西南能源 (SWN) 2013 Q2 法說會逐字稿

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

(Operator Instructions)

As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Steve Mueller, President and CEO of Southwestern Energy. Thank you, Mr. Mueller. You may begin.

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

Also, I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control, and are discussed in more detail in the risk factors in the forward-looking statement section of our annual and quarterly filings of 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 am excited to begin this call today, and for those of you who know me, the word excited is not often used, and we just had an excellent quarter. The combination of high production, 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 strong well performance from our Marcellus Shale properties, combined with more overall wells placed on production. As a result, we have 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 is faster drilling times and more efficiency.

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

Then, when we talk about the Fayetteville Shale, we have always said that we wanted to keep it within cash flow, and we have been trying to do that for the last two or three years. And frankly, they have been so efficient that rather than drop a rig and drill the wells we said we were going to, we are going to keep one rig running. And with that one rig running, we'll 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 will keep eight rigs running at Fayetteville all year, due to our increased capital budget. The one thing I did not mention was, when we started the year, we built our capital budget in Fayetteville to basically balanced. Running eight rigs for the whole year and adding wells, we will actually have $100 million of cash flow from the Fayetteville come back to our Company. That is a great example of adding more for Southwestern Energy.

In the Marcellus, we have learned a lot about productivity in our wells in northern Susquehanna County, and our production ramp out of that area has tremendous, growing from zero to over 180 million a day, in just seven months. When we just look at the wells drilled and the acreage they are actually developing, it is less than 5% of that northeast corner of Range Trust area. But because of the geographic extent, and we will continue drilling farther north through the rest of the year, we already think we've derisked approximately 50% of our total position in Susquehanna north area. There is 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 have purchased this year, but the Marcellus has obviously given us more.

I have mentioned before that we are going to have higher cash flow from Fayetteville and we are going to increase our capital budget. I have talked in several of the calls and talked with many of you about the fact that before we raised our capital budget, we would 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 a debate raging about what the gas price is going to be in the future. We believe 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. You can be sure we will always be focused on disciplined learning -- disciplined investing, continued learning, keeping our costs low, and delivering more value for the business.

I, now, want to turn the call over to Bill. He will give you details on both that 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.

Thank you, Steve. Good morning, everyone. The execution of our drilling and completion programs in our Marcellus and Fayetteville areas has resulted in record production this quarter and has set the stage for a 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 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 have 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; additional drilling activity, due to faster drilling times and increased efficiencies; and capital for our E&P Services group. As 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 three-times greater, when compared to one year ago, rising from 34 Bcf, up from 10 Bcf in the second quarter 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 will keep you updated as things progress for us in that area.

In keeping with our plans for the area, we announced yesterday that we have 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 seven months, gross operated production has increased from zero, 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. I will remind you, this well had 32 stages in completion; a longer [C-lat] of over 6,500 feet; and after 90 days, this well was still 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 are getting closer to conclusions on how to best stimulate these wells.

Wells placed to sales in the first six 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 higher rates.

We have closed on the previously announced acquisition of approximately 162,000 net acres, near our existing acreage position Pennsylvania in May. And, we have 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 have 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. 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 feet 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 eight 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 have seen further encouragement in the completion of our eighth well, the Sharp vertical well. The first stage we stimulated in the Sharp well is the lowest part of Brown Dense and is an interval that we had not previously tested in any of our previous wells. This interval seems to be more highly fractured than we have seen in previous sections. This interval of the 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 of 48-degree gravity oil, 326,000 Mcf of 1,275 Btu gas. We will likely stimulate and test the remaining three wells -- intervals of this well in the next few weeks.

We have also seen industry activity pick up in the area, as both public and private operators have requested drilling permits, and two of five 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 are going to continue to work to unlock the commerciality of this play.

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

To close, we are 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 producible 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 will 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. 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.

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 non-cash 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 three-times higher than the $82 million we recorded in the second quarter of 2012. Again, primarily due to higher production and higher realized gas prices, partially offset by the higher expenses due to increased activity. We realized an average gas price of $3.85 per Mcf during second quarter, compared to $3.12 for Mcf in second quarter of last year, and have 169 Bcf of our remaining 2013 projected natural gas production hedged through fixed-price swaps at a weighted-average price of $4.68 per MMBtu. We also have 233 Bcf 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 of widening basis differentials through hedging activities and sales arrangements at an average basis differential 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 early in the year, we continue to watch the gas markets closely and will look for opportunities to add to our hedge position.

One of the softer basis points of 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 -- excuse me, and winter demand arrives, these differentials should improve. This is all reflected in our expectation of a $0.55 discount to NYMEX for the balance of 2013.

Our cash operating costs of approximately $1.24 per Mcfe in the second quarter continue to be very low relative to the 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 one year ago, and were lower due to decreased employee-related and information-system costs. Taxes other than income taxes were $0.11 per Mcfe, compared to $0.08 one 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 the 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 than 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, so now I will turn it back to the Operator, who will explain the procedure for asking questions.

Thank you. We will now be conducting a question-and-answer session.

(Operator Instructions)

Scott Hanold, RBC Capital Markets.

When we look at that Marcellus -- I guess, tight-curve charts and some of these recent wells that you have got, roughly, 18 stages on seem to be performing the 16 Bcf EUR -- it's pretty impressive. When you step back and look at your acreage, now that you have 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 comp that could be applicable, that would be appreciated.

Just 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 are trying to accelerate our capital budget. I think it is safe to say, we have talked in the past that we had 1,000 wells on the acreage we had before Chesapeake, and with we had at least 300. It's safe to say, whether the size of the well, or the number of well count, there's probably at least 20% additional on all those categories.

Okay. Great, thanks. 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?

Yes, the IP rates are higher, and it just represents geographic mix. We are drilling and completing wells across the play. And depending on, as we mentioned last time, our focus is on value, so with our low well costs, the opportunity to drill in some of the shallower areas and capture our 1.3 or greater PVI benefit is our objective.

The well mix from the previous quarter and into this quarter is impacted by drilling in some of those areas. The real 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.

And I think Scott, the easy way to think about it, it will roll through just like the low IP did last quarter, and I think you will see a 60 day -- 30 and 60 day up this next quarter. It is just one of those boggles, as far as I'm concerned, in that curve.

Okay, just wanted to check. Thanks.

Brian Singer, Goldman Sachs.

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 have 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?

We will tag team this between Bill and myself. From a distance across Range Trust -- and to remind everybody, we have got about 120,000 acres total in Susquehanna County, about 23,000, 24,000 in the southern corner, and the rest is up in the northeast corner of the county. We have been concentrating on the northeast corner the last several months. We are about -- just over halfway north towards the New York line drilling, from 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 thin going north. The section does get shallower, so there is a little less pressure. So, I would expect that the well spacing probably won't be quite as tight as you go farther north.

By the end of the year, we will have drilled all the way up to the New York border, and we can talk all about that at that point of time. Anything you want to add, Bill?

We are getting fairly consistent performance across the 40 producing wells an average up there. The more we get on compression, the higher IPs are coming, or the flatter the declines are. We have got -- from across, really, the entire acreage all the way up to the northeast, where Steve has talked about us testing, we are fairly consistent. We have 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.

Doug Leggate, Bank of America.

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

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

Steve, let me be a little 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 the bigger tight curve, or how should we be thinking about that?

We have 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 look like we're closing in on about a 240-foot stage spacing. In Lycoming, it's a bit further, and we still have some work to do. We are studying it in this, really, in this broad range of 200 to 300 across Greenzweig and Range, but think we've landed about where we are. We ought to have, by the end of the year, sufficient wells drilled in the Lycoming area to better hone in on an exact space.

We think some of the numbers that we have heard out in industry of 600-plus are a bit too far apart, so we are honing in on that 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.

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

That is what I was looking for. Thanks, Steve.

David Kistler, Simmons & Company.

Looking at the Marcellus a little bit, as well -- most recent well 600-foot increase in the lateral length, and call it, four additional stages, if I'm comparing the averages you gave us on the call between full year '12 and first half of '13, costs 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 has been driven by efficiency gains, versus service-cost declines, versus change in well designs, [prophencies], things like that?

I think to kind of break it down in some large chunks -- and I can get some details to you, very specific, if we need to. We have frac costs having come down significantly. Our original frac stage -- or frac contract has some supplemental fracs added to it because of increased activity, so 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. Your drilling times have gone from 16, 15 days, down to 11, 12 days, which is putting a lot of downward opportunity for us to capture on the days to drill. That is offset by these denser fraced wells, so bottom line you end up with a summary, but the large chunks are faster, more efficient drilling, lower cost per unit on fracture stimulation, offset by higher density fracs.

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

Okay. Appreciate that. In the CapEx increase, there was about a $50 million increase to corporate and other that you did not address as you were walking through. Can you give us additional color on that?

I will tell you what, save that question for next quarter, and we will talk about in detail next quarter. It basically has to do with some equipment that we want to buy, but we are in the negotiation stages, so we will talk more about that later.

Okay. Great. Thank you, guys.

Charles Meade, Johnson Rice.

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

The one we are trying to permit first is in Wyoming County. That would be -- at the best, middle of fourth quarter, but that is where we are shooting for first.

Got it. Thank you. Then, going back to the Range Trust area and the graph that you 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, what gathering pressure you would like to see in a mature gathering system?

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 two-thirds of the production we have right now, we are 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 are talking about going down to about 400 pounds --

They're two-stage compression --

It will work its way down. You will see us talk, over the next few years, getting everything down to 400 pounds, and then you see another group of that come back later.

Thank you for that detail. That might be enough to do some kindergarten-level fluid dynamics or something like that -- thanks for the questions.

Arun Jayaram, Credit Suisse.

Steve, I was wondering if you could give us your thoughts, longer term, on basis differentials of the Marcellus, realizing that you largely address 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 a seasonal type of market in the shoulder season, somewhat like we saw the Rockies back in the day? I just wanted to get your thoughts on what basis could look like over time?

I think for the next few years, at least, it is going to be very volatile. Depending on where you are at and who is putting what into what lines, you could have big swings. We have seen it several times in the last 1.5 years, and I think it continues for the next [few] years. Ultimately, everything we have done says that Marcellus fills up the Northeast and has to go back to the South and Midwest.

If it starts to going back to the South and Midwest, it is competing with gas that's already there, so that differential has to ultimately get more into a natural-type differential range. I don't know what the exact timing is -- is that three years out or five years out, but what we use for differential out about three years, going out, is a minus $0.22 to $0.23 the NYMEX average. I think you are going to see a lot of bouncing around, but it is heading towards that direction.

That's helpful. As you have added some firm transportation, I wanted to see if you could talk about the competitive dynamics? How expensive is it to get the firm transportation of the basin?

The firm that we announced yesterday really is not firm, it is gathering capacity to get us to the firm. And then, we had that 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 described. And really, while there's several companies talking about needing it, we haven't seen upward pressure on the cost of that firm at all, just because there's a lot of people who will build if someone starts pushing prices up. I don't know that there's a reason to believe that will go up significantly over any period of time here.

Okay. My final question, Steve, you talked a little bit about the Brown Dense, as well as the Bakken -- what are 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?

Yes, you asked a two-part question there, and I will start with the M&A part. We actively look at various kinds of projects, and we look at areas all the time. Our M&A, from our standpoint, is an extension of our exploration, in that what we are looking for -- it may be an area that we would like 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 [C-point] and grow off that C-point. So, we are looking all the time. 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 will continue doing exploration. You will have some projects that work, and then you will have some projects that don't seem they're going to work, and certainly, the Bakken, we said is in that category. All the other ones that we are working on, today, we think we can still make it work, and we will figure out if we can or can't as we go through. We are excited. I've said this several times, but we have got about 1.3 million acres, not counting New Brunswick, that we are working with, what I call the normal exploration thing to expect from us. And going forward, for the next, at least three to four, five years, expect us in that 1.3 million to 1.5 million acre range. Some will go out of the system because they are successful, some will go out because they are not successful, and we will keep adding to it.

Thanks a lot, Steve.

David Heikkinen, Heikkinen Energy Advisors.

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

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

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

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

One reasons we are drilling in Wyoming, there is a pipeline down there that we think we 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. Those, Susquehanna and Tioga and Wyoming, at least have basic infrastructure. When we start talking about the other acreage, like in Sullivan County, 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 is there, so we could justify pipelines.

Okay. Thanks, guys.

Biju Perincheril, Jefferies.

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

It instructs us, I think, is probably the best way to say that. We wanted to try to test some end members of frac density, a combination of that, flow methodology, and frac design -- that has given us one of those. We will continue to look for opportunities. In fact, I think we have another one planned for another, what I will call, high-rate test or high density, high-flow rate, number of those methodologies, and we will continue to put that into our thinking. Right now, as I said before, I think we are happy with the 240-stage spacing, although we are not final, that certainly instructs us.

Lateral lengths are governed by a couple of things. One, just economics and opportunities to extend them, and certainly, we are doing that. The other piece of that is unit geography. You will see us drill different lateral lengths in some areas just depending on unit size.

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

Not really. We are still pretty early in that, but as we figure that out, we will get back to you on it.

It will be a significant --

It will be bigger --

It will be significant. I've said this in the past, we do have some 15 Bcf wells already on our books. This one is a longer lateral and the tighter [purse] is going to be well above that.

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

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

Okay. Got it. Thanks.

Gil Yang, DISCERN Investments.

Could you talk about the LOE will not be cited -- the increase compression gathering costs in the Marcellus. Are any of those costs due to capacity that you are paying for that you are not fully utilizing -- maybe transportation in there? Or, is there -- is that a cost trend that we should expect to see as the Marcellus grows?

No, it doesn't have anything to do with capacity we are not using. I will say in the Fayetteville Shale, there is some capacity we are not using, but that would be under the transportation side that you'd see it, and it is about [$0.07 nm] right now. On that LOE, the basic difference is, we have an escalator clause with our gathering company, and you had a little bit of increase on that escalation of that portion of it. And then, because of gas price -- basically, the compression gas that you use in flu was up a little bit also. Those are your two major areas.

All right --

Also included in that is the mix of gathering cost, as we ramp Range further and further along, gathering in that area is at a slightly higher cost than the Bradford County area (multiple speakers) part of it.

Okay. 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 predict where your Fayetteville wells costs are going to be trending for the remainder of the year?

I think that you'll see the costs, probably, right around where they are. A couple of things of note that might tweak that a little bit -- the external or third-party completion contracts that we have, have a gas-price trigger in them. So, as gas prices go up, if we saw a quarter -- and this is a look-back quarter, so that's when it happens. You see gas prices go up, there is an adjustment that will increase -- potentially increase the cost of that. At the same time, we continue to drill faster and faster, and so -- our own pumping company takes on more and more of the frac load, so that is an offsetting increase that could bring them back down. But we think [$2.3 million] number is a pretty reasonable number, going forward, with all those moving parts.

Right. Great. Thank you.

Robert Christensen, Canaccord.

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 wondered what the markets -- or the secondary market of FT looks like to you right now?

One of the things we were doing at the end of last quarter, which we have done, is make sure that we had insurance on a line called the Constitution line, that's supposed to be in, in 2015. We wanted to make sure that we had firm that if that line got delayed, we didn't have to delay anything we were doing. We have 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.

So part of the answer is, when you look at 2014, 2015, there are small pieces you can buy from various places and fill in the holes. When you start looking and say -- I want to have a layer of 50 million or 100 million a day and I want it for four or five years, that is a really tight market. And, there is a little bit, as I mentioned, some projects that are either on the drawing boards that we will start next year, or on the tail ends, if we do enough work, we can get a little bit from. But certainly, we are going to need some more pipe out of the area, and we are going to have to commit to some of that pipe as it goes through. We're trying to figure out who that is we commit to, and do that relatively quickly, so some lines can get built.

My second question relates to the Sharp well -- that well, in the Lower Smack, touched down in a high-pressure area -- it was six, seven miles away from where you had been drilling -- I was questioning is it -- we are all trying to understand the aerial extent of the high pressure.

Let me give you a little perspective, as you said, it was six to seven miles away from where we had drilled. It's about six miles from a well that a private company drilled and put online earlier this year. That well is a vertical well, and there is a long story behind it -- basically, it's going to be a commercial well at Brown Dense. So, we drilled halfway between our production and their production.

We did have high pressure in the well that we drilled in the Sharp well. And as we said, we fraced -- we are going to frac across the entire vertical interval. We fraced the lowest amount of that, and the production rates -- we talked about that 125 barrels a day was just in that first of four stages of fracs.

Got it. Thank you.

Andrew Coleman, Raymond James.

I 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, impaired at the end of last year, how much of that was a result of, I guess, the compression needs there in the field?

I would say zero. It is really not a compression issue. We talked about that LOE being up a little bit. You have to run the compressors, so if gas price goes up a little bit, that fee to run the compressor -- the gas you use to run the compressor goes up a little bit. So, we will always have that. Hopefully, that number goes up quite a bit because gas price went up quite a bit.

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

This is Craig Owen. We will certainly explore our options, as was mentioned earlier. As a full-cost company, we don't have impairment by play, we analyze that on a total-pool basis. That will continue to be part of our full-cost ceiling test every quarter.

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

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

Okay, so a small amount, then. All right. Thank you, very much.

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.

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 is important to be 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 is the real thing I am 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, shows progress in all of our drivers, and has resulted in new heights in many of our key metrics. I think the shareholders deserve nothing less from us, and I am excited that, next quarter, we should even see more of that. This year has already provided significant upward revisions to our plans. As we look into next quarter, I am excited, again, to talk with you about how we have even added more value.

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

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