towards the New York line drilling and some -- just a pure drilling standpoint. And from a geological, what are we finding portion of it, wells are looking similar, at least that far north. The section does spin going north. The section does get shallower, so there's a little less pressure. So I would expect that the well spacing probably won't be quite as tight as you go further north. But by the end of the year, we'll have drilled all the way up to the New York border. We can talk all about that at that point in time. And anything you want add, Bill?

William J. Way

We're getting fairly consistent performance across the 40 producing wells on average up there. The more we get on compression, the higher the IPs are coming, or the flatter the declines are. But we've got -- from the cross, really, the entire acreage all the way to the northeast, where Steve has talked about us testing, were fairly consistent. We've seen wells as high as 9.5 million a day and several in the plus 7 or plus 8 area across a broad area of this play or this part of the acreage.

Operator

Our next question comes from Doug Leggate with Bank of America.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I guess if I could try on the Marcellus as well. So Steve, how should we think about, just for modeling purposes, as your rate of rig count is now and how that's been allocated across the different areas as it relates to the type curves we should be using. Because clearly, if everything is getting done on the 17- and 18-stage fracs, one would imagine the growth rate is going to continue to move up.

Steven L. Mueller

I'm not sure I'd count rig count per se because we're getting better on how fast we're drilling the wells. We're cutting that time down. But I would think that as you look at in the future, at least near-term, this year, we've said it to be around 100 wells. Next year, it will be in that roughly same number of range, maybe a little bit more, 110 or 120, but that will be the range that you're looking at next year in what we're doing. And we obviously -- if we're getting 20% better wells and 20% more wells plus, we need to have more takeaway. And as Bill said, we're working on a takeaway, too. And as we get that takeaway, we might be able to go a little bit faster. I would assume that would be late a 2014, early 2015 at the earliest time on that, though.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

So Steve, let me be a little bit more specific. So what I'm getting at is -- the well count is very helpful. But are those wells going to be designed on the larger frac stages? In other words, should we be looking at a bigger type curve? Or how should we be thinking about that?

William J. Way

We've been studying the spacing on these frac stages across the piece. And we really believe that in Greenzweig and Range areas, so Bradford, Susquehanna County, we're -- we look like we're closing in on about 240-foot stage spacing. In Lycoming, it's a bit further and we still have some work to do. So we are studying it in this -- really, in this broad range of 200 to 300 across Greenzweig and Range. I think we've landed about where we are. We ought to have, by the end of year, sufficient wells drilled in the Lycoming area to better hone in on an exact space. We think some of the numbers that we've heard out in the industry of 600 plus are a bit too far apart. So we're honing in on that sort of 500 area. A lot of our drilling this year forward is in Susquehanna and Bradford, in addition to the drilling that we talked briefly about on the acreage we purchased. But we do have wells planned in all of the areas for the remainder of the year.

Steven L. Mueller

And I think, to put a little more color on that, that it varies.

Steven L. Mueller

And I think to put a little more color on that, it varies. Lycoming, the Susquehanna that we drilled to date and Bradford, you're probably around the 5,000-foot lateral on average. It's going to be a little bit longer in Lycoming. And that 16 to 18 stages is probably where you're at. We hesitate a little bit. We know going south that the geology gets a little more complex. And we just don't know what we can average for lateral lengths down there. And there'll always be a spot where there'll have a 3,000-foot lateral and you have lesser stages because of the lateral. But just going back to yours, which curves to look at, that 16 to 18 stages is what you want to look at.

Operator

Our next question comes from David Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Looking at the Marcellus a little bit as well, most recent wells 600-foot kind of increased in lateral lengths. And call it 4 additional stages, if I'm just comparing the averages you gave us on the call between full year '12 and the first half of '13, cost is down about $400,000 despite the longer laterals and more frac stages. Can you break that down for us in terms of the cost benefit that's been driven by efficiency gains versus service cost declines versus maybe change in well designs, province use [ph], things like that?

Robert Craig Owen

I think, to kind of break it down in some large chunks, and I can get some detail to you very specifically, if we need to. But the -- we have frac costs, having come down significantly. Our original frac stage -- or frac contract had some supplemental fracs added to it because of increased activity. So we've -- the cost per stage of frac has dropped rather significantly. We are seeing faster drilling times as we ramp up activity and get into the more manufacturing type mode that we enjoy in the Fayetteville Shale. And so your drilling times have gone from 16, 15 days down to 11, 12 days and -- which is putting a lot of downward opportunity for us to capture on just the days to drill. That is offset by these denser frac-ed wells. And so -- and bottom line, you end up with a kind of a summary. But the large chunks are faster, more efficient drilling, lower cost per unit on fracture stimulation offset by higher density fracs.

Steven L. Mueller

And I'll just add one thing on the fracs themselves. We are doing those a little bit different. Like a lot in the industry, we're putting more sand than we did probably a year ago, putting as much as we can into it. So we continue to adjust the amount of sand. But the actual frac itself hasn't changed much other than that.

David W. Kistler - Simmons & Company International, Research Division

Okay, appreciate that. And then in CapEx increase, there was about a $50 million increase to corporate and other that you guys didn't address as you were walking through. Can you guys give us additional color on that?

Steven L. Mueller

I'll tell you what. Save that question for next quarter. We'll talk about it in detail next quarter. It basically has to do with the some equipment that we want to buy, but we're in negotiations stages, so we'll just talk more about that later.

Operator

Our next question comes from Charles Meade with Johnson Rice.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

I'm curious, the incremental CapEx that you have for the acreage you acquired, is any -- is there one county in particular where that is going to be directed? I guess I'm particularly interested in if you're going to drill a well in Wyoming County in '13.

Steven L. Mueller

The one we're trying to premier first is in Wyoming County. And that would be, at the best, middle of fourth quarter, but that's where we're shooting for first.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Got it. And then going back to the Range Trust area and the graph that you guys have in your press release. I'm curious, can you talk a bit about what kind of gathering line pressure you're currently producing against and where -- what gathering pressure you'd like to see in a mature gathering system?

Steven L. Mueller

Bill addressed a little bit of that in his conversation about putting on compression. Anywhere where we don't have compression, which I would say is about 2/3 of the production we have right now, we're flowing against basically 1,100 pounds, 1,100 to 1,200 pounds. Ultimately, this field will be probably 100 pounds. But when we talk about putting on compression today, we're talking about going down to about 400 pounds.

William J. Way

It's a 2-stage compression.

Steven L. Mueller

Yes. It's 2 stages. It'll work its way down. So you'll see us talk over the next few years and getting everything down to 400 pounds. And then you'll see another group that will come back later.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

All right. That might be enough to do some kindergarten level fluid dynamics or something like that.

Operator

Our next question comes from Arun Jayaram with Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Steve, I was wondering if you could maybe give us your thoughts longer-term on basis differentials out of the Marcellus, realizing that you largely addressed this through your firm, but just wanted to get your thoughts on it. And do you think for companies who don't have firm, we could see kind of the seasonal type of market in the shoulder season, somewhat like we saw the Rockies back in the day? So I just wanted to get your thoughts on what basis could look like over time.

Steven L. Mueller

I think for the next few years at least, it's going to be very volatile. And depending on where you're at and who's putting what in what lines, you could have big swings. And we've seen it several times in the last 1.5 years. I think it continues for the next few years. Ultimately, all of our -- everything we've done says that Marcellus fills up to northeast and it has to go back to the South and Midwest. As it starts going back in the South and Midwest, it's competing with gas that's already there. And so that differential has to ultimately get more into national type differential range. So I don't know what the exact timing is, if that's 3 years out or 5 years out. But what we use for differential out to about 3 years going out is a minus $0.22 to $0.23 at NYMEX average. So I think you're going to see a lot of bouncing around, but it's heading towards that direction.

Arun Jayaram - Crédit Suisse AG, Research Division

That's helpful. And just -- as you've added some firm transportation, I just wanted to see if you could talk about the competitive dynamics, how expensive is it to the firm transportation out of the basin?

Steven L. Mueller

The firm that we announced yesterday really is not firm. It's gathering capacity to get us to the firm. And then we had just a small amount of firm we talked about in our press release, and Bill talked about. There's plenty of people who want to build pipe, and there is some projects that still are not fully subscribed. And really, while there's several companies talking about needing it, we haven't seen upward pressure on the cost to the firm at all. Just because there's a lot of people who build this, someone starts pushing some of the prices up. So I don't know that there's a reason to believe that that will go up significantly over any period of time here.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And just my final question, Steve. You talked a little bit about the Brown Dense as well as the Bakken. What is the -- your future thoughts on New Ventures from here? And could M&A come into the picture in terms of adding another area outside of the Marcellus and the Fayetteville?

Steven L. Mueller

Yes. You kind of asked a 2-part question there. I'll start with the M&A part. We actually look at various kinds of projects and we look at areas all the time. And our M&A, from our standpoint, is an extension of our exploration in that what we're looking for -- it may be an area where we've look to get into, and you can't get into the conventional leasing, but you might buy some production to get into it or somehow figure out how to start, get a seed point and grow up at seed point. So we're looking all the time. And the classic case of doing that was the acquisition we did in the Marcellus, where we could do a bolt-on in an area we want to continue to expand in.

On the exploration side, we believe strongly in the exploration component that we have. We'll continue doing exploration. And you'll have some projects that work and you'll have some projects that don't seem are going work. And we -- certainly, the Bakken, we said, is in that category. All the other ones that we're working on today, we think we can still make it work. And we'll figure out if it can or can't as we go through. And so we're excited. I think I said this several times, but we've got about 1.3 million acres, not counting New Brunswick, that we're working with or call it the normal exploration thing they expect from us. And going forward, for the next at least 3 or 4 or 5 years, expect us in that 1.3 million, 1.5 million acre range. Some will go out of the system because they're successful. Some will go out because they're not successful, and we'll keep adding to it.

Operator

Our discussion comes from David Heikkinen with Heikkinen Energy Advisors.

David Heikkinen

Just a kind of a very specific question, as most has been answered. Can -- the wells in the Marcellus per quarter bounced around a little bit as you got pads coming online. And you give us an idea of the number of wells you'll put on production in the third quarter and fourth quarter? And then does that ever get kind of load-leveled at a flat level, or is does it kind of bounce between 20 and 30?

William J. Way

Our expectation is that that will continue at about probably about 25 wells. We're going to put on 100 wells this year or maybe a couple more. You look forward to how that balances out in the sort of Bradford County area. We'll get about sub 35, 37 of those. The Range area, will get about 50 to -- 55 to 60 of those, and. Then we will schedule the remainder across the piece. And so you'll see us again not change our total more than I announced and we'll just stay on sort of this pattern. The first quarter was a little bit lower. The second quarter was a little bit higher to catch back up, and you'll see us kind of do that, be in that range.

David Heikkinen

And just a follow-up on that, is there pipeline capacity already run to Chesapeake acreage, or is that something that is in roughly $50 million of capital that you added?

William J. Way

In the Susquehanna area were we have overlap, obviously, in the interest that just joined up with ours, those -- any of that opportunity is covered by our transportation capacity. Out and about in the Tioga and some of the other areas we're evaluating, there are some existing transportation arrangements and there are some that we have yet to work through. But we're still in the evaluation stage on that. And that will be part of the timing of where exactly we drill.

Steven L. Mueller

And one of the reasons we drill in Wyoming, there is a pipeline down there that we think we can get into. And Bill mentioned Tioga. The Penn Virginia line goes right through our acreage in Tioga, and we already have some capacity on that line, and we're looking at how to get some more capacity and some more firm takeaway out of there. So those Susquehanna and Tioga and Wyoming at least have some basic infrastructure. When we start talking about the other acreage, like in Sullivan County, that's -- you are going to have to build some pipeline takeaway there. So our first wells in those areas will be more trying to figure out what's there so we could justify pipelines.

Operator

Our next question comes from Biju Perincheril with Jefferies.

Biju Z. Perincheril - Jefferies LLC, Research Division

A couple of questions. On -- so it looks like in the Bradford well -- the declines are maybe not as you had initially feared. Does that change how you're thinking about the well design in terms of lateral length and sort of the frac density?

William J. Way

It instructs us, I think, is probably the best to say that. We wanted to try to test sort of some end members of frac density, a combination of that flow methodology and frac design. That has given us one of those. We'll continue to look for opportunities. In fact, I think, we have another one planned for another, what I'll call, high-rate test or high-density, high-flow rate number of those methodologies, and we'll continue to put that into our thinking. Right now, as I said before, I think we're happy with the sort of 240-stage spacing. Although we're not final, that certainly instructs us. Lateral lengths are governed by a couple things. One, just economics and opportunities to extend them. And certainly, we're doing that. The other piece of that is unit geography. And you'll see us drill different lateral lengths in some areas, just depending on unit size.

Biju Z. Perincheril - Jefferies LLC, Research Division

Okay. And do you have an early read on what the EUR might be for that well?

William J. Way

Not really. It's -- we're still pretty early in that. And -- but we'll -- as we figure that out, we'll get back to you on it.

Steven L. Mueller

It will be a significant...

William J. Way

It will be bigger.

Steven L. Mueller

It will be significant. And I've said this in the past, we do have some 15 Bcf wells already on our books. There's one of the longer lateral in the tighter first is going to be well above that.

Daniel Harris - Fitch Ratings Ltd.

Got it. And just a question on the well cost. You've talked about well cost coming down in the Marcellus, but when I look at sort of CapEx per well with the latest guidance versus the initial guidance, it moved up a bit. Is that to see what the difference is? Is that a more of facilities cost or new areas?

William J. Way

Our -- you'll recall from -- compared to previous quarters, our average stage -- average number of fracs is moving up. So it will work into the average. And as we get more consistent around 17 stage fracs, that's where you'll see the variance in well costs primarily. We're drilling with -- under contract with our -- half are our own rigs and half of third parties, so those costs are fairly fixed and understood. Again, the incremental fracs to our sort of base frac contract in Marcellus are at a much lower level. And that number is also well-understood and agreed. So it's going to -- a lot of the will just depend entirely on sort of the mix and the lateral length and the number of stages per lateral.

Operator

Our next question comes from with Gil Yang with Discern Investments.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Could you talk about the LOE, whether or not you've decided to increase the compression gathering costs from the Marcellus. Are any of those costs due to capacity that you're paying for that you're not fully utilizing? Maybe transportation in there, or is there -- is that a trend, a cost trend that we should expect to see as Marcellus grows?

Steven L. Mueller

No. It doesn't have anything to do with capacity we're not using now. Will is saying in the Fayetteville shale there are some capacity that we are not using. But that would be under the transportation side that you'd see, and it is about $0.07 an M right now. On that LOE, the basic difference is we have an escalator clause with our gathering company. And you have -- it's a little bit of increase on the escalation this year on that portion of it. And then because of gas price, you're -- basically the compression gas that you use in flu [ph] was up a little bit also. And those are your 2 major areas.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

All right. And the rates?

Steven L. Mueller

Sorry?

William J. Way

And also included in that is the mix of gathering costs as we ramp Range further and further along that gathering in that areas have been a slightly higher cost and than in the Bradford County area. So that's a part of it.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Okay. And the second question I have is, based on the mix of wells you're drilling in the areas you're drilling in the Fayetteville, can you sort of predict where your Fayetteville well costs are going to be trending for the remainder of the year?

William J. Way

I think that you'll see the costs probably right around where they are. A couple of things of note that could -- that might tweak that a little bit. The complete -- the external -- our third-party completion contracts that we have a gas price trigger in them. And so as gas prices go up and if we saw a quarter -- and this is a look back quarter, so that's when happens, you see gas prices go up. There's an adjustment that will increase, potentially increase the cost of that. At the same time, we continue to drill faster and faster. And so -- and our own pumping company takes on more and more of the frac load. And so that's sort of an offsetting increase that could bring them back down. But we think that 2, 3 number is a pretty reasonable number going forward with all those moving parts.

Operator

Our next question comes from Robert Christensen [ph] with Canaccord.

Unknown Analyst

As you left it, I think, last quarter, you were seeking to buy firm transportation up in the Marcellus from those that had basically slowed their drilling effort. I just wondered what the markets, sort of the secondary market of FTE looks like to you guys right now.

Steven L. Mueller

One of the things we're doing at end last quarter, which we've done, is make sure that we had insurance on a line called the Constitutional line. It's supposed to be used [ph] in 2015. We want to make sure that we had firm that if that line got delayed, we didn't have to delay anything we were doing. We've done that. We've got that in shape. We also wanted to fill in some holes in 2014 and then some holes we had in 2015. Most of that is done. We still have a little bit more to do. And so part of the answer is, we look at 2014, 2015, there are small pieces you can buy from various places and fill in the holes. So when you start looking say, "I want to have a layer of 50 million or 100 million a day and I want it for 4 or 5 years," that is a really tight market. And there's a little bit, as I've mentioned, that some projects that are either on the drawing board that we'll start next year or on the tail ends where we're that doing that work that we can get a little bit from. But certainly, we're going to need some more pipe out of the area. And we're going to have to commit to some of that pipes as it goes through. We're trying to figure out who that is we commit to and do that relatively quickly so some of the lines could get built.

Unknown Analyst

My second question relates to the Sharp well. That well in the lower smack of touched down in a high-pressure area. I mean, it was 6, 7 miles away from where you had been drilling. I was questioning, is it -- we're all trying to understand the aerial extent of high pressure.

Steven L. Mueller

Yes. Let me just give you a little perspective. As you said, it was 6 or 7 miles away from where we had drilled. It's about 6 miles from our well that a private company drilled and put online earlier this year. That well is a vertical well and there's a long story behind it. Basically, it's going to be a commercial well at Brown Dense. And so we drilled halfway between our production and their production. It did have a high pressure in the well that we drilled in the Sharp well. And as we said, we frac-ed -- we're going to frac across the entire vertical interval. We frac-ed the lowest amount of that in the production rates we talked about that earned 125,000 a day. It was just in that first of 4 stages of fracs.

Operator

Our last question comes from Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

I just had a question more about the compression issues that were brought up earlier on the Fayetteville. When you look at the reserves that were, I guess, compared to the end of last year, how much of that was a result of, I guess, the impression needs there in the field?

Steven L. Mueller

I'd say 0. It's really not a compression issue. We're talking about that LOE being up a little bit. You have to run the compressors. And so if gas price goes up a little bit, that feed around the compressor -- I mean, the gas you use around the compressor goes up a little bit. So we'll always have that. Hopefully, that number goes up quite a bit because gas prices went up quite a bit.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay, perfect. And up to the Bakken, I guess, given the well result out there, sounds like you're going to, I guess, stop that program or is -- should we be looking to impair any of the acreage you have up there? Or is that -- or will you test more down the road?

Robert Craig Owen

This is Craig Owen. We'll certainly explore our options as was mentioned earlier. As a full-cost company, we don't have impairment by play. We kind of analyze that as -- in a total pool basis. And that would be continually be a part of our full cost ceiling test every quarter.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. Have you disclose the total amount of the, I guess, the spend you have on acreage up there?

Steven L. Mueller

We have not, but it's roughly $100 million.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. So just a small amount. All right.

Operator

There are no further questions in queue at this time. I would like to turn the call back over to Mr. Mueller for closing comments.

Steven L. Mueller

Thank you. I started the conversation today saying I'm excited. Hopefully, you could tell why I was excited as we went through the call and you saw our press release today.

Our strategy is to provide ongoing value to our shareholders. And we really concentrate on trying to do something that the others can't, and we think that's important to being in the business. And so we challenge ourselves every day to consistently make better decisions. We want to learn faster. We continually ask how we can develop our fields wiser than anyone else can, and then we drive innovation throughout the company. That's the real thing I'm excited about. The numbers are great, but we continue to innovate, we continue to learn, and that innovation takes several forms. The one we really look at is that incongruity, the anomaly, that small little hint that leads to things like the Fayetteville and the new Marcellus plays. And I think this quarter shows progress in all kinds of innovation. It shows progress in all of our drivers. And as a result, the new heights in many of our key metrics.

I think the shareholders deserve nothing less from us. And I'm excited that next quarter, we should be able to see more of that. This year had already provided significant upward revisions to our plans. And as we look into next quarter, I'm excited again to talk with you about how we did and added more value.

Thank you for listening today. Have a great -- and for the certainly ones in Houston, but the across the U.S., have a cool weekend.

Operator

This concludes today's teleconference. You may now disconnect your lines at this time, and have a wonderful day.

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