西南能源 (SWN) 2015 Q2 法說會逐字稿

Greetings and welcome to the Southwestern Energy Company second quarter 2015 earnings teleconference call.

(Operator Instructions)

As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Steve Mueller, Chairman and Chief Executive Officer for Southwestern Energy Company. Please go ahead.

Thank you, Operator. And good morning and thank all of you for joining us today. With me today are Bill Way, our President and Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, Executive Vice President of Exploration and Business Development; and Michael Hancock, our Director of Investor Relations. If you have not received a copy of this morning's press release regarding second quarter 2015 financial operating results you can find a copy on our web site, 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 and forward-looking statements section of our annual and quarterly filings with the Security and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

Now, let's begin. I do not plan to spend much time reviewing the quarter results, Bill and Craig can do that here in a few minutes. I'd like to briefly answer a few of the questions we received over the past few months. The first question is about cost savings in 2015 and 2016. The guidance in the press release reduced our original capital budget by $140 million while increasing our production. Not all of that is cost savings, but a big chunk is. In 2016, we'll have larger relative savings because most of our third-party agreements cover an entire year of 2016. Bill will address this in more detail.

The second questions are on capital efficiency and production growth in 2016. I have seen several outside projections for 2016 that show Southwestern with a 25% to 30% out spend of cash flow, assuming similar commodity prices to 2015. Let me assure you, and I'll state this more than once, that will not happen. We do not plan to outspend anywhere near 25% to 30%. In fact, investing only $1 billion in 2016, or 53% of the guided capital for 2015, provides a production growth of approximately 4%. Increasing capital at $1.4 billion grows Company production 7%. And every $200 million investment increment after that grows production approximately 2% incrementally.

The third question is about the quality of our recent acquisition in Southwest Appalachians. Bill will supply us on the operational details, but we are already where we had hoped to be in 2017 in the Marcellus. Well costs and days to drill to match the acquisition assumption in 2017 and well productivity is higher. In addition, because of the relatively sparse drilling in the dry gas Utica, we gave this loan very little value at the time of acquisition. The recent history drilling has given us confidence of high productivity and at least 100,000 net acres. The rapid learning of Marcellus and the derisking of Utica by the industry has allowed us to accelerate the drilling of Utica in 2015.

The fourth questions blends specific Southwestern Energy take away concerns from our new acquisition with a macro commodity prices. The first part of the question challenges whether Southwestern can find take away we need, and the second part has to do with delays and overall take away from the Appalachians. As we will be covered in more detail, we have been able to add firm transportation along with firm sales to provide a very significant production growth in West Virginia over the next few years.

The answer to the second part of the question is critical on how you might want to think about investing in our industry. Assuming NYMEX gas prices stay near current levels for an extended period of time requires several things, but the most critical is an increasing US gas supply fueled almost entirely by the Appalachian production. That role for the Appalachian production can only be accomplished if the right pipelines are built on schedule. Once built, the inefficiencies creating today's Northeast basis' issues will be eliminated and Northeast basis will narrow. If we assume the projects will not be large enough or on time, then Northeast basis issues may be stretched in the future, but the Appalachian gas will not be able to completely answer the growing US demand. In that case, NYMEX prices will need to increase to match the longer term issues in the Appalachians.

In short, the worst case is either Northeast basis narrowing or NYMEX prices increasing but not both. Southwestern Energy is well positioned in either case. As pipelines alleviate the Northeast basis, our net backs increase on projects in the best parts of the Northeast Pennsylvania dry gas, as well as the heart of Southwest Appalachian Marcellus and Utica place. Any delays in pipeline construction will have less effect on our production because we've already secured most as firm needed to sell our gas at liquid sales points along various interstate pipelines. In addition, the Fayetteville Shale becomes a natural hedge because it will supply between 40% and 50% of our total production at points that receive full benefits of any NYMEX price increases.

As I mentioned, the answer to this fourth question also points to investment choices. Do we believe the new pipelines will be constructed on time in the Northeast, or will NYMEX rise because of supply bottlenecks? In either case, Southwestern Energy is a logical gas investment when you consider operational track record and our uniqueness as a focused gas producer with three high quality assets unmatched by any other company in the industry.

Let me now turn the call over to Craig Owen so he can discuss our financial results.

Thank you, Steve, and good morning. We had another quarter of strong results, where we once again delivered on our promises by meeting or beating each of our guidance metrics. Excluding certain non-cash items, the most significant of which was a $944 million ceiling test impairment, we reported a net loss contributable to common stock of $9 million, or $0.02 per diluted share, from the second quarter compared to net income of $207 million, or $0.59 per diluted share, for the second quarter of 2014.

Mandatory convertible shares issued earlier in the year had the impact reducing our current quarter earnings by $0.07 per share due to the dividend. Our cash flow from operations, before changes in operating assets and liabilities in the second quarter, was $339 million compared to $579 million for the same period last year. We realized an average gas price of $2.23 per Mcf for the second quarter including hedges of $1.76 per Mcf excluding hedges. All of our realized prices include the impact of transportation costs.

This quarter was no different than the past, where we continued our focus on maintaining our low cost structure, which is even more essential in the challenging price environment facing the industry. Our all in cash operating costs were approximately $1.24 prim CFE in the second quarter of 2015. At June 30, 2015, our total debt was approximately $4.5 billion, down from $5.2 billion at March 31, 2015. It included a combined $676 million borrowed under the revolving credit facility and commercial paper program and providing liquidity of over $1.3 billion.

We continue our focus on returning the balance sheet toward levels similar to what they were before the Appalachia acquisitions and we have delivered on each of our deleveraging steps we committed to during the acquisition financing process and look forward to continued improvements driven by our assets and our capital discipline. I'm proud of the results we delivered this quarter and am very encouraged by the momentum we have created in the second half of 2015. I will now turn it over to Bill Way for an update of our operational results.

Thank you, Craig, and good morning everyone. The second quarter was a strong quarter for us operationally. We once again achieved record productions and progressed our understanding on key operational aspects in each of our businesses, all while maintaining our strict practice of closely watching every dollar we invest to ensure it being put to use to create long-term shareholder value. A common theme to our story over the years has been innovation and learning, and this quarter was another example of our innovative culture and focus on creating value. This innovation and learning has been a key component to, among other things, the new guidance we put out last night where we raised annual production guidance to 973 to 982 Bcf equivalent while reducing our capital investment estimates by $140 million down to $1.875 billion.

Looking ahead, our work to secure new service contracts now for our key third party provided services will yield savings in excess of $150 million in capital for 2016 as we were able to secure 18-month contracts with our suppliers. I'll now recap some of the highlights for the quarter from each of our divisions. In Southwest Appalachia, we are demonstrating some of the many reasons behind our excitement around adding this asset to our portfolio. We're running three rigs in the area with the fourth one being scheduled. We are already realizing well performance improvements and efficiencies ahead of schedule. For the second quarter, we had net production of 35 billion cubic feet of gas equivalent, and the net exit rate of Southwest Appalachia was 416 million cubic feet of gas equivalent per day, an increase of 25% over the exit rate for the first quarter.

On the drilling side, we were able to increase average lateral lengths by over 12%, while reducing average drilling time to total depth by two days, down to 17 days. Additionally, we drilled two wells with lateral lengths over 12,000 feet, one of these a Southwestern Energy record for the longest lateral ever drilled while staying in our targeted zone, 99% of the time, which ranges about 10 feet to 15 feet in this area. We also achieved a cost per foot to drill that is among the best in the region. Current aFes are now using cost estimates of $900 to $1100 per foot, depending on lateral length. The new rigs that were added to our fleet last year, which include the latest technology, are demonstrating their abilities in this new play. These wells are in various stages of completion and we look forward to sharing the results with you as they become available.

Regarding completions, we continue to improve on previous techniques used in the area. For the wells that have been completed using Southwestern's completion methods, we have seen a 35% increase in the EUR per foot for offset wells. We are also managing draw down on new wells, which is increasing condensate production by 20% over the first 180 days. This is a significant uplift to economics of the well, lifting the PVI of the well by approximately 20%. We have remained encouraged by the industry results in the dry gas Utica immediately surrounding our acreage. As a reminder, we have the offsetting acreage from ranges Scotsman Club 11H (sic -- see slide 8 "Sportsman's Club 11H") well that was brought online earlier this year with an IP of 59 million cubic feet of gas per day.

We also have acreage in multiple counties bordering Green County, Pennsylvania, where EQT announced their Scots Run well last week with an IP of 72 million cubic feet per day. Our current plan is to drill our first Southwestern operated Utica well later this year, and plan to have the well online later this year or in early 2016. We're making good progress in determining a plan for our dry gas gathering system in West Virginia, which is needed for increased drive of Marcellus and Utica development. We have completed an initial assessment and design for this project, and we will continue to advance in pace with our development plans.

The marketing group has been very busy over the last few months. First, we signed an agreement with Columbia Pipeline Group adding 500 million cubic feet per day of firm transportation capacity combined on the Mountaineer XPress and Gulf XPress pipelines. This capacity is expected to be in service in 2018. With this new agreement and the previous announced takeaway capacity, we now have 800 million cubic feet per day of takeaway capacity for this asset at a weighted average reservation charge of approximately $0.60 per Mcf. In addition to the new agreement, the marketing team has also added firm sales to its portfolio as well.

Looking forward, if we were to assume we grow our West Virginia asset production by 35% in 2016, and again in 2017, then we have already achieved our objective of covering our expected production with firm capacity and/or firm sales for both 2016 and 2017 by at least 80%. We continue to be engaged in discussions with a number of other counter parties for additional released capacity or firm sales opportunities for the longer term. The marketing team also identified opportunities to improve net back for our condensate sales which has resulted in an uplift of $2.50 per barrel from second quarter differentials beginning in August of this year. This has been accomplished through greater market understanding and by segregating our condensate by gravity to gain higher net by prices at each processing point.

Regarding NGLs, like the rest of the industry, our price realizations took a hit this quarter. We expect overall NGL prices will begin to show improvement in the fourth quarter, with additional export capacity coming online in the Gulf Coast along with higher seasonal domestic demand. In the meantime, we'll continue to optimize our link to transportation and sales portfolio. We've hit the ground running from every angle on this new asset while we have been only operating less than seven months, the improvement seen on well performance, cost reductions and the expansion of pertinent transportation portfolio at economic rates are all ahead of schedule, in many cases over a year or more and they have reconfirmed the significant returns we envisioned when we purchased this asset.

In Northeast Appalachia, the second quarter activity included a number of drilling records set by the Company. We drilled the longest lateral we have ever drilled in Northeast Pennsylvania at over 11,000 feet. We also drilled our fastest Marcellus well to date with reentry to reentry of just over four days. All in, the average time to drill in Northeast Appalachia during the second quarter was less than nine days, the lowest that number has ever been for a quarter at Southwestern.

Drilling in the Northeast Appalachia wasn't the only part of the operation with success during the quarter, the completion team also continues to impress with their results. Team has advanced our understanding of the rock in Northeast Pennsylvania, and we think we are making great strides in determining how best to complete these wells. We continue to be encouraged by our test results, surrounding stage spacing, identifying optimal landing zones and profit loading. We are consistently landing and keeping our wells in zone, plus using higher profit loading per foot, at least 2,000 pounds-per-foot versus around 1,400 pounds-per-foot in earlier years, along with increasing our stage spacing. Our typical profit per stage is now 1 million pounds.

This revised completion design reduces the stage count for wells and lowers the average profit cost per pound. As a result, our well productivity, which is the initial gas rate for PSI of drawdown, has increased 260% over our earlier wells in the play due to these modifications. After initiating these modified completions in early 2014, our 90-day cumulative production-per-well increased 42% over the 90-day fume period versus 2013, and it has continued to increase in 2014. Tight curves with this completion strategy are well above earlier type-curves and the team is now experimenting with even higher profit loading.

These frac optimizations, coupled with service cost reductions, have allowed us to reduce the investment in Northeast Appalachia by almost $100 million by retaining the same well count and improving production performance. Our current AFE's for a 5500-foot CLAT well are running $5.1 million per well versus $6.8 million during the fourth quarter of 2014, a 25% reduction. While these development results are impressive for the division, the delineation efforts in the quarter proved to be promising as well. As mentioned in last night's press release, we had encouraging results in Susquehanna County, Tioga County and Wyoming County derisking additional acreage in those counties.

The Fayetteville delivered impressive results for the second quarter where our net production was 121 billion cubic feet of gas, an increase of 6 billion cubic feet from the first quarter. There appeared to be some concern in the market about the decline in this asset back in the first quarter, but as we said then, weather impacts on the timing of wells coming online was a big contributor to that decline. This is evident with the strong production from those late first quarter wells showing up in the second quarter numbers. As we look forward to the third and fourth quarter, our expectation is for the completion count to be reduced but remain relatively constant, and Fayetteville Shale is planned to deliver a total of 7 Bcf to 10 Bcf above our original 2015 plans.

Another example of the innovation that I mentioned earlier and a big reason for the strong production results this quarter is the effort of the team to find ways to increase production levels with reduced investment amounts. Programs focused on well bore clean out, compression at pad level and managed flow back of our wells has contributed to approximately 3 Bcf of additional volume in the first six months of 2015. With the recount starting the year at seven rigs, the well count is a bit front loaded in the Fayetteville Shale for 2015 and we have brought about 60% of the wells online for the year in the first six months. Production is expected to decline a bit over the back half of the year as we complete the year running four rigs in this core asset.

In closing, we're very proud of the operational momentum that we've built until the first half of 2015. What we have been able to accomplish sets us up extremely well for the second half of the year and for 2016. The portfolio that we have assembled allows us the ability to deliver significant value even in times of low commodity prices and we remain committed to the financial discipline to support our balance sheet while delivering those results. With the new Southwest Appalachia asset just beginning to demonstrate its potential, Northeast Appalachia continuing its remarkable performance and the Fayetteville Shale still producing 3% of the nation's gas, the future is looking very strong for Southwestern Energy. We look forward to sharing more exciting updates with you on our next call.

This concludes my comments so we'll turn it back over to the Operator who will explain the procedure for asking questions.

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

(Operator Instructions)

Thank you. Our first question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Please go ahead with your questions.

Thank you, good morning, everybody. Steve, thanks for the color on the 2016 --spending/growth sensitivity. In this gas price environment, logical following question would be, if your maintenance capital, that is to hold flat, has been reasonably below a billion dollars, which I think is the implication of 4% growth, then why would you pursue growth in this environment if you can improve your debt adjusted metrics until gas prices improve? More of a strategic question, what's the incentive to grow in this gas environment? And I've got a follow up, please.

I don't know that there's an incentive to grow. Really the incentive is to invest wisely and get the return that you're looking for. As we talked about in the past, return isn't based on one quarter's pricing, it's not based on one year pricing, for our wells, it's really based on four to five years of pricing. And so a lot of it is your perception of the future.

Let me talk a little bit about perception of the future. Today we're running $3 flat for this year, and I think we'll be close to that range. Next year $3.25, then $3.75 and then we're going to $4. And $4 flat forever. That's the pricing we're justifying our wells on, and to the extent that we have wells that work within that environment, it makes sense to drill.

Now, the other thing, let me just also address, because part of that is-- why don't you delay it until prices get better. Every time we do those calculations, you have to be really bullish on prices to delay. And by that I mean, if you discount at 10%, if I delay a well one year, I have to be very certain that the price a year from now is going to be 10% higher than it is today. Every time we look at it, we haven't been that certain. We might think it may be that way, and I just told you some numbers that showed you that not quite 10% next year. We can't pound the table, so we'll take our best guess at the future, we'll drill what looks like economic and if there happens to be growth, there will be growth. And if it happens, a billion dollar capital budget is a billion dollar capital budget, if it's a $1.4 billion it's a $1.4 billion or whatever number it comes to.

I appreciate the answer, maybe just a quick follow up on that. So what will determine your, at a 42% net debt to cap right now, so what will determine your ultimate spending level next year, is that debt metrics, or living within cash flow or how would you characterize it?

You know, we've got a formula that says we're going to widely invest within our cash flow. In any given year, we try to invest as best we can within cash flow. Some years, it's a little more difficult than others, especially if you start the year at one price and you lower by the end of the year. But going back, I think where you're going is, how close are we going to be to cash flow? Figure it's within $150 million of cash flow next year with the best estimates we can do of cash flow. So I'll try to do balance but it may not quite work that way.

Thanks, my follow up which hopefully is quick, just, I'm sure is going to be a tiny question and so if I stop to wait here. But just based on the relatively limited information you got with the one well you've drilled, you operated yourselves, is it still too early to take another look at what the ultimate resource/location kind of looks like in your acquired properties? Or is that something we should wait for in future quarters? I'll leave it there, thanks.

I don't think it's so much a resource issue. You know, the resource, I think we've got a good handle of what's in the ground, and then you've got the question of what's your recovery factor is going to be within that resource. It's more how much capital you're investing. If we can get more out of these wells, you drill actually fewer wells to get the same amount out of the ground. That's the way I'm leaning more today. But going back to the initial part of your question, it's early so we'll just have to watch this for a while.

Great, thanks Steve.

Our next question is from the line of Subash Chandra with Guggenheim. Please proceed with your questions.

Hi Steve, thanks again for providing that guidance on 2016. Just some follow up there.

If I think about flexibility in that capital budget, I think about the Southwest Marcellus as being relatively fixed because of the rig of creation that you've guided towards through 2017. So that the 4% growth would be almost entirely Southwest Marcellus driven and anything above that you'd start layering in Fayetteville and Northeast Marcellus. And if that's not the case could you just help me out on picturing the regional contribution to growth?

Yes, I think that is not the case. The thing that will drive us for the next couple of years will be the Northeast Pennsylvania. And we think we can run roughly three rigs and basically get the growth we need for the Company, any kind of growth we'd have in the Company from that stand point.

I think you're correct in the sense that Fayetteville is a little bit of a swing area. And let me just give a little bit of color. I said $1 billion, grow the company 4%, and you mentioned kind of a variable piece of that. The fixed part of that is, you got to remember, on any of these cases we have, we were very conservative. We used roughly $350 million of capitalized G&A and interest, and so when you take that capitalization, now you're talking about a $1 billion dollar cases of less than $700 million that you're investing in. And that's a three rig total case.

We just assumed one was running in Southwest Virginia, one was running in Fayetteville, and one was running in Northeast, and that gave us a 4%. Obviously if you're doing $1 billion dollars, we may not do as much in Fayet, we may drop or even save it and do more in the Northeast and actually get a higher number on it. The numbers we gave you were numbers that we're very comfortable we can hit and are fully loaded numbers.

Okay great. And my follow up is -- in the Northeast Marcellus, if that's the driver, but it's also gets the lowest realizations, is your view that that is going to change in the intermediate term? Or is it that despite the serious differentials and low netbacks, you're still economic on efficiencies?

Yes, I think it's all about economics. I'll keep saying that. If we didn't think it was economic, we wouldn't do it. But I think there's also misconception about netbacks in various areas.

Really, the netbacks for our West Virginia properties and netbacks in Northeast on the gas side weren't that much different this quarter. And so the West Virginia has all the things to go with the liquids part, and how much is liquids and what you're doing with NGLs, but when you look at it year-over-year, it's similar between last year and this year for the second quarter. And when we look at comparing the first and second, they're very similar year-over-year, in the Northeast and very similar in the Southwest to the numbers we saw last year.

So as we said in the past, the debate's always been -- was 2014 the worst year or 2015 the worst year for the summer? It looks like they're going to be about equal. And then, as more pipeline gets put in place, end of this year into 2016, you should see a better 2016 and a better 2017 from there. So either place has the challenge, and in either case, we're investing to get a return, not to get growth.

That helps. Thank you.

Our next question is from the line of Scott Hanold with RBC. Please go ahead with your questions.

Thanks, good morning, guys.

Good morning Scott.

Steve, can you give a little color on some of those longer lateral wells that you drilled, the 12,000-foot laterals, and what kind of productivity did you see from those? Is that sort of the trend you want to kind of continue down the path? And you know, if you look at the data you all provided on your press release, there was one well that was on, you know, for 60 days that produced over, it looked like 9 million a day. Was that one of those longer lateral wells?

I'll let Bill address those questions.

Yes, the two 12,000-foot wells that we have drilled, we don't have on. They're in the process of being completed, so we haven't gotten any upgrade there yet. If you look at the Robert Short well that we drilled, is a 7,700-foot lateral, and our average was about 7,500. We loaded that up quite a bit with sand, at the higher level, about 2,000 pounds per stage. It is really looked like it's on track to be a 15 Bcf well, and I think it's attributed to landing zone, attributed to sand loading and attributed to how we steered that well through the -- interval that we were trying to drill at.

In the Marcellus, we have also had some fairly strong results by these long laterals. I think that the improvement overall in productivity from the wells, and I don't have it off the top of my head the number, and I can get it here in a second, the improvement over previous wells because of how we steered those, and how we've load those with sand has been pretty strong. -- We're running on top of the wells that we produced in the last 18 months or so are running on top of our historical numbers, and our historical 10 Bcf curve.

Let me just say one thing here. Those 12,000-foot laterals are on a several well pad. Those are the first two wells on that pad. So we probably won't even have those completed until towards the end of the third quarter. So we may have some information for you during the third quarter, but it just happens that it's one of those bigger pads we're on.

They should come on in Novemberish time frame.

Your acre is geometry though in general. Is it minimal to doing longer laterals or are these more exceptions?

Yes, in West Virginia, there's no pooling provisions, so it's whatever acreage you can put together. We will try to do longer laterals, but what we have built into our original acquisition and what we're still using our plans, about 7,500-foot average, there will be some of those, there will be smaller units, you just can't put the acreage together right. And it will be these ones like these 12,000s that we can get the acreage together correctly.

And I think the other piece of that is that, probably the balance of this year, the majority of the wells that we will drill will be wells that were permitted previously. And so it's about 130 days to permit wells, so we're building an inventory of those and we'll obviously shift to the longer ones as we can.

Okay understood. And as a follow up question, the Southwest Appalachian, can you remind us what your current firm capacity to produce is today? And how much are you getting on interruptible at this point in time? Just trying to figure out the progression of where you're at now versus, say, where you are into 2016.

Yes, we've got, today we've got ust under 200 million a day of firm capacity. Remember, these wells that come on, all the, you know, there's a big chunk of that that's liquid. And then we've got some additional firm sales that round that all out in total, and that number grows rather significantly through 2017 as we add on additional capacity. Today, when you get to 2016, 40% of our takeaway capacity is through firm transportation, 60% of that is through firm sales and then as we move into 2017 those reverse themselves. And so we're able to move through firm and --interruptible all the volume that we produce.

And I want to add two things to that, Scott, just so everyone understands. We said we were doing 400 million a day equivalent but actual gross production is probably about 250 million a day. So there's very little being sold in the daily markets than what we have today. The other thing I'll just add, we will have a new investor relations book out probably within the next three or four days. That book will have a schedule for West Virginia separated out and then for Northeast PA separated out, and you can see exactly what notches we have left and what that curve looks like all the way out to 2020 and beyond.

That's very helpful. Thanks, guys.

Thank you. Our next question is from the line of Neal Dingmann with SunTrust Robinson, please go ahead with your questions.

Good morning, guys, just look more on the Southwest PA plans. You've already obviously had that initial success. What's your thoughts as far as drilling location, and you obviously have the, you know, acreage clear down to Upshur down there, so if you could just maybe first of all, talk about how you plan to delineate that position?

We've got our well location number is anything going up overall, as we have continued to drill in these areas, and work through this, we've continued to add to that portfolio. Our HBP position's greater than 55% right now, and so we will do some acreage capture wells but mostly be in a place where we're building rate with the 46 wells that we plan to drill this year. The majority of our works in Brook County and Ohio County and Marshall County, between those three counties, there's 36 of the 46 wells that we'll put online. But we will continue to test and pick up and hold acreage with-- part of one of the rigs. As I said earlier, we've got two there now, we'll have the third one here before long, and a part of one of those rigs will hold any acreage that we're required to hold this year.

Let me add to that that the wells we're drilling today were designed to learn and we thought it was going to take a fairly long time to get up to speed with what the rest of the industry is doing. So we want to drill on pads that have other wells, we can compare against, those kinds of things. That has accelerated.

We'll learn the Utica and that's why we're moving the Utica forward. And then as we look into 2016, the mix of the well, we'll still drill some well to hold acreage, but the mix of the wells is not set at all yet. And originally we thought that 2015 would be Marcellus learning, 2016 would be Utica toward the end of 2016 we could make some decisions about mix and then work into 2017. That's all pulled forward, so I don't know what it's going to look like in the future, I can tell you today is based on learning and permits that we had, and then as we learn more about the overall acreage, we can talk about well counts and where exactly we're drilling and what years, and how we're doing that.

We've got a deliberate plan that's already underway to accelerate permitting across the areas to give us that flexibility where we can move around.

And remind me, what take away, again, I know in other areas you continue to build out. I know you have talked about, you know, deciding which way to do that. Again with all these wells coming on, what's your thoughts on how quickly you build to ramp that takeaway there?

--As I said in my comments, we will have for 2016 and 2017, 80% of our production, assuming that we were growing at a, say, a 35% rate. But 80% of our production covered by firm transportation or firm sales on transport that is held by those buyers. That's already done, that work is already finished. So as we ramp from 46 wells or so this year to probably a similar number next year, and then on up from there, we're designing our development program and gathering of transportation kind of in at an interim process to have both of them grow or be able to grow and that's where we choose to invest.

And was your question-- local next few years or what are we trying to grow to maximum?

Yes, I guess that was the second -- part of that, just kind of maximum, is there a sort of cap longer term -? What are you looking to grow to?

We've already got over 800 million a day signed up through-- by the time you get to 2019 or late 2018, we've got more than 800 million a day signed up. One of the things that we're trying to do is sort of get an initial surge of that 800 million to a billion a day, watch the market, make sure the pipelines get built where we want them built so we can continue to ramp. And then watch as this 10 Bcf to 15 Bcf of transportation comes online where we fully expect that the cost of transport on that will moderate from the dollarish number that it is today with 20 year commits back down to a bit of a more geographic differential representative rate. And we'll look to layer on at that point.

We intend to take our residue gas production, again, a lot of this is --liquid rich gas, our residue gas production by late 2018, mid 2019, from the 200 million a day is today up well beyond 800 million a day. And again, we have the firm longer term than that. I think as we understand the Utica better, as we understand increased potential, we'll be looking to increase that number even further on a pretty good growth rate of trajectory.

I don't think any of our plans have changed.

Right.

We talked about in the past that, ultimately, we think there's over 2 Bcf a day that we'll be taking out of this acreage. So the real question is, we go up to 1 Bcf a day, look at the landscape and then we decide if we need to commit to more, if there's other capacity out there. The ultimate number in the early 2020s is a lot higher than that 800 Bcf a day.

Are you all continuing to block up acreage? I know you have a lot of contiguous positions already. Are you limited yet at this point on how long of, you know, laterals you can drill out?

We're definitely blocking up acreage. There's -- the smaller tracks have not been picked up by anybody, and as you clean up those units, that makes a difference between the 7,500-foot and the 12,000-foot, and we'll continue doing that.

Very good. Thank you, all, great details.

Our next question is from the line of Bob Brackett with Sanford Bernstein. Please go ahead with your question.

A question on the ceiling test impairment. Was that driven by oil price, NGL price or natural gas price?

Yes. (laughter) Kind of put it in a general perspective, it was kind of an unusual impairment compared to 2012 when we had an impairment. 2012, I could tell you, it was all coming from Fayetteville Shale. This project took so many projects off the books. What actually happened here was, we look at our quarterly reserves, we look at them today versus the end of the year. The actual reserve number is very similar.

What happened was, we lost PV value in what was going on. The biggest area that we lost PV value in, that really drove most of it, was the Fayetteville Shale And so what I expect will happen going into next quarter, looking at the prices that we have so far, would probably take another write-down, and we may actually start seeing wells drop off the books. But today, we've got plenty of reserves, we just have less PV, and it was mainly Fayetteville shale.

Okay, but the fact that it's NGLs and oil means a little of a hit in Southwest--?

Yes, there was, the next biggest one was actually Southwest Appalachian, West Virginia assets. And it broke out, it was a little over 70% Fayetteville Shale, --high 20% in West Virginia and little bit in Northwest PA. And then like a reserve PV10 takeaway, we did sell those assets too, so there's a little bit of that. It's really Fayetteville Shale driven.

And on your takeaway strategy, it sounds like you're trying to balance the expectation that reversals and new pipe drops the price, but at the same time you want to control your destiny? At what point will you know how fast the asset can grow, and then will you have to commit to takeaway?

With what we see today, it looks to us, by the time you get to 2018, there's actually over built in almost every facet, whether it's the NGLs, the processing, the gas takeaway, it doesn't matter which one of those. As we get a little bit closer, we can tell if that actually is going to be overbuilt. If it's overbuilt, then you really don't care if you're a firm because they're competing for your product, whatever that product is. And so we may understand the next few months or next six months, whether it will or won't be overbuilt, but my guess is it's more decision, mid next year, to understand how that works. But if the pipelines that everyone says are going to get built today, and if the rigs stay in the same general rig count that they have today, it looks like there's a couple Bcf a day gas that can go into pipelines that you don't need to have firm for.

You'd rather take a hit on one or two years of bad differential than sign up for twenty years of bad differential.

Yes, that's exactly right.

Okay, thanks.

Our next question is from the line of Brian Singer with Goldman Sachs. Please go ahead with your question.

Thank you, good morning. If the enhanced completion and the landing zone optimization you tested in Southwest Marcellus, applicable to the rest of Southwest Pennsylvania-- Sounds like it is. And is it consistent with what you are doing already in Northeast PA and the space build simply different from what the prior operator was doing? Or are there also implications on recovery rate and well economics in those other regions?

We're sharing this knowledge across the whole Company. I mean, the work started actually in Northeast Pennsylvania in earnest, looking and trying to optimize landing zones. Then we began, once we figured that out, we began loading up with sand. They have gotten to a 2,000-pound per foot sand loading and they're going to test it a bit higher.

We moved some of those very people to West Virginia and immediately leapfrogged them the time to learn and began 2,000, to as much as 2,500, pounds of sand per foot. Same concept around figuring out where the optimum landing zone was. We had a number of wells that were already drilled that we could theoretically resteer and try to figure out what might have happened with those. The timing zone, with technology changing and these new rigs that we have, and the adaptation that rotary steerable and some other tools to help steer our wells were able to stay in zone virtually 100% of the time in a very narrow window.

That when you do all of these three things, and we haven't quite figured out which one's the largest contributor, because they all are doing that, we're seeing that the application to add to that learning is down there as well. In fact, some of our future wells will test sand loading even higher than we have done so far.

And then you can take that very learning and take it to the Fayetteville, and just over the last year we have doubled the sand concentration. We have improved steering and staying in zone as a metric and looked at landing zones and those wells also have had some benefit from that. It's a little earlier to tell in there because we have been doing some modified flowbacks and that sort of thing. Its really key for us to network and share these learnings across the area. So we think that, with the exception of liquid rich gas, which has some different characteristics potentially on --stage spacing, these techniques are transferable across our divisions.

Great thanks. And then shifting to the take away side, you highlighted in the press release the transport costs associated with the now $800 million a day of contracts to get gas out of Southwest PA are about $0.60 in MMBtu. Do you have a sense based on the markets where you would be dropping off that gas, what the local basis would be versus Henry Hub? We're trying to compare that to your guidance for transportation plus basis on a company wide basis for 2015 of $0.75 to $0.85, and where this $800 million a day would end up out a few years?

Today the combined price, doesn't matter if it's Northeast or the new acquisition, is right at $0.30 transportation. And so, in adding Rover and adding the Columbia Gas piece, the average gets up to $0.60. We can't go into much more details about those because, in the case of Columbia Gas, the confidentiality agreement says we can't do that.

But our target for a lot of what we're trying to do is to get gas back into the Mid-Atlantic. And so even with Columbia Gas, we can get some of the gas back to, all the way back to the Gulf Coast, where we will be dropping it off at various places along the way to get into those markets that are there. So I can't tell you the local market, all I can say is that, for instance, Columbia Gas has five or six major takeaway points, and we can go into almost any one of those. And then, the other pipe that we have, whether it's Northeast PA or wherever else we have it, has a similar type thing where you've got three or four or five things.

In general, we're trying to go east and south, not so much north and west, in what we're trying to do.

Thank you.

Our next question is from the line of Dave Kistler with Simmons & Company. Please go ahead with your questions.

Good morning guys.

Morning.

Real quickly, just to kind of clean up on the transport portion of things and the firm capacity and firm sales for 2015 and for 2016. Obviously covering 80% is a pretty significant uptick from what you guys had shared previously. Can you talk a little bit about the pricing related to that here in the next, call it, year and a half?

Until Columbia Gas or Rover come online, that $0.30 number we're using a day is a good number. And the first one of those come on late next year.

Okay, that's helpful. And then looking at the new guidance, obviously NGL production was significantly higher than the prior guidance, and obviously you had a pretty significant NGL beat back in Q1 as well, and Q2 here. Can you talk a little bit about what you're doing in terms of trying to reduce the volatility around the realizations there and the reduced margins that you're seeing as a result of the pressure on NGL prices?

Now, except for the little things, and Bill mentioned a couple of them in his conversation, where we're breaking NGLs in more grades and trying to sell each individual grade rather than trying to sell NGL at a blended type thing, there aren't a whole lot of options short-term. So it's really a year and a half to two years down the road, or in the case of the winners when you get a higher price for propane or whatever you're doing that direction.

So, this is just-- one of the issues that I think the whole industry is going to have here for a while until we can get better take away, and to better parts of either the industrial system or different parts of the world. Now, there are some things we're trying to do creative in the marketing side, especially with how we're dealing with ethanes and NGLs and all that Bill talked about.

One final comment on the NGLs, less [adopane]. Under our contracts today, the processor markets those for us. We do have options for taking kind and we're --looking at that, trying to better understand what we can do there. On that ethane, as Steve mentioned, we have more ethane pipeline capacity than we need to the Gulf Coast. What we're doing is actually maximizing ethane recovery and then doing some additional allocations of ethane recovery to take our recovery percentage theoretically to 100%.

And then we're buying some additional ethane or having it allocated to us that goes beyond that so we can fill up our ethane capacity, which stands at 24.5 thousand barrels a day, and take those Btus to the Gulf Coast. Today we cover the demand charges associated with that capacity and on a Btu basis that methane, on the Gulf Coast, is worth about $2.37 per MBtu at the Gulf Coast versus leading chunk of it in the gas stream up Northeast, where the differentials are challenged. And so we do a bit of cost recovery, we do a bit of upgrade of ethane and then we do a bit of third party capture. So we'll keep doing that, our ethane capacity rises through the time period and we'll watch that and go back and forth on that.

I think that just goes back to my comment. There's some little things we can do, but NGL prices are going to be challenged.

Okay, I appreciate that. And one last one, just as we look at your increase of location count in the Northeast, you also shared results from the Lepley 6H well, and the John Good 14H well. Can you talk a little bit about what those might do for increasing location count or adding locations to the development portfolio on a longer term basis?

I think in Tioga, for the Lepley well, it's probably a little early to decide just how many locations we have. We've actually got pipelines to build and actually be able to flow gas a bit longer and drill around in that area. But the well economics look solid and so we are very optimistic about those wells.

In the North Range area, or northern Susquehanna County, we have probably added 35 to 50 additional wells locations because we have been able to prove that up. And then, I think as you get into Lycoming County, with the John Good well, very encouraging. I don't have an exact well count number increase, but probably several dozen more, I would think.

Let me talk a little bit about Tioga just for a second. The Tioga block, there's actually a couple of faults that run across it. We've got just over 20,000 acres. We think that Lepley, in the one fault block, establishes about half that acreage as good. And then we'll have some other drilling later this year that will test that other fault block. It should be good, because it's between the Lefley and Lycoming, but because it's a fault block, that goes back to Bill's comment, we don't know the exact number yet. But I would say half that 20,000 acres looks pretty good right now.

Great, I appreciate those qualifications. Thanks so much, guys.

Our next question is from the line of Michael Rowe with Tudor, Pickering and Holt.

Hello, I was wondering if you could provide any context around the progress you have made securing a dry gas gathering solution for your southwest Appalachia acreage?

Yes, our original intent all along was to put together a dry gas solution with our midstream unit and they have gone through the first phase of designing that gathering system, and looking at where that gathering would be delivered into various delivery points along the transport lines that we've gotten available. We have our first pass at what that system looks like and an estimate of what it will cost. We have challenged the midstream group to continue no finalize that.

We want to have a solution nailed down by the end of the year, which is about the timing that we've been working on so far this year. Originally we had, again, talked about doing this in 2018, so we're trying to accelerate it. I think we'll be in good shape to do that.

We'll then look at third party options to see both, whether they make more or less sense, all about economics. In this case, there's also about strategy of how fast we can grow and how nimble we can be or a combination of those two, and we haven't worked through the post-structure details yet, but we will have that as part of our dialogue by the end of the year.

And let me just jump in. There's a lot of things that have moving parts to them. One of them, frankly, was the Columbia Gas system. That system goes right through the middle of our acreage. That is a potential take away. If we wouldn't have received that, we'd be on a different path today, so part of the decisions we now did get what we need on the Columbia Gas, which sends us on another course.

Now we know what we need to build and how to build it. So we just got to go talk to these third parties. We have been making progress, but other things have to fall in place before you can get to the final of what you were trying to do.

With dry gas you have multiple delivery point options which can optimize how the investment's put together, versus a wet with system.

Okay that's helpful. And lastly, given the challenged NGL pricing environment that you discussed earlier, do you feel comfortable about your flexibility on allocating capital between wet gas and dry gas drilling next year in Southwest Appalachia?

I'm not sure I feel comfortable, is the right answer, but we certainly have some options. Ideally, as Bill said earlier, you have permits everywhere, you'd like to have pipelines everywhere, and the rake and on a dime can go one spot to the other spot. We still have things we want to learn. We don't have all the pads we need built, especially on the dry gas side. We do have some dry gas take away. So we have options and, again, let's just assume we drill roughly 50 wells next year. If we drill 50 wells, and we wanted to drill 20 plus wells in dry gas, we could do that. But we couldn't do 15 dry gas.

Great, thanks very much.

Our next question is coming from the line of Drew Venker with Morgan Stanley. Please go ahead with your questions.

Good morning everyone. Really appreciated the sensitivity provided on spending for 2016. I was hoping you could give us a sense of how much that growth would be benefiting from spending in 2015. Or put another way, could you spend a similar amount to the numbers you gave in 2017 and have similar growth in 2017?

I think the general answer is the Bcfs would be similar. The growth rate wouldn't be similar because you are going off a bigger rate. So if you invested $1 billion and grew 4% in 2016, you invest the same amount in 2017, I don't know the exact number but I guess it's half that, it 2% growth, so that's the only difference. The actual Bcfs shouldn't change. The quality of wells are the same and you're drilling the same number of wells with the same amount of capital.

Okay, that's very helpful, Steve. And as far as the Utica, if you're pleased with this first test, how quickly can you redirect capital to the Utica from the Marcellus? And are there any significant impediments to really ramping up activity there in 2016. That goes back to that dry gas system. It's just gathering?

Just gathering would be your issue.

All right, thanks for the color.

Our next question is from the line of David Heikkinen of Heikkinen Energy Advisers. Please go ahead with your questions.

Good morning, and Steve that was really helpful. Can you remind us about your annual midstream CapEx in your longer term plan? I know there's some third party versus insourcing dry gas moves. But rough numbers would be helpful.

The numbers I gave you, for $1 billion and $1.4 billion, assumed that our midstream company was not building out any major systems, so as maintenance capital. And it's about $40 million.

Okay.

Perspective this year is about $80 million, so would be about half in the future.

That's helpful. And then, just thinking about your maintaining the focus on being an investment grade rated company, can you talk about, in a downsider, in your base case, how or what debt governors you have? I know you don't have a reserve base borrowing line. Just trying to think about the balance sheet, and kind of commodity price, and cash flows and what governors there are on maintaining those ratings.

This is Craig Owen. You're right, we don't have any triggers or governors in the credit facility, or anything like that, that limits us. What does limit us is, what Steve mentioned earlier, investing within cash flow or close to cash flow, and in value creating projects. So as we move forward and the plans as we exit 2015 and move into 2016 is our balance sheet will be getting better. It's on a ramp to substantial improvement. Probably not quite exactly where we were before the acquisition, but getting close by the end of 2017. So we're looking at, on a ramp of even current pricing, certainly pushing down our metrics, debt to EBITDA, whatever you may look at, but nothing that would limit us from a capacity in our facility or anything like that.

And do you think about, like a sub $3 gas, what happens on a trailing 12 month EBITDA multiple or any sort of just internal management governors beyond just what the credit agencies think about?

You kind of preface that with what was the number you wanted us to do that off of?

The sub $3. I'm using $3 and so I was just thinking about that.

If we're not in a, roughly, over the next three years, a $3.50 world, all of your metrics get worse from, whether it's a balance sheet metric or credit metric or something, and you go into hunker down capacity at the $3. So if we really believe it's $3 for an extended period of time, we wouldn't already be at that $1 billion capital budget range or less, and-- our debt metrics would start creeping up on us and there wouldn't be much we could do about that on a metrics count.

Yes, even at $8 cash or capital program, your debt may be coming down with free cash flow but your metric, because of EBITDA, like you said. Goes the wrong way.

But you guys are in a better position than peers, given the unsecured facility and your midstream system. I was just thinking about bigger picture, like for the industry, seems like there's some fundamental issues if you run something lower than your price.

Again, we're investment grade today. Two of the grade agencies were within all their parameters. One, we're only missing on one, so we're ahead of almost anyone in the industry from that standpoint. And if it was less than three for an extended period of time, we wouldn't be the ones you were having to worry about. There would be a lot of other people you were worried about in that case.

Thanks, guys, good call.

Our next question is from the line of Sameer Uplenchwar with GMP. Please go ahead with your questions.

Good morning guys, and compliments on a great quarter. Steve, I also like the new swan prism on the presentation.

Thank you.

Following up on your earlier question, you highlighted like the lower maintenance CapEx and I'm just trying to understand how much of that, I mean, operationally you're doing great, but how much of that is also lower service cost? And if commodity prices do move higher, what's the selection in that maintenance capital if service costs move higher?

You're talking about the 2016 numbers we talked about?

Yes.

What we assumed in these numbers was about $50 million of savings on the service cost side. And Bill said that we think there's about $150. Now, the point in time where you measure that from is a little tricky because you got some this year, and we are debating internally. It's not the whole $150 million when you compare 2015 versus 2016. And we just said, put $50 in, and we know it's at least $50 and go from there.

That was the assumption for leading these 2016, and that was, whatever case, the $1 billion or the $1.4 billion, just said $50 million of savings. So that's what you're risking.

Got it, okay. And then on the gas macro front, and it's not just you but everybody in Appalachia seems to be that asset continues to outperform expectations. And how does, you have discussed $3.50 gas, but how does that change the long-term view of supply/demand dynamics? And on a near term basis, you have added take away, and form sales. But what about financial hedging? How were you thinking about that on both those?

Okay. On a macro picture, let me hit that quickly. I want to go back and quickly compared 2012 to today. If you look at the first six months of 2012 pricing versus today's pricing, we were, this year, about $0.10 higher than 2012 all the way through. And that's because we have added over 3 Bcf a day of demand year-over-year between --2014 and 2015. And we have added over 4 Bcf a day of total demand of 2012 and today.

The demand picture gets steeper over the next three years. So it's not, you can't just talk about the supply and getting better wells, you have to talk about both sides. Today, the rate count is down across the entire Appalachians and so it would take a significant, I say significant, add 20 or 30 rigs in Southwest PA or Northeast, or a combination of those, relatively soon, not to have that supply and demand pulled back together and have an upward pressure on prices. The combination of those two, and you get the question of all the time, these big Utica wells, what's that going to do for the future?

Everyone's got the same gas pipeline takeaway issue. So it's more, if it's a problem ever, it's a 2018, 2019, 2020 problem, it's not a near term problem from that perspective. They certainly will drill more wells. We've all got gas take away issues there. Then as far as the heading standpoint, I think you talked about even financial hedges. -- I'll let Craig talk a little bit about what we're doing in the hedge unit, and what we're doing if he wants.

Certainly, as we move into 2016, just looking for opportunities and, historically, you have heard Steve and the Company talk about heading towards a longer term target of $3.75, $4 dollars, and looking for opportunities there. At current stir pricing, we see a lot more opportunity on the upside than downside for the macro reasons Steve indicated. But you've right, typically we do try to add in more hedges than we are. We'll look to get to 40% to 50% possibly. And remember on the midstream cash flow, that's rate based, so that's kind of a natural hedge in and of itself, $300 million or so in any given year.

Got it. Thanks for the color.

Thank you.

Our next question is from the line of Matthew Russell with Goldman Sachs. Please go ahead with your question.

Most of my questions were answered. One quick one on midstream takeaway. Understandable that you would want to avoid getting locked into too many contracts and maintain flexibility, especially with what some of your peers are facing. To what extent have the discussions with the midstream companies expanded to more dynamic contracts, maybe commodity linked pricing? And can you talk a little bit about how that's growing?

I don't think there's been any discussions about any of that to tell you the truth. At least not anything that I know about.

Yes, the only part of that that's ever happened with us is in our Northeast Appalachia area, where we have options basically that can let you lay off transport capacity if you didn't need it. But we have not exercised any of those, but otherwise it's pretty straightforward.

Got it. Thank you.

Thank you. Ladies and gentlemen, we have reached the end of our allotted time for questions. I would like to turn the floor back over to Mr. Mueller for closing comments.

Thank you. I think we've spent a long time talking about commodity prices along with our operations today. And, like everyone, I wish commodity prices were higher. But unlike everyone, I think in our discussion today you saw we're developing some very unique assets and some very unique opportunities that we think will work on almost any price environment, and we have tried to design our Company to do that, work in a low price environment.

As I said before, we're not worried about growth, we're worried about doing good investments and getting good returns. I think that whole scenario is demonstrating our second quarter results. We have already seen opportunities from new acquisition on both the development of Marcellus and the Utica. And Northeast Pennsylvania continues to get better, and we continue to add locations and the Fayetteville Shale continues to surprise to the upside. Most important, though, I think we're answering those questions that the analyst community has had, and the investment community has had, about our assets and about what we can do. And what we have shown is that, as we answer those, we continue to create unmatched value plus. It remains an exciting time for us. We thank you for joining the call today and have a great rest of the week.

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your patience.