EQT Corp (EQT) 2011 Q2 法說會逐字稿

Good morning, and welcome to the EQT Corporation's second quarter 2011 earnings conference call.

All participants will be in a 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 now would like to turn the conference over to Patrick Kane.

Mr.

Kane, please go ahead.

Thanks, Keith, and good morning, everyone.

Thank you for participating in the EQT Corporation second quarter 2011 earnings conference call.

With me today are Dave Porges, President and Chief Executive Officer, Phil Coffee, 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 E& P.

In just a moment Phil will summarize our operational financial results for the second quarter, which we released this morning.

Then Dave will provide an update on our development programs and strategic operational matters.

Following Dave's remarks, Dave, Phil, Randy and Steve will all be available to answer your questions.

First I'd like to remind you that today's call may contain forward-looking statements related to the future events and expectations.

You can find factors that could cause the company's actual results to differ materially from these forward-looking statements listed in today's Press Release and under Risk Factors in the Company's Form 10-K for the year ended December 31, 2010, which was filed with the SEC, as updated by any subsequent foreign 10-Q's which are also filed with the SEC and available on our website.

Today's call may also contain certain non-GAAP financial measures.

Please refer to the morning's Press Release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures.

I'd 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 the second quarter 2011 earnings of $0.58 per diluted share, 190% increase over EPS in the second quarter 2010.

3 items cumulatively added $17.7 million to our pre-tax income, or about $0.07 per share to EPS.

The purchase of the outstanding interest in ANPI, an off-balance sheet structure set up to fund the acquisition from Stato, in 2000 resulted in a book gain.

As we consider potentially more complex financing alternatives to fund our significant growth opportunities, we have looked for ways to clean up and simplify our already relatively simple structure, and the buyback of ANPI is an example of that.

There was also an adjustment for non-income tax matters and a gain on the sale of some available for-sale securities.

Even after adjusting for those 3 items, the EPS in the second quarter 2011 increased 2.5 times over the second quarter of 2010.

Operating cash flow, which for the most part excludes the impact of the 3 items I just discussed, increased by 66% to $189 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 production and Midstream volumes and continued low unit operating costs, which were already among the best in the industry, as well as solid operating income at equity gas.

The operating results in this quarter are fairly straightforward, and I'll start with EQT production where sales volumes continue to grow at a record pace.

The organic growth rate in a recently completed quarter, you saw, was 43% over the first quarter of 2010, even excluding 1.4 Bcfe of volumes from the ANPI transaction.

That growth rate was driven by sales from our Marcellus Shale play, which contributed approximately 39% of the volumes in the quarter, up from only 16% in the quarter a year ago.

Gas prices were also higher.

The realized price at EQT production was $4.16 per Mcfe compared to $3.66 last year.

At the corporate level, EQT received $5.60 per Mcfe compared to $5.33 last year.

NYMEX gas prices basis and liquids revenues were all higher in the quarter, while the impact from hedges was consequently somewhat lower.

Produced liquids, mainly from our liquids-rich Huron and West Virginia Marcellus plays, accounted for 7% of the volumes and about 20% of the un-hedged revenues in the quarter.

As a reminder, we do not include ethane in this calculation as it is currently sold mostly of methane.

If we included ethane, the percentage of liquids produced would approximately double.

Total operating expenses at EQT Production were higher quarter-over-quarter as a result of higher DD&A, LOE and production taxes, however unit cash operating costs were significantly lower and consistent with the volume growth.

Per unit LOE, excluding production taxes, was down by 15% to $0.22 per Mcf equivalent.

That decrease was a result of producing higher volumes while maintaining a cost structure that is, again, already among the best in the industry.

Production taxes were also lower on a unit basis at $0.20 per Mcfe in the current quarter versus about a $0.25 per Mcfe last year.

This time due to an increasing amount of production sales volumes from Pennsylvania.

And you remember that Pennsylvania does not currently impose production taxes, and an increasing percentage of our growth came from the Marcellus play in Pennsylvania.

Moving onto the Midstream results in the second quarter, operating income here was up 25%, 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 32%, somewhat offset by the average gathering rate which declined by 9% due to the increase in Marcellus gathered volumes.

Last quarter we mentioned that 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 production mix, the average gathering rate paid by EQT production will continue to decline.

At the same time, the increase in Marcellus volumes where we experience significant Midstream economies of scale, drove a 33% decrease in Midstream's unit gathering and transmission costs.

So EQT Midstream margins will continue to be strong as the per unit operating expenses for Marcellus production is lower than our current average.

Transmission net revenues also increased by 36%, driven by the additional capacity that came online in the fourth quarter 2010.

Storage, marketing and other net operating income was down about $12 million in the second quarter.

These results include a $4.1 million reduction in processing fees, as we did not own the Langley processing complex during the second quarter of 2011, while we owned it for the full quarter in the second quarter of 2010.

As has been mentioned before, 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 continued to deteriorate.

Given current market conditions and the sale of the Langley plant, we now estimate that full year 2011 net revenues in storage, marketing and other will total approximately $50 million.

The good news is that even with the asset sales and deteriorating seasonal spreads, our Midstream operating income continues to grow significantly.

Net operating expenses at Midstream were flat quarter-over-quarter, excluding the impact of the processing complex and the impact of the previously mentioned tax adjustments.

As I mentioned, per unit gathering expense was down more than 30% as a result of the higher Marcellus throughput while maintaining our cost structure at midstream.

A moment on the Big Sandy Pipeline sale.

You would have seen during the second quarter we announced the sale of our regulated Big Sandy Pipeline.

The sale closed on July 1 so there was no financial impact on second quarter results.

We expect to record a gain of approximately $175 million in the third quarter.

This sale is expected to reduce second half EBITDA by about $14 million and reduce our annualized transmission EBITDA run rate to approximately [$50] million per year.

We plan to invest $230 million over 2 years to add 560 million cubic feet per day of capacity to our Marcellus transmission system, Equitrans.

As a result of those investments, we expect transmission operating income to be about $70 million in 2012 and about $100 million in 2013.

Beyond that, when needed we can expand capacity by another 570 million cubic feet per day for an incremental investment of approximately $50 million, which could ultimately add an additional $30 million to $50 million of EBITDA.

Big Sandy sale will impact our per unit revenue realization, so to help you calibrate your models we forecast transportation and processing revenue to EQT Midstream to go down by $0.14 per Mcf while third party gathering, processing and transportation will increase by $0.14 per Mcf for the second half of 2011.

We also expect the average gathering rate charge to EQT Production to be approximately $1.12 per Mcf for the second half of 2011 and between $1 and $1.05 in 2012, and then between $0.90 and $0.95 in 2013.

Just a quick note on guidance.

Today we increased our production sales forecast for the full year 2011 to between 190 and 195 Bcf equivalent, or approximately 43% higher than in 2010.

We expect that 2012 volume will exceed 250 Bcf equivalent.

We will have more clarity on the 2012 guidance after we establish our capital budget in December.

As a result of a higher volume forecast, we are increasing our operating cash flow estimate for 2011 to approximately $850 million.

As you know, we've raised approximately $620 million in pre-tax proceeds from the sales of Langley and Big Sandy.

As a result of these sales, as well as growing operating cash flow, we closed the quarter with approximately $79 million in cash on hand and full availability under our $1.5 billion credit facility, so we remain in a great liquidity position.

And with that I'll turn call over to Dave Porges.

Thanks, Phil.

This was yet another strong operating quarter as we continue our efforts to maximize shareholder value creation from our core strategic assets.

The 2 topics to which I'd like to devote most of my time this morning are the positioning of our Midstream business within the strategic framework of the Company And separately, some comments on legislative and regulatory issues in the Commonwealth of Pennsylvania, where we've just completed work on the governor's Marcellus Shale Advisory Commission.

First, to set the stage from my Midstream thoughts, 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, we committed that we would live within cash flow plus proceeds from asset sales.

Last quarter, we communicated a longer term goal 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.

The estimate that we can achieve this goal by 2014 was predicated on the assumption that we can outspend cash flow by about $300 million to $400 million per year for the 3 years between now and then, or a little more than $1 billion dollars in external capital from 2011 through 2013 without tapping the equity market.

We have made significant progress towards making that assumption a reality.

First, of course, we sold the Kentucky processing complex in a transaction that was announced and closed in the first quarter this year.

Next we sold the Big Sandy Pipeline at a transaction that was announced in the second quarter and closed at the very beginning of the third quarter.

Those 2 transactions raised about $600 million, For the remainder, we believe that we can utilize the additional debt capacity that our rapid growth and earnings and cash flow are creating.

As we mentioned last quarter, we continue to consider additional asset sales which could provide additional capital to reinvest into Marcellus development.

Not only did these Midstream asset sales fill our funding gap, they also established a marker as to the value of our remaining Midstream assets and organic growth opportunities.

These 2 assets were sold at about 13 to 14 times operating cash flow, and yes, we did note that both buyers accessed lower cost capital from the MLP market.

As we look at our retained Marcellus Midstream assets, we project operating cash flow growth of nearly 20% per year, assuming only EQT production volumes, and an ROTC in the mid-teens, making EQT one of the faster growing and more profitable midstream companies in the country.

This growth, and market comps, indicate evaluation for our Midstream business in excess of $4 billion.

Of course, an additional value of this business is that our control of the location, capacity, and pace of the Marcellus Midstream build-out increases our comfort that we can transport EQT's produced gas from the wellhead to the markets, which increases our confidence that EQT production will achieve its growth objectives.

In our 2011 CapEx forecast, we included $90 million for gathering pipes and compression to add 170 million cubic feet per day of Pennsylvania Marcellus gathering capacity.

But our folks do more than that in working to support our growth in equity production.

Most of the specific activities are not headline material but they are invaluable.

They include adding larger, more sophisticated meters, adding interconnects to interstate systems, adding interconnects between our own systems to route gas around bottlenecks, leveraging the high pressure of the Marcellus production to route around compressor stations that are already at capacity, and blending wet, high moisture gas with dry gas to meet interstate pipeline moisture specs.

This may be more detail than you need, but the point is that these activities are projected to increase the capacity of our existing Pennsylvania Marcellus gathering system by nearly 140 million cubic feet per day by the end of 2011 at a cost of $6 million.

We've not calculated the IRR of that $6 million investment, but it clearly exceeds our hurdle rates.

Our culture encourages innovation, and I am proud of this remarkable achievement.

These specifics support our view that our Midstream business is very valuable, but we realize that some strategic decisions need to be made regarding the amount of investment that should be made in that business prospectively.

One option is to continue with the current model, where we build our needed Midstream system and occasionally sell off some of the seasoned assets, most likely to MLPs.

This is one way to access the value of low MLP costs of capital.

A second option is to basically outsource our Midstream.

Our concern with that approach, in addition to the opportunity cost of foregoing organic growth prospects, is the loss of control that we value immensely, especially during this period of rapid build-out.

But we do recognize that most E& P companies successfully utilize this model.

A third option is to create our own MLP.

Given our forecasted growth profile, this option could make sense even if the only customer is EQT production, but it probably becomes necessary due to capital requirements if we decide to pursue a third party business model.

We realize that there is significant interest from our investors in learning which option we will choose.

At this point, given our current level of study of this issue, the only interim conclusion we've reached is that pursuing a third party growth model on our own or with a partner, probably means an MLP.

While we are unlikely to go that route if we limit our focus to moving equity production.

We appreciate your patience and will keep you informed as we make decisions affecting our future.

From my perspective, this is a high class problem, choosing among several viable alternatives that all create shareholder value.

Shifting gears, let's spend a moment discussing the status of regulatory and legislative issues in the Commonwealth of Pennsylvania.

The Marcellus Shale Advisory Commission, on which I served as a member, forwarded its report to Pennsylvania Governor Tom Corbett on July 22nd.

The 30-member Commission, ably chaired by Lieutenant Governor Cawley, comprised state regulators, producers, local government representatives and environmental organizations.

It made 96 recommendations related to Marcellus development in Pennsylvania, including enactment of an impact fee with revenues return to localities affected by development, enactment of a pooling statute, adoption of legislation of regulations to insure environmentally responsible development, and economic development initiatives such as encouraging the adoption of natural gas as a fuel for buses.

EQT has long believed that each industry needs an appropriate level of state regulation, and each industry should pay for its own externalities.

We are heartened that the Commission's recommendations are aligned with those perspectives and that there was much more agreement among the various constituencies than disagreement.

This is an important first step in developing comprehensive legislation, regulation and public policy that will promote safe and responsible development of the Marcellus Shale and ensure that all Pennsylvanians have an opportunity to economically benefit from this abundant natural resource.

At EQT we are committed to the standard of safe and responsible development, even without governmental mandates.

Along those lines, we are taking steps to reduce the air emissions of our drilling processes.

Air quality has long been a particular problem in this region, and the fact that diesel is the predominant fuel used to power drilling rig equipment in our industry does not help.

We are piloting the replacement of this diesel equipment with natural gas powered equipment.

Replacing this equipment has 3 primary drivers.

First of all, the emissions of the natural gas-powered equipment compared to the diesel equipment operating at present will achieve NOX and total hydrocarbon emission reductions of 46% and a reduction in particulate matter of 78%.

Second, since natural gas is cheaper than diesel fuel, we expect reductions in fuel cost of up to 50%.

And finally admittedly in a small way, this change will increase the adoption of more natural gas-powered equipment and contribute to advancing the new natural gas economy.

Another small step on this path was our opening last week of the first natural gas fueling station in the City of Pittsburg that is open to both fleet vehicles and to the public at large.

This is part of a small but growing network of such stations in this region built by various companies to facilitate the conversion of fleets to nat gas.

The largest customer of our station is Equitable Gas Company, which has recently converted dozens of vehicles to CNG.

Most of the other stations being built around here are similarly anchored by the station sponsor's own fleet, but we all work cooperatively and trust that this bootstrapping, if you will, leads to broader adoption of natural gas as a vehicle fuel.

My concluding remark today, intended as a segue into Q & A, pertains to production.

We completed our first well using the new frac geometry that we've been discussing in October 2010.

Since then, we have turned in line 68 Marcellus wells, of which 13 were completed using that new frac geometry.

We expect to have a total of 27 of the new design wells online by year-end.

We continue to see greater than 60% higher IPs per foot of treated lateral with this new design compared to offsetting wells, and are getting more confident that we will achieve higher EURs though the wells are costing more than we previously estimated, about $1.6 million more for a well with 5300 feet of completed lateral.

We want to gather more production data before making this design our standard, but hope to decide by the end of the year so we can factor the decision into our 2012 capital budget.

In fact, we are now far enough along in this process that we have decided to tweak our normal earnings call Q & A format.

I'm going to ask the first question.

Pat, you can give the instructions to the others in a moment.

My question goes to Steve.

Steve, can you please explain some of the specifics of this new completion design?

Sure, Dave.

As you know, last fall we began testing a new frac design which we hoped would result in both accelerated production and increased reserve recovery from our horizontal Marcellus wells.

We call this design our 30-foot cluster spacing test, and the design basically involves using 150-foot frac stages with 30 feet between perforation clusters versus our standard design of 300-foot per stage,-- 300 feet per stage with 60 feet between perf clusters.

With this design we pump the same amount of water and sand per foot as we do in the standard design, but we achieved double the injection rate per foot versus the standard.

The theory behind this design is to focus the hydraulic energy into a smaller volume of rock, thereby creating a more dense induced fracture network and increasing the recovery factor for that volume of rock.

Additionally, we did expect to see accelerated production in addition to the increased recovery.

As we noted on the last earnings call and Dave just mentioned, we are seeing around 60% higher early time production rates from wells that use the 30-foot cluster spacing design but will take a significant amount of time to accurately quantify the level of increased reserve recovery we are seeing.

That is still true and we don't expect to be discussing levels of recovery or projected economics until the end of this year, at the earliest.

Today, we are posting 2 slides on our website which provide a little more detail.

The first is a schematic showing the stage and cluster spacing for our standard and 30-foot cluster test wells.

The second is a micro-seismic survey we conducted on 2 parallel wells, 1 with the standard frac design and 1 with the 30-foot cluster spacing.

This survey was designed so that we had a third listening well located directly between the 2 test wells, which provided for excellent data quality in the survey.

As you will see on the slide, the well with the 30-foot clusters achieved similar frac half lengths and total stimulated volume but had more than 3 times more micro-seismic events than the standard design.

While this is only circumstantial evidence, we are encouraged that this supports a theory of creating a more dense fracture network.

Much additional analysis is required before drawing economic conclusions about this design, but we continue to be encouraged by the results we have seen and will continue to provide additional details as we continue to test.

Okay, thank you, Steve.

Keith, we're ready to open the call for questions from our investors.

Okay, thank you.

(Operator Instructions) At this time we will pause momentarily to assemble our roster.

And the first question comes from Michael Hall with Wells Fargo.

Thanks.

Good morning everybody.

Congrats on a solid quarter.

Just curious, a little more clarity on the commentary around strategic decisions.

Make sure I'm understanding you correctly.

First, am I hearing you right that option two, then, is off the table?

And then as a follow-up, am I understanding also, then, that the MLP option, option three in your mind, only makes sense if you decide to further expand your activities in terms of sourcing, or serving, rather, third parties?

Not exactly.

Actually none of those alternatives are off the table.

The only thing that is off the table is routinely using our own capital to build out our midstream business.

At some point, the issue was only where does the external capital come from.

If at this point that even though we haven't reached final conclusions, the bias is that we've got now, is if we decide that we want to have a more aggressive growth plan in midstream, we're best off using, having the external capital come from an MLP, either on our own or with a partner.

Whereas, if we decide that we're going to limit the midstream to going more after equity, for just supporting equity production, that external capital will come from more one-off transactions, either selling assets the way we've been selling with Langley and Big Sandy, or possibly taking on a partner.

But that we probably wouldn't want to go down the road, if that's what we do, of having the administrative issues associated with an MLP.

One way or another, the big picture is that we don't really want to be devoting a lot of our, let's call it C-corp capital net, to expanding the midstream business.

One way or another, it's going to have to come from external capital.

Okay.

And I don't mean equity, of course.

The MLP market or asset sales are in whole or in partnership.

And in terms of creating your -- if you did go the route of creating your own MLP and raising capital in that way, is it still possible, or is it at all possible, that at some point, then, you would consider kind of spinning off that part of the entity and at some point having a standalone upstream C-corp?

Yes.

That's actually another conclusion that we've reached.

I guess I just figured I'd get a question, and now I have, is that we have also concluded that having an MLP is not inconsistent with any of the structural alternatives that one might reasonably assume that we would look at.

And look, we recognize that the issue for our company and for other of our peer companies is that the extent of our investment opportunity is greater than -- exceeds in dollars the amount of capital that we have available.

I mean, we laid out a viable plan for a certain level of development, but that doesn't necessarily mean that that's the optimal plan.

So we certainly recognize an issue we're going to be dealing with is, if we wanted to ramp up development more, we need to move further down that road.

So basically, though, we have gotten ourselves comfortable that whether we had an independent midstream business or a midstream business that's associated with -- we stay with a certain C-corp, an MLP is really a better way to raise the money for the midstream business, And incidentally we further decided that, I think we've gotten ourselves comfortable, that if we ever did split the business that it would have probably have been best to do the MLP first,

Okay.

Because we've looked at that sequencing issue too.

Okay, and then, I guess, timing on your final decisions around this?

Well the final decisions, of course, on all kinds of strategic issues get made by the Board, but the normal timeframe for us to really dig into the strategy issues is about this time of year.

So it's going to be during the course of the third quarter.

Well, I'll say through the remainder of the year we're really going to be working through this particular issue in a big way.

Okay, and then on that new frac geometry.

Just curious, if it indeed is successful, does it imply, then, that ultimately tighter spacing per well would also then be required to maximize recoveries.

Or is that -- am I making the wrong assumption or conclusion on that?

I don't think we're ready to draw conclusions on that yet, Michael.

It could imply that, but we're not -- we don't have enough data yet to really draw conclusions.

Okay, and then I guess final one for me, housekeeping.

On the ANPI, what did you pay for that?

Sorry if I missed it.

We took on a debt liability.

Actually, the best way to handle this -- it's sort of complicated and will get into a lot of accounting journal entries.

Why don't you call Pat and he can walk you through it.

But basically high level, that was an off balance sheet financing we did when we bought Statoil.

It only had a few more years to run on it.

There was a lot of administrative burdens associated with it, so we decided to bring it back on the balance sheet and simplify.

So the reserves in production came back on the balance sheet, as well as some debt liabilities and a couple of other liabilities.

The net effects, we told you, production is up about 8 Bcf initially annually, and that declines.

EPS is up only very, very slightly, less than $0.01 a quarter, and cash flow is basically -- operating cash flow is up a little, but total cash flow is sort of neutral because there's a debt service component that includes interest and debt repayment.

And like I said, that's probably more information than you want, but that's the high level story.

It's really just a simplifying transaction.

Okay, that's helpful, thanks.

I'll follow up offline.

Thank you, and the next question comes from Neal Dingmann from SunTrust.

Good morning guys.

Good quarter.

Say, either for Dave or Steve, just wondering on the production guidance, now that you've laid out for the remainder of the year and a little bit into next year.

Can you break that down a little bit as far as -- more detail as far as number of Huron and Marcellus wells anticipated, and then within those, how many you anticipate will use the new technology or technique?

Yes, Neal.

We're anticipating around 100 Marcellus wells for the year and 120 Huron wells for the year, and right now, with the new design, somewhere between 20 and 24 wells.

Okay, and then for Dave or Randy, on the midstream.

Wondering, it looked like Equitrans continues to add, or the phases continue to go long, as you'd planned, remind me as far as the next couple phases, or what benchmarks we should be looking at for the remainder of the year and into next year on it?

I'll let Randy handle that.

Yes.

Neal, as you know, we put the first phase in at beginning of this year for the 100 million a day, and we're focused on adding 130 million a day in 2011, with a project into the third quarter of 2012, an additional 430 million a day in the Equitrans space.

Okay, and then last question if I could.

Just wondering on two things, actually.

One on differentials.

Looked like you continue to be very positive there going into this quarter.

Wondering, going forward, you think that those remain about the same, and then hedging, you're comfortable now where you are at, will you add a little bit more along the way?

Well, on hedging, we're going to continue to re-look at where we want to be.

I mean, honestly we like -- given where our economics are, we like where the prices have been.

Since our development pace is dictated by cash flows, what we've really tended to focus on is to see if we can get more stability around our future cash flows, because that facilitates making the type of longer term drilling rig, frac crew et cetera, commitments that help us reduce those costs over time.

So no, I wouldn't necessarily say that we're done with our hedging.

And for 2011 it's almost become a commercial matter.

It's not really hedging, it's what do you want to sell at but I wouldn't say we're necessarily done at 2012.

I understand that we've added a fair amount since the last time we put out financial results, and certainly with 2013, we've really only just begun to lie in some hedging, but we're focused on cash flow stability.

So as prices move up, that helps us with that cash flow stability that feeds into our ability to accelerate the development of the reserves.

Great point, and then last question, Dave.

One around M & A.

You all have most of your production held, so that's not a big issue.

If there's more Marcellus and acreage in the region for sale, given you are out spending cash flow, will you continue to look for M & A deals or do you have enough acreage at the time?

We are certainly interested in tactical acreage acquisitions.

What I'd really -- and the way I'd think of that is, as we've mentioned before, there's a fair amount of the acreage we have -- and it's not unlike the situation of other companies -- but a fair amount of acreage that we have that doesn't really permit the extended laterals that we would like to have.

Certainly doesn't permit the multi-well pads with everything having extended laterals.

So to the extent that we can get other acreage around us, lease other acreage that would allow us to go from either short laterals, or fewer wells per pad up to more wells per pad, extended laterals, that's attractive to us.

Now, this Marcellus Shale Advisory Commission did recommend, with both industry and environmentalists supporting it, that we come up with a better pooling statute in the Commonwealth of Pennsylvania, and that would, of course, help.

And actually, a similar issue exists in West Virginia.

So some of the view that we have on leasing acreage also is going to be impacted by where the legislation heads in Pennsylvania and West Virginia on pooling.

So you anticipate you will, in addition to M & A, would do more pooling as well, Dave?

Yes, pooling as well.

Clearly that's a more -- that can be a simpler way to save some of the money up front, but we are looking at the tactical leasing.

And we recognize, incidentally, that that means that we need to be more open to asset sales, whether via MLP or straight sales than is necessary -- than what we laid out in that $1 billion dollar over three year time frame.

I mean, it would have to come from that.

We're not going to be going to the equity markets for that.

Okay, thank you.

And the next question comes from Josh Silverstein from Enerecap Partners.

Good morning, guys.

Good morning.

It looks like you guys have been getting pretty efficient on turning the wells that were spud to the wells that are completed.

It looked like, for the numbers you gave, it was about 30% a year ago to 60% now.

Is that basically just a move to pad drilling, or is there anything else that you guys have done to gain at efficiencies, and where do you think that 60% could get to over the course of the next 12 months?

I don't know that we really look at it that way, but really what I think is happening is that we're able to coordinate our midstream and production business a little bit more closely than other companies are, because we control the midstream.

And incidentally, that said, we do recognize that a variety of folks on the midstream business who chat with us about alternative approaches tell us that we could achieve that through partnerships or contractual arrangements.

But that a close coordination between midstream and upstream is what helps us on that front, I'd say.

But I don't know that we'd say that we have a target.

We're always going to have some wells that are -- I think we laid it out in the table in the press release.

There's always going to be gaps between the wells that have been permitted but not spud, spud but not TD'd, TD'd but not fracked, fracked but not tilled.

There's always going to be stuff.

Right.

I was just curious if there's more so delay on frac crews there.

If you guys are looking to add dedicated frac crews, because it seems like as soon as your rigs are moving off the pads, one or two days later the wells are starting to get completed.

Actually that, then, is within production.

They've just done a good job, and I'm confident they will continue doing a good job coordinating between the rigs and the crews.

We do tend to have longer term commitments to both drilling rigs and frac crews, so that they are more under our control.

We're not going pad by pad.

Got you, and then the average lateral length you said was about 5,300.

I was curious how long you guys have tested, and if you think you're still moving towards even further, if you're going out towards 6,000 or 7,000 feet as an average?

Well, as far as the longest laterals we've drilled so far are right around 9,000 feet.

We are trying to permit a well as long as 12,000 feet.

I don't think that would likely be drilled until early next year at this point.

Our philosophy is to drill the longest lateral we can.

As Dave mentioned earlier, we're frequently limited by the least geometry we're faced with.

And especially until there's some better pooling regulations.

That's what limits our averages right now, so we do expect the average to continue to go up.

I don't think we would expect a quick jump up to the 6,000-foot range in the short-term but they will continue to increase.

And actually, that reminds me.

One comment I should have made to an earlier question about acreage is, we are much more actively involved in discussions about acreage swaps with other producers than historically we have been.

So that, of course, is another way that we could head towards optimum.

I don't know that we have a view on what optimal length is right now, other than a view that generally speaking, the land situation prevents us from getting to the optimal length on as many of the well locations as we would like, but that's another tool in the toolkit.

It doesn't just have to be pooling or lease acquisitions.

It can be acreage swaps as well.

Got you.

Then lastly from me on the new fractals.

I know you guys will be talking more about it later on this year, but I was curious if the implied thought was that you would be looking to keep a similar well count year-over-year, but your production rate could grow 30% to 40%, just based on putting the new design in, or would you still grow the total well count next year and then going forward?

Well optimal -- our assessment of optimal is above the type of growth rates that we've talked about before, but the capital will come from internally-generated cash flow or from sales of assets or opportunities.

So really it's going to start with how much capital do we have available and go from there, and again we do recognize -- it's been pointed out by a variety of investors, so that EQT, along with our peers, eventually may wind up being capital-limited and pursuing what is optimal on our own, and that's obviously strategically something that we're going to continue to wrestle with.

Thank you.

Thank you.

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

Good morning.

Two questions for you.

One, on you evaluating strategic options on your midstream business, does this mean that your goal of being free cash flow positive in 2014 is moved forward?

Certainly, we could get free cash flow positive then, if you mean cash flow minus CapEx, but the odds are that we would wind up turning around and investing that business in accelerated development.

I think transactions that we've seen out in the marketplace have pointed out that entities that have, what for practical purposes look to us to be, unlimited amounts of capital have an ability to accelerate the development beyond the capability of companies such -- that are our size, and therefore, getting increasing the value of our company is probably going to continue to be tied to trying to pull forward that development of the resource as much as we can.

But again, subject to the constraint that we actually agree with the investors that we should not be tapping the equity markets for that.

Great, and then on the new frac geometry, why today show us the geometry and what you're doing but not about results, and I understand that it takes a year of data?

But why are you guys giving us that information today, and I think before when you talked about the incremental cost it was $1 million and now it's $1.6 million.

What's changed there?

Well, I think the reason we're not giving conclusions yet is because we don't have conclusions yet.

So, but we did reach the point where I think for competitive reasons, enough information was leaking out and most of our competitors were fairly aware with what our design was.

There was really no advantage to trying to keep that a secret any more.

So that's why we decided to talk more about the specifics.

I think we've said all along we won't be drawing conclusions for quite some time yet.

Regarding the cost, that's a mixture of things.

Some is we've been experimenting with -- the design hasn't been completely static the whole time.

So we've been tweaking it some, and the latest version is a little bit more expensive than where we started.

That, combined with oil field inflation that we've seen since we started doing this has contributed, and some of it is just around because it involves a lot more activity on site in terms of setting plugs and there's a lot of down time.

Honestly, early on it was hard to estimate what the costs would be since a lot of service providers didn't really know how to price it.

So now I think we've done enough.

They know how they're going to price it.

We know what it's going to cost so I think our cost estimates are just more sound now.

So, to kind of reiterate that first point though, Becca, the reason we weren't providing details about this previously is for competitive reasons.

We really didn't have a great interest in sharing that with our competitors.

We've become aware -- and we know that that information eventually leaks out, but we thought why help the cause, and we've become aware over the last couple of months or so that -- through service providers, et cetera, that the information has gotten out to the point where, frankly, it's probably only the investor community and analyst community that wasn't aware of what we were doing.

So we figured that we should levellize the knowledge playing field.

Thanks, and then would it be fair to say that even though you had planned originally to drill a certain number of wells using this new frac geometry, that you drilled your first one late last year, that you wouldn't be continuing this if you didn't think that the economics, and it was higher EURs per well, to justify the higher cost?

I think in an experiment like this, there are several outcomes.

One could be from the initial results were below expectations and it was clear that it was a failure and we would discontinue.

Obviously we haven't done that.

The other outcome for this kind of thing is results are at expectation or above, but because of the nature of what we're trying to do, you need a substantial amount of history before you can draw firm conclusions about the economics, and I'd say that's where we're at.

So you can conclude that the initial results were not bad enough for us to pull the plug, and I think we've given some indication of what we're seeing in the 60% higher IPs versus offset wells.

And that is in the range of what we're expecting to see.

Great.

Thank you, guys.

But it's still true that it's not clear to us that we would want to do this if, in the fullness of time, as it were, it seems as if the only thing we're doing is accelerating the production from given EURs.

So that's what takes time, is to see, compared to the offsets what does that decline curve look like, and is this, in fact, just accel -- to what extent is it acceleration, and clearly there's a lot of acceleration going on, and to what extent is it the higher recovery factors, so higher EURs.

And I guess one thing I would add is, for the costs that we are quoted, $1.6 million for our type well, for this to be an attractive economic opportunity for us, we need to see about 10% higher EUR per well.

So 10% or better, this would be a success, below that, we probably wouldn't adopt it.

Okay, thank you.

So you can also then conclude that we certainly have not gotten -- I guess in a scientific sense, we have not rejected the hypothesis that this is attractive.

Thank you, guys.

Thank you.

The next question comes from Phillip Jungwirth from BMO.

Good morning guys.

What is the goal for the Huron in terms of production growth, the multi-year goal?

Is it to keep production flat there, grow at single digits or double digits, or could you talk about that?

Yes, I don't think we would say that strategically the goal there is necessarily tied to a particular volume growth level.

As with everything, of course, the goal is to extract as much value as we can from that asset, and it's a long lived asset.

We would certainly like to figure out a way to accelerate the monetization of that asset.

I think it remains to be seen whether that's entirely through the drill bit, or whether in some form or fashion, that is a candidate for some other form of monetization, at least partially.

Okay, have you looked at the royalty trust option for that asset or your CBM asset?

I'll let Phil speak to that.

We are looking at it.

We haven't made a conclusion yet on that, but we're certainly aware of that structure and we are looking at it to see how it compares to the cost of capital of our other alternatives.

We haven't ruled out the joint venture structure for Huron either.

I mean, there's a variety of things that still look like they could be attractive with regard to getting, pulling that value forward in the Huron.

Okay, and then can you update us on your latest thinking around the utility, given that you should be building up quite a bit of IDCs, which would help shield any tax gain from the sale of that asset?

Yes.

At this point it's small enough that -- compared to the rest of the company, that my view -- and Pat you can't quite reach me to kick me if you don't like what I'm saying -- but I think that decision should be subsidiary to the broader decision about the structure of the corporation.

Okay, and then--

If we wind up going down the road of splitting it, I think you do not worry about the LDC first.

You do the split first and then you let that subsequent company worry about the LDC.

If you decide you're going to not do that, then I think it makes more sense to revisit, okay, now what do we do with the LDC, but I think the first thing you decide is what to do with the broader structure.

Incidentally, we went through that logic on the MLP also, and we reached the conclusion that you want to do the MLP first, regardless of which way you go on structure.

I mean, we looked at that, we studied it, we got advisors to help us with that, and we concluded that it won't preempt either direction we might want to go on structure, and in fact, if you want to do an MLP, you're probably best off doing it before you make that -- you execute against that.

With the LDC, I think it's the flip side.

I think you wait until after you've made the structure decision.

Okay, makes sense, and then Marcellus, average lateral lengths continue to increase.

They average about 5,000 feet in the quarter, up from 4,800.

Should we expect you to be averaging the 5,300 and the type curve by kind of late this year, or when should we expect that to average 5,300, for wells spud?

I think when we look at lateral lengths by quarter, you're likely to see a fair amount of variability quarter-to-quarter, because it's very much driven by the specific -- well, completely driven by the specific wells we drill in a quarter.

I would say, generally speaking, I would expect that we'll be around that 5,300-foot average next year, but any given quarter could be plus or minus several hundred feet.

Okay, and then last, do you have any well results to talk about from Tioga County or West Virginia?

Well, first, in Tioga County, we're currently drilling up there.

Randy's group is constructing a pipeline to get the gas to market.

We don't expect any production results until the very end of the year.

So first opportunity to talk about it would be the first quarter call.

Full year call.

Full year call.

So nothing really to report there, other than the drilling is going ahead fine and the pipeline construction is moving ahead on schedule.

In West Virginia, I have a couple things I can tell you.

On the last call we talked about a six-well pad with nice results in Doddridge County.

Just to complete the set, I can tell you the seventh well in that pad was the best one.

It's 24 hour average IP was 11.6 million a day, which would pull that average up a little bit.

In total, since the last call, we've turned in line 15 wells.

13 of those 15 were curtailed in some way during their production since that time.

So the IP rates probably aren't particularly representative of the capability of the wells, but those 15 wells average 6.8 million a day in their first 24 hours, all in West Virginia.

Okay, great.

Thanks guys.

You bet.

Thank you, and the next question comes from Mike Matus from Citibank.

Hi, congratulations on a good quarter.

Just had a quick question.

I was unsure as to what equity production actually means when you're talking about the different scenarios you could go through.

What we're referring to there -- so of course that 's in the context of midstream -- is EQT's production versus other producers' production.

So even if there were other -- on the rare occasion that we might have other working interest owners in a well of ours, we'd tend to really include that as traveling along with equity production, but we're really talking about a decision to spend extra money on midstream with the objective of being able to gather gas that is produced by other operators.

Okay, and another one if I may -- and I understand if you don't want to answer it directly -- but one of your peers went the route of actually doing a two-step kind of IPO of the E&P business.

I was just wondering why or why not that might be considered, or not an alternative?

We're looking at a variety of alternatives.

My impression from talking to our -- most of the peers, is we all -- of our size, is that we all realize that we've got this huge investment opportunity, and that the size of our company makes it problematical to attack that opportunity in an optimal way, and we're all finding our own ways to deal with that.

So nothing is off the table.

Okay, understood, thank you.

And I tell you seriously.

If others of you have ideas, we do think -- and I get from one or two people around here chuckle -- but seriously, we are not, we have no pride about it being our idea.

We're happy to execute against somebody else's good idea.

So if you have stuff to consider, I'm happy for you to throw it into the hopper.

We just want the best answer for -- that we're not painting a picture or something here where it's got to be -- it's pride of authorship.

We're just trying to create value.

Understood, thank you.

Okay, there are no more questions at the present time.

I'd like to turn the call back over to management for any closing remarks.

Thank you, Keith.

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