Jan 28, 2010
Executives
Patrick Kane - IR Murry Gerber - Chairman and CEO Dave Porges - President and COO Phil Conti - Senior VP and CFO
Analysts
Scott Hanold - RBC Capital Markets Michael Hall - Wells Fargo Rebecca Followill - Tudor, Pickering, Holt Josh Silverstein - FIG Partners Faisal Khan - Citigroup Ray Deacon - Pritchard Capital
Operator
Good morning and welcome to the EQT Corporation year end 2009 earnings conference call. All participants will be in a listen-only mode.
(Operators Instructions). After today's presentation 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.
Patrick Kane
Good morning, everyone and 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 Chief Operating Officer and Phil Conti Senior Vice President and Chief Financial Officer.
In just a moment Phil will briefly review few topics related to our financial results for 2009 which were released this morning. Then Murry will provide an update of our 2009 reserves, drilling and infrastructure development programs and other operational matters.
Following Murry's remarks we'll open the phone line up for questions. But 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 eliminated -- estimated ultimate recovery for our 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 factors 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-Qs and on our website. Finally, this morning's call may contain certain non-GAAP financial measures.
Please see this morning's earnings press release, a copy of which is available on our website for the reconciliations and other disclosures with respect to such non-GAAP financial measures. Now I will like to turn call over to Phil Conti.
Phil Conti
Thanks Pat and good morning, everyone. What 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 incentive compensation expense which we have talked about all year. And together I think there's nicely outstanding year EQT had from an operational standpoint.
We show the impact of the incentive compensation swing and adjusted EPS table in this morning's release. But as well the 2009 financial results were also negatively impacted by the drop in natural gas prices which began in late '08 and continued throughout 2009.
Lower NYMEX and it was about 56% lower year-over-year but to lower realized average wellhead natural gas prices. As we show in another table in the release this morning, EQT's realized average wellhead natural gas price was $5.44 per Mcfe in '09 or about 20% lower than the $6.82 we realized last year.
These lower natural gas prices resulted in about a $141 million of less operating income in 2009 versus '08 and that includes the impact of our hedges. If you look behind cash flow on EPS however, '09 really was an exceptional operational year for the company in many ways including record produced natural gas cells and significantly lower drilling in per unit operating cost at production which by the way we're already among the best in the industry.
We also had record volumes in gathering transmission and processing in our Midstream business and then record operating income at equitable gas. Between Murry's and my comments we will go into a little more detail on all of that so lets start out by briefly walking through the financial results by business unit starting with EQT Production.
Production with the increasing sales of produced natural gas of almost 20% versus 2008 when you adjust for your extra day last year. I should point out that the majority of the very positive recent well is also in Marcellus and extended lateral Huron/Berea wells which Murry will elaborate upon in a minute were later in the year and did not show up in the 2009 results.
So it was a great year from a sales volume growth standpoint but as I alluded to our front to significant volume increase was more than offset by an average NYMEX price that was again 56% lower year-over-year resulting in the large decrease in sales revenues. Just a moment on expenses at production, total operating expenses were higher in '08, sorry in '09 as a result of higher DD&A and exploration expense.
Despite the almost 20% growth in volumes however, LOE was basically unchanged compared to '08. So on a unit basis LOE was actually down 14% and again that is excluding the impact of production taxes that were $17 million lower in 2009.
And so we continue to see the benefits of scale in our production business. DD&A expense however was higher than '08 reflecting our drilling production volume as well as our higher DD&A rate associated with a recent drilling investment.
The company also invested about $15 million in the purchase and interpretation of seismic data which shows up as exploration expense in the financial results. Exploration expense also included just under $3 million impairment on uncompleted Utica well as a result of our decision to abandon the unit and convert that well 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 a from our Big Sandy pipeline. Gathered volumes increased 11% mainly from gathering EQT Productions drilling sales volumes and combined with higher rates resulted with about an 18% increase in gathered net operating revenues.
Transmission net operating revenues were also up about 49% versus last year, primarily because we had a full year contribution from Big Sandy which was completed in the second quarter of 2008. Processing volumes were also up here about 55% and again that was the result of a full year contribution from our Langley processing plant.
And finally storage marketing and other net operating revenues were higher mainly from marketing activities related to Big Sandy capacity not yet being used by EQT Production. Expenses at Midstream were about $29 million higher than last year and that increase was expected based on a full year of running the freight infrastructure projects.
DD&A expense accounted for about $19 million of that increase in expenses while increased electricity and labor to run our expanded compressor freight accounted for the remainder. Reported SG&A was down about $2 million, somewhat higher SG&A related to the growth in the Midstream business was more than offset by and not having a recurrence of the $5 million charge in the third quarter of '08 for the Lehman Brothers related bad debt expense.
Moving on to distribution, operating income at distribution was a record $78.9 million in '09 or 32% higher than '08. Net operating revenues increased by about $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 led the quite a bit of compensation related volatility in our earning.
In '08 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 about $45 million of executive compensation expense leading to approximately an $87 million year over swing in executive compensation expense. Our current long-term executive incentive programs have been designed to eliminate such volatility going forward as the majority of this expense is set at the time of the grant.
So 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 for $1 change in EQT stock price. One thing that has not changed with our new program designed.
Management payouts from the program will continue to be linked to shareholder returns. Couple of quick observations on the 4th quarter result specifically like the full year the fourth quarter 09 was an excellent quarter from an operating standpoint which is seen above 19.5% production sales volume growth as well as considerable higher gathering, processing and transmission volumes in our midstream businesses.
The fact that the fourth quarter sales volume growth rate and the full year growth rate are virtually the same again both shy of 20%. I think I am a bit misleading in terms of our growth trajectory exiting 2009.
Some of the earlier quarters in 09 had growth rates that were also in the 20% area however they were compared to quarters in 08 while volumes were somewhat suppressed as the big midstream projects either weren’t online yet or were just starting to come online. But by the time we take you 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 actually achieved about 19% growth in the fourth quarter of 08.
So growing almost 20% in 09 fourth quarter, versus that quarter I think is a very strong result for the company. All over again the favorable operating trends in the quarter were partially offset by unfavorable market conditions from IMX natural gas.
One other quick item of note in the quarter of 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 matched the revenue increase in the 2009 fourth quarter from the Pennsylvania rate case and then finally just a quick update on liquidity, we suggested during the third quarter call that our short net short term debt at year end 09 would be less than $100 million and as it turned out we ended with only $5 million of net short term debt on the balance sheet of 12.31.09 and that puts us in a great position as far as liquidity and financing flexibility as we head into 2010. In December in a press release we announced our 2010 CapEx estimate of about $850 million and we also estimated that 2010 operating cash flow would be about $650 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 5 year NOL carry back allowed by legislation that was an act of doing in the fourth quarter of 09.
The approximately $150 to $200 million difference between CapEx and cash flow we expect to find with our currently virtually undrawn $1.4 billion revolver and with that I will turn the call over to Murry .
Murry Gerber
Thanks Phil and good morning everybody as Phil mentioned we had a extremely strong operational quarter across all of our business lines and the year of course was a real good year for EQT and the headline statistic of course was of the nearly 20% growth in produced natural gas sales and as Phil mentioned at a lower capital costs with projecting sales of another 20% in 2010 at as he described lower cost this was all driven by aggressive horizontal air drilling in our Huron, Berea plant all with the drill bit. Significant progress in the development of the Marcellus also all with the drill bit is our sixth consecutive quarter of double digit natural gas sales growth and we had record throughput and operating income at midstream record operating income at distribution.
In total we drilled in the fourth quarter about 184 wells, 702 for the year. And total horizontal wells spread 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 wont repeat what is in the reserve press release but I did want to emphasize a couple of points.
First un-risk potential is still about the same are we thought before about 26 Tcfe. However you are seeing with this release the continuation of the orderly progression of reserves up toward lower risk categories specifically for the proved reserve categories Marcellus reserves are up about 1 Tcfe due mostly as a result of 2009 drilling Huron, Berea reserves are up about 0.5 Tcfe because of new drilling and the new SEC rules.
We 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 SEC 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 again is an indication of orderly development.
One other item worth discussing is the impact on the reserves of the SEC rules requiring locations to be drilled within five years to be included and approved undeveloped category. For obvious reasons the drilling assumptions 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 2 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 that our CBM other reserve category is down about 0.5 Tcfe this year that is because the presumed 5 year drilling schedule no longer includes many vertical conventional wells.
Those locations are now included in unproved categories. The Huron and Berea update you know kind of a story that we drilled about 821 wells now in that program since the inception of the horizontal air drilling a few years ago a third of our production now comes from air drill horizontal Huron Berea wells and of course in 2006, 0% came from horizontal air drilled wells.
To remind you of 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. As I reported there in the last couple of quarters our latest application of new technology is the extended lateral design improvement in product technologies now allowing for 22 or more stages and so we have lengthened our laterals.
To date we have successfully drilled and completed 5 extended lateral wells doubling our footage of play 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 just a little less than $0.90. IRS for extended lateral we are currently estimating in the mid 30s at $7 NYMEX and greater than 20% at $6 pay back period interestingly is about $2.7 years which is a lot faster than Appalachia use to be clearly and we expect that 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 Marcellus play this is an increase of about 45,000 acres the increase is due to about 13,000 leased acres that we have acquired in P.A. and the rest is due to the impact of positive drilling results in West Virginia.
Which expanded our understanding of the size of the area underlying by high pressure Marcellus. Improvements some dramatic in both drilling cost and completion effectiveness are causing us to become increasingly bullish on this play even in the current price environment a great credit to the EQT team.
Here are the reasons why. Well costs for 1 as we discussed on 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 about $3 million per well we still think $3 million per well is a good number for the current lateral design.
On EUR our estimate of the average EUR from 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 that range.
There are 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 6 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 rig shale and B, the best place to frac.
We have changed our frac casing from 4.5 inches to 5.5 inches which lowers our treatment pressures and allows us to more consistently pump the job as designed. Here we have also significantly reduced the spacing between pricked clusters from approximately 150 to 160 feet.
So on the completion side we take in a number of steps that seem to be causing us to have more consistent jobs and less failure on our individual frac stages. The second important thing that's happened to effects Marcellus EURs is that we've encountered some prime geologic conditions for Marcellus production, particularly in Green County which I will discuss in a minute.
Third and this is a bit more of subtle point. The combined effect of more effective and consistent completion techniques, better targeting and lower cost is intercepting to make more areas in 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 is that 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 that unit development cost for Marcellus wells are about a little less than $0.85 our IRRs similar to the Huron/Berea are over 30% and at $7 NYMEX and greater than 20% at $6 NYMEX and payback period is about in the same range as in Huron/Berea about 2.9 years for the standard lateral design. Specifically, on well results for the Marcellus, we have spent 53 horizontal wells to-date, 17 of those have been 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 with 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 well drilled by industry in the Marcellus place so far.
Two adjacent wells the 168 and the 170 wells in Green had 24 hour flow rates similar to the 167 well but are shed in our way of completion of gathering capacity so we don't have those 30 day IPs yet. 12 wells are planned to be drilled on 3 pads within the 2 mile radius of these wells.
And these wells are located on a pad that's approximately 8 miles away from another very prolific Green County well pad which I discussed in the third quarter. In Green County, more generally, we have about 380 drilling locations.
Our EUR expectation in this area is about 4.5 Bcfe per well, obviously some wells would be higher and some lower than that presumed average. The Green County story for EQT is one of confluence and excellent application of technology with prime geological conditions.
Moving on to West Virginia, we are very pleased with what's being going on in the West Virginia Marcellus program. We have turned 10 wells in line to-date.
While the 30 days 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.
IRRs 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 that West Virginia program is looking really, really good to us at this point in time.
Our Midstream in Equitrans as we previously mentioned in our third quarter 2009 call EQT's Midstream has successfully completed an open season for proposed expansion of Equitrans. We are still negotiating binding precedent agreements.
We did submit, if you saw this, our FERC application for the phase I expansion involving about a 100,000 decks on January 25th, the 100 million a day on January 25th, phase one 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 1 and 2 is currently estimated between $450 million and $500 million, that's 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.
And obviously EQT has always been strong and desired to have control of Midstream and make sure that our gas gets to market, it's been a core issue for EQT over the years and we still adhere to that. But there are a number of people currently who are interested in Marcellus Midstream that wasn't the case now so many years ago, it is the case now and we are talking to a number of people to try to see what they can do for EQT without having to sacrifice the comfort of being able to get our gas to market.
So that's really all I have to say, I mean it's a great quarter, great year. We still believe EQT is a very compelling investment; growth rates are good, industry leading cost structure is important particularly in times like today where commodity prices are a bit soft.
And with that I will turn it back over to Pat and we will take your questions.
Patrick Kane
Thank you, Murry. BJ, could you please open the call for questions.
Operator
Yes sir. [Operator Instructions].
At this time our first question comes from Scott Hanold from RBC Capital markets. Please go ahead.
Scott Hanold - RBC Capital Markets
Yeah thanks. Hey guys congrats on the results.
Murry specifically on that Marcellus I mean that it's an impressive well. You identified a few things and somewhat, there's something unique about Green County that you all seem to have contributed to that, more specifically is there anything else you can point to, from a geological stand point in that area, shale thickness organic content?
Murry Gerber
Yeah, I think, I will keep in mind; I don't know that we are not going to find more wells like the Green County wells. But I would say that we are not presuming that the average is going to be as high as what you might predict from those particular wells.
Geologically, yeah, I think it is a couple of things perhaps but I don't think I would put a lot of emphasis on this right now because we are still learning but yes, it is a bit thicker, yes its broader which we think is an important fact for the Marcellus. The organic rich part of the Marcellus is also the most brittle part of the Marcellus and that seems to have an impact on the effectiveness on the fracs that near bore hole brittleness assuming to provide near bore hole permeability which seems to have 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 so sure we are ready to be able to predict that in advance all that much. I mean we know it when we see it after the fact we are not sure yet we are able to predict it.
The other thing that's happening in this area 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 or faulting to steal away the gas that might have been there earlier and kind of leaked out during successive stages of Mountain building.
And that could also have an impact as well. So those were the couple of the geological factors.
Scott Hanold
Okay, is this pretty much a dry gas well?
Murry Gerber
Yeah, pretty much so, yes.
Scott Hanold
And what if, you talked about just base parts of different things you're doing but what is the latter. And specifically with that well and typically when you look at you're the drilling program in the Marcellus, what was the lateral lengths, how many frac stages and also maybe, throughout the specific, the AFE cost on this one?
Murry Gerber
I'm probably not going to give you all of that its 3,000 feet of pay. I think it was nine stages of fracs, but I am not quite sure, we can correct that if we need to.
And my recollection is it's about a 100,000 barrels of frac fluid we used in that well. That's my recollection, but other than that, I don't think we're want to talk much more of that.
Scott Hanold
Murry Gerber
This is a typical well exactly. This is a typical well and as you know and the industry is certainly experimenting with those longer laterals.
We're to add other designs to increase that net feet of pay in the Marcellus even in more cramped these circumstances, so we're working on all kinds of designs.
Scott Hanold
Okay, if I ask you to give an IP on that well, would you?
Murry Gerber
No.
Scott Hanold
Fair enough. Moving on to the reserves real quickly, just one last thing here and you talked a little about the PUD bookings in your probable numbers.
And it seems like you've taken a pretty deliberate approach on how you are going to get these bookings, is there a number like, do you have a number of PUD locations offset that you drilled to give us kind of also get another way of looking at it.
Murry Gerber
That's complicated by the lease design a lot too, but I don't think I'm going to give you a general number on that. It's just, we basically followed the rules just the way they are laid out by the SEC, Scott, there was no, we didn't take extraordinary measures to go beyond that.
I think the factor that I mentioned in my comments which is actually the most important factor on this whole reserve booking calculation and I know you're going to see this with a number of other companies is the presumption of the number of wells that are going to be drilled in the five year period, that's going to swamp any of the stuff that you're talking about now and as you're comparing company-to-company results, you know I am going to make this long because Scott told me to be brief but the fact is that there is a lot more management judgment in the crude reserves now then there was. It used to be, a handed in reserve report, that was it.
Now there is this question of the five year presumed drilling schedule and that's a big factor. Dave, did you want to?
Dave Porges
I also think it's probably true. If you look at our rate of increase versus others with the new rules, I think a higher percentage of our 3P and our total resource really, is in Shales, and the Shales were affected more by the rules, so I think that's probably one of the reasons you saw higher percentage of increase.
Murry Gerber
That's right. The other thing too is if you recall, we were drilling along pipelines.
We wanted to be able to assure that the wells we were drilling, we were going to get to market and so by definition, we were drilling a lot of unproved locations because the pipeline didn't necessarily fit right on the location that was previously classified as proved and we've been doing that for a couple of years now. That's why I think today's point for EQT it makes sense that there was such a large increase in reserves this year.
So that's number one because of the rule change. And number two because we had drilled so many unproved locations in the last couple of years.
Scott Hanold - RBC Capital Markets
Got it in that lined idea one more question. You mentioned that 168 and 169, your production tested, but your not completed those wells but put them on production.
What is the exact constraint there to get them along 9 is that something that you get some of these larger wells that get more active, that we had when we are building our production levels.
Murry Gerber
It's basically midstream constraint. And maybe they want to talk about it, but we didn't anticipate wells of this magnitude so.
Dave Porges
In some cases for instance we've put in what we think are the appropriate line sizes or compressor stations and we think that will handle it. And the first well comes online and it fails us.
And we are still not sure how quickly these things decline etcetera. Right away we can see them over, weave sequels flat but we product $0.5 billion in about 5 weeks from that 1 well which we like.
But you know that’s not what it looks like a year or two out. So we are still struggling a bit with what is the right way to size that midstream.
Murry Gerber
But lets say though there is a considerable flexibility in what we are able to do on the midstream right now, so it's not like these wells are going to sit there for a long time. Scott, we're actively trying to put together a little bit bigger pipe and a little bit more compression to be able to get those what appear to be very, very good wells on production as soon as possible.
Operator
Our next question comes from Michael Hall from Wells Fargo. Please go ahead.
Michael Hall - Wells Fargo
Couple of follow-ups on a few different topics. Maybe getting on the reserves first as we look at all the incremental Marcellus reserve bookings on the approved developed side, is there a meaningful (inaudible) component within that?
Dave Porges
No.
Michael Hall - Wells Fargo
Okay. So that's on what 17?
Dave Porges
Well I mean there is some PUD map producing that we just discussed those couple wells that are ready to go but it's I would say it's not meaningful.
Michael Hall - Wells Fargo
Okay and then I guess in terms, I'm thinking about for well bookings on approved sides in the Marcellus, you talked about you're assuming a tight curve or EUR 3.6 Bs in West Virginia and 4.5 Bs in PA is that the same figure that's being used in the approved reserve report or the press?
Murry Gerber
Let's be real clear about that. The numbers I stated were specifically for Greene County in sense of the high number and then the lower number was for “West Virginia”.
Our current view of the average EUR for a Marcellus well generally is 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.
Michael Hall - Wells Fargo
I'm just trying to get at what's being assumed in the approved reserves report versus kind of your current thinking of generally.
Murry Gerber
It's about 3.5 is what we included.
Michael Hall - Wells Fargo
And then.
Murry Gerber
That is not correct. I am sorry, we assumed a little bit less than 3.5 in our reserve report, more like 2.5 to 3 range kind of that based on.
Michael Hall - Wells Fargo
I got to about 2.8 on some back of the envelope. Is that about right?
Murry Gerber
Exactly, sorry about that.
Michael Hall - Wells Fargo
And then would you care to discuss maybe what the average 30 day rates in PA and average 30 day rates in West Virginia have been to date.
Murry Gerber
It's an average. No, not really.
I don't really think that's meaningful with the number of data points we have just now because we have some. They are all getting close to one of the attractive aspects of what EQT has done over the last year is that and this is a strategic issue for our management team Steve Schlotterbeck and his team Richard Hill etcetera down there in production is to make even the lower EUR wells profitable.
That is been a huge strategic direction for us, so that's kind of been our focus and so when we get these bigger wells, we're really sort of relishing in the upside potential of those. So we're not really focusing so much on it, and I just don't think the statistics yet, they are such that anything other than the half to four that I mentioned is a very good, is worthwhile discussing where 2.5 to 4 edging towards the south path of the range that is about it.
Operator
Thank you our next question comes from Gerald (inaudible) from J.P. Morgan please go ahead.
Unidentified Analyst
Thank you good morning everybody. Murry in your reserves press release and you mentioned on the call as well that $2.9 billion of CapEx over the next 5 years is that what you expect to spend in terms of total E&P CapEx that I just wanted to clarify I mean that is not.
Murry Gerber
This is we are dealing with a brand new reserve reporting technique here we are not sure what others are going to do 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 that we're having in 2010. That's what we did.
Unidentified Analyst
And got you so and just to clarify, so that's not future development cost related to PUDs, it's totally E&P CapEx using just 2009 times five?
Murry Gerber
It is drilling.
Dave Porges
It is the drilling CapEx that would be associated with the five year plan that's consistent with those reserves.
Unidentified Analyst
But it's more than just PUD drilling.
Dave Porges
It's yeah. Okay but we, total drilling, it could be as I said earlier most of our drilling going forward is going to be on PUD locations, but I didn't say all.
So I think we're 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 and more locations go into PUDs, but I didn’t say all of our locations would be on PUD.
Unidentified Analyst
I understand, but let's assume flat commodity prices but growing production and it's a flat cost. You would then have more cash flow, so in reality you would expect to spend more money as you progress to the next five years.
Dave Porges
Yes, but then what you're talking about is that we would expect to drill more wells than we currently have in our five year and that five year plan, but the five year plan what we are trying to do and we think probably a lot of us are trying to do, if we do our best job of interrupting what the SEC is asking us to do without getting out too far out on the limb and that's all that those numbers reflect in our case, probably for a lot of folks. It winds up representing something that looks a fair amount like five times what we are planning on doing in 2010 because we don't have an approved five year drilling plant from our board etcetera.
Murry Gerber
I think, you're going to see this with everybody. Joe, I think this is going to be an ongoing dialogue between you all and all of the companies and what they presumed.
I can just tell you what EQT did. We didn't presume.
We're going to accelerate all that much. We're just going to keep, we're presuming for the purpose of the reserve report that we would stick pretty close to the 2010 budget, and that's it.
Unidentified Analyst
Understood and got it.
Phil Conti
Got it?
Unidentified Analyst
Yeah that's helpful, and then in terms of we backed into a negative reserve revision of about a 100 piece, is that right? Imagine as a price related and
Murry Gerber
That's right. That's right all of those as details have come out and carried that's in the right neighborhood.
Yes, you're in the right neighborhood.
Unidentified Analyst
And was that --
Murry Gerber
The price related aspect of it --
Unidentified Analyst
Were that mostly PUDs or mostly pre-developed tails or can you give us a breakdown to that?
Murry Gerber
Its yes, all of it but it is mostly the if the tails fall off then you get to with a lower price you get to at a negative cash flow sooner on those wells, so it's tails of the wells that fall off primarily.
Operator
Thank you. Our next question comes from Rebecca Followill from Tudor, Pickering, Holt.
Please go ahead.
Rebecca Followill - Tudor, Pickering, Holt
Hi guys, really nice results and impressive reserves. I mean they are just, that's an incredible potential there.
My question is that when you look at the production guidance for 2010, realizing that it's just 2010 and then it's going to grow from here, it's at 34 year reserve life on preserves and a 102 on 3P, so how do you accelerate that further, and you guys have been working hard to do that, that its just such big numbers.
Murry Gerber
Well, I think, first of all a lot of these results that we are talking about here are fairly new Beck as you know, I mean we are experimenting with the extended laterals in the Huron and Berea. I would like to think that it will become a standard operating procedure soon.
The Marcellus is improving certainly in costs but we have huge outstanding issues with respect to well spacing on the Marcellus. Is it a 1000, is it 500, is it somewhere in between.
And then the third aspect that’s still not crystal clear is the pace of development of 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 still need to be reconciled in our mind before we decide to put the pedal to the metal on that.
Rebecca Followill
Okay, that’s fair, two other questions for you, Midstream, if you can say, what are you looking for in a partner, are you looking for money or you are looking for [multiple speakers]
Phil Conti
Yeah. I think that's a great question.
I think in again we are not getting too long with it, I think there are two issues, one is certainly the one you mentioned money and its really 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 that we are getting 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 trade offs that we have to make. But I think it's more than the money.
I mean we are not good and in the liquids business for example I mean not so much that we can’t build our extraction plant which we’ve done and we weren’t very successful as such but when you look at all the issues of fractionation, transporting of liquid, sale of liquid, etcetera, etcetera, these are core capabilities that EQT just does not have. So on that goal it makes no sense for EQT to develop that capability and so we are looking for somebody that can do that.
Moving up stream into the high pressure gathering system, Equitrans, Big Sandy and then the large high pressure corridors that we built, downstream in the compressors frankly once those things are full those little additional EQT value that’s added to those pipes. And the problem in the past has been that we haven't been able and we knew that.
And you can price those in MLP etcetera, etcetera we all get that. The problem is to build the full period, that if you are asking someone to build something fresh, with fresh capital; the costs of capital that we had seen in the past had been fairly high relative to EQT's cost of capital.
Today I would say and Dave can comment on it but I would say we’ve seen an enormous amount of interest among people and 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. So, Beck I think things have changed here in Appalachia there are a number of people in the liquid side that are capable and anxious to come in and EQT is a great partner and on the sort of the moving up stream 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’s suitable for us.
I hope that’s a very long answer but it kind of frames what we are trying to do.
Operator
Thank you. Our next question comes from Josh Silverstein from FIG Partners.
Please go ahead.
Josh Silverstein - FIG Partners
I was kind of curious if you can clarify the CapEx on the up stream side this year. It is about $150 million drop this year with the 20% increase in the sales volume.
So I was just wondering if there is more efficiency gained somewhere, are you shutting down the CBM program because the Marcellus work 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.
Phil Conti
Yeah, I mean we, Josh I think when we announced the capital budget for 2010, we made 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. So it's exactly what you just said.
Josh Silverstein
Go you. So there is no real shut down of any other program, it's just cost efficiency gains.
Phil Conti
No. I think this is, yeah this is raw productivity improvement.
Old fashioned. We are doing it the old fashioned way.
Josh Silverstein
Got you. Okay, understand, and also as compared to last year sorry previous years where you guys had gone into the year very well hedged this year its about 35%.
Just kind of curious if that’s by design or if you guys are planning on layering an additional hedges as you go throughout the year.
Dave Porges
Yeah, we talked about a lot of IRR versus gas prices in his discussion and we make above a 20% return with $6 gas. So we have a lot of protection from our low cost structure.
And we can make our cost to capital return at prices well below where they are right now. But we do look at them all the time.
We haven’t done any hedges in the last couple of years but we look at it all the time and I think it’s fair to say we are looking at it a little more seriously right now. We, as you know we talked about this a lot in the past prefer to do callers so if we see some callers out there that we can mark in our cost of capital and give us a fair amount of exposure for the upside, I will take a look at it.
Operator
Our next question comes from Faisal Khan from Citigroup. Please go ahead.
Faisal Khan - Citigroup
Hey guys it’s actually Tim Schneider for Faisal. First question is sort of what do you envision your Marcellus production could peak out in the next few years and then also on the take away side should we think of it as about 50 million cubic feet a year?
Murry Gerber
First of all we are not going to give that number 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 at wells in Marcellus, scoping out the play we currently believe that certainly production will increase but I am not ready to give you specific guidance on that at this point in time.
Faisal Khan - Citigroup
How about the takeaway capacity?
Murry Gerber
Well, it depends on what you mean and we had the discussion before in terms of the downstream takeaway capacity for gas that is the interstate pipeline capacity, EQT is quite well positioned and we are working with El Paso to complete the 300 line up in northern Pennsylvania that adds incremental capacity of 350 million a day to the eastern markets and backhaul capacity of an additional $350 million a day to the Gulf Coast market. So $700 in total.
So we are very well situated there upstream you know we are building this Equitrans thing and that’s going to help quite a bit. And then as you get further up stream into the gathering, the high pressure gathering etc., its getting built according to the need that’s being generated by the wells and so if you said what is currently least troublesome its the downstream capacity.
What’s currently most troublesome and most uncertain, it’s all of the stuff leading from the well to those interstate pipes.
Faisal Khan - Citigroup
Got it and then just to clarify, you said the Green County well, the $14 million one that was dry gas.
Murry Gerber
Mostly yeah.
Faisal Khan - Citigroup
Okay. Thank you very much.
Operator
Thank you. Our next question comes from Ray Deacon from Pritchard Capital.
Please go ahead.
Ray Deacon - Pritchard Capital
I was wondering could you talk about the, nine frac stages and high rate equated kind of roughly a 2,000-foot lateral? Is that fair?
Murry Gerber
It is 3,000-foot lateral. And I may have the number of frac stages wrong.
Ray Deacon - Pritchard Capital
Okay. Got it.
Alright I was just trying to reconcile that with you are saying you are applying a frac job every 60 feet.
Murry Gerber
Yeah, we are at the stages are longer than that but the clusters are spaced the other stages are spaced more finely closer together than we had previously done.
Ray Deacon - Pritchard Capital
Okay got it. Great.
And 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 are going to end up being quite different in terms of the returns or is it different.
Murry Gerber
No I think the way we are viewing West Virginia currently is that 3.5 Bcf dealers are quite good wells and the costs are a bit lower as well so since the key thing there is that all the IT rates weren’t that flashy it seems like they are holding up a bit better and I can exactly give you the geological explanation for that just now. But that decreased falloff in the production is something that's caught our attention.
Ray Deacon - Pritchard Capital
Got it, and would you, have you got any actual data points for the super long laterals yet and [multiple speakers] talk about not yet.
Murry Gerber
No. We don't yet have, no.
Ray Deacon - Pritchard Capital
Okay, got it.
Murry Gerber
One thing you should be aware of though, I don't want to belabor it but you know the acreage positions are very cut up in the Pennsylvania Marcellus and clearly we don't have forced pooling in Pennsylvania. We are working hard to get it but the question is going to be, if we don't get forced pooling the application of the extraordinary levels is going to be difficult to presume.
So I just want you to be aware of that. I think forced pooling if PA gets forced pooling you are going to see a more rapid deployment of the long laterals.
Certainly if people have concentrated acreage positions can do some of that. But in terms of broad application we really need some kind of forced pooling regulations and we are not really close to deal on that yet with Pennsylvania.
Ray Deacon - Pritchard Capital
Got you. Just one more quick one I guess with the 40 to 50 wells in 2010 in the Marcellus would they roughly half and half West Virginia and Pennsylvania.
Murry Gerber
We are kind of, where we have really not much preference one way or the other it will depend somewhat on locations that are available somewhat on streams that's available so we can get to cash, the market can get some cash for it. So I think we are going to bobbing and weaving a little bit between the two depending on those two factors.
Ray Deacon - Pritchard Capital
Great. Thanks very much.
Murry Gerber
Okay, thank you.
Operator
This concludes our question-and-answer session for today. I would like to turn the conference back over to Mr.
Pat Kane for any closing remarks.
Patrick Kane
Thank you BJ. That concludes today's call.
The call will be replayed for a seven day period beginning at approximately 1:30 p.m. today.
The phone number for the replay is 877-344-7529. You do need a confirmation code which is 136900.
And the call will also be replayed for seven days on our website. Thank you, everyone for participating.
Operator
This concludes the EQT Corporation Year-end 2009 Earnings Conference Call. Thank you for attending today's presentation.
You may now disconnect.