EQT Corp (EQT) 2014 Q1 法說會逐字稿

Good morning, everyone, and welcome to the EQT Corporation first-quarter 2014 earnings conference call.

All participants will be in a listen-only mode.

(Operator Instructions)

After today's presentation there will be an opportunity to ask questions.

(Operator Instructions)

Please also note that today events is being recorded.

At this time, I would like to turn the conference call over to Mr. Patrick Kane, Chief Investor Relations Officer.

Mr. Kane please go ahead.

Thanks, Jamie.

Good morning, everyone, and thank you for participating in EQT Corp's first-quarter 2014 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 and Commercial; and Steve Schlotterbeck, Executive Vice President and President of Exploration & Production.

This call will be replayed for a seven-day period beginning at approximately 1:30 PM eastern time today.

The telephone number for the replay is 412-317-0088.

The confirmation code is 10037662.

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

To remind you, the results of EQT Midstream Partners, ticker EQM, are consolidated in EQT's results.

There was a separate press release issued today by EQM, and there is a separate conference call today at 11:30 AM, which creates a hard stop for this call at 11:25.

If you are interested in the EQM call, the dial-in number is 412-317- 6789.

In just a moment, Phil will summarize EQT's operational and financial results for the first quarter of 2014, which were released this morning, then Dave will provide an update on strategic and operational matters.

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

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 under risk factors, and -- I'm sorry, and under risk factors on EQT's Form 10-K for the year ended December 31, 2013, which was filed with the SEC as updated by any subsequent Form 10-Qs, which are on file at the SEC and 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 would now like to turn the call over to Phil Conti.

Thanks, Pat, and good morning, everyone.

As you read in the press release this morning, EQT announced first-quarter 2014 adjusted earnings per diluted share of $1.35, which represents a 214% increase over adjusted EPS in the first quarter 2013.

Adjusted operating cash flow also increased by 57% to $483 million in the quarter.

As a reminder, EQT Midstream Partners' results are consolidated in EQT Corp's results, and EQT recorded $18.7 million of net income attributable to non controlling interest, or about $0.12 per diluted share in the first quarter.

We had a very solid operational quarter including record produced natural gas [wells] and record gathering volumes at midstream.

The high-level story for the quarter was strong volume growth and higher realized prices, coupled with lower unit costs in both the production and the midstream businesses.

While our volume and growth in the quarter was a little ahead of the guidance we provided at year end, the realized price was probably quite a bit above expectations.

I will start by walking you through some details around realized price this quarter.

First, NYMEX was 48% higher than last year at $4.94 per MMBTU.

As you are aware there are a variety of factors that will cause our realized price to vary from NYMEX, many of which were listed in the press release this morning.

One of the most obvious factors is basis, which averaged a negative $0.22 per MCF equivalent in the first quarter, compared to approximately flat with NYMEX during the first quarter of 2013.

From a reporting perspective, EQT accounts for its basis relative to NYMEX at the first liquid delivery point.

Even though we deliver to many points, the average basis has tended to be close to the TETCO M2 price, where approximately half of our gas is sold.

That was certainly the case in the first quarter as TETCO M2 was also a negative $0.22 per MBTU.

One point of clarification; as opposed to spot prices you may see reported, much of our gas is sold based on a bid week price, which is set by taking the last five business days of the month preceding the delivery month.

For example, March 25 through the 31 of March for deliveries throughout April.

And that is otherwise known as first of month, or FOM pricing as it's often referred to.

EQT's realized price also varies from NYMEX due to revenue deductions for the net cost of third-party gathering and transmission.

And our transportation costs are reported at -- in that line item.

These costs are often partially offset by selling the gas into higher priced markets utilizing our transportation capacity and by reselling unused transportation capacity when we have it.

That was the case in the first quarter with the unusually cold temperatures.

So much of the increased prices we received in those markets more than so much so that much of the increased prices we received more than offset our entire third-party transportation costs.

So instead of what normally has been a deduction, we are reporting positive net revenue of $0.64 per MCF equivalent associated with our third-party capacity, more than offsetting the negative basis this quarter.

To kind of tie all that together and removing the negative $0.21 by MCF equivalent related to hedge and effectiveness, EQT Corp realized $5.50 per MCF equivalent in the first quarter, or 33% higher than in the first quarter last year.

Moving on to EQT Production operating results, the story in the quarter of production continues to be the growth of sales and produced natural gas.

The growth rate was 30% in the recently completed quarter over the first quarter of 2013.

That growth rate was almost all organic and was driven by sales from our Marcellus and Upper Devonian shale plays, which saw together volume growth of 50% versus last year.

NGL volumes were also 16% higher than last quarter -- than the first quarter of 2013.

As discussed, price also contributed as the realized price at EQT Production was $4.40 per MCF equivalent, compared to $3.05 per MCF equivalent last year.

Total operating expenses at production were $191 million or $14.1 million higher quarter over quarter.

Higher DD&A expense accounted for $16 million of that increase and was driven by volume growth and partially offset by a lower average depletion rate in 2014.

Production taxes were $5.2 million higher, consistent with the higher volumes, and other operating expenses at production were about $2.6 million higher.

Sales continued to grow at a significantly faster pace than expenses, per unit cost continued to improve.

For example, per unit LOE, excluding production taxes of $0.14 per MCFE, was 13% lower than last year.

Moving on to midstream results, operating income here was up 12%.

This is consistent with the growth of gathered volumes and increased capacity based transmission charges.

Gathering net operating revenues increased by 9% to $89.4 million as gathering volumes increased by 25%, but was somewhat offset by the average gathering rate which declined by 12%.

The decline in rate continues to be driven by the increasing Marcellus mix, which as you know has significantly lower gathering rates than the other plays.

Transmission net revenues increased by $14.8 million or 40% as additional fund capacity was sold in the second quarter 2013 and we also received transmission revenue associated with the Allegheny Valley connector system, acquired as part of the consideration for the utility sale last December.

Storage marketing and other net operating revenues were down $2.5 million in the first quarter.

Net operating expenses at midstream were $11 million higher quarter over quarter as a result of our growth in midstream activities, but here again on a per unit basis, midstream and compression expense was -- I'm sorry, gathering and compression expense was down 16% as a result of volumes growing faster than expenses.

And then just a brief summary on liquidity.

EQT exited the first quarter 2014 with approximately $900 million in cash on hand and full availability under EQT's $1.5 billion credit facility, but we remain in a great liquidity position to accomplish our goals for the remainder of 2014.

And with that I will turn the call over to Dave Porges.

Thank you, Phil.

This was another strong quarter.

But since the results are pretty straight forward, I will focus my comments on the related issues of realized price and basis.

In our discussions with investors over the past several months, there have been many questions around these topics as a basis in our region went from premium to or parity with Henry Hub, to discounts.

Over time, basis should reflect the transportation costs in the producing region for the markets.

This notion has been tested recently because the historic construct of the producing regions being near the Gulf Coast and the markets in the northeast has clearly been turned on its head due to the tremendous growth of Marcellus production.

Thus, while EQT has always sold and will continue to sell to the local market, most of our efforts recently have been to ensure that we have sufficient capacity on long haul pipes to ship our gas to other consuming markets, an imperative that didn't really exist before the growth in Marcellus production.

More specifically, in total we currently have 980,000 dekatherms per day of (inaudible) capacity out of the basin and expect to have 1.2 million deks per day by the end 2014.

We also have about 300,000 deks per day of firm sales.

In total our firm price on capacity plus firm sales will total 1.53 million dekatherms per day by the end 2014, so we feel very comfortable with our position in 2014 and heading into 2015.

This represents a mix of local sales, sales to the traditional northeast markets, and back haul sales to the Gulf Coast.

We continue to look at and make commitments on long haul pipeline to get gas to a variety of markets with our goals being to stay ahead of our production growth and take a portfolio approach to end markets in terms of location, channel distribution, and our accessory.

We have recently entered into several agreements to that add to that portfolio.

Our most significant recent addition became effective on February 1 when we added 225,000 dekatherms per day at capacity for seven years on the Texas Eastern system to TETCO M3.

Another addition is 300,000 dekatherms a day of capacity that will go on line in November as part of effected Eastern [team port steam process].

We will continue to add to this portfolio and to add to the diversity of our markets, including the growing Midwest and Southeast markets.

We readily acknowledge this situation presents challenges for producers, but it's also true, however, that it presents opportunities for midstream companies such as ours.

There's really nothing better for the growth prospects of a midstream company than disconnect between supply and demand, for example EQT Midstream Partners, or EQM, is an active open season on a project that connects Equitrans to Clarington, Ohio.

I will elaborate in a moment.

Our main goal in any capacity is to ensure the profitable sale of EQT debt, but there are times, like this winter, when the capacity portfolio creates economic value.

In the long cold winter that has just ended, at least I hope it has ended, increased demand, we optimize our assets and sold some production to premium priced markets.

While we do not record this in basis, it does get reflected as lower net third-party transmission costs.

The benefit of this intersection between production and midstream with commercial and domestic is ultimately reflected in a higher realized price.

We have provided guidance on basis and transportation costs, the two variables besides NYMEX that impact our realize price.

Also today we have a slide in our analyst presentation that shows our approximate exposure to various pricing points and is consistent with the capacity update I just provided.

There are ranges on the slide, but you will see that a little under half of our gas is sold that sold at M2, a little less than 30% of TETCO M3, and a little over 10% at both NYMEX and PICO.

We will update this slide periodically as we continue to add capacity.

There are a few other topics that I would like to comment on briefly.

First, the perspective sale of midstream assets from EQT to EQM.

As we have discussed in the past, we do plan a drop-down this year, but, as is our norm, we will not provide specific guidance on its size or timing.

We will just announce it when it occurs.

Please note that EQM's recent distribution announcement is consistent with our guidance that the GT will be into the high splits by the end of 2014.

¶ The next comment is on the Utica.

While we do not have any Utica results to share with you today, we do have an activity update.

Our regional capital budget contemplated drilling 21 Utica wells this year, we have revised that number to 0. Our current plans is five wells spud in 2013.

The first three will be completed in the current quarter using a different frac design than the wells completed last year.

We will evaluate the results of both free wells, probably revise our approaching again, and then frac the remaining two wells late in the year.

Only after evaluating all those results will we decide whether to drill additional wells.

Leaving any such additional wells would not be spud in 2014.

We use the capital allocated for the 21 Utica wells to drill 8 traditional Marcellus wells and 13 additional Upper Devonian wells in 2014.

Volumes from these wells will show up in 2015 but they do not impact our 2014 guidance.

Now for an update on the Ohio Valley connector project.

In January EQM initiated a non-binding open season for a FERC project that is 35 miles long with a volume of 1.2 BCF per day, and expected cost of about $300 million.

It would extend the Equitrans transmission system from West Virginia to Clarington, Ohio, and connect with the Rockies Express pipeline and the Texas Eastern pipeline.

(Inaudible) was expressed in this project.

The estimated in service date is second quarter of 2016.

As requested by numerous producers, EQM also extended the non-binding open season to garner interest in a second project that would move gas from Clarington to liquidity points further west into Ohio.

This would be compatible with the initial project, but would not impact its timing or its cost.

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

We continue to be focused on earning the highest possible returns from these investments and are doing what we can to increase the value of their shares.

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

With that I will turn the call back over to Pat.

Thank you, Dave.

Jamie, we're ready for questions.

Ladies and gentlemen, at this time we will begin the question-and-answer session.

(Operator Instructions)

And our first question comes from Christine Cho from Barclays.

You had some impressive gains for your third-party gathering and transportation lines.

I know you discussed it but can you talk more about the dynamics of that?

Were you marketing someone else's gas or your own?

Seems like there was some capacity releases too, it was a little unclear to me what's going on.

Also if you could talk about delivery into which markets drove this dynamic?

Randy?

Sure.

Christine this is Randy.

The majority of the activities are selling our own gas into the, really primarily into the TETCO M3 market, but we also have had some capacity releases on our Tennessee 300 line as well, but primarily we enter into those capacity contracts to ensure flow assurance and diversity of market and pricing and so that is primarily to receive the higher prices that we did this winter.

And the TEP 300 line is that mostly for your Huron gas?

It certainly does access the Huron gas but we also have the ability to deliver our Marcellus through other interconnections that we have with other capacities, so we can utilize it in both aspects as well as some of our Tioga gas.

Okay, and then can we talk a little bit more about the second leg of this Ohio valley connector?

When you say you want to go more west, are you essentially trying to go parallel to, you know, a part of Rex?

Because it sounds like Rex is going to be full going the other way.

What pipelines are you trying to interconnect to or markets are you trying to deliver into?

Sure, Christine.

We're looking at -- your point on Rex is a good one, but producers are looking for diversity of markets, including the Midwest.

We'll connect to a variety of pipes along the way but certainly there's the A&R pipeline, Panhandle and such, Tennessee, along the route our pipelines that I think producers are looking for to access both the Midwest markets as well as the Gulf Coast.

The producers are really focused more on that than the fact that it might or might not parallel Rex.

They're interested in getting to other markets.

You pick up more interconnect as you move further west into Ohio.

When you talk about more interconnects as you go west, are you guys also looking to go north, like Michigan and maybe [beyond], and I think A&R is offering that on their pipe.

Sure.

I think what we're looking for, as David said to go further west to hit those liquidity points that will give the producers access to go in either direction, quite frankly, when you connect to some of those other additional pipelines you can go north as well.

Those pipes are working on projects to turn around as you go into the Gulf Coast as well.

I meant the E&P.

We wouldn't be going to Michigan in this (multiple speakers)

No, no, no.

I meant you as a producer; would you look to maybe take capacity to go north?

We'll certainly look at that.

Our overarching driver is to diversify our market and to realize to get to the best markets.

And certainly as part of a diverse portfolio we would consider that certainly.

Okay.

And then last one for me, can you discuss what drove your decision to postpone your 2014 Utica program without even getting any of your own well results?

Is some of this of this based on competitor results?

Or is kind of the thinking around there?

Christine this is Steve.

I think the decision was driven by the fact that the first wells that we drilled were not where they needed to be to have a viable economic play there.

We have some very specific completion design changes we're going to implement.

We just thought it prudent to execute those changes, get the data, evaluate the data, and we do expect, since we're doing it in two phases, we'll make some changes based on the first phase, and then collect the data from the second before we commit a lot of capital dollars into another drilling program.

So we think five wells, we'll learn a lot from those five wells, and we just want to be prudent with the capital investments we're making.

Great.

Thank you so much.

Our next question comes from Neal Dingmann from SunTrust.

Please go ahead with your question.

Good morning, guys.

Say, I was trying to look at just on the basis differential obviously continue very positive for you all.

Just looking at the recent slide you all talk about the price uplift, either for Steve or one of you all, just wondering about -- if you still have the same type of uplift for -- is it still about 35% of the acreage in the wet -- is still considered wet, Steve?

And then secondly, I think on the slide it shows the uplift going from, when it's not processed, around 557 to 676.

Is that uplift that percentage still in line, or is it even going to be higher than that?

I think both of those numbers are still our best estimate.

Okay.

And then what about -- and then if I could ask just a follow-up on that, I think part of that says, what are you seeing, Steve, on the propane side?

Are those numbers holding in as far as like on the product question kind of talking about different markets where you would go?

Wondering about either on the propane, isobutane, or some of these others, how some of those markets right now look for marketing some of those production?

Neal this is Randy.

I'll answer that, obviously you have seen the pricing of propane remain reasonably strong I mean for the exports that have been some of the export projects announced.

We're looking at it in numerous ways to take advantage of that and to get that propane to the best market.

Okay.

Very good.

Thanks, Randy.

Very last question.

Steve, are you still comfortable I thinks got you've got the slide that shows the type curves of the three different areas are those still holding up?

Is there any thoughts about as these wells continue to look solid to say the least, about maybe even bringing those up anytime soon?

Neal, I think as you know our practice is to gather data, analyze it before we update our type curve.

So I think for now those are our best estimates.

The only color I can provide is we've more recently been doing more drilling in the southern Allegheny portion of our acreage, and those wells that are still pretty early in their life, so it's too early for us to incorporate them into a new type curve, but I will tell you that they are -- the results have been a little bit better than we expected, so I think there's reason to be optimistic in that area, but it's very early.

The wells are just coming on line, so we need to see how they hold up before we decide to make any changes either way.

Thanks, Steve.

Great color.

Great execution, guys.

Thanks.

Our next question comes from Scott Hanold from RBC Capital Markets.

Please go ahead with your question.

Thanks.

Good morning.

To clarify, you all provided updated guidance on what you think base is going to be, $0.40 to $0.60.

That just clarify is that just your best view, or do you have some of that locked in at this point?

So specifically could we see that bleed up or down through the year?

And if could you give any color on if going through 2Q, 3Q, 4Q, how that sort of marches on and widens out then tightens back up towards the end of the year.

Yes, Scott this is Randy.

Certainly that's our forecast.

We certainly throughout the year take different positions on hedging our basis, but obviously there's a lot of volatility in the basis going forward.

As you get forward into the year, into the winter, the prices do improve.

So again I think that the key driver for us is that with our diverse portfolio the ability to access all of these different markets continue to provide EQT with very good pricing.

And we're going to continue to utilize our commercial and midstream capabilities to make the best of whatever situation exists, whether you saw the effect of what happens on a cold winter, but quite possible as you get into the shoulder months in the summer that the focus will be on mitigating any negative effects that we get from basis.

So it's not just the basis numbers.

It's utilizing the commercial and the midstream capabilities to get the best realized price for the corporation.

Okay.

Understood.

I guess the crux to my question is if you had a bias, I know that's your best guess now, but what does it look like in the summer, specifically if we were to look at 3Q?

What kind of basis do you think on average that you all would have of that $0.40 to 0.60?

What does it look like in kind of that worst quarter of the year?

I don't know that we have -- I don't think we have a -- if I knew what the weather and such was going to be like I could predict it.

I would tell you the commercial team is doing an excellent job.

They do a great job maximizing the value for EQT and I think we will continue to do that.

But we have no special insight into what M2 is going to be or M3 is going to be or NYMEX is going to be.

We just base it on what we see in the market.

As we kind of joke internally if you know where those things are going you should quit and go into business as a proprietary trader and make a fortune.

But we don't.

We have to deal with the markets as we see them and try to build as much optionality both financially and operationally into our business as we can.

Okay understood.

Appreciate the color.

Just kind of a follow-up on, maybe it was Neal's type curve question.

More specifically to this quarter, it seemed like you had the Marcellus performance is pretty strong.

Was that a lot to do with those southern Allegheny wells?

It seemed like the wells that you tied in was a little less than I thought but production still was a little stronger.

Is that what's really driving the performance there?

That certainly was a portion of it since some of the new wells were in the last quarter in the previous quarter in the southern Allegheny area, but I think overall it's just continued good performance of the wells.

They're holding up very well.

Southern Allegheny was a contributor to that.

Okay.

And then when you look at like your completion backlog grew a little this quarter.

How is that going to progress through the year?

Is that somewhat dictated by infrastructure?

Is it going to be a little lumpy or linear as we go through the year?

It will continue to be lumpy just as it has in the past.

It is driven primarily by drilling and fracking timing, not so much by infrastructure timing, although that occasionally has some small impacts.

It's more with the larger multi-well pads, large number of wells tend to come on in chunks.

So we didn't have a lot of new wells come on-line in the first quarter.

That means in the next couple of quarters we're likely to be a little bit above the run rate.

So it has been chunky, and I think it is going to continue to be chunky just from the nature of our drilling completion practices.

So we should anticipate the production in the next couple of quarters as well lifted a little bit more by a higher amount of [pad drum] being completed, is that a fair context?

I think you just to have keep in mind, turning wells online in a quarter is very dependent, the volume impact of that is dependent on when in the quarter that happens.

So you could have a lot of wells come on late in the second quarter and not have much impact in the second quarter.

So you do have to be mindful of that.

But I think our backlog does indicate that over the next couple of quarters we will have quite a few wells coming on line.

Look we are particularly focused as a company on multi-well pads, often several wells on a pad, and a lot of stages per well.

So that's probably a reason that we could show a little bit lumpier results than some of the peer groups.

There can be hundreds of stages at one pad.

Understood.

Appreciate the color.

Thanks.

Our next question comes from Faisel Khan from Citigroup.

Please go ahead with your question.

Good morning and thanks for the time.

If I could ask another question on the change in sort of the mix change reductions going from the positive $0.64 this year to negative sort of $0.26 last year.

Van you give us a little color on what your expectations are the rest of this year for that number?

We put those specific numbers in the release, Faisal.

That's different from basis assumptions, right?

We gave basis and the guidance on that line item as well.

Okay, fair enough.

I'm looking at your Marcellus capacity assumptions the slide you guys laid out in your slide deck, page 35.

This market mix, is it fair to say that the 11% to 12% that you are assuming for NYMEX, that's all the capacity getting to the Gulf, is that how I should look at it?

That's from back haul, yes.

So everything else basically ends up in M3, TCO, and M2, and that's that pricing which you guys don't know what it could be.

You have assumptions for it but it could be anything over the course of the year?

Right.

Okay.

And then in terms of the injection rates into storage for you guys is there any sort of, given what kind of winter we had this last few months, is there any sort of restrictions on the injection rates into storage in terms of getting back out to full capacity before the next winter season starts?

This is Randy.

As you probably know a lot of the northeast storage is reservoir storage so there are certain, from a utilities perspective there's a certain amount of injection daily that's required, but certainly the filling of that storage will be challenged throughout the year at the low levels.

So physically and contractually there are some limitations.

Okay, got it.

Looking at sequential depreciation and amortization D&A from the fourth quarter to the first quarter, it looked like it ticked down.

Just trying to figure out exactly what caused that to happen.

It was based on the reserve report that we released during the year end.

Increase in proved reserves.

That's mostly what drove it down.

I think it was $1.50 last year.

It was $1.21 in the first quarter.

Got it.

Thanks, guys, appreciate it.

Our next question comes from Michael Hall from Heikkinen Energy Advisers.

Good morning.

Congrats on the update.

Just want to come back a little bit on the outlook around basis and marketing.

Number one, through the summer, that $0.64 gain that you had in the first quarter, you have given the guidance for the rest of the year, I think implies probably around $0.20 or so, negative on the gathering and transport.

I'm just trying to understand to what extent there's a possibility that as we work through the summer and into the fall as regional prices look likely to be pretty volatile, to what extent do you have ability to repeat what we saw in the first quarter and kind of surprised to the upside by accessing other markets?

Was that purely a weather driven phenomenon in the first quarter, or is there really a flexibility that's provided by that line item that can really offset any basis headwinds as we make our way through the summer?

Yes, Michael, Randy again.

They're both.

Certainly the weather had an impact but these capacity constraints and the optionality that EQT holds and has continued to hold upstream firm capacity contracts certainly provide us the optionality to improve pricing.

It's easier to make a lot of money on it, frankly, when there's a lot of demand, to be as straightforward as possible.

Kind of getting into some of the operational issues, one thing I'm maybe not sure we related as anecdote, there was a circumstance where some of our commercial folks saw an opportunity to move gas in a different direction, but it wound up that we had to utilize a compressor station that actually hadn't been run for while, so the operations folks in midstream went out and restarted the compressor station and flowed gas to take advantage of that opportunity.

And we will continue to try to leverage our various capabilities to be able to do that.

It is just a lot easier to do it when we do have high demand.

Okay.

I guess I'm also just trying to understand if it's in part a function of when you have these big inter-regional spreads across these different price points if that creates an opportunity.

So even if you do see a lot of negative basis throughout the region, if there's a lot of variability across those different points that there's an opportunity for you guys to then -- (multiple speakers)

-- as long as we have the assets in place.

I think what you will see going forward is that we're going to continue to -- an asset strategy that allows us to have more optionality going forward.

That's helpful.

And then looking out to 2015 you provided the mix in the slide deck today for 2014 as it relates to the different price points you are selling to, which is helpful.

How should we think about that evolving in 2015?

Is it materially different where we stand today versus what 2014 looks like?

And then I guess as a follow-up on that.

At would point, as we think about reversals and changing flow dynamics in the Northeast, at would point do you see an environment and I know it's hard to predict, but where maybe we get back to a more normalized type setting for basis in the Northeast?

I'll take your first part.

David mentioned in his comments we have the team 14 capacity that comes on in November of this year.

That capacity allows us to move gas both to the Northeast city gate markets as well as to the Gulf Coast.

So that again will have an impact in 2015 on our realized prices and the optionality.

And your other question was really I guess about the growth in production and that exceeding local markets.

Certainly again that's why we go forward with our continuing to get our capacity in excess of a variety of markets.

And over time we will get to a point where there will be more enough infrastructure to take the gas to the market.

But that will be a new steady state.

So we're not particularly worried over time about the basis flowing out in a negative way here, but it is going to wind up reflecting the cost of those reversals, et cetera.

So, we look forward, and we see that our region of the country is going to be a net exporter to other regions of the country, and that's going to get reflected in basis, but that basis within over the next three, four years, that starts correcting so that it meets up with, matches what the cost is of moving the gas.

And what is that cost currently as you start looking at?

It depends on where you are going.

The example of the tariffs on the new pipeline projects as they come on.

Last one on my end is just in the Utica what are the completion design changes that you are bringing forward on these next five wells?

What's different versus the prior well?

This is Steve.

That's a topic that we're not ready to talk about.

If it works, we want the techniques to remain proprietary for awhile.

And if it doesn't work, you won't really care.

(Laughter)

Fair enough.

Great.

Appreciate it.

Congrats on highlighting the power and flexibility in your business model.

Thank you.

Our next question comes from Andrew Venker from Morgan Stanley.

Please go ahead with your question.

Morning, guys.

In West Virginia there's some talk about a pretty nice Utica play.

Do you see that as perspective on your acreage?

Andrew, this is Steve.

We're certainly monitoring the results from our competitors in the dry gas Uticas, and certainly as it seems to be moving further east toward where we have larger holdings.

That said, we're currently updating our geologic review of the play which we did a couple of years ago, and right now all I can say is we're updating our assessment of the play and hope to be able to report a little more detail later in the year, but for now we're monitoring what's going on and taking a closer look at the geology and how our assets sit on top of that.

Can you provide some color on just the geology?

Is it higher pressure than the Marcellus that sits right on top?

It's certainly higher pressure.

It's clearly very widespread from a geologic standpoint.

I think the producibility of reservoir in certain areas is still an unknown.

I think one of the biggest challenges for us that we're looking hard at is the depth.

So from a cost standpoint the wells are going to be expensive.

Where most of our acreage is the minimum depth we'd be looking at is 10,000 feet all the way up to north of 13,000, perhaps even closer to 14,000 feet in some areas.

So that's a cost challenge as well as a completions challenge.

So we have questions that we need to dig into concerning what will it take to stimulate this reservoir, particularly at the 12,000 foot depth at the pressures we have been looking at.

Can we effectively pump the rates we think we would want, what kind of equipment would it take, what kind of well bore design would it take, and therefore what would be the cost and the economics?

So we're looking into all of those aspects.

But clearly the challenges get a little more difficult as we move further to the east and deeper into the basin.

Is there any significant chance that gas there is overcooked, or are you fairly confident that it's just dry gas?

It's a huge play.

So I don't think you can make blanket statements.

Clearly there are areas where it's not every cooked, but as you approach the deeper areas of the basin it is certainly possible that it is.

So that's where I'd say the producibility is an unknown, especially as you get further to the east.

Okay.

Thank you.

And our next question comes from Joe Allman from JP Morgan.

Please go ahead with your question.

Thank you.

Good morning, everybody.

On the Marcellus, are you set with your completion techniques, or are you still modifying some of the completion techniques?

I'll tell you, we'll never be set object our completion techniques.

That will be a constantly evolving practice for us and for probably our competitors.

I don't know that -- we're trying to know an unknowable when it comes to stimulating these reservoirs.

We'll never know all we would like to know to have the perfect design so you should expect we will always be (technical difficulty) on our completion process.

Could you talk about some of the recent modifications you made and the impact on production?

I'd rather not talk about specifics.

More recently the changes for the Marcellus in our core areas where most of our drilling has been have been focused on small changes around sand sizing, pump rates, stage sizing, those types of things.

The normal things that completions engineers would be looking at.

In central PA where we have a, there's a test program going on, we're a little earlier in our understanding of that rock, particularly around how we design our completions around faulting, there's more faulting up there.

So those are sort of the aspects of the design that we're focused on up there, more than in the quieter and core parts of the play for us.

But that's about as specific as I'd like to be.

Okay, that's helpful.

I know the Utica is not nearly as important for you as some other plays, but could you just repeat what you are going to do there?

Because I think you drilled seven wells.

Have you completed two already and you're just not terribly satisfied with those results?

I think you said you are going to complete three using a different technique.

And then are you going to complete the next two using yet another technique?

Could you just describe what you are going to do?

Yes.

Actually, I think we drilled eight wells.

Three are online.

The results are certainly not where we'd like them to be and not competitive with our other investments.

So if we can't make improvements, it's not a play we put any more capital into.

However, based on those results and the data we collected during those completions, we saw some very specific things that we want to address in the next phase which will be three wells that we're currently implementing right now.

So we're going to finish fracking those wells, get them on line mid year, get some results back, gather some more data.

Based on that we have two more wells that have been drilled that we will likely modify the completion design again, frac those, get the results that will be late in the year.

Then based on all of that data we'll start to make some decisions about do we move forward in this play or do we not move forward, and we'll update you at that time on what we think.

That's a year from now probably.

Got it.

Very helpful.

Thank you.

And everyone at this time I'm showing no additional questions I would like to turn the conference call back over to management for any closing remarks.

Thank you, Jamie.

And thank you all for participating.

Ladies and gentlemen, that does conclude today's conference call.

We do thank you for attending.

You may disconnect your telephone lines.