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Executives

Steve Schlotterbeck – Senior Vice President, Exploration and Production

Analysts

Gil Yang – Bank of America/Merrill Lynch

EQT Corporation (EQT) Bank of America/Merrill Lynch Global Energy Conference Call November 16, 2011 2:50 PM ET

Gil Yang – Bank of America/Merrill Lynch

Finish up, the conference we have got EQT, so, I think the quality certainly has stayed high through the day. Steve Schlotterbeck, Senior Vice President of Exploration and Production will give the presentation. Steve?

Steve Schlotterbeck – Senior Vice President, Exploration and Production

Thank you, Gil. Good afternoon everybody. Glad to see some folks made it in this beautiful sunny day in Miami, Florida and following a fire drill, it was good to see some folks made it back and are here to hear our story at EQT. I will try and keep it fairly brief and happy to take some questions at the end, but I am sure everyone is probably anxious to start heading back home.

So, our story actually is pretty simple. We are a 100-year-old company based in Pittsburg, Pennsylvania who has been blessed with these new technologies and unconventional reservoirs. And we find ourselves in a situation, where we now have bounties of excellent investment opportunities even at today’s gas prices and the strategic challenges that are facing us in the short-term is accessing sufficient capital to try and pull those opportunities forward and create the most shareholder value we can as a result. So, most of my talk will evolve around the assets we have and why I say we have this bounty and then the actions that we are taking and that we are considering to try and pull that value forward. So, that’s mostly where I am going to focus on, but regarding the bounty, significant amounts of reserves currently have 5.2 Tcf of proved reserves.

And when we look at our entire asset base that we have today we see upwards of 32 Tcf of gas recoverable from that position. And we feel more and more comfortable as time goes on that, that 32 Tcf is a good number and that as we develop our asset base we continually see reserves moves from resource potential in the 3P and then into proved reserves as we drill across our acreage position.

So, given that huge asset base, I think over the past few years, we have proven that we have the operational capabilities to have an aggressive development program on our acreage position. Being a long-term Appalachian producer in days when gas prices were closer to $2, we have a culture of being a low cost operator. We have been able to maintain that through this rapid growth period we have been in and we intend to maintain that. And certainly gas prices in the mid 3s where we are at today, we see that as a clear advantage for EQT in keeping our margins as high as possible.

We have a very expensive midstream asset base, that’s very well-integrated into our acreage position. I will talk a lot more about that and what our plans are for that and what the opportunities are. And we have just for a basis of discussion, we have talked about the ability to have a five-year compound annual growth rate of 30% by outspending our cash flow about $300 million or $400 million per year for the first three years of that period. So, that’s excess of cash flow in total about $1 billion to $1.2 billion. Earlier this year, we sold two midstream assets that brought in about $620 million. Just last week, we issued some debt and brought in another $750 million. So, we think we have fully funded that cash flow gap, so we think the 30% five-year CAGR fully funded and well within our wheelhouse operationally.

We are a company that has three main business units. Over time, we have seen rapid growth in the Production business unit and Midstream business unit. Those two are very well-linked. The majority of Production’s gas flows through Midstream’s pipelines and the majority of their throughput is from EQT Production’s gas wells. We do have a local distribution company mostly around the City of Pittsburgh, about 275,000 customers, a very stable business in terms of regulated return. It hasn’t been growing. It hasn’t been shrinking. It stayed the same over the past several years. The other two business units have seen rapid growth. So, we would expect that to continue upstream and midstream continued to grow and our downstream business will stay relatively flat.

I mentioned reserves, I think, if you look at a pie chart of how our reserves were laid out a few years ago, Marcellus wouldn’t even show up in the first few years it did, it was fairly small. You can see now it pretty much dominates our reserve picture and we expect that trend to continue significant 3P reserves in the Marcellus. I’ll talk more about our Huron play in a little bit, but suffice it to say, at this point, it is a significant resource base. It doesn’t compete particularly well return wise with the Marcellus and I will talk about that, but it’s a large, large acreage position with a very significant amount of gas underneath it.

On to the Marcellus play, we have just over $0.5 million acres in the play. The bulk of our acreage is legacy acreage that we have had for decades in many cases. It’s nearly 100% held by production. It has on average very high net revenue interest. We are about 87.5%, 88% average net revenue interest across our acreage. So, it’s a very – it’s a very nice acreage position for us to have particularly the acreage in Southwestern Pennsylvania, where we think we have drilled some of the best wells in the play. We have got some excellent geology there, a lot of room to run. So, it’s an acreage position we are very, very excited about.

You can see in 2011, we plan to drill about two-thirds of our wells in Pennsylvania, but a third in West Virginia. We are focusing really on three main areas in 2011, the Green Washington County area, which is the best rock we have. We have done a lot of drilling there. It’s really driven a lot of growth. In West Virginia, we are focusing the bulk of our activity in the weather areas near Doddridge County, West Virginia. MarkWest is building a processing plant that will be operational mid next year and once that’s up in running we will start getting a bigger benefit from liquid distraction.

We currently take a fairly shallow cut with some JT skids we have out there. Next year when the plant is operational, we’ll take a much deeper cut get much more uplift from the liquids. And we are currently drilling up in some lease position, we have in Tioga County, it’s about 6,000 acres. We have a rig up there actively drilling. We just started fracing the first well about a week ago that seems to be going well. And so we should have our first production in Tioga County roughly around the end of the year maybe first or second week of January. So, we are pretty excited about that. It looks to us like it should be a good area as well.

On a return basis, we talk a lot about the excellent returns in the Marcellus and they really are pretty phenomenal. Historically and internally, the bottom line on this graph, the red line is the line we typically refer to, it’s fully loaded, all of our costs are in there including an estimate of the severance tax for Pennsylvania which doesn’t currently exist, but we think it’s coming, I’ll talk a little bit more about that in a minute. And that’s the line we internally make our decisions on. We have been told that there is some inconsistency in the industry with how returns are discussed. So, we thought we show at the wellhead. So, excluding the Midstream cost excluding taxes, you can see the returns are pretty phenomenal. And then we also show it after Midstream, but before taxes. Just for reference, it’s hard to read on this scale that fully loaded after-tax return at $4 is about 40%, so even at these low gas prices it’s pretty phenomenal stuff.

We have been taking last six months or so publicly about a new frac technique, we have been experimenting with. The basic idea behind this experiment is even with these great production rates we are getting. We still leave more than half of the gas that’s in the Marcellus shale we leave it behind. So, we view that as a huge opportunity to apply technology to get greater gas recoveries and that’s – that will be a slow process to get up to where conventional reservoirs of 80% or 90% recoveries are, but we have a lot of our technical folks focused everyday on trying to figure out ways to get more of that gas out. And one of the things they came up with was a re-look at our standard practice on and what they came up with from the frac modeling and the reservoir modeling they did was – if we would focus our hydraulic energy in the smaller units of rock, but pump the same total volume of water and sand in the well, we could get a more extensive fracture network and therefore greater gas recovery from the same unit of rock. So, that was the theory. We began a test about a year ago to test that and we have done 25 or 26 wells so far just starting to get preliminary indications of whether it’s going to work or not.

One thing we did to see if we are getting the effect that we anticipate we have run a microseismic survey, which measures microseismic events in the ground and this is a brief example of what that look like. I think the thing to highlight here is the bottom row, the events per acre. We were hoping to get more intense fracturing and you can see we are seeing about three times the number of microseismic events per acre with the new design versus the old. So, it’s very anecdotal not conclusive in and of itself, but we thought that was a nice data point that confirmed what we thought we would see.

Another nice confirmation point was our model suggested 50% to 60% higher initial rates per well. That’s almost exactly what we are seeing. I’d also predicted a little steeper decline rate and slight increase in recovery which was the basis for the whole design in the first place. It’s going to take quite a few more wells and more production history to draw firm conclusions on that.

What we think we are seeing at the current time is areas where the silica content and the rock is fairly high and the rock is brittle. We think we are seeing enough enhanced fracturing to pay for the extra $1.8 million per well that is technique costs. Areas with higher clay contents and it’s more ductile, we are not sure we are seeing enough benefit at $4 gas to make it economic. So, I think for the time being our working hypothesis is there is going to be some areas of high silica rock, where this becomes our standard, other areas where we stick with the normal design and then there are scenarios where we just have to gather more data.

As gas prices go up more acreage shifts towards the new design. So, it’s very gas price dependent, because there is a large acceleration component to it. We do have another big play, I mentioned, a few moments ago, it’s our Huron play. It’s a low pressure, Devonian shale play primarily Eastern Kentucky, Southern West Virginia. This is a play that back in 2006 and 2007 EQT pioneered the use of horizontal air drilling for this play. We saw immediately tripling our more productivity of our wells and it ramped our volume growth at the time from 4%, 5%, 6% per year, up to the mid to upper teens per year and this was before the Marcellus really came into its own. So, we have a huge acreage position, it’s all HBP. Current returns at $4 gas are above our cost of capital, but well short of Marcellus returns.

So, our strategy in this play in 2011 has been to keep it on life support meaning just shipping enough capital into play to keep the technologies in place, to keep the human capital in place that can deploy those technologies, so that we can – the ability to develop this play in the future remains in that area. Our strategy now is going to be to likely continue at that level of investment on life support and in 2012 really focus on what is the long-term strategy for the Huron given we have these numerous opportunities in the Marcellus ahead of us. So, presumably we will be looking at ways to bringing other people’s money, because there are attractive drilling opportunities there to continue development of the play.

This mentioned just very briefly I mentioned the historic 4%, 5%, 6% growth you can see that in the left hand of this chart. The yellow is when we implemented the horizontal air drilling in the Huron kicked this up into the mid-teens in growth and you can see what the Marcellus has done, it sort of really dwarfed everything else. Last quarter, we reported over 50% volume growth from the prior year. Volumes have been going up quite rapidly.

Very briefly on that we’ve been ramping up in the Marcellus and conversely we have been really pulling back in the Huron, the left two charts on this page just illustrate that, of course, high growth rates in sales and improved reserves along the way as well. I mentioned we are a low cost producer, you can choose how you calculate these metrics, but I think under any calculation scenario we are amongst the best in the industry in these categories in finding and development cost and per unit operating expenses. We’ve always thought that was very important. We continue to think that’s very important and $3.40 gas, I think where we are at today that really makes the big difference on our margin. So, we continue to be amongst the best and that’s where we are going to stay.

On Midstream, our current thinking before I really talk much about what’s on the slide strategically the way we are looking at the business now as with these many, many high return opportunities, primarily in the Marcellus – for drilling Marcellus wells and a company that has been capital limited, our desire is to find the way to dedicate as much of our internal cash flow toward further development of the Marcellus and attempt to use someone else’s money for the development of the Midstream, which is a significant amount of capital as well. So, we have announced on our last call that we are looking at a couple of options including an MLP and a JV for the Midstream. I think we are actively working both of those paths and hope to make some decisions sooner rather than later. But we think the best shareholder creation opportunity for EQT is to put as much money into the Marcellus drilling as we can.

We do think it’s very, very important from our experience of having control of the Midstream. We think it’s very important that we maintain control of that. We’ve gotten significant advantages from being able to design the pipelines to suit our needs in terms of pressures and flow rates. We have a lot of certainty about the timing of the pipelines, because it’s all internal and those are advantages that we are very, very reluctant to give up. So, we are evaluating structures that would allow us to keep that in house. So, very, very important to us. You can see it’s a very extensive system. It was designed to move gas from our acreage position. So, it’s very, very well integrated to what we are doing on the upstream side.

And you can see below the capacity additions that we are anticipating on the gathering side this year. On the transmission side, we have a business called our Equitrans pipeline system, another legacy asset that was originally installed to bring gas to Pittsburgh to serve the industrial users of Pittsburgh when it was a big steel town. That system is now being used as a header system to move gas from our Marcellus acreage position into five different interstate pipelines that interconnect with. So, it’s been a great asset for us getting our gas to market. They have significant expansion opportunities on this and it’s been a great asset for our Midstream group.

And then one step further downstream on capacity on the third-party transmission lines, EQT has been proactive in this sense going back three years. We anticipated that with the quality of the wells we were drilling and just the huge scope of the Marcellus that there would be difficulties in getting gas to market. So, we took a fairly sizable firm capacity position on the Tennessee gas Pipeline, Line 300 project. About three years ago, we signed up a 350,000 dekatherms a day capacity to New York and we also for very small incremental cost got back all rights to the Gulf Coast for another 300,000 dekatherms per day.

So, in total, 650,000 dekatherms a day of the interstate transmission capacity, all of which is now incremental to what we are producing today. This capacity came on line this month. So, we’ve been moving all of our gas without this capacity up to this point. So, this is really available for future growth. So, we think we are in excellent position for the next several years and our commercial folks are really now focused on 2014/2015 timeframe and what is the next tranche of capacity we need to have to move how much gas we think we are going how out there. So, I think all said and done when we talk internally about getting gas to market. We really have been very fortunate in having two-thirds of the system under our control and the last lag that isn’t in our control, we had no foresight to lock up the capacity, so we really have not had any difficulties getting gas to market.

We do still have a rather small LDC mostly based around the City of Pittsburg, 275,000 customers. Again, it’s a very stable business. I think we clearly view it as a non-core business. But in the short-term, it provides us several benefits including supporting our credit rating, it supports our dividend, it’s very stable, it earns a regulated return so, and has a very little tax basis. So, the thoughts of just an outright sale of this business doesn’t seem to be a particularly tax efficient thing to do. So for now, we are happy to let it chug along in earnings return. It’s not growing, it’s not shrinking, and I think further down the road, it might enter into some more strategic discussions for us.

We think as a producer that if there is anything we can do to spur the demand side of the equation. We think that’s something we should do. I will say we are not big enough to make a big move in this area, but we certainly want to do what we can. So, one thing we have done is we installed the first publicly available NGV fueling station in Pittsburg, not too far from our office downtown and we are converting all of our fleet over to natural gas. So, that will be the primary customer. There are some other return to base fleets in the area that will use that there are some Pittsburg city garbage trucks that are now using it.

I do want to be clear though that we don’t intend for EQT to get into the retail natural gas fueling business. So, this isn’t the first of many stations for us. This is sort of a test case to get the idea out there in Pittsburg. We were able to use our engineering expertise after building this to help a local grocery store chain who installed the second NGV station in Pittsburg. We did the engineering design for them. So, just as experiences sort of help, promote, at least one more station, hopefully more in the future.

Of course, we think being good corporate citizens is absolutely imperative. It’s imperative anywhere we operate as an industry and it’s even probably more acute or more on the front pages in the Marcellus. So, we think that’s critically important, we have had good relationships with the regulators in the states we operate in. Some of that is a function of having been there so long. But I think it’s mostly a function of we have been able to do a good job and we’ve supported regulations that are in line with industry best practices.

We don’t think there is an advantage of the industry to have regulations that fall short of what industry best practices are. So, we have supported stricter regulations as long as they are sensible and they are doing the right thing of protecting the environment, protecting the safety and health, the citizens or workers that are out on our locations. The last thought on this page, I think is a key point, especially this week.

EQT was a first company and still wanted probably a few that is publicly supported of severance tax in Pennsylvania. It’s now being called an impact fee, you call severance tax impact fee. But we have always thought that oil and gas company should pay for the impacts that they have on the communities we operate in and without a severance tax that clearly hasn’t happened in Pennsylvania, there is lots of truck traffic. We do damage roads, now we do generally repay the roads, but there is dust, there is noise.

There are impacts on the citizens. We think if we cause that then we should be the ones paying for it. So, last night, I believe maybe this morning, the Pennsylvania Senate voted on a bill that includes an impact fee. We think that impact fee is very reasonable. It’s less or it’s about what we include in our economics already. So, we think that’s important. We think to gain the public trust, if we are not paying, if we are the only states in the country not paying a severance tax, we will never gain the public trust so.

On the drilling and fracing side, water continues to be a hot topic of conversation. Of course, we need all local state and federal regulations. We have all the necessary spill prevention plans in place. And I think just as importantly as we were one of amongst the first companies to publicly report the composition of our fracturing fluids. We never really saw why there would be any need for that to be a secret. So, we published that on our website. We publish it on, in fact, focused on a lot, if you want to go look it up.

We were one of the first companies to recycle our flow-back water. We are now recycling a fair amount of our produced water as well. So, we have very little water that we have to dispose of and we continue to look for technologies and techniques to further minimize the impact on the water resources of the states we operate in. We are one of the leaders in drilling multi-well pads, which has much less surface impact. The more wells we drill, prepare, the less surface impact we have, the community really, really likes that.

So, just to sum it all up, I think it’s a pretty simple story. We have been blessed with this huge resource base, still a fairly small company in the scheme of things, so we found ourselves a little capital short over the past couple of years. I think we have committed to selling assets as necessary and using our debt capacity as our growth creates additional debt capacity. We have accessed that which we did last week and with the whole idea of dedicating as much capital toward the high return Marcellus projects as we can and as we prudently can. And I think that’s it, happy to take any questions.

Question-and-Answer Session

Unidentified Analyst

Hi. You alluded to some disappointment in your last call on not having a definitive plan for your Midstream and as I see it you are going to have a JV or an MLP or some combination thereof, but did you say today that you reached that decision when you figured out how to keep it in-house?

Steve Schlotterbeck

Well, I don’t remember alluding to disappointment, but maybe I did. And clearly, there was a little bit of disappointment. I think what we are saying is we clearly think we need to use someone else’s money to fund the development of the expansion of our Midstream system. And we can control that expansion is critical. So, we have noted down to basically two options that we think could achieve our objectives and that one is an MLP and the other is a joint venture. And I think regarding an announcement, we will announce our plans for the Midstream once we firmly know what we are going to do. And I think for the time being we are working both options simultaneously. So, we haven’t put one path on hold and progressing down another path. So, both moving forward when we make an internal decision we will end quickly let our investors know what we intend to do. With all that shed with our expectation that we will execute then on whatever that is in 2012.

Unidentified Analyst

Okay. One other question (indiscernible), in your last slide about being a good citizen, take care of the water, do you do that in-house or you outsource that water creating a transportation or whatever?

Steve Schlotterbeck

Actually, we – in terms of recycling, I’d say it’s in-house, but we have companies that we rent pumps from and we try and pump as much water from place-to-place as we can to minimize the truck traffic. So, the pumps and the people who hooked up the pipeline can run the pumps are contracted out, but the actual recycling is actually very, very simple. And that for the most part there is limited actual treatment necessary of the water. It’s mostly dilution. So, we only get about 20% of the water back, so we transport that to the next frac pit. And we placed it where we add 80% new freshwater. And by the time we do that, primarily the sulphates – the concentration of the sulphates is low enough or the frac chemicals we need are effective. So, sort of constant, we re-use what comes back, but we are always adding new freshwater to it. So….

Unidentified Analyst

Hi, just a clarification question, you said the Pennsylvania Senate supported the severance tax this morning is that, has the house approved it as well just curious what the progression is before it becomes law?

Steve Schlotterbeck

My understanding from quickly reading some e-mails today from a government (indiscernible) group, I believe the house has already approved a bill that has an impact fee. And I may get the numbers a little lull, but I believe the house bill has something like $40,000 per well the first year ramping down the $10,000 per well in year 10 and then zero after that. The senate bill starts at $50,000 the first year ramping down I think also to $10,000 in year 10, but then it’s 10,000 per year in years 11 through 20 in the senate bill. So, now they will get together, they will negotiate and come up with something, but I think either of those are very reasonable.

Unidentified Analyst

Okay. Any indication of timeline?

Steve Schlotterbeck

I think sooner rather than later on that.

Unidentified Analyst

Okay, thank you.

Unidentified Analyst

A finishing question, so if it’s $10,000 a year for years 10 through 20, how will that – will that change the EURs as well?

Steve Schlotterbeck

No, no that $10,000 a year in cost won’t even move the needle on economic limit. In terms of the ongoing operating cost of a well, no, but I will be honest what I don’t know, because I don’t think this would ever be an issue, but if a well wasn’t producing, if a well is produced for 10 years whether that we owe the impact fee for years of 11 through 20, I don’t know, but we have seen nothing that would suggest. Once any of our Marcellus wells are in production, the ongoing operating costs are really fairly low. So, it’s unlikely that we would ever see a situation, where gas prices were so low that we couldn’t cover operating expenses and we shut our wells in and wait for higher prices.

Unidentified Analyst

You wouldn’t want to see that $10,000 a year to $30,000 to $40,000?

Steve Schlotterbeck

We’d rather not, but if your PV is 30 through 40 probably not that bigger deal, but I think having an end to it, there is lot of advantages. At some point, you do start wondering about the economic limits of the well, do you pay the severance tax if the well doesn’t produce. And I don’t think we want to get into debating whether we owe a severance tax on an asset that we have already plugged. But, I think year 20 we can live with that.

Unidentified Analyst

In the Huron, what’s your royalty acquisition again?

Steve Schlotterbeck

In Huron?

Unidentified Analyst

Yeah.

Steve Schlotterbeck

It’s about 90% on average.

Unidentified Analyst

Royalties are 90%....

Steve Schlotterbeck

No, no we have generally our leases are 87.5%.

Unidentified Analyst

Right.

Steve Schlotterbeck

And then we have a fair amount of acreage that we own in fee. And I think the weighted average is around 90%, 91%, but generally any given well is generally either 87.5% or 100%.

Unidentified Analyst

You said you would like other people’s mine to drill that well, if the rate of return is 20% $5 gas normally to incentivize somebody to drill, put money down, you’ve got to give them a rate of return, if you are splitting a rate of return that’s sort of okay at $5 and not greater than $4 how you can incentivize somebody to put money?

Steve Schlotterbeck

Well, I am not trying to indicate that we will do that and you are right if there is not enough juice, you won’t really where you could attract somebody and they give us $10 a bill for the whole thing. But I think our view would be there is a huge resource base, I think it’s massive. If we can find a way to keep the technology there and development going and develop that resource base at a profit we are interested in that. If we are not going to get paid for that development potential, so just no way to do that, then we will hold on to that. But we might then shift our focus to the proved developed producing properties in that field and see if there is a way to monetize that, right, the various options there. So, not trying to signal that we have any idea what we will do other than we are going to commit to studying it pretty hard in 2012.

Unidentified Analyst

And that 20% rate of return includes that royalty position that you have?

Steve Schlotterbeck

Yes. And it’s a weighted average.

Unidentified Analyst

Right. Now, sort of flip the question, because you are partnering with Range and Nora.

Steve Schlotterbeck

Yes.

Unidentified Analyst

And they have the royalties in Nora.

Steve Schlotterbeck

Yes.

Unidentified Analyst

So, you have the sort of economic disadvantage for drilling there versus their position?

Steve Schlotterbeck

Yes.

Unidentified Analyst

So, you operate.

Steve Schlotterbeck

Yeah, we operate the coalbed methane part of the field. They operate the deeper part of the field.

Unidentified Analyst

What’s going to be the destiny of that asset is there an impact where you don’t really want to drill coalbed methane, they like you to drill….

Steve Schlotterbeck

I can’t really comment on details of our contractual relationship or what I will say about Nora is we view that as the non-core asset. The returns for us without the royalty at today’s gas prices are below our cost of capital. So, our desire is to have basically no investment in that asset, that’s on the coalbed methane. Well, that’s what we did this year. Now, our agreement allows them to continue development on their own and we can opt out. So, they did some of that in 2011. I think our position in 2012 is also going be, we don’t think we should be investing money in that field, because its non-core and its now sub-economic for us, we think that’s one of the upstream assets that might have potential for monetization. So, it’s a nice mature asset. It has some future development. If you had a lower cost of capital to drill, it might be attractive. So, I think we are going to pursue our options on net asset. That’s definitely not an asset where we are tried to.

Gil Yang – Bank of America/Merrill Lynch

Well, there is no other questions. It’s been a long day, long conference. Appreciate everybody’s willingness to check it out and see it, especially you for giving the last presenting here. Thank you very much.

Steve Schlotterbeck – Senior Vice President, Exploration and Production

Yeah, thanks.

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