Jul 28, 2015
Executives
Steve Mueller - Chairman, CEO Craig Owen - SVP, CFO Bill Way - President, COO Jeff Sherrick - Executive Vice President of Exploration and Business Development Michael Hancock - Director of Investor Relations
Analysts
Doug Leggate - Bank of America/Merrill Lynch Subash Chandra - Guggenheim Scott Hannold - RBC Neal Dingmann - SunTrust Bob Brackett - Sanford Bernstein Brian Singer - Goldman Sachs Dave Kissler - Simmons & Company Michael Rowe - Tudor, Pickering Holt Drew Venker - Morgan Stanley David Heikkinen - Heikkinen Energy Advisors Sameer Uplenchwar - GMP Matthew Russell - Goldman Sachs
Operator
Greetings and welcome to the Southwestern Energy Company Second Quarter 2015 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. In the interest of time, please limit yourself to two questions.
Afterward, you may feel free to re-queue for additional questions. [Operator Instructions] As a reminder, this conference is being recorded.
It's now my pleasure to introduce your host, Steve Mueller, Chairman and Chief Executive Officer for Southwestern Energy Company. Please go ahead.
Steve Mueller
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; and Jeff Sherrick, Executive Vice President of Exploration and Business Development and Michael Hancock, our Director of Investor Relations. If you've not received a copy of this morning’s Press Release regarding the second quarter 2015 financial operating results, you could find a copy on our website at 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 the outcomes many of which are beyond our control and are discussed in more detail in the Risk Factors and the forward-looking statement sections 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 from the press release reduced our original count of 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 the entire year of 2016.
Bill will address this in more detail. The second question is around capital efficiency and production growth in 2016.
I’ve seen several outside projections for 2016 that shows Southwestern with a 25% to 30% outspend 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%.
And creating capital of $1.4 billion grows company production 70% [ph] and every $200 million investment increment after that grows production approximately 2% incrementally. The third question is about quality of our recent acquisition in Southwest Appalachian.
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 of drill match their acquisition assumption in 2017 and well productivity is higher and addition because of the relatively sparse drilling in the dry gas Utica we gave this loan very little value at the time of the acquisition, the recent history drilling has given us confidence of high productivity in at least 1000 net acres.
The rapid learning in the Marcellus and the de-risking of the Utica by the industry has allowed us to accelerate the drilling of Utica in 2015. The fourth question blends Pacific Southwest takeaways, Southwestern Energy takeaway concerns from our new acquisition with a macro commodity prices.
The first part of the question challenges whether Southwestern can find takeaway we need and the second part has to do with delays and overall take away from the Appalachians. As we will be covering more detail, we’ve 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, we require several things but the most critical is an increasing U.S.
gas supply fuelled 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 inefficiency is 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 into the future, but the Appalachian gas will not be able to completely answer the growing U.S.
demand. In that case, NYMEX prices will need to increase to match the longer term issues in the Appalachians.
In short, those cases either, Northeast basis narrowing or NYMEX prices increasing, but not low. Southwestern Energy is well positioned in either case as pipelines alleviate the Northeast basis, our net backs increase on projects that are in the best part in the Northwest, but Northeast Pennsylvania dry gas as well as the heart of Southwest Appalachian Marcellus and Utica plays.
Any delays in pipeline construction will have less effect on our production, because we’ve already secured most of the firm needed to sell our gas at liquid sales points along various interstate pipelines. In addition, the Fayetteville shale that natural becomes a natural hedge, hedge because it will supply between 40% and 50% of our total production at points they receive full benefits of any NYMEX price increases.
As I mentioned the answer to this fourth question also points to investment choices. We believe the new pipelines will be constructed on time in the Northeast or 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 focus 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.
Craig Owen
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 of shareholder to common stock of $9 million or $0.02 per diluted share for the second quarter compared to net income of $207 million or $0.59 per diluted share for the second quarter of 2014.
The mandatory convertible shares that we 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 during the second quarter including hedges and $1.76 per Mcf excluding hedges.
As a reminder, 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 and the challenging price environment facing industry.
Our all in cash operating cost were approximately $1.24 per Mcfe 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 and included a combined 676 million borrowed under revolving credit facility and commercial paper program and providing liquidity of over 1.3 billion.
We continue our focus on returning the balance sheet towards the level similar to what they were before the Appalachian acquisitions and we have delivered on each of our de-leveraging steps we committed to during the acquisition and financing process and look forward to continued improvements driven by our assets and our capital discipline. I am proud of the results we delivered this quarter and are very encouraged by the momentum we have created as we head into the second half of 2015.
I will now turn it over to Bill Way for an update for an update of our operational results.
Bill Way
Thank you, Craig, and good morning, everyone. The second quarter was a strong quarter for us operationally.
We once again achieved record production and addressed 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 in learning and this quarter was another example of our innovative culture and focus on creating value.
This innovation in learning has been a key component to among other things and new guidance we put out last night where we raised annual production guidance to 973 Bcf 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 are 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 for Southwest Appalachia was 416 million cubic feet of gas equivalent per day, an increase of 25% over the exit rate from 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 debt 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 above 10 feet to 15 feet in this area. We also achieved a cost preferred to drill that is among the best in the region.
Current AFEs [ph] are now using cost estimates of $900 to $1100 per foot depending on lateral length. The new rigs that have 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 continued to improve on previous techniques used in the area.
For the wells that have been completed using South western’s completion methods, we’ve seen a 35% increase in the EUR preferred over offset wells. We are also managing draw down on new wells which is increasing condensate production by 20% or with the first 180 days.
This is a significant uplift to economics of the well lifting the PVI of the well by approximately 20%. We remain encouraged by the industry results in the dry gas Utica immediately surrounding our acreage.
As a reminder, we have the offsetting acreage from Rangers Sportsman [ph] 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 in 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 groups have been very busy over the last few months; first, we signed an agreement with Colombia Pipeline Group adding 500 million cubic feet per day of firm transportation capacity combined on a Mountaineer Express and Gulf Express Pipelines.
This capacity is expected to be in service in 2018. With this new agreement, and the previous announced take away capacity we now have 800 million cubic feet per day of take away capacity for this asset at a weighted average reservation charge of approximately $0.60 per Mcf.
In addition to this 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 a 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 release 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 the second quarter differentials beginning in August of this year.
This has been accomplished through greater market understanding and by segregating our condensate production by gravity to gain higher netback 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 on line in the Gulf Coast along with higher seasonal domestic demand. In the meantime we will continue to optimize our liquid 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 firm transportation portfolio at economic rates are all ahead of schedule in many cases over a year or more and they have reconfirm 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’ve ever drilled in Northeast Pennsylvania at over 11,000 feet. We also drilled our fastest Marcellus well today with re-entry to re-entry of just over four days.
All in, the average time to drill in North 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 was success during the quarter.
The completion team also continues to impress with their results. The team is advanced our understanding of the rock in Northeast Pennsylvania and we think we are making great strides in determining how fast to complete these wells.
We continue to be encouraged by our test results surrounding stage phasing, identifying optimal landing zones and proppant [ph] loading. We are consistent in landing and keeping our wells in zone plus using high proppant loading per foot at least 2000 pounds per foot versus around 1400 pounds per foot in earlier years along with increasing our stage phasing.
Our typical proppant 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 per PCI 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 period versus 2013 and it has continued to increase in 2014.
High curves with this completion strategy are well above earlier type-curves and the team is now experimenting with even higher proppant 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 AFEs for 5500 foot sea lat well are running $5.1 million per well versus $6.8 million during the fourth quarter of 2014, a 25% reduction. While the 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 Lycoming County derisking additional acreage in those counties. The Fayetteville wells delivered impressive results for the second quarter where our net production was 121 billion cubic feet of gas and increase of 6 billion cubic feet from the first quarter.
There appear 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 on line 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 that remained relatively constant and the Fayetteville Shale is plan to deliver a total of 7 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.
Program is focused on well bore clean out, compression at pad level and managed flow back on our wells is contributed to approximately 3 bcf of additional volume in the first six months of 2015. With the rig count starting the year at 7 rigs the well count is a bit prop 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 running – 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 in the first half of 2015.
We’ve been able to accomplish -- while we’ve enable to accomplish to sets us up extremely well for the second half of the year and for 2016. The portfolio that we’ve assembled allows us the ability to deliver significant value even in times of low commodity prices and we’re remained 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.
Operator
Thank you. We’ll now be conducting the question and answer session.
In the interest of time please limit yourself to two questions. Afterward you may feel free to re-queue for additional question.
[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 question.
Doug Leggate
Thank you. Good morning everybody.
Steve, thanks for the color on the 2016, I guess sensitivity spending/growth sensitivity, but I guess in this gas price environment logical kind of following question would be, if your maintenance capital that is to hold flat has been reasonably below $1 billion, 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. I’m just kind of a strategic question is about, what’s the incentive to grow in this gas environment and I’ve got follow-up, please?
Steve Mueller
I don’t know that there’s an incentive grow. Really the incentive is to invest wisely and get the returns you’re looking for.
And as we talked about in the past return isn’t based on one quarter’s pricing and 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 in the future and so let me talk a little bit about perception in the future. Today we’re running $3 flat for this year and I think we’ll in close to that range.
Next year $3.25, then $3.75 and then we’re going to $4, so and then $4 flat forever. So that’s the pricing we’re just to find 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 here from now is going to be 10% higher than is today. Every time we look at it we haven’t been that certain or might think it maybe that way and I just told you some numbers that showed you not quite 10% next year.
We can’t pound on the table, so we’ll take our best guess of the future we’ll drill what looks like economic and if there happens to be growth there’ll be growth. And if it’s happen to $1 billion of capital budget, a $1 billion capital budget, if it’s 1.4, its 1.4 or whatever numbers it comes to.
Doug Leggate
I appreciate the answer, maybe just a quick follow-up on that. What well determine yield at 42% net debt to capital right now, so what will determine your ultimate spending level next year, is that debt metrics or living within cash flow, how would you characterize it?
Steve Mueller
Well, we’ve got a formula that says we’re going to widely invest within our cash flow. So 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 second I think lower by the end of the year. But going back I think where you’re going is how closer we’re going to be at cash flow.
Figures 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.
Doug Leggate
Okay. Thanks.
And my follow-up which I hopefully is quick, I’m sure [Indiscernible] questions on Southwest Appalachia, but just based on the relatively limited information you’ve got with the one well you’ve drilled, you operated yourself. Are you – is it still too early to take another look at what the ultimate resource/location kind of look likes in your acquired properties or is that something we should wait for in future quarters now.
I’ll leave it there, thanks.
Steve Mueller
I don’t think it’s so much a resource issue. 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 your recovery factors going to be within that resource? It’s more how much [Indiscernible] with the investing.
If we can get more out of these wells, you drill actually fewer wells to get the same amount out of the ground. So, that’s the way I’m leaning more today, but going back to the initial part of your question it’s early, so we just have to watch this for a while.
Doug Leggate
Okay. Thanks, Steve.
Operator
Our next question is from the line of Subash Chandra with Guggenheim. Please proceed with your questions.
Subash Chandra
Yes. Hi, Steve.
Thanks again for providing that guidance on 2016, just some follow-up there. If I think about flexibility in that capital budget, is there – should I think about the Southwest Marcellus has been relatively fixed because of the rig accretion that you’ve got it 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?
Steve Mueller
Yes. I think that is not the case.
The thing that will drive us for next couple of years anyway would 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 would have in the company from that stand point.
I think you’re correct in the sense that Fayetteville is little bit of swing area. And let me just give you a little bit of color.
I said $1 billion I mean growth of the company 4% and you mentioned kind of the variable piece of that. But fixed part of that is you got to remember on any of these case we have we were very conservative.
We use roughly $350 million of capitalized G&A in interest, and so when you take that capitalization, now you’re talking about $1 billion cases of less than $700 million that you’re investing in. And that’s a three rig total case.
We just assume one was running in Southwest Virginia. One was running in Fayetteville.
One was running in Northeast and that gave us a 4%. Obviously, if you’re doing $1 billion we may not do as much in Fayetteville and drop in Fayetteville, do more in the Northeast actually get a higher number on it.
So the numbers we gave you were numbers that we’re very comfortable we can hit and our fully loaded numbers.
Subash Chandra
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 still economic on efficiencies?
Steve Mueller
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, netbacks in the northeast on the gas side won’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 doing with NGLs, but when you look at year-over-year it similar between last year and this year for the second quarter.
And when we look at comparing the first and second they are very similar year-over-year and the Northeast and very similar in the Northwest the numbers we saw last year. So, as we said in the past, the debates always been was 2014 worst year or 2015 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 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.
Subash Chandra
That helps. Thank you.
Operator
Our next question is from the line of Scott Hannold with RBC. Please go ahead with your questions.
Scott Hannold
Thanks. Good morning, guys.
Steve Mueller
Good morning, Scott.
Scott Hannold
Steve, can you give a little color on some of those longer lateral wells that you drilled the 12000 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 if you look at the data you all provided on your press release, there was one well that was on for 60 days that produced over – it looks like 9 million a day, was that one of those longer lateral wells?
Steve Mueller
I’ll let Bill, kind of address those questions.
Bill Way
Yes. The two 2,000 foot wells that we’ve drilled, we don’t have on – they are 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 7700 foot lateral and our average is kind of – was about 7500. We loaded that up quite a bit with sand at the higher level about 2000 pound per stage.
It is really look like is on track to be a 15 Bcf well and I think its attributed to landing zone, attributed to sand loading and attributed to how steer that well through the interval that we’re trying to drill at. In the Marcellus, we have also had some fairly strong result by these long laterals and I think that the improvement overall in productivity from the wells I don’t have it, off the top of my head the number, I can get here in a second.
The improvement over previous wells because of how we steered those and how we’ve – lot of those were sand has been pretty strong. We’re really about – we’re running on top of the wells that we produced in the last 18 months or so.
We’re running on top of our historical numbers and our historical 10 Bcf curve.
Steve Mueller
And let me just say one thing here. Those 12000 foot laterals are on a several well pad.
Those were first two wells on that pad. So we probably won’t even have those completed until towards the end of third quarter.
So we may have some information for you during the third quarter, but it just happens that its one of those biggest pads are on.
Bill Way
They should come on in November each timeframe.
Scott Hannold
Okay. So your acreage geometry though on general like, is it a minimal to doing longer laterals or are these more exceptions?
Steve Mueller
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 built in to our original acquisition and we’re still using our plans about 7500 foot average.
There will be some wells will be smaller unit, you just can’t put the acreage together right, and these 12000 that we can get the acreage together correct
Bill Way
And I think the other piece of that is that probably for the balance of this year the majority of the wells that we will drill will be wells that were committed 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 one as that we can.
Scott Hannold
Okay. Understood.
And as a follow-up question, the southwest Appalachian, can you remind us what your current firm capacity to produce today and how much are you getting on interruptible at this point in time, so I just trying to figure all the progression of like where you at now versus say where you are into 2016?
Bill Way
Yes. We’ve got today we’ve got about just under 200 million a day of firm capacity.
Remember these wells that come on, there’s a big chunk of that, that’s liquids. 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 14% of our takeaway capacity is through firm transportation, 60% of that is through firm sales and then as we move into 2017, those reversed themselves.
And so we’re able to move through firm and through firm interruptible all the volume that we produced.
Steve Mueller
Let me add two there, Scott, just everyone understands. We said we are doing 400 million day equivalent, but our actual gross production is probably about 250 million day, so it’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.
You can see exactly what notches we have left and what that curve looks like all way out to 2020 and beyond.
Scott Hannold
That’s very helpful. Thanks guys.
Operator
Thank you. Our next question is from the line of Neal Dingmann with SunTrust.
Please go ahead with your questions.
Neal Dingmann
Good morning, guys. Steve, just looking more on the Southwest PA plans you’ve obviously had that initial success.
What your though as far as drilling location and you obviously have the acreage clear down to up shire down there. So if you could just maybe first of all talk about how you plan to delineate that position?
Bill Way
We’ve got our well location number is anything going up overall as we continue to drill in these areas and work through this, we’ve continue to add to that portfolio. Our HBP positions, greater than 55% right now and so we will do some acreage capture wells, but mostly be in a place where we’re building right with the 46 wells that we planned to do this year.
And the majority of our works in Brooke and Ohio County and Marshal County, between those three counties there is 36 of the 46 wells that we’ll put online, but we will continue to test and pick up and hold acreage with one of the – part of the one of the rigs. As I said earlier we’ve got two there now, we’ll have a third one here before long and part of one of those rigs will hold any acreage that we’re required to hold this year.
Steve Mueller
Let me add to 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 industry is doing. So we want to drill on pads that have other wells, we can compare against to those kind 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 wells 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, towards the end of 2016 we could make some decisions about mix and we’re into 2017, that’s all forward.
So I don’t know what is going to look like in the future. I can tell you today that’s based on learning and the permits that we had and then as we learned 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.
Bill Way
And we got to deliver a plan that is already underway to accelerate permitting across the areas to give us that flexibility where we can move around.
Scott Hannold
And remind me what takeaway again, I know in other areas you continue to build that, I know you’ve talked about deciding which way to do that, again with all these wells coming on what’s your thoughts on how closely you build to ramp that takeaway there?
Bill Way
We will have 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 similar number next year and then on up from there, we’re designing our development program and our gathering of transportation kind of an interim process to have both of them grow or be able to grow if that’s what we choice to invest.
Steve Mueller
And then with your question, local next few years or what are we trying to grow to maximum.
Scott Hannold
Yes. I guess that was the second – the second part of that just kind of maximum, is there sort of cap longer term or just kind of longer term what are you looking to grow to?
Bill Way
We’ve already got over 800 million a day signed up through once – by the time you gets in 2019 or late 2018 we’ve got more than 800 million a day signed up. One of things that we’re trying to do is sort of get to the initial surge of that 800 to 1 billion a day, watch the market, make sure the pipeline gets build where we want them build so that we can continue to ramp and then watch as this 10 to 15 Bcf of transportation comes online where we fully expect that the cost of transport on that will moderate from the dollar-ish number that it is today with 20-year back down to a bit more of the geographic differential representative rate.
And we’ll look to layer on at that point. We intend to take our residue gas production, again, this is – lot of this is liquids gas, liquid rich gas, but our residue gas production by late 2018 to 2019 from the 200 million a day or so is today well beyond 800 million a day.
And again we have 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 growth rate trajectory.
Steve Mueller
I don’t think any of our plans have changed, we talked about in the past that ultimately I think there’s over 2 Bcf a day that we will be taking out of this acreage. So the real question is we go to 1 Bcf a day, look at the landscape and then we decide if we need to commit the more, those are the capacity out there, but the ultimate number in the early 20120s is a lot higher than that 800 Bcf a day.
Scott Hannold
And I guess, are you all continuing to block up acreage, I know you have a lot contiguous positions already. Are you limited yet at this point on how long those laterals you can draw – you can drill out?
Steve Mueller
We’re definitely blocking up acreage. There's -- the smaller tracks have not been pickup by anybody and as you clean up those units that makes that there’s 20 to 7500 in the 1200 foot and we’ll continue to doing that.
Scott Hannold
Very good. Thank you all.
Great details.
Operator
Our next question is from the line of Bob Brackett with Sanford Bernstein. Please go ahead with your questions.
Bob Brackett
Question on the ceiling test impairment, was that driven by oil price, NGL price or natural gas price?
Bill Way
Yes.
Steve Mueller
Okay. I’ll put in general perspective, it was kind of unusual impairment compared to 2012, we had impairment, 2012 like I can tell you, it’s all coming Fayetteville Shale, took so many projects off the books.
What actually happens here was, when we look at our quarterly reserve, we look them today versus beginning of the year, the actual reserve numbers very similar. But what happen more as we loss PV value and what was going on the biggest area that we loss PV value in it really drove most of it was a Fayetteville Shale.
And so what I expect what will happen going into the next quarter, looking at the prices that we have so far will probably take another write down and we may actually start think some wells drop off the books. But today we’ve got plenty of reserves, we just have less PV and it was mainly Fayetteville Shale.
Bob Brackett
Okay. But the fact that it’s NGL and oil means a little of it hit in Southwest Appalachia [ph]?
Steve Mueller
Yes. There was – the next biggest one is actually Southwest Appalachia and West Virginia assets, and it broke out, it was little over 70% Fayetteville Shale, 20 some percent in the West Virginia high 20s less Virginia and little bit in Northeast PA.
And then on just a pure like a reserve PV-10 takeaway we did sale those assets too, so there’s a little of that, but it’s really Fayetteville Shale.
Bob Brackett
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, but at what point how fast the asset can grow and then will you have to commit to take away?
Bill Way
With what we see today it look to us by the time you get to 2018 there is actually over built in almost every facet, whether it’s the NGLs, processing, the gas takeaway, it didn’t matter which one of those. As we get little bit closer we can tell that actually is going to be overbuilt.
If it’s overbuilt than you really don’t care if you have firm, because they’re competing to your product whatever their product is. And so, we may understand the next few months or next six months whether we’ll won’t be able to built, but my guess is that’s more decision, mid-next year to understand how that works.
But if the pipeline as everyone says that they’re 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 of Bcf a day gas that can go into pipelines that you don’t need to have firm for.
Bob Brackett
And you’d rather take a hit on one or two years of bad differential than signed up for 20 years of bad differential?
Steve Mueller
That’s exactly right.
Bob Brackett
Okay. Thanks.
Operator
Our next question is from the line of Brian Singer with Goldman Sachs. Please go ahead your questions.
Brian Singer
Thank you. Good morning.
Bill Way
Good morning.
Steve Mueller
Good morning.
Brian Singer
If the enhanced completion in the landing zone optimization you tested in Southwest Marcellus applicable to the rest of Southwest Pennsylvania, it sounds it is, and is it consistent with what you are doing already in Northeast PA and Fayetteville simply different from what the prior operator was doing? Or there are also implications on recovery rate and well economics in those other regions?
Bill Way
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’ve figured that out we began unloading with sand.
They’ve gotten to a 2000 pound per foot sand loading and they’re going to test it a bit higher. We moved some of these people to West Virginia and immediately leapfrog, the time to learn and began 2000 to as much as 2500 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 can theoretically re-steer 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 of rotary steerable and some other tools to help steer our wells, we’re able to stay in zone in a virtually 100% of the time in a very narrow window that when you do all these three things and we haven’t quite figured out which ones the largest contributor, because they’re all – they all are doing that.
We’re seeing that the application to add to that, that learning is down there as well. In fact some of our future wells will test sand loading even higher than we’ve done so far.
And then you can take that very learning and take to the Fayetteville and just over the last year we’ve doubled the sand concentration with improved steering and staying in zone and some metric and looked at landing zones and those wells also have had some benefit from that. So little earlier to tell in there because we are doing some [Indiscernible] flow backs and that sort of thing that it’s really a key for us to network and share these learning’s across the area, so we think that with the exception of liquid rich gas which has some different characteristic potential on steering – I mean not on steering but on stage phasing, these techniques are transferable across our divisions.
Brian Singer
Great. Thanks.
And then shifting to the takeaway side, you highlighted in a press release the transport costs associated would be now 800 million a day of contracts to get gas out of Southwest PA are about $0.60 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 or trying to compare that to your guidance for transportation plus basis on a company what basis for $0.15 or $0.75 to $0.85 and where this 800 million a day would end up out a few years?
Steve Mueller
Today the combined kind of prices, doesn’t matter if it’s northeast or is it new acquisition is right at $0.30 transportation. And so – and adding Rover and adding Columbia Gas piece to average to get up to $0.60 and – but we can’t go into much more details about those because in the case Columbia Gas with that confidential [ph] agreement, so 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 the well Columbia Gas we can get some of the gas back to all of that to Gulf Coast 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 the local market.
All I can say for instance Columbia gas as 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 has a similar type plans where we have three or four, 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.
Brian Singer
Thank you.
Operator
Our next question is from the line of Dave Kissler with Simmons & Company. Please go ahead with your questions.
Dave Kissler
Good morning, guys.
Steve Mueller
Good morning.
Dave Kissler
Real quickly just to kind of clean up on the transport portion of things in the firm capacity and firm’s 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?
Steve Mueller
Until Columbia Gas or Rover come online that $0.30 number I’m using a day is a good number.
Dave Kissler
Okay.
Steve Mueller
And first one of those comes on late next year.
Dave Kissler
Okay. Got it.
Helpful. And then looking at the new guidance obviously NGL production was significantly higher than the prior guidance and 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?
Steve Mueller
Expect for little things and Bill mentioned couple of in his conversation, we’re breaking NGLs in more grades and sell each individual grade really and trying to sell NGL on a blended type thing. There aren’t a whole lot options short term, so it’s really year and a half to two years down the road or in the case of winners when you get a higher price for propane or whatever you’re doing in that direction.
So, this is just the – one issues that I think the whole industry is going to going to have here for a while until we can get better take away into better parts of the industrial system for different parts or the world. Now, there are some things we trying to do in the marketing side, especially with how we are dealing with [Indiscernible] and NGLs and I’ll let Bill talk a little bit about that.
Bill Way
Yes one final comment on the NGLs less ethane, under our contracts today, the process or markets close for us. We do have options for taking kind and we are looking at that kind to better understand what we can do there.
On Ethane as Steve mentioned, we have more ethane capacity, pipeline capacity than we need to the Gulf Coast and so what we are doing is actually maximizing ethane recovery and doing some additional allocations of ethane recovery to take our recovery percentage theoretically to 100% and then we are buying some additional ethane or having it allocated to us that goes beyond that so that we can fill up our ethane capacity which stands right now I think at about 24.500 [ph] barrels a day and take those Btus to the Gulf Coast, A we get – we cover the demand charges associated with that capacity and B, on a Btu basis that ethane on the Gulf Coast is worth about $2.37 per MBtu at the Gulf Coast versus leading a chunk of it in the gas stream up Northeast where the differentials are challenged. And so, we do a better cost recovery, we do a bit 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 from that.
Dave Kissler
Thank you. Appreciate…
Bill Way
Well that just goes back to my comment, there is some little things we can do but NGL prices are going to be challenged.
Dave Kissler
Okay, 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?
Bill Way
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 the net area.
But the well economics looks solid and so we are very optimistic about those wells. In the North range area or Northern Susquehanna County, we’ve probably added 35 to 50 additional wells locations because we’ve been able to prove that up.
And then I think as you get into Lycoming County with the John Good well and very encouraging. I don’t have an exact well count number increase but probably several dozen more I would think.
Steve Mueller
And let me talk a little bit about Tioga just for a second. The Tioga block there is actually a couple of thoughts around the process, so we’ve had just over 20,000 acres.
We think that roughly in the one fault block establishes about half that acreage is good and then we’ll have some other drilling later this year that will test that as a fault block. It should be good, because it’s between Lepley and Lycoming but because it’s a fault block that’s goes back to Bill’s comments, we don’t know the exact number yet, but let’s say half of that 20,000 acres is a pretty good range.
Dave Kissler
Great. I appreciate those clarification, thanks so much guys.
Operator
Our next question is from the line of Michael Rowe with Tudor, Pickering Holt. Please go ahead with your question.
Michael Rowe
Hi, I was wondering if you could provide any context around the progress you’ve made securing a dry gas gathering solution for your Southwest Appalachia acreage?
Steve Mueller
Yes our original and our intent 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 task at what that system looks like and an estimate what it will cost.
We have challenged the midstream group to continue to 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 in fact again talked about doing this in 2018, so we’re trying to accelerate it.
I think we’ll be in a good shape to do that. We’ll then look at third party options to see both whether they make more or less sense, it’s all about the economics in this case results or about strategy of how fast we can grow nimble we can be or a combination of those two and we just haven’t worked through the post structure details yet but we will have that as part of that dialogue by the end of the year.
Bill Way
And let me just jump in. There’s a lot of things that have moving parts to them.
One of them frankly was the Colombia gas system. That system goes right through the middle of our acreage.
That is a potential takeaway, if we wouldn’t have received that we would have been on a different path today. So part of the decisions we now did what we need on the Colombia gas would send us on another course and now we know what we need to build and how to build it and so we just got a good talk to these third parties.
So we’ve been making progress but the thing is other things have to fall in place before you can get to the final of what you were trying to do.
Steve Mueller
And the dry gas of course you have multiple delivery point options which can optimize how the investment is put together versus our wet system.
Michael Rowe
Okay, that’s helpful. And just 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?
Steve Mueller
I'm not sure feel comfortable is quite the right answer, but we certainly have some options, the ideal way as Bill said earlier you’d like to have permits everywhere, you’d like to have pipelines everywhere and that really can – on a dime go one spot to the other spot. We still have some things we want to learn, we don’t have all the pads that we need to build a special on the dry gas side.
We do have some dry gas takeaway and so we have options and again, let’s just assume we drilled roughly 50 wells next year. We drilled 50 wells and we want to drill 20 plus wells and dry gas and we could do that but we couldn’t do 50 and dry gas.
Michael Rowe
Great. Thanks very much.
Operator
Our next question is coming from the line of Drew Venker with Morgan Stanley. Please go ahead with your questions.
Drew Venker
Good morning everyone. Really appreciate the sensitivity provided on spending for 2016.
I was hoping if you would give us a sense of how much that growth of being benefitting from spending in 2015 or put it another way could you spend a similar amount to the numbers you gave in 2017 and have similar growth in 2017?
Steve Mueller
I think the general answer is the Bcfs would be similar, but your 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 have invested in the same month 70, I don’t know the exact number but I guess it’s half about 2% growth, so that’s the only difference.
The actual Bcf’s shouldn’t change, the quality of the wells are the same and you are drilling the same number of wells of [Indiscernible]
Drew Venker
Okay, that’s very helpful Steve. And as far as Utica’s if you are pleased with this first test, how quickly can you re-direct capital to the Utica from the Marcellus and are there any significant impediments to really ramping up activity there in 2016?
Steve Mueller
And that goes back to the dry gas system…
Drew Venker
It’s just gathering.
Steve Mueller
Yes just gathering would be your issue.
Drew Venker
Okay, all right. Thanks for the color.
Operator
Our next question is from the line of David Heikkinen with Heikkinen Energy Advisors. Please go ahead with your questions.
David Heikkinen
Good morning and Steve that was really helpful. Can you remind us about your annual midstream CapEx and your longer term plan; I know there is some third party versus in sourcing dry gas moves [ph] but rough numbers would be helpful.
Steve Mueller
Yes the numbers I gave you it’s $1billion and $1.4 billion assumed that our midstream company was not building out any major systems so its maintenance capital and it’s about $40 million.
David Heikkinen
Okay.
Steve Mueller
And in perspective this year is about $80 million, so it would be about half in the future.
David Heikkinen
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 downside or in your base case how or what debt governors you have.
I know you don't have a reserve base borrowing line, I mean just trying to think about the balance sheet and kind of commodity price and cash flows and kind of what governors they are on maintaining those ratings?
Craig Owen
David, this is Craig Owen. You’re right.
We don’t have any triggers or governors in the credit facility or anything like that, that lend themselves. What does limit us is what Steve mentioned earlier investing within cash flow or close to cash flow in value creating projects.
So as we move forward and kind of the plans as we exit 2015 and into 2016 is our balance sheet will be getting better and it’s on a ramp to substantial improvement probably not quite, we’re happy where we were before the acquisition but getting close by the end of 2017, so we are looking at on a ramp of even it stretched your pricing, certainly pushing down our metrics debt-to-EBITDA whatever you may look at, but nothing that would limit us from our capacity and our facility or anything like that.
David Heikkinen
And do you think about – sub $3 gas what happens on a trailing 12-month EBTIDA multiple or any sort of just internal management governors beyond just what the credit agencies think about?
Craig Owen
Yes you kind of process that with the lowest number you wanted us to do…
David Heikkinen
Yes, that’s up $3, I mean you are using $3.
Craig Owen
We’re not in a roughly say over the next three years or 350 old, all of the metrics get worse from a whether it’s a balance sheet metric or a credit metric or something. And you are going to honker down capacity in the $3.
So we are really pleased with the $3 for an extended period of time we would already be at the $1 billion capital budget or anything less and we would our debt metrics would start creeping up on us and there wouldn’t be much we could do about that on a metric standpoint.
Steve Mueller
Yes even at an $8 cash or capital program your debt may be coming down with free cash flow but your metrics in terms of [Indiscernible]
David Heikkinen
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, it seems like there is some fundamental issues if you run something lower than your…
Steve Mueller
Again, we’re investment grade today. Two of the rating agencies were within all the parameters one rolling just on one, so we’re ahead of almost anyone in the industry from that standpoint and if it was less than three from an extended period of time, we wouldn’t be the ones you were having to worry about, there will be lot other people you are worried in that case.
David Heikkinen
Okay thanks guys. Good color.
Operator
Our next question is from the line of Sameer Uplenchwar with GMP. Please go ahead with your questions.
Sameer Uplenchwar
Good morning, guys and congrats on another great quarter. Steve, I also like the new swan prism on the presentation.
Following up on the earlier question, you highlighted like the lower maintenance CapEx and I’m just trying to understand how much of that I mean operationally you are doing great, but how much of that is also lower service cost and if commodity prices do move higher, what’s the flex in that, in that maintenance capital, if service cost move higher?
Steve Mueller
Yes and you’re talking about 2016 numbers we talked about.
Sameer Uplenchwar
Yes.
Steve Mueller
What we assumed in these numbers was about $50 million of savings on the service cost side and Bill said that we think it’s about 150 now. The point in time when you measure that becomes a little tricky because you got some this year and we are debating that internally.
It’s not the whole 150 million we compare 15 versus 16 and we just said put 50 in and we know it’s at least 50 to go from there. So that was the assumption for the – 2016 and that was, whatever case $1 billion or $1.4 billion it just had $50 million of savings.
So that’s what you are risking.
Sameer Uplenchwar
Got it. 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 I mean you have discussed 350 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 from sales but what about financial hedging how are you thinking about that on both those?
Steve Mueller
Okay. On a macro picture, let me kind of hit that very quickly.
I want to go back and quickly compare 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’ve added over 3 Bcf a day of demand year-over-year between 2013 and in 2014 and 2015 and we’ve added over 4 Bcf a day of total demand between 2004 [ph] 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 rig count is down and across the entire Appalachians and so it would take a significant, I’d 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 hold back together and have an upward pressure on prices. So the combination of those two and the question all the time, the big Utica wells, what they are going to do for the future.
Everyone’s got the same gas pipeline takeaway issue, and so it’s more, if it’s a problem average [Indiscernible] it’s not a near term problem from that perspective. They certainly will drill more wells, revolve that gas take away issues there.
Then as far as the hedging standpoint, I think you talked about even financial hedges as you go through, I’ll let Craig talk a little bit – little bit more on the hedge unit and what we’re doing next month.
Craig Owen
Yes certainly Sameer, as we move into 2016 we’re just looking for opportunities, and historically you’ve heard Steve and the company talk about getting towards a longer term target of 375 [ph] and $4 and look for opportunities there. At current pricing we see a lot more opportunity on the upside and downside for the macro reason Steve indicated but you are right, typically we do try to add in more hedges than we’ll look to get the 43% [ph] possibly and you remember on the midstream cash flow that’s rate base, so that’s kind of a natural hedge and of itself bringing in a million or so in any given year.
Sameer Uplenchwar
Got it. Thanks for the color.
Craig Owen
Thank you.
Operator
Our next question is from the line of Matthew Russell with Goldman Sachs. Please go ahead with your question.
Matthew Russell
Actually most of my questions have been answered, but one quick one on midstream take away. It is understandable that you would want to avoid gain loss into too many contexts 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 length pricing and can you talk a little bit about how that’s growing?
Steve Mueller
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.
Bill Way
Yes the only part of that that has ever happened with us is in our Northeast Appalachia area but we have auctions basically that can let you lay off transport capacity if you didn’t need it, but we’ve not exercised any of those, but otherwise it’s pretty straightforward.
Matthew Russell
Got it. Thank you.
Operator
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.
Steve Mueller
Thank you. I think we spend a lot of time talking about commodity prices along with our operations today.
And like everyone wish the commodity prices were higher, but unlike everyone I think the discussions there you saw we are developing some very unique assets and I’ve got some very unique opportunities that we think we are working on the same price environment and we’ve tried to design our company to do that, working in a low price environment and as I said before we are not worried about growth, but we are worried about doing good investments and getting good returns. I think that the whole scenario is demonstrated in our second quarter results.
We’ve already seen opportunities from new acquisitions on both the development of Marcellus and 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 are answering those questions that the analyst community has had and the investment communities 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.
Operator
Thank you. This concludes the teleconference.
You may disconnect your lines at this time. We thank you for your participation.