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Executives

Patrick Kane – Chief Investment Relations Officer

Philip Conti – SVP and CFO

David Porges – President and CEO

Steven Schlotterbeck – SVP, President - Exploration and Production

Analysts

Neal Dingmann – Sun Trust

Scott Hanold – RBC Capital Markets

Michael Hall -Wells Fargo

Becca Followill – US Capital Advisors

Rhett Bruno – Bank of America/Merrill Lynch

Josh Silverstein – Enerecap Partners

Raymond Deacon – Pritchard Capital

EQT Corporation (EQT) Q1 2011 Earnings Call April 28, 2011 10:30 AM ET

Operator

Good morning and welcome to the EQT Corporation First Quarter 2011 Earnings Conference Call. All participants will be in listen-only mode (Operator Instructions). After today’s presentation, there will be an opportunity to ask questions. Please note this event is being recorded.

I would now like to turn the conference over to Patrick Kane, Chief Investment Relations Officer. Please go ahead.

Patrick Kane

Thanks, Andrew. Good morning everyone and thank you for participating in EQT’s first quarter 2011 earnings conference call. With me today are Dave Porges, President and Chief Executive Officer; Phil Conti, Senior Vice President and Chief Financial Officer; Randy Crawford, Senior Vice President and President of Midstream, Distribution and Commercial, and Steve Schlotterbeck, Senior Vice President and President of Exploration and Production.

In just a moment, Phil will summarize our operational and financial results for the quarter, which we released this morning. Then Dave will provide an update on strategic operational and regulatory matters. And following Dave’s remarks, Dave, Phil, Randy and Steve will all be available to answer your questions.

But, first, I’d like to remind you that today’s call may contain forward-looking statements. It should be noted that a variety of factors could cause the company’s actual results to differ materially from the anticipated results or expectations expressed in these forward-looking statements. These factors are listed under risk factors in the company’s Form 10-K for the year-ended December 31st, 2010 that was filed with the SEC as updated by any subsequent Form 10-Qs which are on file with the SEC and are available on our website.

Today’s call may also contain certain non-GAAP financial measures. And you can refer to the morning’s press release for important disclosures regarding such measures and forward-looking statements discussed on today’s call.

I’d now like to turn the call over to Phil Conti.

Philip Conti

Thanks, Pat, and good morning, everyone. As you read in the press release this morning, EQT announced first quarter 2011 earnings of $0.82 per diluted share, a $0.26 increase over EPS in the first quarter of 2010. Three items cumulatively added $40 million to our pre-tax income, or about $017 after tax earnings per share.

The sale of the Kentucky processing complex resulted in a book gain of $22.8 million. There was also an adjustment for non-income tax matters that added about $13 million, and we recognized a $4 million gain on the sales some available for sale securities.

Adjusting for those three items, EPS was flat with last year’s quarter, despite the fact that gas prices were considerably lower in the first quarter of 2011. Operating cash flow, which excludes the impact of gains on sales of the Langley processing complex and the available for sale securities increased by 22% to just short of $250 million for the quarter.

Increase in cash flow comes as a result of another outstanding operational quarter across all three of EQT’s business units, including record produced natural gas sales, and continued low per unit development and operating costs for production, which were already among the best in the industry, another record and gathering in transmission volumes, lower per unit cost in our midstream business, and solid operating income at equitable gas.

The operating results of this quarter were pretty straightforward. And I’ll just talk to them fairly briefly starting with EQT production, where the story in the quarter continues to be the growth in sales of produced natural gas. The growth rate was a little over 43% in the recently completed quarter over the first quarter of 2010, and sequentially a little over 11% versus the fourth quarter of 2010. That growth rate was all again – was driven by sales from our Marcellus Shale play which contributed over 37% of the volumes in the quarter, up from only 13% in the quarter a year ago. As I mentioned, gas prices were lower in the quarter, the realized price at EQT production was just under $4, compared to about $4.74 last year. At the corporate level, EQT received $5.43 per Mcf equivalent, or almost 20% less than the $6.45 per Mcfe received last year.

Produced liquids mainly from our Huron and West Virginia Marcellus play accounts for 7% of the volumes, and 20% of the un-hedged revenues in the quarter. As a reminder, we do not include ethane in our liquids count as ethane is currently sold mostly as natural gas. But just FYI ethane also accounts for about 7% of the total well head stream. Total operating expenses at EQT production were higher quarter-over-quarter as a result of higher DD&A and SG&A although unit cash operating costs were significantly lower consistent with the significant production growth. Production taxes were down a fair amount in the quarter especially on a unit basis where we reported $0.19 per Mcf equivalent versus $0.28 last year.

Since that large of a decrease maybe not be intuitive remember that Pennsylvania does not currently impose production taxes and a big chunk of our growth came from the Marcellus play in Pennsylvania in the quarter. Per unit LOE excluding production taxes was also down by 28% to $0.18. That decrease was as a result of our higher throughput while maintaining the cost structure that again is among the best in the industry. There is some to month-to-month variability in our LOE activities but we do expect to average about $0.20 per Mcfe for the year.

A couple of notes on the Marcellus well status so far this year we have spud 23 wells with an average length of 4,775 feet nearly 15% longer than our forecasted average length. We continue with implementation of our new frac geometry design experiment. So far we have completed 13 Marcellus wells with the new frac geometry eight of the 13 wells are producing, four wells are shut in leading on pipeline construction and one well should be turned in line later this week.

We continue to see higher IPs per foot treated of lateral with this new design however we are still gathering more long-term production data before making this design our standard. We do plan to complete 19 Marcellus wells using the new geometry in 2011. In other well result news we drilled two wells in Jefferson County during in the quarter both wells had 24 hour flow rates of about 10 million per day these results will be used to mid-size the Midstream build in that new area. This month we spud our first well in Tioga County where we intend spud 10 wells this year and we will have more in flow on that as the year goes on.

Our norm has been to provide a breakdown of our Marcellus wells that are in various stages of completion. So as of the end of the quarter EQT has spud a total of 167 horizontal Marcellus wells of which 82 are currently online. Of the 85 wells not yet online 29 have been fracked and awaiting pipeline hook ups, 39 are drilled and awaiting a frac job, 16 are either currently drilling or have been top flow and one well is not successfully completed and will be plugged. We also track our progress internally by frac stages online we’re in the system for our Marcellus wells and on that metric as of the end of the quarter 1,032 frac stages are online, 418 more are completed, but not yet online, 600 are planned for wells that have been drilled to total depth, but not yet fracked and 261 are planned for wells that have been spud, but again, not fracked.

Finally, we would like to update the expected returns from our Marcellus play taking into account the continued oil field inflation. While we have our frac services contracted through 2011, there are variable costs that are passed through the EQT, and we expect to see more oil fueled inflation next year.

We now estimate that a typical 5,300 foot well will cost above $6 million. Partially offsetting this inflationary pressure is a lower expected cost to gather and transport the Marcellus gas. With all of that considered our all-in after tax IRR estimate is now 64% at $5 NYMEX or 136% pre-tax at the well head again at $5 NYMEX.

Moving on to Midstream results. Operating income there was up 26% consistent with growth of gathered volumes and increased capacity based transmission charges. Gathering net revenue increased by a little over $10 million as gathering volumes increased by 31%, while the average gathering rate declined by 8%, and that decline was driven by the Marcellus mix and a 20% decrease in per unit operating cost.

One change we have made to better reflect the relative economics of the respective plays is that instead of charging a blended rate for gathering the Midstream group now charges EQT production $0.66 per Mcf for Marcellus gathering, and $1.25 per Mcf for gathering everywhere else. As Marcellus production continues to grow as a percentage of our total, the average gathering rate should continue to decline.

Transmission net revenues also increased by 22% to $26.4 million driven by the additional capacity turned online in the fourth quarter of 2010. Keep in mind that approximately 90% of transition net revenues are from capacity charges, so as we expand and execute contracts on our system, net revenues will continue to grow accordingly.

Storage, marketing, and other net operating income was down about $10 million in the first quarter. These results included a $2.5 million reduction in processing fees as we only own the Langley processing complex for one month of the first quarter of 2011, versus owning it for the full quarter of the first quarter of 2010. The storage and marketing part of the Midstream business relies on natural gas price volatility and seasonal spreads in the forward curve and those have trended down for the last couple of years.

Also, third-party marketing volumes and rates for reselling unused pipeline capacity continue to be under pressure. Given current market conditions, we estimate that full year 2011 net revenues in storage, marketing, and other, will be approximately $25 million lower than last year related to storage and marketing activities, and about $15 million lower from processing fee revenues collected in 2010 for our Langley processing services that now will be paid to MarkWest.

Having said that, we expect to grow – we expect the growth in gathered and transported volumes to more than offset this reduction in net revenue in the Midstream business. Net operating expenses at Midstream were about $1.3 million higher quarter over quarter, excluding the impact of the previously mentioned tax adjustments. Per unit gathering and compression expense excluding the property tax adjustment was down 20% to $0.30 per Mcf as a result of higher throughput while maintaining our cost structure.

Just a quick note on distribution, our operating income was up 6%, excluding the tax adjustments, mainly from lower bad debt and (inaudible) lower 2.5% than last year.

2011 guidance – today, you saw we increased our production sales forecast for the full year 2011 to 180 Bcf. Our forecasts are intended to represent a realistic projection, factoring in some negative impacts from inevitable unplanned delays or disruptions, such as delays in midstream projects, permit delays, weather impacts like freeze-offs, etcetera, and our cautious approach to pad drilling.

Our current practice is to not turn wells in line, where there is drilling or fracing of other wells on that same pad. If we do not experience any unplanned disruptions, we will realize higher sales volumes than our published forecast.

As a result of the higher volume forecast, we are also increasing our operating cash flow estimate for 2011 to between 800 and $850 million. As you know, we raised approximately $225 million in after-tax proceeds from the sale of the Langley complex in the first quarter.

As a result of that sale as well as our growing operating cash flow, we closed the quarter with approximately $139 million in cash on hand, no short-term debt and virtually full availability under our $1.5-billion credit facility. So we remain in a great liquidity position for 2011.

And with that, I’ll turn the call over to Dave Porges.

David Porges

Thank you, Phil. We are off to a good start this year, but we still have a lot of work ahead of us in order to realize our potential from a shareholder value perspective. And we are determined to do so.

Phil spoke about some of the operational results from the first quarter. And we are happy to answer additional questions you may have about our operations during Q&A, but we believe that this quarter’s results make it clear that we know how to execute. So I’d like to direct my comments to some more strategic issues for ourselves and the industry.

During the past year or so, we have talked quite a bit about addressing our greatest strategic challenge – applying capital to our best investment opportunities. Last year, I committed to you that we would live within cash flow plus proceeds from asset sales.

Our longer-term goal is to achieve organic volume metric and cash flow growth north of 30% per annum in production and associated cash flow growth in the midstream, while living within operating cash flow – that is, without proceeds from asset sales.

We estimate that we can achieve this goal by 2014, provided we outspend cash flow by about 300 to $400 million per year for the three years between now and then. In total, this means a little more than the $1 billion in external capital from 2011 through 2013.

Now, I wanted to discuss why we are very confident we can meet this target without tapping the equity market. First, of course, we funded the forecasted excess spending in 2011 by selling our Kentucky processing complex. Most of the remainder of our funding need could be achieved by the sale of our Big Sandy pipeline plus utilizing the additional debt capacity that our rapid growth in earnings and cash flow are creating.

Without getting into too many specifics about particular assets, I do wish to share what we think we have learned from our examination into the market value of all of our assets and investment opportunities and then comment on debt capacity.

The sale of the Kentucky processing complex and other of our efforts along these lines have sharpened our view that at least some of our midstream assets, especially, are more valuable to others than they are to us – at least, when the value to us is measured by inferring what the equity market is giving us credit for in our stock price.

It seems this value gap is most pronounced for long-lived assets, when most of the investment in the asset has already been made with contracts in place to increase the stability of the cash flows, yet there remains attractive incremental investment opportunities that create visible cash flow growth prospects. It is our observation that this combination of long-lived, stable cash flows and visible growth prospects is of a greater value to others than the roughly eight times current year EBITDA valuation that appears to be assumed in our stock price. Hence, the shorthand that we have previously used, assets that are worth more to others than to us.

While this value disconnect existed for the Kentucky facility and seems likely to exist for Big Sandy, we believe that we own several other assets, our CBM assets, various gathering assets, mature slow declining PDPs, et cetera, that quite possibly fit this description. In contrast, some of our most attractive organic investment opportunities, such as both Upstream and Midstream Marcellus are ones about which our knowledge of our own asset base and confidence in our ability to execute against these opportunities translates into a value proposition that is at least as compelling us to as it seems to be to others.

Now, back to debt capacity for a moment. Operationally, we have been exceeding our growth expectations. This is increasing our projections for internally generated cash flow. This in turn leads to additional debt capacity. The asset sales, when the funds are redeployed into our higher earning opportunities, create incremental cash flow and debt capacity even above the current projections. Incidentally, by additional debt capacity I mean the ability to wear debt without comprising our credit rating. So given our extensive list of potential asset sales, combining proceeds from asset sales with our more optimistic cash flow generation potential is, we believe, more than enough to fund this billion dollars or so for the accelerated development of our reserves.

The other topic I wanted to touch on for a moment is the need to develop these opportunities in a safe and environmentally sound manner. There has certainly been a lot of chatter about the pros and cons of shale gas development over the past few months. Much of this is probably due to the relative newness of this activity in the northeastern portion of the U.S. Our assessment of the situation is that the industry, as a whole, has been taking these issues seriously, especially recently, and that while the speed of the ramp-up has caused some issue for some of our peers, the industry is generally very committed to improving and sharing best practices, and working cooperatively with regulators to make sure that we achieve the promise of this great economic development opportunity.

You know that EQT was among the first companies to recycle most of its produced water, and also one of the first to post frac fluid composition on our website. We were also one of numerous companies that have participated in a project to post frac fluid composition on a well-by-well basis on a common website called FracFocus.org, a project coordinated by the Ground Water Protection Council. We continue to look for ways both internally and based on what we see other companies doing to improve our practices and our disclosure. Separately, we also realize that the long-term best interests of our communities is probably best served by heading towards fewer pads with more wells per pad, so that we cut down on the overall percentage of land that is affected by our drilling operations, and the associated roads, pipes, compressor stations, et cetera.

Our industry has a tiny physical footprint as a personal of acreage drained once wells are in operation, but the tinier the better from the perspective of our communities. This multi-well pad approach will probably mean that we will typically have a relatively sizable inventory of wells that have been spud, TDed, or even completed but are not yet flowing. But we think that this is the best long term approach to minimize our surface impact.

A variety of companies have short term issues in moving towards this approach because of lease related commitments, and sometime this local pooling rules are less than helpful, but we believe that there is a growing consensus that this smaller footprint approach is part of the long-term answer.

It is certainly possible that there will be some short-term economic costs from an environmentally sensitive approach. Better and more meters, more between CapEx and flowing production etcetera, but these are typically modest costs. Often they actual result in a better cost structure, as in the case of pad drilling, and will, in any event, lead to the best long term answer for all of us.

Finally, it is our observation that Pennsylvania is probably moving towards some sort of impact fee that will compensate local communities for direct and some indirect cost associated with the burgeoning natural gas business in this state.

Provided if such a fee is set at a reasonable level, it is dedicated to addressing actual impacts, and perhaps, as we would prefer, funding some economic development initiatives to encourage local use of more natural gas, and provided it is also accompanied by other regulations that clarify some of the rules governing the industry.

We believe that the consensus in the industry is to support such a compressive approach as being in the long term best interest of natural gas companies. Therefore, as is the case for many of our peers, EQT will continue to present all of its economics as if such is a fee structure exists, even though the actual results, as you descend from this quarter’s numbers, will obviously reflect the current reality.

In summary, EQT remains committed to increasing the value of our vast resource by accelerating the monetization of our reserves, but doing so in a safe and environmentally responsible manner. We continue to be focused on doing what it takes to get the most economic value out of our assets and investment opportunities even when that means selling them. We look forward to continuing to execute on our commitment to our shareholders, and appreciate your continued support.

And with that, I’ll turn it back over to Pat.

Patrick Kane

Thank you, Dave. This concludes the comments portion of the call. Andrew, we’re ready for you open the lines for questions.

Question-and-Answer Session

Operator

(Operator instructions) The first question comes from Neal Dingmann of SunTrust. Please go ahead.

Neal Dingmann – Sun Trust

Good morning, guys. Good quarter. Say, could you give us a little more color on – you mentioned that you may not have seen enough results on those newer wells yet decide if you’re going to go with that design on all the wells, maybe give us an idea of is it the length, is it the way you’re fracking those maybe a little bit more color on why the wells are doing well.

David Porges

We’ll let Steve handle that.

Steven Schlotterbeck

Neal, regarding the specifics of the technique we’re still not ready to talk about the specifics, a couple of things I’ll say though, typically 5300 foot length of well with the new design is quite a bit more expensive, probably about a million dollars more expensive.

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So while we are clearly seeing higher production rates initially, it’s very important that we get a little longer production history so we can accurately calculate the return we are getting for that extra million dollars.

I can say we have about five wells so far that have more than 100 days of production with the new technique and they’re averaging a little more than 60% higher production over that time period than their offsets would be standard technique. So results are very encouraging, but it’s going to be closer to the end of the year before we talk in more detail about it.

Neal Dingmann – Sun Trust

Okay. And a follow-up maybe on that a little bit. Are you convinced I know one of your peers has talked about maybe going to a shorter lateral, they think maybe you’re just trying to cut cost but you seem to imply that you think the lateral – the longer laterals are more well – you know, well worth that, maybe give us an idea of just your thought as far as the length versus the cost of these wells and what you’re seeing from these wells incrementally?

David Porges

Sure. I think we are absolutely convinced that longer laterals are better, at least up to 9,000 feet, which is as far as we’ve drilled to-date. We do plan a few laterals this year, even longer than that, but at least up to 9,000 feet, we are absolutely convinced, based on what we’ve done, that longer is better from an economic standpoint. We think what you may be hearing from others when they’re looking at their all-in economics, is they’re factor in these lease obligations, so the drilling obligations related to leases.

But if you factor in an assumption that you would lose leases because of failing to meet the drilling obligations, and then you might say that you would assume that you would have to pay market rate to get those leases back and you factored those into the economics. It is probably true that shorter laterals make more sense because what you want to do in that circumstance is touch as many of those leases as possible.

Remembering that these initial lease terms, that the norm has been a five-year lease term, and some folks did, especially ones who moved to the Marcellus earlier than us, would be nearing the end of some of those initial terms. So from an all-in economics perspective for those companies, it probably does in fact make the most sense, until they’re – you know, until they’ve got the volumes flowing and they’ve honored the obligations, and then they’ll move into whatever seems to be most economic at that point. And it may also be the different parts of the state have different – there are slightly different geologies in different parts of the state.

Neal Dingmann – Sun Trust

Sure. With your positive cash position, are you out there adding any leases, are you out there top leasing to your area, some bolt-ons, etcetera?

David Porges

We have had a relatively modest leasing effort in the recent past. I’ll probably leave it at that. Frankly, we’ve been waiting for economic circumstances to have caused the lease bonuses to have dropped, though I have to acknowledge that doesn’t really seem to have happened very much.

Neal Dingmann – Sun Trust

Got it. And last question, if I could. Just as production ramps up, will you continue to add the hedges on the out years, or what are your thoughts with the hedging?

David Porges

Yes, we will.

Neal Dingmann – Sun Trust

Okay. Thank you very much.

Operator

The next question comes from Scott Hanold of RBC Capital Markets. Please go ahead.

Scott Hanold – RBC Capital Markets

Thanks, good morning, guys. I think you all mentioned that it looks like Marcellus well costs have moved up to around $6 million, and I think your prior estimated current data model is around 5.3 million. When you look at your 2011 CapEx, is there going to be – are you going to be spending more than you had planned previously, or is there sort of a mix shift activity that will offset some of that?

David Porges

All of the – all of the numbers we’ve given you on volume guidance, Scott, are consistent with staying at that CapEx level. Now, look, we’ve talked about asset sales before, because part – realistically part of the grand plan is to monetize some other assets and ramp up, and eventually, as a result, ramp up the development pace and in that circumstance, absolutely you would see over some period of time capital going up, but we’re very conscious of the concern, frankly, that a number of investors have that we are not spending money before we have it.

Scott Hanold – RBC Capital Markets

Okay. So just so I understand, you’re not – even though your well customer higher, you’ve not made a change to your 2011...

David Porges

Oh, it’s the total number of wells actually has declined a bit as a result, but there is also longer laterals.

Scott Hanold – RBC Capital Markets

Okay. And that when you amount of wells that declined you specifically talk about Marcellus wells?

David Porges

Yes.

Scott Hanold – RBC Capital Markets

Okay. And then...

Philip Conti

One of the reasons we’ve tended to focus more on feet of pay and frac stages and things like that, as opposed to the well count itself.

Scott Hanold – RBC Capital Markets

Okay. No, that makes sense. And then as you look, and it sounds like you’re doing a little bit more stepping out in some of your Marcellus areas and you’re seeing – it seems to be pretty good results, and you recently said you are drilling a well in Tyoga, how much just in general terms of your activity is going to be in the areas of like Tyoga where it’s a little bit of a stretch from where you’ve operated previously.

Philip Conti

I’ll let – I think Steve is the best one of us to answer that one.

Steven Schlotterbeck

I think probably 15% of our wells this year would probably fit that category, although while Tyoga is probably the – obviously the furthest we’ve gone afield from most of our activity has been – it’s getting close to where lots of our competitors have drilled a lot of wells, so we have a high level of confidence in Tyoga, and now that we’re drilling up there, I think we have a pretty good spread across our acreage position with test wells of some sort. So our knowledge and confidence level in our acreage just continues to improve.

Scott Hanold – RBC Capital Markets

Okay. Okay. Thanks. And one last question. You mentioned opportunity to monetize a lot of different assets, and you made a comment relative to below the pine PDPs are you considering something like a VPP, or would you not try something like its lack of better term, that exotic?

Steven Schlotterbeck

I don’t know that we would go with a VTP proper, but I love – Phil and his group have been looking at what’s out there and I’m happy to let him share any observations he’s got about what we’ve seen in the marketplace.

David Porges

We’ve seen there are various factors out there with overriding royalty interests and VTP there is another structure that’s out there. I think my simple answer is we’re looking at all of that and comparing the cost of capital to some of our other alternatives to see which of those structures make the most sense for EQT.

Scott Hanold – RBC Capital Markets

Okay. And when do you think we could get some, significant news flow on some things you’re actually going to going forward into doing?

David Porges

Honestly I would expect that every couple of quarters you’ll be hearing something.

Scott Hanold – RBC Capital Markets

Great. Thanks guys.

David Porges

And I recognize when I say that that the first quarter you already heard something, which we announced and also closed on the Langly thing, and we would certainly expect that you’ll be hearing more very specific stuff in 2011, and then you’ll hear specific stuff in 2012. I mean that’s absolutely the goal.

Scott Hanold – RBC Capital Markets

All right. I appreciate it, thanks.

Operator

The question comes from Michael Hall with Wells Fargo. Please go ahead.

Michael Hall –Wells Fargo

Thanks. Congrats on solid results. Just curious, as I look at your current production guidance, what sort of 2011 Marcellus exit rate is embedded within that?

Philip Conti

I believe we actually provided some of that. So Pat, why don’t you –

Steven Schlotterbeck

We’re 280 million projected at year-end, Michael.

Michael Hall –Wells Fargo

Okay, thanks. And then, as you look at the cost structure, solid cost structure improvement quarter-on-quarter at the production level. How sustainable, particularly like on the LOE front, is that? Is there anything in that that would be more one-time in nature, or should we think about that as a fair run rate?

Steven Schlotterbeck

I think it is a fair run rate. The efficiencies that we gain in the Marcellus from the high production rates, the multiple wells per pad, as we do more and more Marcellus, that should only support those low LOE unit costs that we see. Now, obviously, the one exception is on production taxes. And I think Phil spoke to that. But you’d probably have to look at 2010 or 2009 as a better normalized rate, if you assume that there is some form of compact fee that eventually comes to Pennsylvania. And Randy is the best one to talk about it, if you want to hit cost structure on the Midstream side.

Michael Hall –Wells Fargo

Sure.

Steven Schlotterbeck

Yeah. Well, Michael, with respect to that, again, when you work with the more pads per well and the longer lateral, the efficiency gains associated with the Midstream are also significant, and you can see that in the results. And essentially, less miles of pipe or more volume per mile of pipe capacity is what we achieve in Marcellus. I mean it’s actually with the longer laterals and more pads. And also, a factor in the environmental footprint that Dave had mentioned earlier. So those efficiency gains do translate in the Midstream cost reductions, as well.

Michael Hall –Wells Fargo

Okay, great. And then as it relates to the future monetizations or potential monetizations, how does the storage and marketing business fit into that thinking? You’ve seen some pretty juicy multiples on storage assets recently. Is it fair to say that that’s also being considered?

Steven Schlotterbeck

You know, Randy, I’ll let you answer that one, too.

Philip Conti

Well, I think there’s still – we look at everything in terms of the value proposition and what’s best to create shareholder value. Obviously storage, going forward, the spreads have been narrowing, but our judgment is that that’s a – it’s a key part of the growth in Marcellus and in this basin, creating demand and a need for storage. So we certainly would look at that, but we see that as an integral asset, as well, as we continue to grow our volumes going forward.

Steven Schlotterbeck

So if you know people who’ll call in on that one, what we’re telling folks who call on that, because I think we’ve now made it clear enough that we are open to just about anything that we actually do to get a fair number of inquiries. And it’s this changing dynamic in the Marcellus which gives us some pause on storage. We’re going to be moving away from long line pipes to bring gas into this region. It’s going to be more local production. And what’s going to be the role of storage is going to be a question.

And when I say that, I recognize that it is always possible, though, to contract for storage, even if one doesn’t own it. It’s just that that’s an asset where the value is a little bit – it’s a little bit less clear whether the changes in dynamics in the market are going to – what effect they’re going to have on the value of the assets, compared to what’s going on in some of the other areas of the midstream further south of the Marcellus.

Michael Hall –Wells Fargo

Okay. That’s helpful color. Appreciate it. Thanks, guys.

Steven Schlotterbeck

But everything we’ve got here, in case you are talking to friends and stuff, there’s a price for everything, so don’t be shy.

Operator

The next question comes from Becca Followill of US Capital Advisors. Please go ahead.

Becca Followill – US Capital Advisors

Hey, guys. Two quick ones. I think the Greene County well that you talked about last quarter was completed using the new frac geometry, and that had a 30 day flow rate of 23 million a day. Can you tell us what that well is doing now after – what is it, how many days?

Steven Schlotterbeck

I’ll be honest, Becca, I don’t have that data with me. I can’t tell you. Call Pat later maybe.

Becca Followill – US Capital Advisors

Okay. I’ll do that. And then just to clarify, you guys had talked before about a 20% growth rate longer term, living within your means, now upping CapEx by 3 to 400 million over the next few year and picking up by 30%. If we see some assets over the next three months, would you go ahead and start upping CapEx spending for 2011, given that you’re already above that 30% level?

Philip Conti

Yes, but the practical reality, given that most of the money for the Marcellus, at least, is spent on fracing, would be even if we were making a commitment, most of that would – or a big chunk of any increased commitment that we would have would, under the scenario you described, would probably still show up in 2012, and with the volume showing up in 2012 and then out years. So the short answer is yes, but I wanted to make sure you had a better feel. But with the pad drilling, we do have longer lags on when the money actually gets spent versus committed.

Becca Followill – US Capital Advisors

Yeah, I’ve got that, Phil. I just wanted to make sure that you guys would put that money to work pretty quickly. You wouldn’t say, I am going to save that for the next year, I am going to go ahead and start...

Philip Conti

And honestly, the reason for that – at one point I was thinking we would, that it would be a rainy day fund or something like that, and frankly now, based on more of the work that we’ve done in the asset market, our view would be, no, that would come from the next, you know, if we wanted that, that would be the next asset sale.

Becca Followill – US Capital Advisors

Great. Thank you.

Operator

Next question comes from Rhett Bruno of Bank of America/Merrill Lynch. Please go ahead.

Rhett Bruno – Bank of America/Merrill Lynch

Hey, guys.

Philip Conti

Hello. Good morning.

Rhett Bruno – Bank of America/Merrill Lynch

Can you give us an update in the waiting on completion backlog in Doddridge County and where you are now production-wise relative to the remaining capacity, and if there was any surprises from the wells that you would have brought on late in Q4 or Q1?

Philip Conti

Yes, great question. Some of them were asked. We have had an email match – we have had a fairly significant backlog in Doddridge Country primarily because we’ve been drilling some pretty large multi-well pads, and as Dave said previously, we take a fairly conservative approach to not having simultaneous operations on the pad. So we’ve had a backlog build up here recently, now we’ve begun to work that down. And just this week, we started turning in line a 7-well pad in Doddridge County, six of those wells are – have been in line for 24 hours or more, as I speak. I can tell you the average 24-hour rate from those six wells is 9.2 million cubic feet a day. These were relatively short lateral wells due to the nature of the lease, the average lateral length was 2,970 feet and we had average of just under 11 stages per well. So the total up all is IP, it’s a little over 55 million a day total. You want to talk to the capacity.

Steven Schlotterbeck

Sure. I mean in (inaudible) Steve with the excellent results, we’ve positioned ourselves to stay out in front, and we positioned to have 70 million a day out of the West Virginia, and we are – one of the positive aspects of that is at a higher BTU gas, and we have JT skids there to extract and to meet the pipeline quality. Going forward and the previously announced agreement with MarkWest on the processing facility, is in the next year is when we’ll be able to expand additional capacity over and above the 70 million a day.

Rhett Bruno – Bank of America/Merrill Lynch

Okay. Great, thanks.

Operator

The next question comes from Josh Silverstein of Enerecap Partners. Please go ahead. Enerecap Partners – excuse me.

Josh Silverstein – Enerecap Partners

Hey, good morning, guys. Just following up on the midstream and takeaway issues. Could you just kind of walk through the planning stages of how you guys are looking at developing the Marcellus capacity over the next few years with significant growth there, how you’re trying to kind of stay ahead of that, since it seems like most of the bigger producers are starting to bump against their current capacities, and are having to expand faster than they probably thought they would have to?

Philip Conti

First, Randy is going to answer that. But we have become one of the bigger producers. I think that the – missed some, but we have actually become one of the bigger producers on the Marcellus, but that said –

Steven Schlotterbeck

No, absolutely. And you’re right, we work, of course, Steve and I and the two teams that work hand in glove to ensure that the development plan and the midstream plans are working together, and they’ve done an excellent job, and we’ve been focused in, in a couple of primary areas, right our Greene County and our Doddridge area and we’ve been able to build out the additional capacity in those areas.

One of the benefits of the Marcellus, just so you are aware, is the higher pressure wells, and so we do take advantage of some of those higher pressures, so as we stage in the larger diameter pipe, the longer lead items such as compression that we can stage in as the wells are brought in line, and so that’s how we look at it, is that we put the Bates infrastructure in and then we bring in the compression as the wells come on.

With respect to our Equitrans asset, as we previously announced in line, we turned on line in excess of a hundred million a day of capacity this year, we have an additional 400 million a day that we are through the certificate process that will be coming on in 2012. And again we’ve at EQT in terms of the commercial we’ve always been proactive on the downstream capacity commitments on the interstate pipelines.

We have a large position on Columbian transmission to move our HERON gas. We’ve been – we have a contract as you’re aware of with the Tennessee gas pipeline for 350 million a day that moves our product even further downstream into a northeastern market. And also with segmentation provides the flexibility to move an additional 300 into the south market. So again, that’s how we look at it, we work closely together. We built out the infrastructure and we have – I think an excellent track record of being out in front and doing just that.

Josh Silverstein – Enerecap Partners

Got you. And then, you know, just looking at the frac inflation cost, or I guess the well inflation costs, I was curious if this new frac geometry is a way to reduce some of that inflation, or even lower some of well costs?

Philip Conti

No, in fact just the opposite. The revise design would raise our per well cost and per stage cost. However, what we’re waiting to see is if that incremental investment is justified by the higher production and reserve. So, we’re going to wait until later in the year before we start drawing conclusions on that, but – so the goal is per unit costs going down, but per well or per stage costs would certainly go up.

Josh Silverstein – Enerecap Partners

Gotcha. And then lastly for me, just want to see if there’s any update on drilling into the other formation for the Utica, Upper Devonian or other stacks?

Philip Conti

Well, we are certainly looking at those and watching what our competitors are doing in those areas. I think the Upper Devonian, we have drilled one well in the Upper Devonian several months ago in West Virginia. And we will drill at least one more this year in Southwestern Pennsylvania. Our plans for the Utica right now are to sit tight and watch what our competitors are doing, and if that ends up being the next big thing, we’ll be right there with them.

Josh Silverstein – Enerecap Partners

As you know, we pride ourselves on being innovate in a lot of areas, but we have thought that it is more prudent for us for the time being to focus on getting the most of our Marcellus position. And actually for that matter Huron as well. But we do pay close attention to what the other companies in the area are doing in the Upper Devonian and the Utica. And eventually we’ll hopefully figure out what works and we’ll jump right in.

Philip Conti

Good. Thanks, guys.

Operator

The next question comes from John Abbott of Pritchard Capital. Please go ahead.

Raymond Deacon – Pritchard Capital

Yeah, hey, this is Ray Deacon. I was wondering, Steve, if you were to correlate the 9.2 million a day IP rate, 24 hours to your experience in Green, what would that kind of correlate to like a 5 or 6, 7 BCF well or–?

Steven Schlotterbeck

Well, I think, I mean, I just do the simple math for you, if you double the lateral length from those, from our experience we would double the initial rate. So you’d be looking at a 5300-foot lateral well with 18 million a day IP, if you just double those averages. And I think – I’m not going to quoting the UR, but you can probably go back to numbers we’ve published before, and see what an 18 million a day IP would – might look like.

Raymond Deacon – Pritchard Capital

Got it. Great. And why did you have to drill the shorter laterals in West Virginia. I thought you had a pretty key blocky acreage position in...

Steven Schlotterbeck

Well, we do generally, but we have a lot of leases and a lot of acreage in certain areas, the short laterals just fit better than longer ones. And that was the case on this lease. So, we can drill economic wells with extremely short laterals, down well below 2,000 feet per well, and we’re still generating excellent returns. So when we have to drill short, we will. Obviously when we can drill longer, that is our strong preference.

Raymond Deacon – Pritchard Capital

Got it. And did the 9.2 million a day that would have had a pretty big liquids component, I think?

Steven Schlotterbeck

Well, its – the BTU content is about twelve fifty in that area.

Raymond Deacon – Pritchard Capital

Okay. Got it.

Steven Schlotterbeck

But you are aware that our processing – the processing plant that we’ve -where we’ve contracted for capacity, that MarkWest facility is not going to be ready until next year.

Raymond Deacon – Pritchard Capital

Got it.

Steven Schlotterbeck

Right now the only way to get any liquids out, actually get liquidities out, is to use these little J.T. skids. And what kind of extraction do you actually get when you’re using those?

Philip Conti

Per Mcf if you’re getting in the range of between 0. 5 and a gallon of 1 – 0.5 and 1 gallons.

Raymond Deacon – Pritchard Capital

So this is what you would expect from a plant...

Steven Schlotterbeck

A Cryo about 2.5 gallons, and so that’s – and then we – we’re essentially meeting the specs and we blend the gas and we’re able to move that way. So overly not getting much in the way of – we’re getting the benefits from liquids and that you’re getting more BTU per unit volume, but we’re not getting the pick-up in the premium – really much of a pick-up for a premium in per BTU value, those liquids, until that plant is...

Raymond Deacon – Pritchard Capital

When that plant does come on line, where do you think the 7% liquids contribution could go to, I guess?

Steven Schlotterbeck

Yeah, so I’m not sure that it goes – in that area, of course, it’d be higher than 7%, because that was an average number across all of our properties, but the issue, if you’re getting it, about the ethane, it’s more of a question of when do the ethane markets start delivering better value per BTU than methane.

And when we follow the reports of folks, who are coming up over other ways to move the ethane, it doesn’t strike us that they’re getting any better than ethane prices. So the real issue is making sure that you – you’re moving ethane, so that you can get the gas to pipeline quality, not really to get a pick-up in per BTU pricing. Does that – hope I said that in a way that my – that it’s clear.

Raymond Deacon – Pritchard Capital

Great. No, that makes sense.

Steven Schlotterbeck

I mean, obviously, it would be great if we had robust ethane markets here, and a bunch of us in the industry are looking for those types of longer term opportunities to see if we can get those, but right now we’re really just talking about folks making sure they can move the ethane, so that they can, so the gas can lock.

Raymond Deacon – Pritchard Capital

Got it. And I guess, Steve just one quick follow-up. I’ve had a couple of people tell me, the completion costs were up sort of like 10% sequentially in the Marcellus, and I was just wondering how shielded are you from furthering increases with the contracts you have in place?

Steven Schlotterbeck

Well, generally speaking, the contracts we have are for frac services are basically fixed plus variable, so a lot of the consumables we use are variable, and we have seen – I think on average about a 7% increase in those over the – sequentially from the prior quarter. Much of the rest is fixed, but they can still vary based on a few indices.

So as inflation picks up, we may – we are subject to some continued costs increase, but I think we’re pretty well mitigated from the supply/demand pressures that we’ve seen in the past. So when there’s no a lot of activity and operators are willing to pay whatever it takes to get a frac crew, and prices shoot up, we’re insulated from that, at least through the end of the year.

Raymond Deacon – Pritchard Capital

Got it. Okay. Thank you.

Operator

The next question is a follow-up from Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Hanold – RBC Capital Markets

Yeah, thanks, guys. Hey, real quickly, could you remind me what – I guess in the last quarter, what was the EBITDA from the Big Sandy system was?

Philip Conti

Can’t remember exactly what we said, but it’s in the $25 million range.

Unidentified Company Representative

(Inaudible).

Philip Conti

25 to 28 I think.

David Porges

Yeah.

Steven Schlotterbeck

I was...

David Porges

Annually.

Philip Conti

Yeah.

Scott Hanold – RBC Capital Markets

Annual. So in theory, we’re talking about something like 10 or so multiple on that, so you’re probably looking at something close to nearing $300 million, monetize that? Does that sound reason?

Philip Conti

Or so. Well, I wouldn’t call us with an offer for 300.

Scott Hanold – RBC Capital Markets

Understood. Appreciate it. Thanks.

Operator

The next question is a follow up from Michael Hall with Wells Fargo. Please go ahead.

Michael Hall –Wells Fargo

Thanks for the follow-up. Just quickly, curious on the kind of longer range growth, you talked about trying to get to 30%-plus annual growth, and in the next couple of years, like you said, that requires some outspend. Does that suggest, then, that’s the kind of level of growth you would expect in the next couple of years, or is that – may be gear up to get to that level? Obviously, this year you’re going to be above 30%, but just kind of get a feel for 2012.

Steven Schlotterbeck

I’m sorry, could you – I’m not sure if I followed all – your...

Michael Hall –Wells Fargo

So you said, you’re trying to get a long-range CAGR of 38% per year or better.

Steven Schlotterbeck

Yes.

Michael Hall –Wells Fargo

In terms of production growth, and that’s going to require some outspending. I’m just trying to understand, does the initial couple of year period, the 2012 to 2013 period, is that lower than 30%?

Steven Schlotterbeck

No, no, no. no, I’m sorry. No, I wouldn’t. We wouldn’t see that being lowered. As a matter of fact, the way we kind of seen that two is that we’d be talking about a more of a several year CAGR, even though we’re only talking about outspending for three years, so it kind of gets the machine going. And in fact, by the end of that period is when you probably start dropping down a little bit. When you’re – obviously, it is difficult to grow any business at 30% – any capital instance of business at 30% while living within cash flow indefinitely, so we actually rely on the jump start kind of front end load a little bit of that.

Michael Hall –Wells Fargo

Okay. I didn’t know if you needed some sort of jump start and spend to get the growth later, but...

Steven Schlotterbeck

I actually think about this a lot. That is happening now. And we’re already benefiting from some of that lag, because we have put money in – obviously, we have outspent our cash flow for the last couple of years.

Michael Hall –Wells Fargo

Right, right.

Steven Schlotterbeck

So we’re actually getting – we actually are benefiting from the fact that that occurred over the last year or two currently. And that would – we would anticipate that continuing, but it does mean that that’s – that’s why we do feel some urgency to make sure we keep that going.

Michael Hall –Wells Fargo

Okay. That’s super helpful. Thanks.

Operator

The next question comes from Rhett Bruno of Bank of America, Merrill Lynch. Please go ahead.

Rhett Bruno – Bank of America/Merrill Lynch

Hey, guys. Just one quick follow-up on this resized sort of capital outlook you guys are talking about. Is the midstream spend, does that change? Could you give us some idea on the run rate maybe the next two or three years?

Steven Schlotterbeck

No, I think the – probably the ratio that we spend on midstream to total remains pretty similar to what it is in 2011. Obviously, that’s a lot lower than what it had been.

Rhett Bruno – Bank of America/Merrill Lynch

Okay. All right. Great. Thanks.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to Patrick Kane for any closing remarks.

Patrick Kane

Thank you, Andrew. That does conclude today’s call. The call will be replayed for a seven-day period beginning approximately 1:30 PM Eastern Time today. The phone number for the replay is 412-317-0088. The confirmation code for the replay is 447030, and it’s also available on our website for seven days. Thank you, everyone, for participating.

Operator

This concludes the EQT Corporation first quarter 2011 earnings conference call. Thank you for attending today’s presentation. You may now disconnect.

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