EQT Corp (EQT) 2011 Q1 法說會逐字稿

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 Investor Relations Officer.

Please go ahead.

Thank you, 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 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 would 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 on the Company's Form 10-K for the year ended December 31, 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 would now like to turn the call over to Phil 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 26% increase over EPS in the first quarter of 2010.

3 items cumulatively added $40 million to our pre-tax income, or about $0.17 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 sale of some available for sale securities.

Adjusting for those 3 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.

The increase in cash flow comes as a result of another outstanding operational quarter across all 3 of EQT's business units, including record produced natural gas sales, and continued low per-unit development and operating costs at production, which were already among the best in the industry; another record in gathering and 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 walk through 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 organic, and 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 Mcf we received last year.

Produced liquids, mainly from our liquids-rich Huron and West Virginia Marcellus plays, account for 7% of the volumes, and 20% of the unhedged 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 headstream.

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.

We reported $0.19 per Mcf equivalent, versus $0.28 last year.

Since that large of a decrease may 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 a cross-structure that again is among the best in the industry.

There is some month-to-month variability in our LOE activities, but we do expect to average about $0.20 per Mcfe for the year.

A couple 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.

8 of the 13 wells are producing, 4 wells are shut and waiting on pipeline construction, and 1 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 2 wells in Jefferson County during the quarter.

Both wells had 24-hour flow rates of about 10 million per day.

These results will be used to midsize the Midstream build in that new area.

This month, we spud our first well in Tioga County, where we intend to spud 10 wells this year, and we'll have more info 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 are awaiting pipeline hook-ups; 39 are drilled and awaiting a frac job; 16 are either currently drilling or have been top holed; and 1 well was not successfully completed and will be plugged.

We also track our progress internally by frac stages online or in the system for our Marcellus wells.

And on that metric, as of the end of the quarter, 1,032 frac stages are on-line; 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 to EQT, and we expect to see more oil-fueled inflation next year.

We now estimate that a typical 5,300 foot well will cost about $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 wellhead, again at $5 NYMEX.

Moving on to Midstream results -- operating income there was up 26%, consistent with the growth of gathered volumes and increased capacity-based transmission charges.

Gathering net revenues 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 transmission 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 owned 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 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 the growth in gathered and transported volumes to more than offset this reduction in net revenues 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.

And just a quick note on distribution.

Operating income was up 6%, excluding the tax adjustments, mainly from lower bad debt and weather that was a little over 2.5% colder 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 our realistic projections, factoring in some negative impacts from inevitable unplanned delays or disruptions; such as delays in Midstream projects, permit delays, weather impacts, like freeze-offs, et cetera, and our cautious approach to pad drilling.

Our current practice is to not turn wells in line while there is drilling or fracking of other wells on that same path.

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 million 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.

Thank you, Phil.

We are off 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.

We are determined to do so.

Phil spoke about some of the operational results from the first quarter.

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 would 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 volumetric 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 million to $400 million per year for the three years between now and then.

In total, this means a little more than $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 several 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, has 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 remain 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 greater value to others than the roughly 8 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 to us 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 additional debt without compromising our credit rating.

So, given our extensive list of potential asset sales, combining proceeds from asset sales with our more optimistic projection of cash flow generation potential, is, we believe, more than enough to fund this $1 billion 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 US.

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 are 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 disclosures.

Separately, we also realize that the long-term best interest 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 percentage 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, TD'd, 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 sometimes the 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 of a lie between CapEx and flowing production, et cetera; but these are typically modest costs.

Often, they actually 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 costs associated with the burgeoning natural gas business in this state.

Provided that such a fee is set at a reasonable level, 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 legislation of regulations that clarify some of the rules governing the industry, we believe that the consensus in the industry is to support such a comprehensive approach as being in the long-term best interests 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 a fee structure exists, even though the actual results, as you can discern 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 shareholders, and appreciate your continued support.

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

Thank you, Dave.

This concludes the comments portion of the call.

Andrew, we're ready for you to open the lines for questions.

We will now begin the question and answer session.

(Operator Instructions)

The first question comes from Neal Dingmann of SunTrust.

Good morning, guys.

Good quarter.

Say, could you give us a little more color on -- you mentioned that you maybe haven't seen enough results on those newer wells yet to 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 those wells -- if the well are doing just so well?

We're going to let Steve Schlotterbeck handle that one.

Neal, I think regarding the specifics of the technique, we're still not ready to talk about the specifics.

A couple things I'll say, though.

Typically, a 5,300 foot length well with the new design is quite a bit more expensive, probably about $1 million more expensive.

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 returns we're getting from that extra $1 million.

I can say we have about 5 wells so far that have more than 100 days of production with the new technique, and they are averaging a little more than 60% higher production over that time period than their offsets with the 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.

Okay.

And to follow-up maybe on that a little bit.

Are you convinced -- I know one of your peers has talked about maybe going to the shorter lateral; they think maybe just trying to cut costs, but you seem to imply that you think the longer laterals are more 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?

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 factoring in these lease obligations that they have, the drilling obligations related to leases.

If you factor in an assumption that you would lose leases because of failing to meet the drilling obligations, and then you might say you 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 5-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'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 that different parts of the state have different -- there are slightly different geologies in different parts of the state.

Sure.

Sure.

With your positive cash position, are you out there adding to leases?

Are you out there top-leasing in and around your area, some bolt-ons, et cetera?

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 lease bonuses to have dropped, though I have to acknowledge that doesn't really seem to have happened very much.

Got it.

And last question, if I could.

Just as production ramps up, will you continue to add to hedges on the out years, or what's your thoughts with the hedging?

Yes, we will.

Okay.

Thank you very much.

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

Please go ahead.

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 estimate, and correct me if I'm wrong, was around $5.3 million.

When you look at your 2011 CapEx, are you going to be spending more than you had planned previously, or is there sort of a mix shift in activity that will offset some of that?

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, 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.

Okay.

So just so I understand, even though your well costs at Marcellus are higher, you've not made a change to your 2011--

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

Okay, okay, in that when you say total amount of wells have declined, you are specifically talking about Marcellus wells?

Yes.

Okay.

Okay.

And --

And that's incidentally, 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.

Okay.

No, that makes sense.

And then, as you look, and it sounds like you're doing little bit more stepping out in some of your Marcellus areas, and you're seeing -- it seems to be pretty good results; and I guess you recently said you're drilling a well in Tioga.

How much, just in general terms, of your activity is going to be in areas like Tioga, where it's a little bit of a stretch from where you've operated previously?

I think Steve is the best one of us to answer that one.

I think probably 15% of our wells this year would probably fit that category; although, while Tioga is obviously the furthest we've gone afield from where 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 Tioga, 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.

Okay.

Thanks.

And one last question.

You mentioned opportunity to monetize a lot of different assets, and you made a comment relative to below-defined PDPs.

Are you considering something like a VPP, or would you not try something, for lack of a better term, that exotic?

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

What we've seen -- there are various structures out there with overriding royalty interests.

VPPs 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.

Okay, and when do you think we could get some significant news flow [and ax] on things you're actually going to be going forward and doing?

Is that--?

Honestly, I would expect that every couple of quarters you will be hearing something.

Great, thanks guys.

And I recognize when I say that, that the first quarter you already heard something; which was, we announced, and also closed, on the Langley 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.

All right, I appreciate it.

Thanks.

The next question comes from Michael Hall with Wells Fargo.

Please go ahead.

Thanks.

Congrats on solid results.

Thank you.

Just curious -- as you look at your current production guidance, what sort of 2011 Marcellus exit rate is imbedded within that?

I believe we actually provided some of that, so Pat, why don't you --

We're $280 million projected at year end, Michael.

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 of that as a fair run rate?

That's a fair run rate or--?

I think that 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.

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's some form of impact fee that eventually comes to Pennsylvania.

And Randy is the best one to talk about it if you wanted to hit cost structure on the Midstream side.

Sure.

Yes, well, Michael, with respect to that -- again, when you work with more pads per well, and the longer laterals, the efficiency gains associated with the Midstream are also significant, and you 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.

And it is associated with the longer laterals and more paths; and also a factor in the environmental footprint that Dave had mentioned earlier.

So those efficiency gains do translate into Midstream cost reductions as well.

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 is also being considered?

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

Well, I think that Phil and Dave meant -- well, 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 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.

So, if you know people who 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 get a fair number of inquiries.

And it's this changing dynamic in the Marcellus which gives us some pause on storage.

You know, 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 of 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.

Okay.

That's helpful color.

I appreciate it.

Thanks, guys.

But everything we've got here, in case you're talking to friends and stuff, there's a price for everything.

So--

I'll -- I'll

Don't be shy.

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

Please go ahead.

Hello, 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 it had a 30-day flow rate of 23 million a day.

Can you tell us at what that well is doing now after -- what is it?

How many days?

I'll be honest, Becca, I don't have that data with me.

I can't tell you.

Call Pat later, maybe.

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 $300 million to $400 million over the next few years -- you can grow by 30%.

If we see some asset sales 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?

Yes, but the practical reality, given that most of the money for the Marcellus, at least, is spent on fracking, 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.

No--

But with the pad drilling, we do have longer lags on when the money actually gets spent versus committed.

Yes, I've got that feel, I just wanted to make sure that you guys would put that money to work pretty quickly.

Yes.

You wouldn't say--

Yes--

I'm going to save that for the next year.

I'm going to go ahead and start--

No and honestly, the reason for -- 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 -- if we wanted that, that would be the next asset sale.

Great.

Thank you.

Next question comes from Rhett Bruno of Bank of America Merrill Lynch.

Please go ahead.

Hello, guys.

Hello.

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 then if there was any surprises from the wells you would have brought on late in Q4 or Q1?

Yes, great question.

I was hoping someone would ask.

E-mail him--

We have had a fairly significant backlog in Doddridge County, 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.

6 of those wells have been in line for 24 hours or more, as I speak.

I can tell you the average 24-hour rate from those 6 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 2,770 feet, and we had an average of just under 11 stages per well.

So, if you total up all those IPs, it's a little over 55 million a day.

You want to talk to the capacity?

Sure.

In Doddridge, and Steve, with the excellent results, we have positioned ourselves to stay out in front, and we've positioned to have 70 million a day out of the West Virginia.

And one of the positive aspects of that is that 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.

Okay.

Great, thanks.

The next question comes from Josh Silverstein of EnereCap Partners.

Please go ahead.

Hello, good morning, guys.

Yes, just following up on the Midstream, and gathering 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 stay ahead of that, because 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?

Well, first, Randy is going to answer that.

But we have become one of the bigger producers.

I think that's been missed some, but we have actually become one of the bigger producers on the Marcellus.

But that said -- Randy?

No, no, absolutely.

And you're right, we've worked, of course, Steve and I and the two teams worked 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 a couple of primary areas, right?

Our Green County and our Doddridge area -- and we've been able to build up 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 base infrastructure in, and then we bring in the compression as the wells come on.

With respect to our Equitrans asset, as we previously announced, we turned in line in excess of 100 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, 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 Columbia Transmission to move our Heron gas.

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 northeast market; and also with segmentation, provides us the flexibility to move an additional 300 million into the south market.

So again, that's how we look at it.

We work closely together, we build up the infrastructure, and we have, I think, an excellent track record of being out in front and doing just that.

Got you.

And then, just looking at the frac inflation costs, 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 the well costs?

No, in fact just the opposite.

The revised 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 till later in the year before we start drawing conclusions on that.

The goal is per-unit cost going down, but per-well or per-stage cost would certainly go up.

Got you.

And then, lastly for me, just wanted to see if there was any update on drilling into the other formations, whether it be the Utica, Upper Devonian, or other stacks -- stack pay?

We are certainly looking at those, and we're watching what our competitors are doing in those areas.

I think on the Upper Devonian, we have drilled 1 well in the Upper Devonian several month 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.

As you know, we pride ourselves on being innovative in a lot of areas, but we have thought that it's more prudent for us for the time being to focus on getting the most out of our Marcellus position -- 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, hopefully by following them, we'll figure out what works, and we'll jump right in.

Great.

Thanks, guys.

The next question comes from John Abbott of Pritchard Capital.

Please go ahead.

Yes, hello, 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 correlate to -- like a 5 or 6, 7 Bcf well, or --?

Well, I'll 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 would be looking at a 5-point or 5,300 foot lateral well, with 18 million a day IP.

If you just double those averages, and I think -- I'm not going to quote an EUR, but you can probably go back to the numbers we've published before, and see what an 18 million a day IP might look like.

Got it.

Great.

And why did you have to drill the shorter laterals in West Virginia?

I thought you had a pretty blocky acreage position in Doddridge.

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.

Got it, got it.

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

Well, the BTU content is about 1250 in that area.

Got it.

But you're aware that the processing plant that we've -- whereby we have contracted for capacity, that MarkWest facility, is not going to be ready until next year.

Got it.

Right now the only way to get any liquids out -- actually get liquids out -- is to use these little JT skids; and, Randy, what kind of extraction do you actually get when you're using those?

Per Mcf, you're getting in the range of between 0.5 and a gallon -- 0.5 and 1 gallon .

Versus what you would expect maybe from a plant.

A cryo, maybe about two and a half gallons, and then we're essentially meeting the specs, and we blend the gas, and we're able to move that way, but--

So we're really not getting much in the way of -- we're getting the benefit from liquids in that you're getting more BTU per unit volume, but we're not getting much of a pick-up of a premium per BTU value for those liquids, until that plant is in.

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

Or you're at 7% now--?

Yes, I'm not sure that it goes -- you know, in that area, of course, it would be higher than 7%, because that was an average number across all of our properties.

But the issue, if you're getting at what about the ethane, it's really 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 with other ways to move the ethane, it doesn't strike us that they're getting any better than methane pricing.

So the real issue is making sure that you're removing ethane so that you can get the gas to pipeline quality, not really to get a pick-up in per-BTU pricing.

Does that -- I hope I said that in a way that it's clear.

Right.

No, that makes sense.

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 the gas can flow.

Got it.

And I guess, Steve, just one quick follow-up.

I've had a couple of people tell me completion costs were up, sort of 10% sequentially in the Marcellus, and I was just wondering how shielded are you from further increases with the contracts you have in place?

Well, generally speaking, the contracts we have 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 sequentially from the prior quarter.

Much of the rest is fixed, but can still vary based on a few indices.

So, as inflation picks up, we are subject to some continued cost 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 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.

Got it.

Thank you.

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

Please go ahead.

Yes, thanks, guys.

Hey, real quickly, could you remind me what in the last quarter, what was the EBITDA from the Big Sandy system was?

I can't remember exactly what we said, but in the $25 million range.

Yes, it might have been

$25 million to $28 million annually.

Yes -- I was thinking -- $28 million -- annually.

Annual.

So, I mean, in theory, we're talking about something like a 10 or so multiple on that, so you're probably looking at something close to nearing $300 million, monetize that?

Does that sound reasonable?

Or so.

Well, I wouldn't call us with an offer for $300 million.

Understood.

Appreciate it.

Thanks.

The next question is a follow-up from Michael Hall with Wells Fargo.

Please go ahead.

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 that's the kind of level of growth you would expect in the next couple of years, or do you need to 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.

I'm sorry, could you -- I'm not sure if I followed all of how you were --

So you said you're trying to get a long-range CAGR of 30 -- 30% per year or better

Yes.

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, 2013 period -- is that lower than 30%?

No, I'm sorry -- no, we wouldn't see that being lowered.

Matter of fact, the way we've kind of seen it, too, is that we'd talking about more of a several-year CAGR even though we're only talking about outspending for three years, so that it kind of, it gets the machine going.

And in fact, by the end of that period is when the you would probably start dropping down a little bit.

When you're -- obviously, it is difficult to grow any capital instance of business at 30% while living within cash flow indefinitely.

So we actually rely on the jump start to kind of front end load a little bit of that.

Okay.

I didn't know if you needed some sort of jump start in spend to get the growth later, but --

No I actually said that is happening now.

And you know, 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, so we're actually getting -- we actually are benefiting from the fact that that occurred over the last year or two currently.

And we would anticipate that continuing, but it does mean that that's why we do feel some urgency to make sure we keep that going.

Okay.

That's super helpful.

Thanks.

The next question comes from Rhett Bruno of Bank of America Merrill Lynch.

Please go ahead.

Hello, guys.

Just one quick follow up on this revised 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 2, 3 years?

No, I think 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.

Okay.

All right.

Great.

Thanks.

This concludes our question and answer session.

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

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.

This concludes the EQT Corporation first quarter 2011 earnings conference call.

Thank you for attending today's presentation.