EQT Corp (EQT) 2011 Q4 法說會逐字稿

Good morning, and welcome to the EQT Corporation year-end 2011 earnings conference 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 Patrick Kane, Chief Investor Relations Officer.

Please go ahead, sir.

Thanks, Laura.

Good morning, everyone, and thank you for participating in EQT Corp.'s year end 2011 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.

In just a moment, Phil will summarize our 2011 operational and financial results, which were released this morning.

Then Dave will provide an update of our well development programs, reserve reports, and strategic operational matters.

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

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

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

The confirmation code for the replay is 447033.

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

But first, I would like to remind you that today's call may contain forward-looking statements relating 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 10-K for the year ended December 31, 2010, which was filed with the SEC.

And is updated by any subsequent Form 10-Qs, which are also on file with the SEC and available on our website and in the Company's upcoming 10-K for the year ended December 31, 2011, which will be filed with the SEC.

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

Please refer to the morning's press release for information on these non-GAAP financial measures.

I would now like to turn the call over to Phil Conti.

Thanks, Pat, and good morning, everyone.

As you saw in the press release this morning, EQT announced 2011 earnings of $3.19 per diluted share compared to $1.57 per diluted share in 2010.

After adjusting for several items which cumulatively added $148.4 million to our net income, our adjusted EPS was $2.21 in 2011.

The adjustments to net income include the impacts of the sale of Big Sandy pipeline in the third quarter, the purchase of the outstanding interest in ANPI in the second quarter, the sale of the Langley natural gas processing complex, an adjustment for non-income tax matters in the first quarter and a gain on the sale of some available-for-sale securities in the first half of the year.

Operating cash flow, which was not significantly impacted by these items in 2011, also increased by $236 million, or by about 36%.

These results were driven by another outstanding operational year at each of EQT's business units.

Leading the way on the annual operating performance was a 44% increase in sales of produced natural gas and liquids at EQT Production, which represented our highest annual sales growth rate ever.

Gathered volumes at EQT Midstream also increased by 32%, trending up with the higher volumes at EQT Production.

The EQT average wellhead sales price was $5.37 per Mcf in 2011, or about $0.25 lower than in 2010.

The realized price drop resulted from lower NYMEX natural gas prices in '11 as compared to '10, partially offset by higher natural prices liquids prices.

Approximately 7% of EQT's total production in 2011 was in the form of liquids.

For segment reporting purposes, of that $5.37 per Mcf of revenue realized by EQT Corporation, $4.04 per Mcf was allocated to EQT Production and the remaining $1.33 per Mcf to EQT midstream.

Overall absolute costs increased, as expected, given our outstanding growth rate.

But on a unit basis, the total cost to produce, gather, process, and transport EQT's produced natural gas and NGLs was down about 22%.

The fourth quarter results basically mirrored the full year, so I do not intend to discuss them in detail.

However, I will point out that the revenue deduction for third-party gathering, processing, and transportation was $0.43 for the full year of 2011, and $0.29 in the fourth quarter, as shown in the table in this morning's press release.

The fourth quarter number was positively impacted by the Company's ability to resell its unused contracted capacity on the recently completed El Paso 300 line, at unit rates above what we currently pay under the existing agreement with El Paso.

The margin from capacity that was sold under short-term contracts -- that is, contracts with a duration of less than a year -- reduced the revenue deduction by about $0.$0.12 per Mcf on gas sold by EQT in the quarter.

Put another way, by adding the $0.12 to the $0.29 reported in the fourth quarter, a reasonable per unit rate, run rate for the deduction for third-party gathering, processing, and transportation in your models, would be approximately $0.41 per Mcf.

This number will be impacted positively or negatively going forward, depending on market rates we will receive for the resale of our 300 line capacity that is not currently reserved for EQT Production, or under long-term resale contracts with third parties.

Moving on to a brief discussion of results by business segment.

Starting with EQT Production.

And there, as has been the case for several years now, the big story in the quarter at EQT Production was the growth rate in sales of produced natural gas.

As I mentioned, the growth rate was a little bit north of 44% for the year and was slightly north of 37% for the quarter.

By the way, the sixth straight consecutive quarter of more than 35% rolling year-over-year growth.

Those growth rates were driven by sales from our Marcellus wells, which contributed 42% of the volumes in 2011.

In the fourth quarter, Marcellus sales volumes accounted for 47% of the total volumes.

Total sales volume would have been about 300 Mcf equivalent higher for the year and the quarter, but for a dehydration equipment malfunction in December.

Unit realized price at EQT Production was slightly, or about 3% higher than last year, even as the Corporation's realized price declined a bit, as I already mentioned.

This is one of the benefits of an increase in the Marcellus sales percentage, as the Marcellus gathering rate is $0.60 per Mcf compared to $1.25 per Mcf for the majority of our other production.

Moving on to expenses in the production unit, total operating expenses were $90 million higher year-over-year.

Absolute DD&A, SG&A, LOE and production taxes were all higher, consistent with the significant production growth.

DD&A represented about $73 million of the $90 million increase.

Absolute LOE was a bit higher year-over-year.

However, volume increases have been outpacing the general trend of higher absolute expenses.

And as you would expect, per unit LOE was lower in 2011 by about $0.04, or 17%, to $0.20 per Mcfe for the full year 2011.

Moving on to the Midstream business, excluding the gains of the Big Sandy and Langley sales, operating income here was up about 19%, consistent with the 32% growth in gathered volumes.

Mainly from EQT's Production's growing sales volumes.

And that resulted in an 18% increase in gathering net operating revenues.

Transmission net revenues also increased by almost 7% year-over-year, as a result of added Equitrans capacity from the Equitrans Marcellus expansion project, and increased throughput, more than offsetting revenues no longer received from the Big Sandy pipeline.

On the other hand, the line item titled Storage, Marketing, and Other Net Operating Income was down about $7 million in the fourth quarter and $35 million for the full year.

This part of the Midstream business, as we've talked repeatedly about, relies on seasonal volatility on spreads and the forward curve.

And those continued to trend down in 2011 versus prior years.

Also, the loss of processing fees from Langley third-party liquids resulted in lower marketing revenues.

For 2012, we expect revenues from storage, marketing, and other, to be approximately $45 million.

Net operating expenses at Midstream were about $27 million lower year-over-year.

Lower O&M and DD&A expenses, which collectively were $28 million lower year-over-year, represented basically the entire absolute decrease in Midstream expenses.

The absence of expenses associated with the sold Big Sandy and Langley assets and reductions in non-income tax reserves resulted in those decreases.

Then in conclusion, finally with our standard liquidity update, we did close the year in a great liquidity position with zero dollars in net short-term debt outstanding under our $1.5 billion revolver.

And about $830 million of cash on the balance sheet.

As detailed in the press release, due to the current low natural gas price environment, we have lowered our cash flow forecast for 2012 by about $100 million.

And therefore, consistent with our intent to live within our means, the Company has decided to discontinue drilling Huron wells.

As a result, our 2012 CapEx forecast decreased by about $135 million to $1.465 billion for 2012.

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

Thank you, Phil.

2011 was another record year for EQT.

Earnings per share, operating cash flow, sales volumes, midstream throughput, and natural gas reserves were all higher than ever before.

Though the primary purpose of this call is to communicate with investors, I first wish to convey my congratulations for these accomplishments to the 1,800-plus employees at EQT Corporation.

Having such a strong group managing our assets gives me confidence that we will continue to earn premium returns for our shareholders.

Sales of produced natural gas and liquids were 44% higher than in 2010.

This is on top of 30% growth in 2010 over 2009.

Put another way, our daily sales volumes, when we exited 2009, totaled 300 million cubic feet.

We exited 2011 at 580 million cubic feet per day, 93% higher in just two years.

The Marcellus continues to drive our growth.

Marcellus production accounted for 47% of our sales of produced natural gas in the fourth quarter.

EQT has tremendous assets.

While our objective is to maximize value creation rather than volume creation from these assets, the only practical way to do so is by economically monetizing our extensive reserve base, via production and other means.

And by extracting value from our midstream assets and midstream opportunities.

However, we believe it is also necessary that we live within our means financially without issuing equity.

In 2011, I believe we made great strides towards doing so, but the work continues.

I would like to review a little of how we did this in 2011 and also how we intend to do so in 2012.

In 2011, we invested $1.4 billion into our business.

We funded this investment with $900 million of operating cash flow, plus $620 million of Midstream asset sales.

Proceeds from the asset sales came from the outright sale of two assets.

We examined other structures and assets, but determined that selling these two assets outright was the best approach.

For 2012, we have decided that the best approach to create value is again investing our operating cash flow, plus also utilizing other available capital.

This other capital includes utilizing our investment grade debt capacity, which we did in late 2011, and further monetizing Midstream assets by forming an MLP.

As we announced last month, we plan to file the S-1 this quarter, but we recognize that this merely starts the process with the SEC.

The advantages to EQT shareholders of forming an MLP include maintaining operational control of where, when, and to what specs gathering is built.

Access to an ongoing source of low-cost capital.

And participation in any MLP distribution growth.

Of course a publicly traded currency would also provide a market view of the value of the MLP's assets.

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 largely unaffected by the changes we have experienced lately.

Tactics, however, can and should change.

Despite a bit of a rebound this week, natural gas prices are down sharply since we established our capital budget in December.

Lower prices impact us in two ways.

First, they reduce cash flow from operations and thus cash available for investments.

We have over 50% of our dry gas hedged at an average price of $5.43 and about 7% of our production is in the form of NGLs and oil.

Incidentally, recall we include ethane in our dry gas numbers since the netbacks for ethane are essentially equivalent to methane on a per BTU basis.

Even so, based on cases we ran using last week's lows for the 2012 strip, our 2012 cash flow estimates were almost $100 million lower than when we established our capital budget.

Lower prices also reduced the projected returns of our drilling program.

Marcellus returns are still strong at the current five-year strip, about $3.90.

We also stress test our investments and the projected returns are still adequate at a $3.00 NYMEX strip.

Please do keep in mind that the lags between spending capital on Marcellus wells and selling natural gas produced from those wells is several months.

Meaning the relevant five-year strip looking at 2012 investments is actually the 2013 to 2017 strip, which is currently somewhere north of $4.00.

Therefore, it is clear to us that investments in developing a Marcellus play are attractive, though they would obviously be even more attractive at higher prices.

Regarding our Huron wells, even though they are liquids-rich, their returns are still below the Marcellus wells.

But since lower prices mean a reduction in operating cash flow and we are committed to living within our means, something has to give.

That something is the Huron and this is why we have suspended drilling in that play, effective immediately.

We will complete the wells that we have already been spud and continue to produce from existing wells.

This decision will reduce our 2012 CapEx by about $135 million.

And reduce our forecast of sales of produced natural gas by approximately 5 Bcfe.

The effect of this decision on volumes in the out years is a decline of 6 Bcfe in 2013 and a little over 3 Bcfe in 2014.

The fact that the lag between drilling and sales in the Huron is much less than in the Marcellus is why the 2012 impact is as large as this, and the 2013-2014 impacts are as small as they are.

Normally, one might lean away from cutting spending in an area in which we experience a shorter lag, but 2012 is not shaping up as a normal year.

I would now like to comment on our reserve report, which was released today.

Our continued success in the Marcellus resulted in a 535 Bcfe, or 18.5% increase in proved reserves.

This increase was partially offset by a 413 Bcfe decrease in Huron proved reserves, as we eliminated all of the proved undeveloped reserves, consistent with our decision to suspend drilling of Huron wells.

I remain confident that this play has value for our shareholders, but we are not going to be pursuing that value via the drill bit in the near future.

So, our moving these PUDs now seemed appropriate.

Further regarding reserves, we continue to have success with our experiment with tighter frack clusters.

As we previously noted, this design works best in the more brittle areas of our play.

Brittleness is also positively correlated with higher EURs using the standard frack design.

With a year of well data in Rogersville, Greene County, we estimate an IP 40% higher than a standard frack well.

With EURs trending 20% to 25% higher.

Our 2012 plan includes 49 wells using this design, with about half applied where we have well control, and half to derisk areas where we predict success.

We still do not have enough data to book many reserves or extrapolate these results across our acreage, but are excited about the results so far.

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 doing what we should to increase the value of your shares.

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

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

Pat?

Thanks, Dave.

This concludes the comments portion of the call.

Laura, could you please open the call for questions?

(Operator Instructions) Neal Dingmann of SunTrust.

Dave, just wondering, if you could quick comment on -- obviously on the new frack design that you've talked a lot about and had seen, obviously, quite incremental results.

Again, with what's going on with gas prices, does that cause you to give pause to that, or does it actually cause you to increase?

Just wanted comments around that and if you're going to continue to ramp that out?

I'll let Steve comment mainly on it.

But we do focus, and we have focused all along, on the extent to which we're getting increases in EURs versus just acceleration.

As you can see from the numbers, a lot of it are results that we're getting from increased EURs.

So it's really just a more efficient way to spend.

In theory, if you could spend the same amount of money and have the same volume come from fewer wells, you would have a lot of efficiencies in other aspects of the business.

And a lot of that is what we are seeing.

We certainly understand that this is not a timeframe in which you would seek acceleration for its own sake.

But we do take that into account when we're looking at the projected returns.

And actually, Steve, would you like to add anything?

I think the only thing I would add is, you'll notice that 50% of the wells we intend to use that technique on in 2012 are in our, we call our Rogersville area in Greene County.

Where, as we get more data, our confidence level continues to rise, that we are actually seeing quite a fairly significant increase in ultimate recovery.

Our numbers, even at the current strip prices, show the returns on that incremental capital to be in excess of the base return on our Marcellus drilling.

So I think even with exceptionally low prices on half of those wells, it makes excellent sense.

The other half are still, I would call them experiments.

But based on what we've seen in Rogersville, where we have the most data, we feel like those experiments are worthwhile.

And they are targeted in areas that, based on the geology, we expect good economic returns, but we need to gather more data to be sure.

And Steve, your focus on this Rogersville area, is it more because of the continuity of the play, or is it because of the particular formations of this?

What has you focused on this area?

One, the initial results we got were very encouraging.

So that obviously attracted our attention.

But I think the reason that it's a clear winner is the brittleness of the rock is pretty high there.

So higher silica content in the rock there than we have other places.

And that seems to be a key factor in having this technique increase recovery.

Okay.

And, Dave, maybe for you or Steve, as far as just a quick comment on services out there.

We obviously continue to see more an exodus from some of the gas plays to oil plays.

I'm just wondering how that factors into what your service forecasts are for the remainder of the year.

On the fracturing side, which is the bulk of the spend on a well, our prices are pretty fixed for 2012, so I can't tell you we're going to benefit in the short term from any softening in the market.

On the rig side, we do have a couple of new rigs coming into the fleet in the next couple of months that have lower average day rates than what we're currently spending so we'll see a little bit of an improvement there.

And generally speaking, we are very aware that they are finally -- finally -- the leverage is shifting back to the producer community from the service community.

It's just that this decline has been really, the steep decline has only occurred over the course of the last six to eight weeks.

So we are very focused on getting more efficiencies and lower costs in that front.

I can't give you specific numbers on it right now.

Sure.

Okay, very good.

And then last one, if I could, it looked like with the reallocation of the capital and the CapEx, you did, as you mentioned, admittedly pull back a little bit on the upstream side.

But it looks like going forward on the midstream.

Do you still see, around the MLP and just I guess I could say the midstream in general, the same opportunities as far as, besides Equitrans, just to continue to build out the midstream and able to have the benefits around controlling your midstream?

And that's why we didn't see any pullback on that side per se?

Absolutely.

Even though there's been a lot of talk about pulling back, even with some of the discussions from a variety of others about the Marcellus, and moving some of their activities away from the Marcellus, et cetera, all we're talking about for the Marcellus at this point seems to be the rate of growth.

What we see, and I think what others who participate here see, it is the most economic natural gas play in the country.

Continues to be economic at these prices, therefore continues to need midstream.

So even though there are cash flow issues when prices drop that we all have to be focused on, the economic attractiveness of the midstream continues to be there.

I absolutely agree with you, Dave.

Thanks.

Anne Cameron of BNP Paribas.

Just a question on your Midstream.

Is there anything, like now that you're planning to file the S-1 this quarter, is there anything before or after that point until you do an IPO that prevents you from receiving bids on that from a third party?

No, there is nothing about that that prevents us from receiving bids, having conversations, et cetera.

Okay.

And are you still talking to any potential bidders or partners?

I'm not sure that I want to comment on that, if you don't mind.

We remain open minded, maybe I can leave it like that.

We remain open minded.

Just so you know, the only time a company gets committed on an MLP -- it's not with the first filing of an S-1.

It's when you ultimately finalize the entity.

So even a filing of an S-1 would not change the things I just said about the open-mindedness, et cetera.

Thank you, that's helpful.

And then just a question around your West Virginia liquids production.

The plant that MarkWest is building in Logansport -- that is going to increase your liquids yield on your Marcellus production.

So how much of your current NGL volumes are actually coming from West Virginia, and what's that going to do to them?

Randy?

Most of our liquids production comes out of the Huron play.

We're currently, as we mentioned, we have a JT skid that we process out of Doddridge County that provides a 0.5 gallons per Mcf that is produced.

And when our plant comes on, that will increase to 2.5 gallons per volume produced in the wet area.

Okay, thanks.

And that's July, correct?

Yes, right.

That is a mid-year thing.

So we would expect that you would see a big jump up in our liquids numbers once that plant comes online.

Okay, super.

Thank you very much.

Scott Hanold of RBC.

Dave, can I ask you, what would it take for you guys to drop a rig in the Marcellus?

How bad does gas have to be for you guys to make that decision?

I don't know.

We tested it against the current prices.

And by current I actually mean, what we decided was the prudent thing to do was to test it against the lows that we hit last week.

And of course clearly it could test those lows again.

And it still makes a fair amount of sense to continue with our approach in the Marcellus.

So we keep challenging ourselves on all of this when the environment changes.

Maybe the safest thing I can say, and most accurate thing I can say, Scott, is that so far what we've seen wouldn't cause us to make those alterations and drop a rig.

Certainly you can imagine -- at this point, who wouldn't be able to put out a number and say -- Here, what if gas prices went to, I don't know, what if gas prices went to zero and stayed that way forever?

And how much would you like to drill?

And obviously then you wouldn't.

But within reason, I don't see that being something that we're concerned about.

We will look at the cash flows, obviously.

That would be the thing that would cause us to change something, is if we thought because of prices, that cash flows were drying up enough that we had to make some other form of move.

And then we would take a look at the rest of the operations to see what other form of move was required.

But as I think we described with the Huron, that saves us enough so that it more than makes up for the cash flow reduction that we saw, even at last week's lows.

So certainly it would have to go below last week's lows for us to be worried about the cash flow.

Okay.

So, obviously things are moving quick and fast, and some operators have made some deeper cuts at this point, and you obviously made a decision there in the Huron.

But, throwing numbers out there, if gas was at $3.00, $3.50 on average through the end of 2013, it comes down to, not necessarily a Marcellus economic question, but it's more of what your cash flow capabilities are in funding for that.

Is that a fair way to conclude?

That's exactly right.

Which means these other things we're talking about with regard to midstream monetization then factor into this heavily, as well.

Okay, understood.

A question on the production during the quarter.

I think you mentioned the exit rate was like 580, and I think your average during the quarter was 576.

It looks like you may have had a little bit of a backlog of wells to be brought on.

Is there a bit of a backlog there right now that you'll be working through in the first part of this year?

You want to comment on that, Steve?

There is a bit of a backlog.

I think if you look at our earnings release, you'll see we have a larger number of frac stages complete but not online than we typically have.

The bulk of that increase is in our wet area of the Marcellus, where we're waiting for the MarkWest plant to be operational.

Normally, we probably would not have fracked those wells yet, given that that won't be online for a few more months, but because of the West Virginia regulations regarding reclamation of pits, we needed to go ahead and frac those so we could reclaim the pits in the proper time.

So that's a temporary influence and it means we'll have a lot of liquids-rich gas ready to go when the plant's online.

Okay, got it.

And lastly, looking at your reserves, obviously the adjustment, the Huron and some CBM adjusted that number downward, But just stepping back and looking at it, it seems like your reserve additions, you were a bit light relative to prior years, considering that your CapEx spend is at least those levels.

Can you give a little color on that?

Yes, that's mostly a function of where we decided to drill.

The bulk of our drilling was focused in areas where we already had a lot of proved reserves on the books.

So we weren't really out into new areas where there's a lot of room to add new proved reserves.

Combined with the fact that if you look at the prior couple years, we had added large amounts of proved reserves.

I think it was just the nature of the beast, given where we decided to drill.

Because when we decide to drill, we focus on where we get the best returns and really don't factor in what the reserve addition impact's going to be.

And this year, as a result, we had lower additions.

Yes, we never manage -- at least as long as I've been here -- we have not managed to a reserve number.

We haven't tried to dot wells.

When we're coming up with our development plan, we have not tailored it with offsets in mind, et cetera, to create a particular growth pattern to the reserve.

We come up with the most economic development plan and then we let the reserves fall out the way they do.

And obviously, then, when you're focusing on drilling in a more concentrated area, you're going to tend to get less reserve adds.

When you're having more step-outs, you're going to tend to get more reserve adds.

Okay.

Understood.

I appreciate that.

Thanks.

Gil Yang of Bank of America Merrill Lynch.

I just wanted to follow up on this issue of the well backlog and talk about implications.

Is there any risk, or what do you think is the risk of having these wells fracked?

Presumably, they are just sitting there with a frac load in the well?

Or what's going on with those wells?

A lot of times, we'll flow them back to clean up the bulk of the water and then shut them in.

Sometimes we'll leave the full load in.

If your question's about a concern of reservoir damage, I would refer back -- I think we talked about this a few years ago.

For a time there, we actually were thinking that it might be beneficial to leave that load in, based on some results we had seen.

We backed off on that.

But what I can say is we have never seen any negative impact of keeping the frac load in the well for extended periods of time.

So just doesn't seem to damage these Marcellus wells.

Okay.

Do you have a rule of thumb for how much volume you expect to get out of each stage?

That varies by area.

I would probably refer you to our type curve information on our website, and you'll be able to calculate by area what that is.

Okay.

The type curves are based on a 5,300-foot well, so you can ratio that for different lengths.

Okay.

Now, was the buildup in the backlog in any way related to your willingness to sell the excess pipeline capacity?

No, not at all.

It's just that when you enter into those kinds of agreements, you're entering into long-term agreements.

And you're forecasting what you're going to need several years out.

And since you grow into it, the odds are you're going to have excess capacity in the early years.

So we knew that going in.

Frankly, when we looked at that particular line, the one that we've been talking about having made some money on at the very tail end of 2011, that El Paso 300 line, we also felt more comfortable making that commitment because we have a sense that in the early days, there's probably going to be a little bit of money to be made on that anyway.

We do plan on growing into that capacity, though, just so you know.

Okay.

Can you give us an idea of when you grow into the capacity?

Over the next -- actually, I'm not sure if we've released this before -- but how far out do some of the contracts -- what's the longest term of the contracts?

About 15-year.

No, I mean that we sold down to other people.

Didn't go out more than a couple of years.

And that's a good point.

We did no more than two years, and one for three years, small level.

So, no, we intend to grow into that over that period of time.

Okay.

So in effect, the transportation subsidy, if you will, from selling at a higher price than you paid for, will lapse over the next two or three years and will head for that $0.41?

The potential is there.

Obviously, just following the basis markets, you would assume it will tend to be higher in the winter than it will be in the summer.

And we've layered those contracts in so that, as Randy said, there's one that goes out for three years and then there's another that goes to two.

And then there's others that are shorter term than that to the point of monthly and even daily.

So it gradually goes away over the course of the next two to three years.

This is Phil Conti.

That's why I tried to guide you.

The $0.12 that I said add back to the run rate for the fourth quarter is the part that's not subject to long-term deals.

So we'll either do better than that or worse, depending on what the market's like, call it, next winter.

So in a simplistic sense, it should go from the current number $0.29 up to $0.41 over the next two or three years, right?

You should use $0.41 right now.

As I said, some of it is under contract.

We've baked that into that calculation and we're just telling you that depending on what the market's like when we go to sell that capacity next winter, it could be more or less than that $0.12 impact.

But we think $0.12 is a good number for you to run with.

So add $0.12 to the $0.29.

We'll continue to quantify how much was from the resale each quarter.

I'm sorry.

I missed that.

We'll continue to provide guidance, or quantify how much of the impact on that transportation fee is each quarter, as we report.

And we'll try to come up with a way to be as transparent on this stuff as we can.

Because the reality is, as we continue to layer in other transport contracts, they are going to have the same feature, where you layer something in for the long-term.

You're not going to be using all of it in the early years.

Because obviously, unless you can guess perfectly correctly, which I think everyone in our industry has demonstrated that we cannot do, I think we join other industries in that inability, you have to choose.

Do you want to have too little capacity or probably err a little bit on the side of having more capacity.

And you wind up with a little bit more.

So it means we're probably going to have more of this excess as we enter into other contracts.

But that's not to say that it's going to be worth more than what we're paying.

We enter into it assuming that we'll be able to cover the costs, but not profit from it.

It just happens that there's a lack of capacity going into some of the northeastern cities right now.

All right.

And just a last question.

I missed the number.

How much liquids volumes do you expect to come on when that JT skid comes online?

I mentioned the 2.5 gallons.

We hold 120 million a day of capacity into that plant going into the summer.

And so, again, that number also does not include ethane.

That's not the JT.

You asked on the JT skids.

We use the JT skids to get the wet gas down to pipeline specs routinely.

So the increase that Randy's talking about is actually when we don't have to use those JT skids there anymore because we're going through that MarkWest plant.

Okay, great.

Thank you.

Joseph Allman of JPMorgan.

Just a couple questions.

One, the base decline for your Huron production, what would you estimate your base decline is?

We gave the 6 Bcf decline next year from this year's run rate, and then another, a little bit over 3 Bcf for the year after that.

Okay, got you.

And then on the drop in the CBM possibles, what's the reason for that drop?

I think some of that was economics driven.

Some of our CBM drilling at these really low gas prices, it was hard to even keep those in the possible category.

Okay.

Anything performance-related?

No.

We haven't drilled in that field for a while, so there is no new, new production information.

And our PDPs, there was no revision to those.

The performance there is, at these prices, mediocre.

It's just not any worse than it was a year ago or two years ago or five years ago.

It's not that.

It's that in this price environment, it has a hard competing against Marcellus gas and associated gas.

I got you.

And then in terms of your booking per well in the Marcellus, in your release you indicated that your PUDs, you booked at 6.3 Bs, and that appears higher than year-end 2010.

Because I think in Pennsylvania, you booked 6.3 Bs, but in West Virginia, 4.7.

So it appears that you increased the per well EURs, assuming shorter laterals actually.

So could you just clarify that?

And then this year, you booked the proved developed at 5.7 Bcfe.

How does that number compare to the year before?

I think to your first question, two factors came into play.

One was improving well performance, and the other is mix.

We had a higher percentage of PUDs in our very best area this year than we had last year.

So those two factors came into play.

Could you repeat the second part of your question?

Yes, just for the proved developed, you booked your proved developed at 5.7 Bcfe per well.

What's the comparable number in 2010?

4.5 Bcfe per well last year.

That's helpful.

So in terms of the new frac design, how many wells have you drilled so far using that new frac design?

I believe it's 27, plus or minus a couple.

Okay.

And then in terms of -- someone asked a services question -- are you having any issues or any concerns about just logistics, getting sand or any other materials?

No, no problems at all.

Okay.

And then just on the comment on the midstream, you guys made a conscious decision to not sell it outright.

So I'm assuming just the openness that you express is really just, if you get a really great deal, right?

I had a feeling actually that this had to do with the other alternative that's long been on the table, which is a joint venture.

But you're right.

Look, we're in business to create value.

And so across the board, anything that will create value for the shareholders is something we're open to.

But the nature of the discussions that had gone on in the past about the MLP were really more along the lines of various forms of joint ventures.

Right.

But the earlier question, I think, if I'm not mistaken, was, are you open to just selling it outright, and you said you're open.

Because we're open to anything.

The question for us is where do we get the most value for the shareholder.

Right, but you've already gone through that whole thinking process, right?

We have, but if you're trying to give a hypothetical, if somebody's coming in with whatever number we think is the value and they are adding a zero, then that changes our view.

You can't answer yes/no when it's value, because that's all in the eye of the beholder.

And we can't predict whether us saying we'll file an S-1 or actually filing an S-1 will alter the way other folks will view it.

We're very aware.

You look out in the market -- you don't have to look very far to find folks who announced a transaction and then that focuses the mind of somebody else and they react to it by putting a different -- kind of sharpening their pencil.

That stuff happens, and we don't want to stick our head in the sand and pretend it couldn't happen here.

Sure, but there's no change in your thinking versus your last disclosure.

No.

That's exactly correct.

And control of the assets, the ability for you to be able to grow your Marcellus at the pace that you want hinges on having some control of the midstream.

It has value to us.

I don't know if I want to say hinges on, because that turns it into a black or white.

It has value to us.

Got you.

Okay.

And lastly, what prices are you using for your CapEx budget for 2012?

What we tested it at, all the numbers that we gave you were based on a $3 or a little below $3 strip for '12.

For the cash flow estimate.

The budget was set based on the cost per well, and the number of wells.

Okay, got you.

Very helpful.

Thanks, guys.

Craig Shere of Tuohy Brothers.

Can you discuss the percent of your gas stream that is made up by ethane and the potential upside from an eventual industry ethane solution, in light of Range's announcement this morning that they secured a $0.145 per gallon transport cost on EPD's ATEX Express line to Gulf area connections?

Yes, we announced what the percentage is of liquids, it would double essentially with the take of ethane.

As we've mentioned before, the plant that will be coming online in Northern West Virginia will provide EQT the opportunity to extract ethane, which would increase the amount of gallons from 2.5 to 5.

We have the flexibility to make that decision economically.

And as we look out and make that decision, if it's in EQT's best interest to extract ethane from the price that we'll receive, then we'll have the ability to do that.

And if we are in a position to sell it as methane, as we do today, and blend it, if that's in the economic best interest then we'll do that as well.

And we're glad that pipelines are being built to move ethane.

That's good.

But, realistically, if you look at the macro situation for ethane supply/demand in the Marcellus, and you read through the specifics of any of the agreements that people enter into -- you extract ethane from the methane stream mainly because you have to, to get down to pipeline spec.

It doesn't really create a lot of value the way propane and butane, et cetera, do.

As Randy said, if the pipelines are there and you can enter into transactions where you add a little bit of money, that's great.

But the mindset -- we still think the prudent mindset with ethane is to assume that you extract it when you have to, to meet pipeline specs.

And if you can make a few bucks on top of that, that's obviously great.

But isn't that, given today's pricing with $0.14, $0.15 per gallon transport costs, isn't that a premium to methane gas?

First of all, those things, those pipes will be -- when will that be completed?

A few years or more.

Yes, and start netting back that and fuel and loss, it's a pretty close call.

Okay.

So you think that at this point, there's marginal uplift potential from finding end markets for the ethane, it's really just making sure your gas --

And you have to enter into long-term, firm commitments.

The only thing firm about that kind of pipeline deal -- and it's the same with our gas price, with the El Paso expansion that we've signed up, it's the same thing.

The only thing that's certain is that you got to write them checks.

And if you're in a position where you need to extract ethane to meet the pipeline specs, then economics may not drive that decision.

EQT's in a position right now to make that decision based on the economics.

Look, wetter gas is better than -- in this market is better than drier gas.

But for the most part, for all of us here, half of the C2 and above, roughly speaking, is C2.

So if you want to be able to extract the value from the C3 and above, you have to be able to do something with the C2.

So, I think net-net, it's attractive if you have wet enough gas.

You just want to make sure you can let the gas flow.

And to let the gas flow, you have to have little enough ethane in it that you can beat pipeline specs.

In that context, the all-in economics can work very well, but the all-in economics don't work because of the specifics of the ethane deal.

That's just a means to an end.

That's what facilitates the ability to develop the wells that have more C3 and above.

Range has talked about the possibility of actually exporting from the East Coast within two, three years to Europe.

If there was a closer export opportunity to global markets, would that change your outlook on the incremental value of ethane?

Yes, absolutely.

If the value is there, we're prepared to pursue it.

It's just that that's still not the driving force behind even the wet gas development.

It's the C3s and above that is the driving force.

But, yes, absolutely.

If there's the opportunity to make material uplift, then we certainly would pursue that.

Okay.

Thank you very much for the discussion.

Ray Deacon of Brean Murray.

I had a question for Phil.

I was wondering, could you just talk about your borrowing base in light of the fact that a number of companies have talked about downward revisions to their borrowing lines?

And my understanding is you have a corporate base facility, right, so there's--

There's no borrowing base at all.

It's $1.5 billion without a borrowing base calculation ever done during the life of that facility.

It matures 2014, so I think November of 2014.

Okay, got it.

And what's likely to happen with the IPO of the midstream business?

Does part of that go with the midstream?

You're just trying to get us in trouble with the SEC, Ray.

(laughter)

Just wait for the S-1 for that one, Ray.

Okay, all right.

And just in terms to clarify the economics on the program in 2012, when you say you stress tested down to $3 strip, do you include the impact of the 50% that's hedged in that, or no?

Actually, I'm happy to make a philosophical point.

When we look at the all-in economics of the program, obviously we take the hedges into account.

But when we're making marginal decisions, on the margin, every MMBtu of, every incremental or decremental MMBtu of natural gas should be priced at the market.

And I think that extends, even if you were fully hedged and you dropped, you can always tear up the contract.

You don't actually tear it up.

You can always cash in the contract.

Nobody asks to know the production's there.

The accountants might have an issue with how you record it.

Our controller's chuckling through that.

But you can still collect the money on a hedge, even if you were fully hedged and decided to cut production.

So the right way to make marginal decisions is based on the strip, no matter what your hedge percentage is or isn't.

It happens, of course, that the Huron decision on a piece of paper increases the percent hedged that we've got, just because it takes the denominator down.

But we make these decisions on what we should do on the margin, by looking at the market.

Okay, got it.

Makes sense.

And two quick questions for Randy.

I was wondering, there's been a lot of discussion that a lot of the major trunk lines that run through the Marcellus are going to fill up this year.

And given the cutbacks that people announced, could you just talk about some of your long-term plans and how the back haul might play into that as an asset?

Sure, Ray.

As you know, EQT's always been proactive to procure capacity to, one, to ensure flow assurance, and number two, to access markets downstream and have liquidity.

And I think we've demonstrated that with our capacity on Tennessee.

Going forward, as the development continues, we'll continue that strategy.

We still continue to see significant drilling and the need for capacity.

And that's been our strategy going forward.

Got it.

Okay.

You don't see any bottlenecks.

There will always be certain bottlenecks.

With respect to the back haul, again, we look at accessing a variety of markets.

Obviously, the most attractive market's in the Northeast.

But the back haul, again, with the possibility of exporting LNG and accessing more meters, we continue to look at utilizing our portfolio to access a variety of markets.

And that does include the back hauls into the Gulf Coast and forward hauls into the northeast.

So we look at a variety of options to give EQT, one, flow assurance, and to realize the best price for our product.

Our approach on the LNG export issue is the same as it is on -- an earlier participant had asked about ethane export.

We're not prepared to enter into that type of arrangement right now.

But we like the fact that the back haul gives us the opportunity to do so if we wind up deciding in the future that it is in fact an attractive thing to do.

Got it, great.

Thanks.

And I was just curious, with that JT skid, would you be able to sell the two of those, or is there much value there?

Or would you continue to use them somewhere else?

Ray, we would use those somewhere else.

As we continue to grow into -- in order to meet pipeline specs, we'll have the flexibility to move those.

All right.

Thank you.

Stephen Richardson of Deutsche Bank.

A quick question, just a clarification.

Following up on the discussion of marking the strip to where it was last week and thinking about cash flow for this year, as you think about '13, can you just clarify how you think about this term, living within our means?

And what that could mean?

Is the plan here to try to keep this program flat year-over-year?

Or how do you think about that in light of the $3 thereabouts strip next year?

Practically, it means cash flows from operations plus monetizations of, probably, midstream assets.

Though really anything is open.

I don't mean to sound -- make it trite, but everything is for sale at a price.

And to the extent that there's others who find some of our assets more interesting to them than they are to us right now, that becomes a monetization opportunity.

But I think practically, we'd look at 2013 and say it's operating cash flow, plus those sorts of monetizations.

And the stuff that's nearer term, of course, is a continuation of some form of midstream monetization.

Of course we've chatted about what some of the ways that that could happen would be.

Right, okay.

Thank you.

The other question is a clarification on the reduction of activity in the Huron.

You mentioned that there's well completions going on this year.

Is there any other penalties or anything else in terms of shutting down that business that's included in that capital number for 2012?

No, no.

Actually the only missing -- we were chatting about it before the call began, so we'll share it with the rest of you.

If you're doing the math on the number of wells that we're not doing, not going to drill that were originally in the plan, you would have to factor in that some of the wells that get spud would have, but no longer will.

But in the plan have gotten spud late in 2012, they would have had a fair amount of their CapEx occurring in 2013.

This one decision causes a reduction in CapEx in 2012 of $135 million, which we've stated.

And roughly, let's say, $25 million in 2013, from those 2012 wells.

You spud the well, but you would have still had more work to do, fracking, et cetera, that would have bled into 2013.

Got it.

But the previous plan where you were already trending down in terms of activity, so you would have held fewer wells waiting on completion at year end '12 versus what you held in '11?

Or was it the same?

No, because actually the '12 plan, the beginning '12 plan was pretty similar to the '11 plan.

There's no doubt that we've trended down, but the '12 plan actually reflected a plateauing versus '11.

And the Huron program has a very short lag from spud to TIL.

So we don't generate a large backlog in the Huron play.

As you recall, we never really used to talk about that when it was just the Huron.

A lot of the backlog issues, when the growth was coming from the Huron three or four years ago, were more because of midstream projects than they were because of the wells.

It's turned around in the Marcellus in that it's more of the wells, more multi well pads, longer laterals, and that sort of thing.

And the nature of the beast that's caused it to be more the wells that have resulted in that lag.

Great.

Thank you very much.

This concludes our question-and-answer session.

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

Yes, thank you, everybody, for participating.

And as I mentioned earlier, the call will be available for seven days for replay.

Thank you.

The conference has now concluded.

Thank you for attending today's presentation.

You may now disconnect.