EQT Corp (EQT) 2009 Q4 法說會逐字稿

Good morning and welcome to the EQT Corporation year end 2009 conference call.

(Operator Instructions) There will be an opportunity to ask questions.

Please note this event is being recorded.

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

Sir, the floor is yours.

Thank you, for participating in EQT Corporation's year-end 2009 earnings conference call.

With me today are Murry Gerber, Chairman and Chief Executive Officer, Dave Porges, President and COO and Phil Conti, Senior Vice President and Chief Financial Officer.

In just a moment Phil will briefly review a few topics related to our financial results for 2009, which were released this morning.

Then Murry will provide an update of our 2009 the reserves, drilling and infrastructure, development programs and other operational matters.

Following Murry's remarks we will open up the call for questions.

First, I would like to remind you that today's call may contain forward-looking statements related to such matters as our well drilling and infrastructure development initiatives including the impact of technological developments, production and sales volumes, reserves, the estimated recovery for the wells, financing plans, operating cash flow, capital budget, growth rate and other financial and operational matters.

It should be noted that a variety of factors could cause the Company's actual results to differ materially from the anticipated results or other expectations expressed in these forward-looking statements.

These are listed in the Company's Form 10-K for year-end December 31, 2008.

And in the Company's Form 10-K for the year-ended December 31, 2009 to be filed with the SEC.

As updated by any subsequent form 10, 10-Qs on the website.

Finally, this morning's call may contain certain non-GAAP financial measures.

Please see this morning's earnings press release, a copy is available on the website for the reconciliations and other disclosures with respect to such non-GAAP financial measures.

I will turn call over to Phil Conti.

Thanks Pat and good morning everyone.

As you read in the press release this morning, EQT announced 2009 earnings per share of $1.19 which compares with EPS of $2 in 2008.

The reduction in year-over-year EPS, as well as cash flow, comes as a result of the lower commodity price environment as well as the stock based compensation expense swing which we talked about all year.

Together, those mask the outstanding year EQT had from an operational standpoint.

We show the impact of the incentive compensation swing and the adjusted EPS table in this morning's release.

But as well, the 2009 financial results were also negatively impacted by the drop in natural prices which began in late 2008 and continued throughout 2009.

Lower NYMEX was about 56% lower year-over-year, but the lower realized average well had natural gas prices.

As we show in another table in the release this morning, EQT's realized average well head natural gas price was $5.44 per MCF in 2009, where about 20% lower than the $6.82 we realized last year.

These lower natural gas prices resulted in $141 million of less operating income in 2009 versus 2008 and that includes the I impact of the hedges.

If you look behind cash flow and EPS however, 2009 was an exceptional operational year for the Company in many ways including record produced national gas cells and significantly lower drilling and per unit operating cost at production, which by the way are already among the best in the industry.

We also had record volumes in gathering transmission and processing in our midstream business and record operating income at equitable gas.

Between Murry's and my comments we will go into a little more detail in all that.

So let's start out by briefly walking through the financial results by business unit, starting with EQT Production.

And again, the big story in 2009 at Production was the increase of sales that produced natural gas up almost 20% versus 2008 when you adjust for the extra day last year.

I should point out that the majority of the positive well results in Marcellus and extended lateral here on Berea wells, which Murry will elaborate upon in a minuter, were later in the year and did not show up in the 2009 results.

So it was a great year from a sales volume and growth standpoint, but as I alluded to up front, the significant volume increase was more than offset by an average NYMEX price that was 56% lower year over year, resulting in the large decrease in sales revenue.

Just a moment on expenses at Production, total operating expenses were higher in 2009 as a result of higher DD& A and exploration expense, despite the almost 20% growth in volumes, however, LOE was unchanged compared to 2008.

On a unit basis, LOE was down 14% and that is excluding the impact of production taxes that were $17 million lower in 2009.

So, we continue to see the benefits of scale in our Production business.

DD&A expense was higher than 2008, reflecting our growing production volume as well as higher DD&A rate associated with a recent drilling investment.

The Company also invested $15 million in the purchase and interpretation of seismic data which showed up as exploration expense in the financial results.

Exploration expense also included just under $3 million impairment on the uncompleted Utica well as a result of our decision to abandon the Utica well and convert it to a Marcellus well.

Moving on to midstream results.

Operating income there was up 40% consistent with the overall growth of gathered and processed volumes as well as increased revenues from our Big Sandy pipeline.

Gathered volumes increased 11% mainly from gathering EQT production growing sales volumes and combining with higher rates resulted in 18% increase in gathered net operating revenues.

Transmission net operating revenues were also up 49% versus last year.

Primarily because we had a full year contribution from Big Sandy which as you know was completed in the second quarter of 2008.

Processing volumes were up here about 55% and that was the result of a four year contribution from our Langley processing plant.

And finally storage, marketing and other net operating revenues were higher from mainly from marketing activities relating to Big Sandy capacity not yet being used by EQT Production.

Expenses at midstream were about $29 million higher than last year.

That increase was expected based on full year of running the 2008 infrastructure projects.

DD&A expense accounted for about $19 million of that increase in expenses.

We increased electricity and labor to run the expanded compressor fleet accounted for the remainder.

Reported SG&A was down $2 million.

Somewhat higher SG&A related to the growth in the midstream business was more than offset by not having a reoccurrence of the $5 million charge in the third quarter of 2008 for the Lehman Brothers related bad debt expense.

Moving on to distribution.

Operating income at Distribution was a record $78.9 million in 2009 or 32% higher than 2008.

Net operating revenues increased by $9 million mainly due to higher rates that became effective at the end of February 2009 when we received final approval of our Pennsylvania base rate case.

Distribution expenses were about $10 million lower as a result of lower bad debt expense, lower rent and lower corporate overhead allocations.

A couple of other matters.

First incentive compensation expense.

As you know the volatility in the EQT stock price over the last couple of years has lead to quite a bit of compensation related volatility in our earnings.

In 2008 when the stock price dropped 37%, we realized almost a $42 million reversal of previously recorded executive compensation expenses and then in 2009 with the stock up 31%, we recognized $45 million of executive compensation expense leading to a $87 million-dollar year over swing in executive compensation expense.

Our current long term executive incentive programs have been designed to eliminate such volatility going forward and the majority of the expenses set at the time of the grant.

If you are trying to predict the cost of incentive compensation in 2010, we estimate an annual long term incentive compensation expense of approximately $30 million with a less volatile change of approximately $1 million per $1 change in EQT stock price.

One thing that has not changed with the program design.

Management payouts from the program will continue to be linked to shareholder returns.

A couple quick observations on the fourth quarter results specifically.

Like the full year, the fourth quarter 2009 was an excellent quarter from an operating standpoint with in about 19.5% production sales volume growth as well as considerably higher with gathering, processing and transmission volumes in the midstream businesses.

The fact that the fourth quarter sales volume growth rate and the full year growth rate are virtually the same and just shy of 20%, I think I am a bit misleading in terms of the growth trajectory exiting 2009.

Some of the area quarters in 2009 had growth rates that were also in the 20% area.

However, they were compared to quarters in 2008 where volumes were some what suppressed as the big midstream projects either went online or were just starting to come online.

By the time we did get to the fourth quarter of 2008, all of the midstream projects were online and we were hitting on all cylinders in the Production business, we achieved about 19% growth in the fourth quarter of 2008.

So growing almost 20% in 2009, fourth quarter versus that quarter, I think is a strong result for the Company.

However, the favorable operating trends in the quarter were partially offset by unfavorable market conditions for NYMEX natural gas.

One other quick item of note in the quarter.

Distribution, the fourth quarter 2008 revenues did include about $3.5 million related to a customer assistance program which did not reoccur in 2009 and that partially masks the revenue increase in the 2009 fourth quarter from the Pennsylvania rate case.

Finally, just a quick update on liquidity.

We suggested during the third quarter call, the net short term debt at year end 2009 would be less than $100 million and as it turned out we ended up with only $5 million of net short term debt on the balance sheet at 12/31/2009.

That puts us in a great position as far as liquidity and financing flexibility as we head into 2010.

In December press release, we announced our 2010 CapEx estimate of about $850 million and estimated that 2010 operating cash flow would be about $650 million to $700 million at the current strip.

And that included about $100 million we will receive from a tax refund as a result of the five year NOL carry back allowed by legislation that was enacted during the fourth quarter of 2009.

The approximately $150 million to $200 million difference between CapEx and cash flow we expect to fund with our currently virtually undrawn $1.4 billion revolver.

I will turn the call over to Murry.

Thanks, Phil and good morning everybody.

As Phil mentioned, we had an extremely operational quarter across all of our business lines and the year of course was a real good year for EQT.

Headline statistic was the nearly 20% growth in produced natural gas sales.

As Phil mentioned, at lower capital costs we are projecting sales of up another 20% in 2010 at as he described lower cost.

This is all driven by aggressive horizontal drilling in our Huron Berea pate all with the drill bit and significant progress in the development of the Marcellus also all with the drill bit.

This is our sixth consecutive quarter of double-digit natural sales growth and we had record throughput in operating income at midstream, record operating income at distribution.

In total we drilled in the fourth quarter, about 184 wells.

702 for the year.

Total horizontal wells spent in the fourth quarter was 132 and year to date was 403 wells.

Turning to reserves.

The 2009 reserve report was prepared in accordance with the SEC guidelines.

I won't repeat what is in the reserve press release.

But I wanted to emphasize a couple of points.

Unrisk potential is still about the same as we thought before, about 26 Tcfe.

However, you are seeing with this release a continuation of the orderly progression of reserves up toward lower risk categories.

Specifically for the proved reserved categories, Marcellus reserves are up about one Tcfe due to the results of of the 2009 drilling.

On Berea reserves, they are you up a half Tcfe because of the new drilling and new FCC rules.

You recall perhaps that the vast majority of EQT drilling in recent years has been done on unproved locations.

In 2009 for example, 79% of our wells were drilled on unproved locations.

Due both to the FCC rules and to our expanded drilling programs over the past few years, most of our drilling in 2010 and beyond will take place on PUD locations.

This is an indication of orderly development.

One other item worth discussing is the impact on our reserves of the FCC rule requiring locations to be drilled within five years to be included in the proved undeveloped category.

For obvious reasons, the drilling assumption used in the reserve calculation is an important variable.

Our 2009 reserve report is based on a five year drilling schedule that costs $2.9 billion, approximately five times our 2010 budget.

This five year drilling schedule results in our booking approximately two Tcfe as probable reserves from locations which aside from the assumption of the timing of the drilling, would have otherwise been booked as proved.

For example, you will note the CBM other reserve category is down a half Tcfe this year.

That is because the presumed five year drilling schedule no longer includes many vertical conventional wells.

Those locations are now included in unproved categories.

The Huron and Berea update.

We drilled 821 wells in the program since the inception of the horizontal air drilling a few years ago.

A third of the production now comes from air drilled horizontal Huron Berea wells and of course in 2006 0% came from horizontal air drilled wells.

To remind you the scope of the play, we reported 6.7 Tcfe of 3P and an estimate of 13 Tcfe of resource potential in the Huron Berea.

And as I reported during the last couple quarters, the latest application of new technology is extended lateral design, improvement in frac technologies now allowing for 22 or more stages, so we have lengthened our laterals.

To date we have successfully drilled and completed five extended lateral wells, doubling the footage of pay from 3,000 feet to 6,000 feet.

With this improvement, we believe we are doubling reserves and productivity per well for less than 40% more cost, approximately 1.6 BCF per well for about $1.4 million.

Unit development cost is a little less than $0.90.

Our (Inaudible) for extended lateral, we are currently estimating in the mid 30s at $7 NYMEX and greater than 20% at six.

Pay back period interesting is about 2.7 years which is faster than Appalachia used to be and we expect this extended lateral design will be our standard operating procedure by year-end.

On the Marcellus play, EQT now has approximately 445,000 acres in the core of the Marcellus play.

This is an increase of about 45,000 acres.

The increase is due to 13,000 leased acres that we have acquired in PA and the rest is due to impact of positive drilling results in West Virginia.

Which expanded our understanding of the size of the area underlaying by high pressure Marcellus.

Improvements, some dramatic in both drilling cost and completion effectiveness, are causing us to be increasingly bullish on the play even on the current price environment, a great credit to the EQT team.

Here are the reasons why.

Well costs for one as we discussed in the third quarter call have seen a marked improvement this year in 2009.

On our third quarter we reported having achieved completed Marcellus well costs of $3 million per well.

We still think $3 million per well is a good number for the current lateral design.

On EURs, our estimate of the average EUR from the Marcellus wells is moving up.

Our current view is that the average will be between 3.5 and 4 BCF for all of our acreage and we wouldn't be surprised, given current data, that the average EUR will edge up towards the top of the range.

Three important reasons for the improvement, in our opinion, about Marcellus EURs.

First, on the completion side, we have made several significant changes over the last six months which we feel have contributed to improve results.

First has to do with targeting.

We are able to drill now in the most brittle section of the Marcellus and that seems to provide a, the most organic rich shales, and b, the best place to frac.

We changed our frac casing from 4.5 inches to 5.5 inches, which lowers the treatment pressures and allows us to more consistently pump the job as designed.

Third, we have also significantly reduced the spacing between perk clusters from approximately 150 feet to 60 feet.

On the completion side we have taken a number of steps that seem to be causing us to have more consistent jobs and less failures on the individual frac stages.

The second important thing thats happened to effect the Marcellus EURs.

We have encountered some prime geologic conditions from Marcellus production, particularly in Green County, which I will discuss in a minute.

Third, and this is a subtle point.

The combined affect of more effective and consistent completion techniques, better targeting and lower cost is intercepting to make more areas of the Marcellus attractive.

This is particularly emphasized by our results in West Virginia, which I will also discuss briefly in a second.

Another way to put this, we here at EQT are now confident that regardless of the Marcellus geology put before us, we will find a way to exploit it profitably.

Current economics show the unit development cost for the Marcellus wells are a little less than $0.85.

Our IRRs similar to the Huron Berea are over 30% at NYMEX at $7 NYMEX, and greater than 20% at $6 NYMEX and payback period is about in the same for range as the Huron Berea, about 2.9 years for the standard lateral design.

Specifically on well results for the Marcellus, we have 53 horizontal wells to date and 17 of those are turned in line.

We are expecting to drill 40 to 50 Marcellus wells in 2010.

Green County, in particular, in the fourth quarter we turned in line our best Marcellus well, we call it the 167 well.

Which had a 30 day average initial production of 14 million cubic feet a day.

This well has been in line for approximately 37 days and is currently producing in the 12 million cubic feet a day range.

Based on the 30 day IP rates, this well to our knowledge is the most prolific drilled by industry in the Marcellus play so far.

Two adjacent wells, the 168 and the 170 wells in Green had 24 hour flow rates similar to the 167 well that are shut in and are waiting completion for gathering capacity, so we don't have those 30 day IPs yet.

12 wells are planned to be drilled on 3 pads within a 2 mile radius of these wells.

These wells are located on a pad that is approximately 8 miles away from another very prolific Green County well pad that I discussed in the third quarter.

In Green County, more generally, we have 380 drilling locations.

Our EUR expectation in this area is about 4.5 BCF per well, obviously some wells will be higher and some lower than that presumed average.

The Green County story for EQT is one of confluence of excellent application of technology with prime geological conditions.

Moving on to West Virginia.

We are pleased with what has been going on in the West Virginia Marcellus program.

We have turned 10 wells in line to date.

While the 30 IPs on these wells are not very flashy, averaging about 2.1 million cubic feet, the decline curves are such that we expect EURs to be in the 3.5 Bcfe range.

IORs for the West Virginia wells are consistent with those of the Marcellus generally, greater than 30% at $7 NYMEX and again, greater than 20% at $6.

So the West Virginia program is looking really, really good to us at this point in time.

Midstream in Equitrans, as we previously mentioned in the third quarter 2009 call, EQTs midstream successfully completed an open season for proposed expansion for Equitrans.

We are still negotiating binding precedent agreements.

We did submit, if you saw this, our FERC application for the phase I expansion involving 100,000 decks on January 25th -- hundred million a day.

On January 25th, phase I is expected to be on line this year.

Phase II, as we mentioned earlier, takes the project up to the full 1.1 million decks.

The total project cost, including phase I and II is currently estimated between $450 million and $500 million.

That is a bit less than we talked about previously.

And also, I did want to emphasize, and we talked about this on the third quarter call, we are currently considering partnerships or ventures on various aspects of our midstream business.

We are talking to a number of people about that.

Obviously, EQTs always been strong and the desire to have control of midstream and make sure our gas gets the market has been a core issue for EQT over the years and we still adhere to that.

There are a number of people currently who are interested in Marcellus midstream.

That wasn't the case so many years ago.

It is the case now.

And we are talking to a number of people to see what they can do to EQT without us having to sacrifice the comfort of being able to get our gas to market.

That's all I have to say.

It is a great quarter, great year.

We still believe EQT is a very compelling investment.

Growth rates are good, industry leading cost structure is important in times like today where prices are a bit soft.

I will turn it back over to Pat and we will take your questions.

Thank you, Murry.

BJ, can we open the call for questions.

Yes.

(Operator Instructions) At this time the first question comes from Scott Hanold from RBC Capital Markets.

Thanks, hi, congrats on the results.

Thanks.

Murry, specifically on that Marcellus well, that is just an impressive well.

You identified a few things and it sounded like there was something unique about Green County that you all think has contributed to that.

Specifically, is there anything else you can point to from a geological stand point in the area?

Shale thickness, organic content?

Yes, I think keep in mind, I don't know that we are going to find more wells like the Green County wells.

But I would say we are not presuming that the average is going to be as high as what you might predict from those particular wells.

Geologically, yes, it is a couple of things perhaps, but I don't think I would put a lot of emphasis on this right now.

We are still learning.

Yes it is a bit thicker, it is brittle, which we think is an important fact for the Marcellus field.

The organic rich part of the Marcellus is also the most brittle part of it am and it seems to have an impact on the effectiveness on the fracs that near borehole brittleness is seeming to provide near borehole permeability, which has an impact on flow rates.

So that seems to be consistent The question is how do you predict the actual presence of this brittle Marcellus and I am not sure we are able to be able to predict that in advance all that much.

We know it when we see it after the fact, but we are not sure yet we are able to predict it.

The other that is happening in the area is there is not a lot of structural complexity and therefore, there hasn't been a lot of structural events post the Marcellus deposition that would cause an extreme amount of fracturing of faulting to steal away the gas that might of been there earlier and leaked out during successive stages of mountain building.

That could have an impact as well.

Those are a couple of the geological factors.

Is this pretty much a drag as well?

Yes, pretty much so, yes.

You talked about various parts of different things you are doing, but what is the latter, specifically with the well and typically when you look at your drilling program on the Marcellus, what was the lateral length, how many frac stages and also, throughout the specific the AFE cost on this one.

I am not going to give you all of that.

3,000 feet of pay.

Nine stages of frac, but I am not sure, we can correct that if we need to.

Recollection is it is about 100,000-barrels of frac fluid were used in the well.

That's my recollection.

Okay.

Other than that, not much more.

No, I think that answers it.

It's not like you drilled an extended long lateral, this is a typical well.

This is a typical well, exactly.

This is a typical well and as you know and the industry is experimenting with those longer laterals, we are too, and other designs to increase that net foot of pay in the Marcellus and even in more cramped these circumstances and we are working on all kinds of designs.

If I ask you to give an IP on the well, would you?

No.

Fair enough.

And moving on to the reserves real quickly and you talked about the PUD bookings and probable numbers and it seems you have taken a real deliberate approach and how you are going to get these PUDs in.

Is there a number, do you have a number of PUD locations, per -- offset that you drilled.

To give us, also to get another way of looking at it.

That is complicated by the lease design a lot too.

I am not going to give you a general number on that.

We basically followed the rules the way they are laid out by the SEC, Scott, no way.

We didn't take extraordinary measures to go beyond that.

And the factor that I mentioned in my comments which is actually the most important factor on this whole reserve booking calculation, and you will see this with a number of other companies.

It is the presumption of the number of wells that will be drilled in the five year period.

That is going to swamp any of the stuff you are talking about now and as you are comparing company to company results.

I don't want to make this long-winded.

Pat told me to be brief.

There is more management judgment in the proved reserves now than there was.

Used to be they handed me a reserve report and that was it.

Now, there is a question of the five year presumed drilling schedule.

And that's a big factor.

It is true if you look at our rated increase versus others with the new rules.

I think a higher percentage of of our 3P and the total resource really is in shales and the shales were effected more by the rules.

So, I think that's one of the reasons you saw higher percentage of increases.

The other thing too, if you recall, we were drilling a long pipelines.

We wanted to be able to assure that the wells we were drilling would get to market and by definition we were drilling a lot of unproved locations.

Because the pipeline didn't necessarily fit right on a location that was previously classified as proved and we have been doing that for a couple of years now.

That's why today's point for EQT, it makes sense there was a large increase in reserves this year.

Shale was number one because of the rule change and and number two, because we had drilled so many unproved location insist the last couple of years.

Got it.

In the light of that idea, one more question.

You mentioned 168 and 169, you production tested and you've not yet completed those wells of permount production.

What is the exact constraint there to get them on line?

Is that something you get the larger wells and get more active when we are building a production model.

Yes, it is basically midstream constraint.

And maybe they want to talk about it.

We didn't anticipate wells of this magnitude.

You want to talk about this.

We put in what we think are the appropriate line sizes and compressor stations and we think it will handle it.

And the first twelve comes on line and kills us.

We are still in the sure how quickly they decline.

We can see them over.

[About half a bee] in five weeks from the first well.

Which we like.

Not a lot of us know what it looks like a year or two out.

We are still struggling with what is the right way to size the midstream.

There is a considerable flexibility in what we are able to do on the midstream right now.

It's not like these wells are going to sit there for a long time.

We are actively trying to put together a little bit bigger pipe, a little more compression to be able to get those.

What appear to be very good wells on production as soon as possible.

Okay.

Appreciate it.

Okay.

Our next question comes from Michael Hall from Wells Fargo.

Please go ahead.

Congrats on a solid year gentlemen.

Couple follow ups on a few different topics.

Getting on the reserves first, as we look at all the incremental Marcellus reserve bookings, on the proved developed side is there a meaningful PDNP component within that?

No.

So that's on what?

There is some PD not producing what we just discussed, those couple wells that are ready to go, but I would say it's not meaningful.

In terms of thinking about the per well bookings on the proved side in the Marcellus, you are talking about -- you are assuming a tight curve or EUR of 3.6 Bs in West Virginia and 4.5 Bs in PA, is that the same figure that is being used in the proved reserve report?

Let's be real clear about that.

The numbers I stated were specifically for Green County because of the high number and the lower number was for quote unquote West Virginia.

Our current view of the average EUR for a Marcellus well is generally 3.5 to 4 and I did say that based on the results we are thinking that could edge toward the higher end of that range.

Based on the current results.

That's what I said.

I am trying to get at what is being assumed in the proved reserve report versus your current thinking.

It is 3.5 what we included.

Okay.

And then --

I am sorry.

That is not correct.

I am sorry.

We assumed a little less than 3.5 in the reserve report.

More like 2.5 to 3 range.

About 2.8.

Exactly.

Sorry about that.

Would you care to discuss what the average 30 day rates in PA and the 30 day rates West Virginia have been to date.

It's an average.

No, not really.

That is not meaningful with the number of data points we have just now, because they are getting good and one of the attractive aspects that EQT has done over the last year is this is a strategic issue for our management team, [Steve Flatterback] and his team, [Richard Hill] et cetera, down there in production, is to make even the lower EUR wells profitable.

That has been a huge strategic direction for us.

That has been our focus so when we get these bigger wells we are really sort of relishing in the upside potential of those so we are not really focusing so much on it.

I don't think the statistics yet, are such that anything other than the 3.5 to 4 that I mentioned is a very good -- is worthwhile discussing.

We are at 3.5 to 4 edging towards the top half of the range.

That's about it.

Thank you, our next question comes from Joseph Allman from JPMorgan.

Please go ahead.

Thank you, good morning.

Murry, in your reserves press release and you mentioned on the call that $2.9 billion of CapEx over the next five years.

Is that what you expect to spend in terms of total EMP CapEx?

I just want to clarify that.

This is, look, we are dealing with a brand new reserve reporting technique here.

We are not sure what others are going to do to in their presumption.

We have no idea.

What we presumed was that tomorrow would be kind of the same as today.

And we put a five year drilling schedule out consistent with the budget we are having in 2010.

That's what we did.

Okay.

Got it.

Just to clarify.

That is not future development costs related to PUDs.

It is totally CapEx.

Using 2009 times five?

It is drilling.

It is drilling CapEx that would be associated with the five year plan that is consistent with those reserves.

It is more than PUD drilling.

Well, yes.

Okay.

I don't know.

It is total drilling.

And could be as I said earlier, most of our drilling going forward is going on PUD locations.

I didn't say all.

We are going to have the situation going forward where you will see less and less of our wells being drilled on unproved locations because as we drill more, more and more of the locations go into PUDs, but I didn't say all of our locations would be on PUD.

Got it.

Understand.

But, let's assume flat commodity prices and growing production and let's say flat cost.

You would have more cash flow.

And in reality, you would expect to spend more money as you progress in the next five years.

Yes, but then what you are talking about is we would expect to drill more wells than we have in the five year plan.

But the five year plan, what we are trying to do and probably a lot of folks are trying to do is the best job of interpreting what the SEC is asking us to do without getting too far out on a limb.

That's all that the numbers reflect.

In our case, probably for a lot of folks.

It represents something that looks a fair amount like five times of what we look like we are doing in 2010.

We don't have an approved five year drilling plan from our board et cetera.

I think you are going to see this with everybody, Joe.

This is an ongoing dialogue between you all and all the companies on what they presumed.

I can just tell you what EQT did.

We didn't presume.

We are going to accelerate that much.

We are going to keep.

We are presuming for the purpose of the reserve report that we would stick pretty close to the 2010 budget.

And that's it.

Understand.

Got it.

Got it?

That's helpful.

In terms of -- we backed into a negative reserve revision of about a 100 Bs is that right, I imagine that is price related.

That's right.

That will all come and all those details will come out in the K.

You are right in the right neighborhood.

I am sorry.

That price related aspect of it.

Was that mostly PUDs or mostly true developed tails, can you give us a breakdown of that?

It is, yes.

All of the above, but it is mostly the tails fall off and you get to a lower price and you get to negative cash flow sooner on those wells, so it is tails of the wells that fall off primarily.

Our next question Rebecca Followill from Tudor, Pickering, Holt.

Hi.

Really nice results and impressive reserves.

There is such an incredible potential there.

My question is though, when you look at the production guidance for 2010 and realizing it is just 2010 and it is going to grow from here.

It is a 34 year reserve life on proved reserves and 102 on 3P.

So, how do you accelerate further?

I know you have been working hard to do that, but it is still such big numbers.

Well, first of all.

A lot of these results we are talking about here are fairly new, Becca as you know.

We are experimenting with extended laterals in the Huron and Berea and I would like to think it is a standard operating procedure soon and the Marcellus is improving in costs, but we have huge outstanding issues with respect to well spacing on the Marcellus, is it a 1,000, is it 500, is it somewhere in between.

And then the third aspect is not crystal clear is the pace of development of the midstream, where it should be.

Where are the big wells, where are the smaller wells and how should that midstream infrastructure be laid out to minimize the cost and maximize the deliverability and all of those things are under consideration right now.

And I agree with you, that EQT needs to, and will accelerate the growth of sales.

But there are some outstanding issues that need to be reconciled in our mind before we decide to put the pedal to the metal.

Two other questions for you.

Midstream, if you can say, what are you looking for in a parter?

Are you looking for money or for opportunity?

That's a great question.

Without getting too long-winded, I think there are two issues.

One is the one you mentioned, money.

It is not so much money, we think the midstream investments are quite profitable, they make EVA, but the question is where do we get the maximum leverage and at this point in time it is very clear we get the maximum leverage for dollars on the E&P side and therefore, given the fact that we don't have enough capital to develop this, as you mentioned, as quickly as we would like, there are some tradeoffs we have to make.

It is more than the money.

We are not good in the liquid business for example.

And not so much that we can't build an extraction plant, which we have done, and we run it very successfully and such, but when you look at all the issues of fractionation, transporting of liquids, sale of liquids, et cetera, these are core capabilities that EQT just doesn't have.

On that score it makes no sense for EQT to develop the capability and so we are looking for somebody that can do that.

Moving upstream into the high pressure gathering system, Equitrans, Big Sandy and the large high pressure corridors that we built, downstream of the compressors, frankly, once they are full, those little additional EQT value that is added to those pipes.

The problem in the past has been that we haven't been able and we knew that and you can price them at an MLP and we all get that.

The problem is the build to fill period, that -- if you are asking someone to build something fresh with fresh capital, the cost of capital that we had seen in the past had been fairly high relative to EQT's cost of capital.

Today, I would say, they could comment on it, I would say we have seen an enormous amount of interest among people in potentially building those.

And so, the rent payments, we think, might be coming down versus what we might have anticipated a couple of years ago, even for projects that require fresh capital.

I think things have changed here in Appalachia.

There are a number of people on the liquid side that are capable and anxious to come in and EQT is a great partner.

And moving upstream a bit on the pipeline side, there are also people who seem anxious to deploy capital in those pipes and we are talking to a lot of people to see if we can find something that is suitable for us.

That is a long answer, but it kind of frames what we are trying to do.

Thank you.

Our next question comes from Josh Silverstein from FIG Partners.

Please go ahead.

Good morning.

Hi, Josh.

Can you clarify the CapEx on the upstream side this year.

It is about $150 million drop this year with the 20% increase in the sales volume.

I was wondering if there is more efficiency gained somewhere.

Are you shutting down the CBM program?

The Marcellus flow count is up slightly a little bit, but you are getting more cost effective there, so just kind of curious if you can clarify that.

Well, Josh, when we announce the capital budget for 2010, we made the exactly the points that you are currently making and that is that we are getting about the same growth for less CapEx and it is precisely because the well costs have come down and the results per well, the productivity per well has gone up.

It is exactly what you just what you said.

There is no real shut down of any other program.

It is just cost efficiency gains?

No.

This is raw productivity improvement.

Old fashioned.

We are doing it the old fashioned way.

Got it.

Understand.

As compared to last year or previous years when you had gone into the year very well hedged, this year it's about 35%.

Just curious if that's by design or if you are planning on layering in additional hedges as you go through out the year.

We talked about IRRs versus gas prices in his discussion and we make above a 20% return at $6 gas.

So, we have a lot of protection from our low cost structure.

And we can make our cost of capital return at prices well below where they are right now.

We do look at it all the time.

We haven't done any hedges in the last couple of years, but we look at it all the time, I think it is fair to say we are looking at it a little more seriously right now.

We, as you know talked about it this in the past, prefer to do callers, so if we some callers our there that we can lock in our cost of capital and give us a fair amount of exposure to the upside, I will take a look at it.

Thanks.

Our next question comes from Faisel Khan from Citigroup.

Please go ahead.

It is Tim Schneider for Faisel.

First question is sort of where do you envision your Marcellus production could peak out in the next few years?

In the take away side, should we think about as 50 cubic feet a year?

We will not give that number out right now for Marcellus.

I think as I mentioned earlier in my comments, and Dave may wish to elaborate, we are still drilling a lot of wells at Marcellus, scoping out the play.

We currently believe that production will increase, but I am not ready to give you specific guidance on that at this point in time.

How about the takeaway capacity?

Well, it depends on what you mean.

And we had the discussion before.

In terms of the downstream take away capacity for gas, that is the interstate pipeline capacity, EQT is quite well positioned and we working with El Paso to complete the 300 line in northern Pennsylvania that adds incremental capacity of 350 million a day to eastern markets and back haul capacity of an additional 350 million a day to the Gulf Coast markets, so 700 million total.

We are well situated there.

Up stream, we are building the Equitrans thing and that is going to help quite a bit.

As you get further upstream into the gathering, the high pressure gathering, et cetera, it is getting, getting built according to the need that is generated by the wells.

If you said what is currently least troublesome, it is the downstream capacity.

What is currently most troublesome and most uncertain, it is all the stuff leading from the well to those interstate pipes.

Just to clarify, you said the Green County well, the 14 million one, you said that was dry gas?

Mostly, yes.

Thank you very much.

Thank you.

Thank you.

Our next question comes from Ray Deacon from Pritchard Capital.

Please go ahead.

Hi, Murry.

Can you talk about the nine frac stages in this high rate well equate to roughly a 2,000-foot lateral?

Is that fair?

It is 3,000-foot lateral.

I may have the number of frac stages wrong.

Okay.

Got it.

I was trying to reconcile that.

You are saying you are applying a frac job every 60 feet?

The stages are longer than that, but the clusters are spaced within the stages are spaced more finely.

Closer together than we had previously done.

Great.

Would you attribute, when you talk about the variance between West Virginia and Pennsylvania, is part of that due to, leases or is it geology, or lateral lengths or I guess, do you think over time they could be quite different in terms of the returns?

No.

I think the way we are viewing West Virginia currently.

The 3.5 Bcfe's are quite good wells and the cost are a bit lower as well.

And so, I think the key thing there is that although the IP rates weren't that flashy it seems like they are holding up a bit better.

I can't give you the geological explanation for that right now.

But that decreased fall off in the production is something that has caught our attention.

Got it.

And would you, have you got any actual data points for the super long laterals yet in the Huron?

No.

We don't yet have, no.

Got it.

One thing you should be aware of it, I don't want to belabor it, but the acreage positions are very cut up in the Pennsylvania Marcellus and currently we don't have forced pooling in Pennsylvania.

We are working to get it.

If we don't get forced pooling, the application of the extraordinary low levels is going to be difficult to presume.

I want you to be aware of that.

If PA gets forced pooling, you will see a more rapid deployment of the long laterals.

People who have concentrated acreage positions can do some of that, but in terms of broad application we really need some sort of forced pooling regulations and we are not really close to a deal on that yet with Pennsylvania.

One more quick one.

With the 40 to 50 wells in 2010 in the Marcellus, were they roughly half and half, West Virginia and Pennsylvania?

We are kind of -- we have not much preference one way or the other.

It will depend some what on the locations that is are available, some what on the midstream that is available so we can get the gas to market and get some cash for it.

I think we are going to be bobbing and weaving a little bit between the two depending on those two factors.

Great thank you.

This concludes the question-and-answer session today.

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

That concludes today's call.

The call will be replayed for a seven day period beginning at approximately 1:30 PM today.

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And the call will also be replayed for seven days on the website.

Thank you, everyone for participating.

This concludes the EQT Corporation year end 2009 conference call.

Thank you for attending today's presentation.

You may now disconnect.