Transcript of
Southwestern Energy Company
Second Quarter 2015 Earnings Teleconference Call
July 28, 2015
Participants
Steve Mueller – Chairman and Chief Executive Officer
Bill Way – President and Chief Operating Officer
Craig Owen – Chief Financial Officer
Analysts
Doug Leggate – BofA Merrill Lynch
Subash Chandra – Guggenheim
Neal Dingmann – SunTrust Robinson Humphrey
Bob Brackett – Sanford Bernstein
Brian Singer – Goldman Sachs
Dave Kistler – Simmons & Company
Michael Rowe – Tudor, Pickering and Holt
Drew Venker – Morgan Stanley
David Heikkinen – Heikkinen Energy Advisers
Sameer Uplenchwar – GMP
Matthew Russell – Goldman Sachs
Presentation
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. 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.
Steve Mueller – Chairman and Chief Executive Officer
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 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 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 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 show 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%. Increasing capital of $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 Appalachian. Bill will supply some of
the operational details, but we are already where we had hoped to be in 2017 in the Marcellus. Well costs and
days to drill matched 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 zone very little value at the time of the acquisition,
but recent industry drilling has given us confidence of high productivity in at least 100,000 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 specific Southwestern Energy takeaway concerns from our new acquisition with the
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 in overall takeaway 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 rate 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 into 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 that are in the best parts of the northeast Pennsylvania dry gas as well as the heart of the
Southwest Appalachian Marcellus and Utica play.
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 becomes a natural 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. Do you 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 our 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.
Craig Owen – Chief Financial Officer
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 attributable 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.
Mandatory convertible shares issued earlier in the year had the impact of 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
Page | 2
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 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. 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.
Bill Way – President and Chief Operating Officer
Thank you, Craig. Good morning, everyone. The second quarter was a strong quarter for us operationally. We
once again achieved record production 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 is
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, the 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 depth by 2 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 from 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 $1,100 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 continued to improve on previous techniques used in the area. For the wells that
have been completed using Southwestern’s completion methods, we’ve seen a 35% increase in the EUR per foot
over offset wells. We are also managing drawdown 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 remain encouraged by the industry results in the dry gas Utica immediately surrounding our acreage. As a
reminder, we have the offsetting acreage from Range’s 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 Scotts 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
Page | 3
gathering system in West Virginia which is needed for increased dry 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 Colombia
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 previously 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
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 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 counterparties 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 production by gravity to
gain higher net back 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 will 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 firm
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 re-entry to re-entry 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. The 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 proppant loading. We are consistently landing and keeping our wells in zone plus using higher proppant
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 proppant per stage is now 1 million pounds. This revised completion
design reduces the stage count for wells and lowers the average proppant 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 2015. Type 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 AFE's for a 5,500-foot CLAT well are running $5.1 million per well versus $6.8 million
during the fourth quarter of 2014, a 25% reduction.
Page | 4
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 the
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 rig count 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 in 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.
Operator
Our first question comes from the line of Doug Leggate with Bank of America Merrill Lynch.
<Q>: Steve, thanks for the color on the 2016 spending/growth sensitivity. In this gas price environment, logical
follow on 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 is about what's the
incentive to grow in this gas environment? And I've got a follow up, please.
Steve Mueller – Chairman and Chief Executive Officer
I don't know 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 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's your perception of
the future. So, 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 in close to that range, next year $3.25, then $3.75
and then we're going to $4 and then $4 flat forever. So, 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 well why don't you just 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.
While we might think it may be that way, and I just told you some numbers that showed you at 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
Page | 5
if there happens to be growth, there will be growth. And if it happens with a billion dollar capital budget, it's a
billion dollar capital budget. If it's $1.4 billion, it's $1.4 billion or whatever number it comes to.
<Q>: I appreciate the answer. Maybe just a quick follow up on that, Steve. So, what will determine— you're at
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?
Steve Mueller – Chairman and Chief Executive Officer
We've got a formula that says we're going to wisely 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 it's 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.
<Q>: My follow up which hopefully is quick, just I'm sure there's going to be a ton of questions on Southwest
Appalachia, but just based on the relatively limited information you have with the one well you've drilled and
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?
Steve Mueller – Chairman and Chief Executive Officer
I don't think it's so much a resource issue. The resource, I think we have a good handle of what's in the ground,
and then you have 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.
Operator
Our next question is from the line of Subash Chandra with Guggenheim.
<Q>: Just some follow up there— if I think about flexibility in that capital budget, if I think about the Southwest
Marcellus as being relatively fixed because of the rig count 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?
Steve Mueller – Chairman and Chief Executive Officer
Yes, I think that is not the case. The thing that will drive us for the next couple of years anyway 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 standpoint.
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, we can grow the company 4% and you mentioned kind of a variable piece of that. The
fixed part of that is you have to remember on any of these cases we have, we were very conservative. We used
roughly $350 million of capitalized G&A and interest. 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 Appalachia, one was running in Fayetteville, and 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. We may drop or even save it and do
more in the Northeast and actually get a higher number on it. So, the numbers we gave you were numbers that
we're very comfortable we can hit and are fully loaded numbers.
<Q>: My follow up is in the Northeast Marcellus, if that's the driver but it 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?
Steve Mueller – Chairman and Chief Executive Officer
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. So, the West
Page | 6
Virginia has all the things to go with the liquids part, 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.
Operator
Our next question is from the line of Scott Hanold with RBC.
<Q>: 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 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 – Chairman and Chief Executive Officer
I'll let Bill address those questions.
Bill Way – President and Chief Operating Officer
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 update 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 looking 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 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 loaded those with
sand has been pretty strong. 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.
Steve Mueller – Chairman and Chief Executive Officer
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 at the end of the third quarter, but it just happens that it's one of those
bigger pads we're on.
Bill Way – President and Chief Operating Officer
They should come on in November-ish time frame.
<Q>: Your acreage geometry though in general, is it amenable to doing longer laterals or are these more
exceptions?
Steve Mueller – Chairman and Chief Executive Officer
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 in 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 some will be these ones like these 12,000s that we can get the acreage together correctly.
Bill Way – President and Chief Operating Officer
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.
Page | 7
<Q>: 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.
Bill Way – President and Chief Operating Officer
Yes, we've got, today we have 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 have 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. 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.
Steve Mueller – Chairman, CEO
Let me add two things to that, Scott, just so everyone understands. We said we were doing 400 million a day
equivalent but actual gas 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 up to 2020 and beyond.
Operator
Our next question is from the line of Neal Dingmann with SunTrust Robinson.
<Q>: Just looking more on the Southwest PA plans, you've obviously already had that initial success. What's
your thoughts as far as drilling location? You obviously have the 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.
Bill Way – President and Chief Operating Officer
We have our well location number, if anything, is 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 is 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 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 have two there now; we'll have a 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.
Steve Mueller – Chairman and Chief Executive Officer
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 wanted to drill on pads that
had other wells we could 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 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 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 the 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.
Bill Way – President and Chief Operating Officer
We have a deliberate plan that's already underway to accelerate permitting across the areas to give us that
flexibility where we can move around.
<Q>: And remind me— what take away, again, I know in other areas you continue to build out and I know you
have talked about 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?
Page | 8
Bill Way – President and Chief Operating Officer
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 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 our gathering of transportation kind of in at an interim process to have both of them
grow or be able to grow if that's where we choose to invest.
Steve Mueller – Chairman and Chief Executive Officer
And was your question that local next few years or was it what are we trying to grow to maximum?
<Q>: Yes, I guess that was the second part of that, just kind of maximum, is there a sort of cap longer term or
just kind of longer term, what are you looking to grow to?
Bill Way – President and COO
We already have over 800 million today signed up through— by the time you get to 2019 or late 2018, we have
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
that 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 dollar-ish 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 but 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 trajectory.
Steve Mueller – Chairman and Chief Executive Officer
I don't think any of our plans have changed. We've talked about in the past that ultimately we think there's over
two Bcf a day that we'll be taking out of this acreage. So, the real question is if we go up to one 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, but the
ultimate number in the early 2020s is a lot higher than that 800 Bcf a day.
<Q>: 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 laterals you can drill out?
Steve Mueller – Chairman and Chief Executive Officer
We're definitely blocking up acreage. 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.
Operator
Our next question is from the line of Bob Brackett with Sanford Bernstein.
<Q>: A question on the ceiling test impairment. Was that driven by oil price, NGL price or natural gas price?
Steve Mueller – Chairman and Chief Executive Officer
Yes. Kind of put it in 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 and we look at them
today versus the beginning 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, we would probably take another write-down and we may actually start seeing some
wells drop off the books, but today, we have plenty of reserves; we just have less PV, and it was mainly
Fayetteville shale.
<Q>: Okay, but the fact that it's NGLs and oil means a little of a hit in Southwest App?
Page | 9
Steve Mueller – Chairman and Chief Executive Officer
Yes, there was, the next biggest one is actually Southwest Appalachian, West Virginia assets and it broke out. It
was a little over 70% Fayetteville Shale, 20-some percent in West Virginia, high 20s West Virginia and the little bit
in Northeast PA, and then on just a pure reserve PV10 takeaway, we did sell those assets too, so there's a little
bit of that, but It's really Fayetteville Shale driven.
<Q>: 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 take away?
Steve Mueller – Chairman and Chief Executive Officer
With what we see today, it looks to us that 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
have firm because they're competing for your product, whatever that product is. 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 of gas that can
go into pipelines that you don't need to have firm for.
<Q>: You'd rather take a hit on one or two years of bad differential than sign up for twenty years of bad
differential?
Steve Mueller – Chairman and Chief Executive Officer
Yes, that's exactly right.
Operator
Our next question is from the line of Brian Singer with Goldman Sachs.
<Q>: If the enhanced completion and the landing zone optimization you tested in Southwest Marcellus is
applicable to the rest of Southwest Pennsylvania, it 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?
Bill Way – President and Chief Operating Officer
We're sharing this knowledge across the whole company. 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 then
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 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 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 that rotary steerable and some other tools to help steer our wells, we 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, but it's really a 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.
<Q>: And then, shifting to the takeaway 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 or 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
Page | 10
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?
Steve Mueller – Chairman and Chief Executive Officer
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 all the way back to the Gulf Coast where we'll 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 we have 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.
Operator
Our next question is from the line of Dave Kistler with Simmons & Company.
<Q>: 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?
Steve Mueller – Chairman and Chief Executive Officer
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.
<Q>: 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, 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 – Chairman and Chief Executive Officer
Now, except for the little things, and Bill mentioned a couple of them in his conversation, 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 winters 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 takeaway into
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 I'll let Bill talk a
little bit about that.
Bill Way – President and Chief Operating Officer
One final comment on the NGLs, less ethane— under our contracts today, the processor markets those for us.
We do have options for take in 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. So,
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 right now I think
at about 24.5 thousand barrels a day and take those Btus to the Gulf Coast. A, 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 leaving a 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.
Steve Mueller – Chairman and Chief Executive Officer
I think that just goes back to my comment. There are some little things we can do, but NGL prices are going to be
challenged.
Page | 11
<Q>: 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 location to the development portfolio on a longer term basis?
Bill Way – President and Chief Operating Officer
I think in Tioga, for the Lepley well, it's probably a little early to decide just how many locations we have. We
actually have 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 well
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.
Steve Mueller – Chairman and Chief Executive Officer
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 have 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 Lepley 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.
Operator
Our next question is from the line of Michael Rowe with Tudor, Pickering and Holt.
<Q>: 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?
Bill Way – President and Chief Operating Officer
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 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, 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, it's also about the strategy of how fast we can grow and how 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 our
dialogue by the end of the year.
Steve Mueller – Chairman and Chief Executive Officer
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 takeaway.
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 will send us on another course.
Now we know what we need to build and how to build it. So, we just have 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.
Bill Way – President and Chief Operating Officer
With dry gas, you have multiple delivery point options which can optimize how the investment's put together,
versus a wet system.
<Q>: 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?
Page | 12
Steve Mueller – Chairman and Chief Executive Officer
I'm not sure I feel comfortable is the right answer, but we certainly have some options. Ideally, as Bill said earlier,
you like to have permits everywhere, you like to have pipelines everywhere, 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 takeaway, and so we have options and, again, let's just assume we drill
roughly 50 wells next year. If we drill 50 wells, and we want to drill 20 plus wells in dry gas, we could do that, but
we couldn't do 50 in dry gas.
Operator
Our next question is coming from the line of Drew Venker with Morgan Stanley.
<Q>: 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?
Steve Mueller – Chairman and Chief Executive Officer
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 and you invest at the same amount in
2017, I don't know the exact number but I guess it's half that, it's 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.
<Q>: 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?
Steve Mueller – Chairman and Chief Executive Officer
That goes back to that dry gas system.
<Q>: It's just gathering?
Steve Mueller – Chairman and Chief Executive Officer
Just gathering would be your issue.
Operator
Our next question is from the line of David Heikkinen of Heikkinen Energy Advisers.
<Q>: Can you remind us about your annual midstream cap ex in your longer term plan? I know there's some
third party versus insourcing dry gas moves but rough numbers would be helpful?
Steve Mueller – Chairman and Chief Executive Officer
The numbers I gave you, the $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. Perspective, this year is about $80
million, so it would be about half in the future.
<Q>: And then, just thinking about 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. 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.
Craig Owen – Chief Financial Officer
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 in the plans as we exit 2015 and move into 2016 is our balance sheet
will be getting better and 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 strip
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.
<Q>: 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?
Page | 13
Steve Mueller – Chairman and Chief Executive Officer
You kind of preface that with— what was the number you wanted us to do that off of?
<Q>: The sub $3. You're using $3 and so I was just thinking about that.
Steve Mueller – Chairman and Chief Executive Officer
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 under $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.
Craig Owen – Chief Financial Officer
Yes, even at a million dollar cash or capital program, your debt may be coming down with free cash flow but your
metric, because of EBITDA, like he said, goes the wrong way.
<Q>: But you guys are in a better position than peers given the unsecured facility and your midstream system.
So, I was just thinking about bigger picture. Like for the industry, it seems like there's some fundamental issues if
you run something lower than your price.
Steve Mueller – Chairman and Chief Executive Officer
Again, we're investment grade today. Two of the grading 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.
Operator
Our next question is from the line of Sameer Uplenchwar with GMP.
<Q>: Following up on your earlier question, you highlighted like the lower maintenance cap ex and I'm just trying
to understand how much of that, 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 inflection in that maintenance capital if service costs move
higher?
Steve Mueller – Chairman and Chief Executive Officer
You're talking about the 2016 numbers we talked about?
<Q>: Yes.
Steve Mueller – Chairman and Chief Executive Officer
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. So, that was the assumption
for leading these 2016, and that was, whatever case, the $1 billion or the $1.4 billion, it just said $50 million of
savings. So that's what you're risking.
<Q>: 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. 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 takeaway, and firm sales, but what
about financial hedging? How were you thinking about that on both those?
Steve Mueller – Chairman and Chief Executive Officer
On a macro picture, let me hit that quickly. I want to hit that very quickly, and I'm going 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 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 between
2012 and today.
Page | 14
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 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. So, it's a combination of those two.
We get the question all the time, all these big Utica wells, what's that going to do for the future? Everyone has 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 takeaway 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 about what we're doing in the hedge unit and what we're doing if he wants.
Craig Owen – Chief Financial Officer
Certainly, as we move into 2016, just looking for opportunities, and historically, you have heard Steve and the
company talk about getting towards a longer-term target of $3.75, $4 dollars and look for opportunities there. At
current strip pricing, we see a lot more opportunity on the upside than downside for the macro reasons Steve
indicated, but you're right; typically, we do try to add in more hedges than we are. We'll look to get to 40% to 50%
possibly, and you 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.
Operator
Our next question is from the line of Matthew Russell with Goldman Sachs.
<Q>: Most of my questions were answered, but 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?
Steve Mueller – Chairman and Chief Executive Officer
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 – President and Chief Operating Officer
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.
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 – Chairman and Chief Executive Officer
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 I have some very unique opportunities that we think will work in
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 the new acquisition on both the development of Marcellus and the Utica. 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. 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.
Page | 15