EQT Corp (EQT) 2012 Q2 法說會逐字稿

Good morning.

Welcome to the EQT Second Quarter 2012 conference earnings call.

All participants will be in listen-only mode.

(Operator Instructions) After today's presentation, there will be an opportunity to ask questions.

Please note, this event is being recorded.

I would now like to turn the conference over to Mr. Patrick Kane.

Mr. Kane, please go ahead.

Thanks, Amy.

Good morning everyone and thank you for participating in EQT Corporation's Second Quarter 2012 earnings conference call.

With me today are Dave Porges, President and Chief Executive Officer; Phil Conti, Senior Vice President and Chief Financial Officer; Randy Crawford, Senior Vice President and President of Midstream, Distribution, and Commercial; and Steve Schlotterbeck, Senior Vice President and President of Exploration and Production.

This call will be replayed for a seven-day period, beginning at approximately is 1.30 PM Eastern time today.

The phone number for the replay is 412-317-0088, the confirmation code is 10006595.

The call will also be replayed for seven days on our website.

As you already know, we successfully completed an IPO of EQT Midstream Partners earlier this month.

Before we review this quarter's results, I want to remind you that there was no impact to our second quarter results as the IPO did not close until July 2. Next quarter our EQT results will include the results EQT Midstream Partners on a consolidated basis.

Below the net income line, in the statement of consolidated income, EQT will present the amount of net income attributable to the public unit holders under the caption debt income attributable to non controlling interests.

The cash distributions from the partnership to the non-controlling interest will be reflected in the financing section of EQT's statement of cash flows as a use of cash.

The cash distributions to the non-controlling interest will not impact the consolidated cash flows provided by the operating activities or cash flows from investing activities.

There will also be a separate press release, 10Q and conference call to detail EQT Midstream Partner's third-quarter results.

In just a moment, Phil will summarize our operational and financial results for the second quarter 2012, which were released this morning.

Then Dave will provide an update on our strategic operational matters.

Following Dave's remarks, Dave, Phil, Randy, and Steve, will all be available to answer your questions.

But first, as usual, I would like to remind you that today's call may contain forward-looking statements related to future events and expectations.

You can find factors that could cause the Company's actual results to differ materially from these forward-looking statements listed in today's press release and under risk factors in the Company's form 10K for the year ended December 31, 2011, filed by the SEC as updated by any subsequent form 10Qs which are on file at the SEC and are available on our website.

Today's call may also contain certain non-GAAP financial measures.

Please refer to this morning's press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measure.

I'd now like to turn the call over to Phil Conti.

Phil?

Good morning everyone.

As you read in the press release this morning, EQT announced second quarter 2012 earnings of $0.21 per diluted share, a $0.30 decrease from adjusted EPS in the second quarter 2011 Two price-related items together reduced EQT production revenues by $15.3 million or $0.07 per share this quarter.

One item was related to gas price quotes that should have been recognized in 2010 and 2011, resulting in a non cash revenue reduction of $8.2 million in the second quarter of '12.

The other was a $7.1 million increase in third-party gathering, processing and transmission revenue deductions from the sale of unused firm capacity that rates below what we are paying.

And I'll give you some more on that in a minute.

Operating cash flow in the quarter of approximately $160 million decreased by 14% verses cash flow in the second quarter of '11.

Other than that, the operating results this quarter are fairly straightforward.

In short, we had another strong operating quarter at EQT.

Production sales volumes were 28% higher than last year and 11% higher than in the first quarter of this year.

NGL volumes were 10% higher than last year and 8% higher than in the first quarter.

And midstream gathering volumes were 24% higher than last year and 9% higher than in the first quarter.

However, commodity prices were significantly lower than last year and that more than overwhelmed our operational progress.

I will discuss that in a bit more detail in the segment results starting with EQT Production, where sales volumes continue to grow as planned.

As I mentioned, production volumes were 28% higher and that growth was driven by a 74% increase in sales from our Marcellus Shale play.

We did hit two significant Marcellus milestones this quarter.

First, we turned our 200th Marcellus horizontal well online, and second, our Marcellus production accounted for over half of our total volumes for the first time, hitting 4.54% of the total in the quarter.

Offsetting the impact of volume growth, however, the realized price at EQT Production was $2.62 per Mcfe compared to $4.16 last year, or about 37% lower.

At the corporate level EQT received $3.83 per Mcfe, compared to $5.60 received last year.

Nymex gas prices basis and liquid revenues were all lower in the quarter, somewhat offset by our natural gas hedges which contributed about $85 million to revenue in the second quarter.

The two price-related items that I mentioned up front, lowered both the EQT Production and the EQT Corporate price in the second quarter 2012 by a combined $0.26 per Mcfe.

The revenue deduction for third-party gathering processing and transportation to arrive at those realized prices was $0.56 for the second quarter, and you can see that in the table in this morning's press release.

That $0.56 includes $0.12 per Mcfe resulting from the Company's inability in the quarter to resell its unused contracted capacity on the recently completed El Paso 300 line, at units at or above what we currently pay under the existing agreements with El Paso.

Put another way, by subtracting that $0.12 from the $0.56 reported for the second quarter '12, a reasonable per unit run rate for the reduction for third-party gathering, processing and transportation, would be approximately $0.44 for Mcfe.

Going forward, the run rate will vary from, we think, $0.40 to $0.45 and the actual reported rate each quarter will be impacted positively or negatively depending on the market rates we receive for the short-term resale of our 300 line capacity that is not currently reserved for EQT production or that is not currently under long term resale contracts with third parties.

The value of the unused capacity will vary seasonally.

And to illustrate that point, in the first quarter of 2012, the revenue deduction for third party gathering processing and transportation was actually offset positively by about $0.12 from the run rate as a result of sales of unused capacity at rates above our costs.

We expect to continue to see this volatility perspectively as we continue to contract for capacity to move production and sales volumes to market and then sell the unused portion as those volumes ramp up.

As such we will quantify the impact each quarter so that you can see the underlying trend of the production revenue deductions more clearly.

Produce NGL volumes, mainly from our liquids-rich Huron and West Virginia Marcellus plays were 10% higher than last year and account for 6% of the volumes in the quarter.

As a reminder we do not include ethane in this calculation, as it is currently mostly sold as methane.

If we included ethane, a percentage of liquids produced would approximately double.

Total operating expenses at EQT Productions were higher quarter over quarter, as a result of higher DD&A, LOE and production taxes.

Per unit LOE, excluding production taxes, was down 14% to $0.19 per Mcfe in the quarter.

That decrease was the result of producing higher volumes while maintaining our cost structure that is already among the best in the industry.

Production taxes were also lower on a unit basis at $0.17 per Mcfe verses $0.20 last year this time, due to lower prices in the second of '12 verses the second quarter of '11.

Moving on to Midstream results.

In the second quarter, operating income here was up 14% consistent with the growth of gathered volumes and increased capacity-based transmission charges.

Gathering that revenue's increased by $10.9 million, as gathering volumes increased by 24%, somewhat offset by the average gathering rate which declined by 5% due to the increase in Marcellus gathered volumes, which do get charged a lower rate.

As Marcellus production continues to grow as a percent of our total production mix, the average gathering rate paid by EQT production will continue to decline.

However, EQT Midstream margins will continue to be strong as the per unit midstream expenses from Marcellus production is also lower than our current average.

Midstream transmission net revenues are also increased by 31% in the quarter, after adjusting for $8.1 million of Big Sandy revenues recorded last year, when we still owned Big Sandy.

Storage marketing and other net operating revenues was up about $2.7 million in the second quarter.

This has been mentioned before, the storage and marketing part of the midstream business relies on natural gas price volatility and seasonal spreads in the pool occur and those will continue to deteriorate.

Given current marking conditions, we now estimate that full-year 2012 net revenues in Storage, Marketing and Other will total approximately $50 million.

Net operating expenses at Midstream were up quarter over quarter, consistent with the growth of the business.

Per unit gathering and transmission expense was flat as we maintained our cost structure.

Finally, a little bit of guidance.

Today, we did reiterate our production sales forecast for full year 2012 of between 250 and 255 Bcfe or approximately 30% higher than 2011.

We expect that third quarter 2012 production sales volume to be approximately 66 Bcfe.

Base on our forecast, we are reiterating our operating cash flow estimate of 2012 of proximately $800 million using the current strip.

We are also tweaking our production CAPEX forecast to $900 million from $965 million and our total Company CAPEX forecast to $1.3 billion to (inaudible) from $1.365 billion to reflect year-to-date actual investments in our second-half investing plans.

Our plan is still to draw 132 Marcellus wells in 2012.

Closed the quarter with approximately $515 million in cash on hand.

And subsequent to quarter end, we did receive $232 million in proceeds from the IPO of EQT Midstream Partners, which they will discuss momentarily.

We continue to have full availability under our $1.5 billion credit facility, which was recently expanded through November 2016.

With that, I'll turn the call over to Dave Porges.

Thank you, Phil.

As I've previously communicated, our objective, maximizing shareholder value is unchanged by changes in the environment in which we operate.

The strategy, accomplishing this via monetization of our asset base and prudent pursuit of investment opportunities, while living within our means, is also unchanged.

Of course, the specifics of these monetizations, the assets, the timing, the form, are very much affected by market conditions.

We took another major step forward this month with the successful IPO of EQT Midstream Partners, LP.

Including the impact of the underwriter's over allotment option, which was fully exercised, EQT Midstream sold about 40% of the Limited Partnership units to the public with the unit's pricing on schedule and at the top of the indicated price range.

These units trade on the New York Stock Exchange using the ticker EQM.

We believe EQM will provide us with ongoing access to capital at relatively low cost, consistent with the steady cash flows generated by those midstream assets.

As we were on our multi-city MLP IPO road show, we met with many of our existing EQT shareholders and many of our new EQM unit holders.

Both groups of equity owners, including those now owning both securities, recognize the symbiotic relationship between EQT and EQM.

The capital raised in this offering will be redeployed to accelerate the development of our vast Marcellus acreage position.

This acceleration will lead to increased sales of produced volumes and also increased gathering and transmission volumes and cash flow for EQT Midstream and EQM.

This increase in midstream cash flow drives MLP unit-holder returns and will help increase the amount of capital available through additional midstream sales of assets from EQT to EQM so-called drop-downs.

For the timing being, we anticipate that most large midstream investments will be made at the EQT level, with most of the EQM capital investments coming in the form of purchases from EQT.

We do anticipate that there will be some direct construction of facilities at the EQM level, but we do not want too much of EQM's capital tied up in investments that are not yet generating cash flow.

Therefore, the basic model is to build most of the facilities at the EQT level until EQM is larger.

Conceptually, our current construct is that over time, EQT's capital expenditures in the midstream will roughly equal proceeds from sales to EQM.

As EQM grows, more of the capital expenditures related to midstream construction will be made inside EQM.

We believe that this approach will allow us to continue to benefit from a key attribute of the MLP structure and that we retain operational control, so that we can make sure that we have gathering capacity where and when we need it to achieve our development targets.

Moving on to other operational matters, as we told you on the last call, MarkWest is building a processing plant to serve our West Virginia wells.

This plant construction is moving along and we still anticipate completion by year end.

This is later than originally anticipated, but the schedule has remained the same since our last quarterly update.

Since that last call, EQT and MarkWest have also developed an interim solution using some existing and some new assets to provide EQT with some cryogenic processing until the originally contracted facilities are turned in line.

This capacity, roughly equivalent to 40 million cubic feet per day or a third of contractual capacity, came online late last week.

As we also mentioned in the last call, our production sales volume targets remained the same, even with the current schedule for the full plant, that we will obviously not have as high a percentage of natural gas liquids in that full-year total as originally anticipated.

Still, this interim solution will help us gain back some of the liquids uplift that was considered lost due to the delay.

As you saw in this morning's press release, we reiterated our production sales volume guidance.

We grew production sales volumes by 11% over the first quarter and expect to grow at a similar sequential rate in the third and fourth quarters.

I mentioned in the last call the growth rates versus same quarter prior year can vary due to the inherent lumpiness of how we add volumes.

As an example, since the beginning of 2010 our sequential growth rates, probably a better way to capture this particular issue, averaged about 8%.

That is an average quarter head volumes about 8% higher than the immediately preceding quarter.

However, these sequential growth rates range from just over 3% to nearly 14%.

This lumpiness is largely the result of a combination of pad drilling and the timing of infrastructure adds.

Knowing all that, we are right on plan year to date and confident that we will hit our targets.

To give you a specific example to speak to this, we are just now bringing online a ten well-pad in Green County.

On average, the wells on this pad will have initial flow rates of about 10 to 12 million cubic feet per day each.

So we expect that this will be our first 100 million per day pad.

Typically, turn the wells on such pads in line one at a time and we will be well into August before all ten wells on this pad are flowing.

You can expect that over the next couple of years we will continue to have periods during which volumes more of less plateau for a period of time and then surge with the turning in line of a multi-well pad or a new infrastructure product.

Moving on to other matters.

Earlier this month, EQT announced the launch of a pilot program to begin converting drilling rigs to LNG, liquefied natural gas, displacing the diesel used to power equipment at the well sites.

EQT is the first operator in the Marcellus to convert a diesel rig to LNG, which will provide a cleaner burning alternative fuel for the region's drilling operations.

However, we do believe that this is going to quickly become more commonplace throughout the industry and that will improve the logistics of getting natural gas to the rigs for all of us.

EQT's initial rig conversion is now operating in northern West Virginia, and pending evaluation of the pilot program, we hope to convert additional rigs in West Virginia and Pennsylvania.

The LNG being used for EQT's pilot program is produced from Marcellus natural gas reserves and is about 40% less expensive than diesel.

The use of LNG also provides another means of adding to the use of natural gas.

And we do expect that there will be circumstances in which we will be able to improve the economics further by using field gas.

We are proud to be a leader in reducing the environmental impacts related to drilling.

Along with safety, protection of the environment is top of mind for employees, contractors, and of course, communities.

Compared to diesel, natural gas emits between 20% to 30% less carbon dioxide and has a fraction of the emissions of nitrogen oxides, sulfur oxides and particulates.

In summary, EQT is committed to increasing the value of our vast resource by accelerating the monetization of our reserves and other opportunities.

We continue to be focused on earning the highest possible returns from our investments and are doing what we should to increase the value of your shares.

We will stay disciplined and live within our means, investing our available cash flow from operations and from future monetizations.

We look forward to continuing to execute on our commitment to our shareholders and appreciate continued support.

Pat?

Thanks, Dave.

That concludes the prepared portion of the call.

Amy, could you please open the line for questions?

Thank you.

We will now begin the question and answer session.

(Operator Instructions)

At this time, we will pause momentarily to assemble our roster.

Our first question is from Neal Dingmann, SunTrust Robinson Humphrey.

Good morning.

Just a couple of questions.

First, you alluded to in the drop-downs, I guess my -- I was just wondering in timing, how soon could we begin to see some of those drop downs?

And remind me the rationale initially why to buy through the EQT and then drop down versus, I thought maybe there would be a lower cost structured the other way?

Well, I'm not that comfortable giving timing guidance on drop-downs at this point because we just kicked this off.

Obviously, routinely we would want to have drop-downs.

But, I'd just as soon stay away from, pretty much guidance on that.

Fair enough.

Neal, was your other question about why the construct we're using, for the time being at least, is to build facilities at EQT and then drop, as opposed to building that at EQM?

Correct.

I'm certain you looked at sort of cost basis extracted.

I'm just -- what are the benefits?

Or how much you anticipate saving that way?

Sure.

The general view -- certainly over time, we would expect there will be more facilities constructed EQM.

The issue that you have though, is that -- as we understand, and of course we're neophytes in this.

But -- in the MLP world.

But as we understand it, what we're really trying to do to drive value at that level is you try to drive unit distribution growth.

And it is more difficult to that when a high percentage of the capital employed is tied up in non-cash generating assets, such as assets under construction.

So from that perspective, and I actually think even with large MLPs, you see that there's only a certain percentage of their capital that they have invested in non-cash generating assets.

It's just that at the size of EQM, that's not a very big number right now.

Over time, you would expect to see that number grow.

Okay.

Then just two more if I could, Dave, for you or Steve, as well.

Looking at the last presentation you had out, I think you have identified maybe 30% -- 35% of the Marcellus as being wet.

Number one, is that still accurate?

And number two, around that, clearly with these pads, what kind of well cost savings should we continue to assume?

This ten well pad just is amazing, so I'm just wondering how much savings we could see because of these?

At this point, I'm sure you're bored of hearing my voice so I'll let Steve answer it.

Neal, regarding the break-out of wet versus non-wet, that still holds.

I will be clear on our definition of wet versus non-wet that goes into those numbers is an 1100 BTU cut-off.

So, I think that's not always consistent amongst companies but that's what we're using to come up with that number, but nothing has changed in that area.

Regarding well-cost savings, the average cost numbers that we are using for our type curves, incorporate the fact that some of our wells will be on ten-well pads.

So, I think you'll be safe to continue to use those type curve numbers.

Okay, and then lastly, maybe, Steve, just following up.

As far as, you were uniquely able to cut CAPEX a little bit, even on the upstream side.

Just wondering, when you look at lease expirations, any -- again you generally haven't had any issues there.

Will that continue to be the case?

Yes.

Nearly all of our acres is HBP.

We have a small handful of drilling commitments that we are easily able to keep up with.

So, really no issues what so ever with these lease expirations.

Perfect.

Thanks for the color, you all.

You bet.

Michael Hall, Robert W. Baird.

Hello.

I have a feeling we might have answered his questions already.

Or he's rushing out to buy more stock.

Amy, are you still there?

Amy?

Yes, our next question is from Anne Cameron with BNP Paribas.

Yes, yes, I am here.

So, just a question on the drop-down schedule.

I know you don't want to talk about it too much, but you made a comment before I was just curious about.

If you are going to fund CAPEX at EQT with proceeds from drop-downs at EQM, I mean just given the run rate of your spending this year, that implies a some what slower drop-down schedule than I was expecting.

If we slap in an assumption of 10, 11, whatever you want, multiple on it.

Can you just comment on whether or not the drop-down schedule could get ahead of your CAPEX?

Well, certainly, it could, yes, because this is all -- you know, all of this is over time.

I'm trying to talk -- rarely will you find a quarter and maybe even a calendar year in which they just line up perfectly.

So, yes, absolutely it is possible for us to run ahead, and I do realize that over a longer period of time, of course, there will be more drop-downs than there will be CAPEX.

More and more of the business will shift to EQM.

The issue that we get into, the struggle that we have, is trying to forecast what drop-downs are, frankly, especially given the various disclosure constraints with a new entity.

So, yes, absolutely there can be periods of time, even in the near term, when drop-downs run ahead of CAPEX.

And is there a target of how much of the EQM units that EQT wants to remain the owner of?

No, we do not have such a target.

Okay, and how important are the IDCs from your drilling business in terms of shielding gains on sale from those drop-downs?

That is definitely something that will be taken into account when we're timing drop-downs.

Okay.

I guess what I am asking is, is there a scenario where you could maybe spin off the LP and the GP and drop down without those IDCs able there to shield it?

Sure.

I mean as you know, we have said that we're open to anything to create shareholder value.

That is the tax attributes are something that -- are one of the issues that one weighs when looking at those kinds of decisions.

So, I don't feel that comfortable saying anything more than yes, we would certainly take that into account, but that's not the sole determining factor in anything that we do from a structural perspective.

Got it.

Thank you, very helpful.

Becca Followill, US Capital Advisors.

Good morning.

A couple of questions for you.

On Tennessee capacity, can you give us more information on how much capacity you released of the total that you have?

And then how you expect that trajectory to change over time?

At what point do you think you'll be fully utilizing that capacity and not having to sell at a discount?

Well, we'll turn that one over to Randy.

Well, Becca, obviously we have growing production options that we have with our Huron to move into that capacity, as well as some of our Tioga productions.

So, we do expect to utilize that capacity over time.

While the market has been increasing, primarily the demand market around the power generations, it is seasonal.

It's not a robust market in the summer.

However, it is a constrained pipeline, and as demand increases in the northeast and supply, I think the value of this capacity will increase.

But it is seasonal.

But our intent is over the next couple of years to utilize that capacity primarily to move our product to market.

So, probably on a 2Q and 3Q level, we'll usually see some discounting and not in Q1 and Q4, and then over the next couple of years that completely goes away?

Is that fair?

That's right, Becca.

It is seasonal.

And I think that is correct.

Though, it's probably just as -- it does -- the difficulty with looking at second and third, even though they are likely not to be as good as first and fourth from the perspective of the market is, it's really driven by extreme weather.

So, it is certainly possible that extremely hot weather can drive demand just as much as extremely cold weather can drive demand.

As we like to say around here, we're more comfortable when you're not comfortable.

The comfortable weather is not good for the business.

Okay, thanks.

And then on the MarkWest, the incremental 40 million a day?

Can you quantify about how much liquids to uplift you think you'll get from that?

Well, we have a slide in our board presentation.

I'm sorry, with our investor relations website that calculates that, Becca.

It's in the range of --

Okay.

I'll look at that then.

Okay, just to summarize, Becca, we're currently getting a half gallon per MCF on average, and that will go up to 1.8, is what we estimate.

On that incremental volume?

Right.

Okay, thanks.

And then you talked last quarter about moving more to the wet gas area.

With the pull-back in liquids prices, is that stall the plan?

Has anything changed?

Yes, it affects economics, but its still -- you get more -- look, it's just one factor.

We still get more value per unit volume in the wet areas than in the dry areas.

But it can certainly affect individual decisions.

Okay, thanks.

Then the last question, on the $65 million CAPEX cut, I think the wording was that you were fined your estimates.

Can you give us any more information on what went into that $65 million reduction?

No, Becca, that's really just having a better idea of exactly which wells we're going to drill, where we're going to drill them, and when we're going to drill them than we did back in November when we put our original plans together.

So, there's really nothing more to it than that, than just more knowledge about specifically what's going to happen in the second half of this year.

So it's not fewer wells or lower well costs, it's more the individuality of the wells?

Exactly.

Perfect.

Thank you, guys.

Michael Hall, Robert W. Baird.

Thanks.

Sorry for missing the earlier call.

Just quickly, a couple of things on my end.

Number one, and apologies if you covered this at all, but the backlog uptick quarter on quarter?

I understand your drilling more on pads, and I'm thinking that probably is driving part of that.

Do you expect that then to kind of maintain at that sort of level or how should we think about that?

Michael, this is Steve.

I think we expected to bounce around a good bit because it is driven almost solely by the timing of these large multi-well pads we're drilling.

I would remind you that we're also doing a lot more fracs per well or per foot of well drilled than we used to.

Which also means there's more frac stages out there per well that can add to the backlog.

But, just to follow on the pad that Dave talked about, the pad in Green County, where we have ten wells.

There's 203 total frac stages on that pad, which will be coming online here in the next couple of weeks.

So that backlog of 412, I believe it is, backlog of frac stages, half of those will be going away just in the next couple of weeks from one pad in Green County.

It just happens to be very lumpy because of the timing of these things.

Okay, that makes sense.

I guess the other one on my end then is a little more structural.

And thinking, now, obviously, we've made our way through the MLP process.

It kind of begs the question, I suppose, regarding the distribution business.

How you guys are thinking about that in the grander scheme of things within the EQT corporate structure currently?

And to what extent is there an ability to put away if production unit from the others or desire along those lines?

Well, first of all, I do not intend to make news on that front in this conference call.

So, if you interpret any of my remarks as making news, then please reconsider.

We did say that once we are going to, once we get past what we did with the midstream, which wound up being EQM that we would again, kind of resume looking at some of the other structural issues.

All I would say on that front is we just got finished with the MLP and we are really just kind of catching our breath, and we will start looking at all of the various possibilities to increase shareholder value.

But it's -- I say it is a little too -- you know we're just not that big of a company that -- We pour a lot of our resources, management and otherwise, into getting that EQT Midstream Partners up and running.

So, even though we have the opportunity to looking at other stuff, we are really only at the very beginning of looking at other things.

I would not limit that, incidentally, to just distribution.

We are looking at all aspects of our business to see how we can create more value.

Okay.

Is it fair to say that maybe by the end of the year you will have caught your breath enough that maybe you'll have some more, let's say concrete thoughts around next steps?

I promise that by the end of the year, I'll be able to answer that question.

Whether we have it.

Honestly, my view is we all learn things in new jobs.

And one of the things I learned is not sharing too much about thought process.

So, I don't know where we'll -- we continue -- we try to make progress on creating shareholder value on virtually a continuous basis.

And I just think it's -- we're in the same month as we closed on EQM going public.

So, I would rather not put any timing commitments other than to promise you everything's always on the table.

That is not news.

That is the way it's been, I would say since I have been at EQT, our mindset has been everything is always on the table.

Okay.

That's helpful, I appreciate it.

Certainly understand, like you said, just got out of the MLP.

Thanks.

Thank you.

Chris McDougall, Westlake Securities.

Thank you very much for taking the question, gentlemen.

I wanted a little bit more color on your natural gas drilling convert, the running the rig off natural gas.

And two questions.

What percentage of the overall well cost is attributable to the diesel for the rig?

And then what percentage for diesel overall, which I suspect is dominated by the frac stages?

Chris, this is Steve.

I don't have a specific number for you, but diesel costs, as a percent of a total well cost, is fairly small, certainly in single digits percentages.

It's not a huge driver toward the overall cost of a well.

But it's the little things.

Doing a lot of little things adds up over time.

So, I wouldn't say it's trivial that we have a cost savings.

But in and of itself, it is not a marked reduction in well costs.

And so, what was the second part of your question?

Yes, so, you had talked about this being a pilot program, and I understand infrastructure and everything else has to kind of develop along with it.

Do you have any thoughts on the timing for converting more wells or more drilling rigs to this?

And have you experimented all with running the frac spreads off natural gas?

At the current time we -- I think as we speak, we have our second rig running on natural gas.

So, that's two out of five of the Marcellus rigs.

I think we're going to see how that goes probably through most of the rest of the year.

If it continues as well as it has so far, I would expect next year we'll talk about trying to convert over the entire fleet.

Assuming that it continues to work well.

We have had discussions about the frac fleet.

That is a much more difficult problem to solve there.

I think ultimately our desire is to convert our frac fleets over to natural gas.

But that is clearly going to take significantly longer than the drilling rigs.

So, it's something we're beginning to work on.

Expect it to take quite a while before you see us actually fracking with natural gas, with natural gas powered pumps.

Okay, thanks.

And lastly on the rig costs, how much conversion costs do you have, in the capital sense, to convert one of these to run off the natural gas?

I think it is in total -- and for these first ones we have paid for it as a pilot program.

We certainly hope in the future we can convince the drilling companies to make the conversions themselves.

It varies a lot.

It's between a $0.5 million and $1 million.

The difference is for when we want to operate with field gas, which is taking gas off pipelines and LNG, we have to have a gas conditioning skid.

The cost of that skid is about a $0.5 million dollars, but the cost of the gas is significantly less.

So, from an economic standpoint, we think field gas will be the best way to go in the areas where it is available and we can use it.

In the areas where we can't, we'll go with LNG.

Thanks a lot, guys.

Marcus Talbert, Surveyor Capital.

Hi gentlemen.

Good morning.

Thanks for taking my call.

I had a quick question on the Midstream segment.

Given the way that you framed the capital budget for the Company with the reduction on the upstream side.

Just curious as to how the projects are coming along, the gathering in expansion projects within the midstream business and if there has been any change to the prior guidance in terms of how much you had planned to allocate to these projects this year?

Hi Marcus, this is Randy.

No change in our forecast.

And we're on time, on budget.

In fact our Sunrise project will be turned in line in the third quarter, August 1. And that is the 300 million a day capacity on Equitrans.

So, on time and no changes.

Okay, thanks very much.

And just one more quick question for me on the EMP business with this initial ten-well pad that you guys are putting in line in August.

Is it that all ten of these wells will be turned into sales during the month of August?

And then just a follow-up in terms of the completion design.

Was there any differentiation between your standard frac design and some of the newer completions that you have spoke about in the past?

Yes.

All these wells should be online by the end of August.

Three are currently online.

Those three are producing about 40 million a day as we speak.

Over the next couple of weeks we should have the rest in line.

On the completion designs, there was a mix on this pad.

But for the most part, most of these wells used are reduced cluster spacing design.

Okay, great.

Thanks very much, guys, for the color.

This concludes our question and answer session.

I would like to turn the conference back over to Mr. Patrick Kane for any closing remarks.

Thank you, Amy, and thanks everybody for participating.

We'll see you next quarter.

Thanks.

The conference is now concluded.

Thank you for attending today's presentation.