EQT Corp (EQT) 2009 Q1 法說會逐字稿

Good morning, my name is Tamara and I will be your conference Operator today.

At this time I would like to welcome everyone to the EQT first quarter 2009 fiscal earnings conference call.

All lines have been placed on mute to prevent any background noise.

After the speakers' remarks, there will be a question-and-answer session.

(Operator Instructions)

Thank you.

Mr.

Kane, you may begin your conference.

Thanks, Tamara.

Good morning, everyone, and thank you for participating in EQT Corporation's first quarter 2009 earnings conference call.

With me today are Murry Gerber, Chairman and Chief Executive Officer; Dave Porges, President and Chief Operating Officer; and Phil Conti, Senior Vice President and Chief Financial Officer.

In just a moment, Phil will briefly review a few topics related to first quarter financial results, which were released this morning, and provide a liquidity update.

Then Murry will provide an update our drilling program and other operational matters.

Following Murry's remarks, we will open the phone lines up for questions.

But first, I would like to remind that you today's call may contain forward-looking statements related to such matters as our well drilling program, infrastructure development initiatives, growth rate, storage, and marketing prospects and other financial and operational matters.

Finally, it should be noted that a variety of factors could cause the Company's actual results to differ materially from the anticipated results or other expectations expressed in these forward-looking statements.

These factors are listed in today's earnings release, the MD&A section of the Company's 2008 Form 10-K, the 2009 first quarter 10-Q that will be released later today, as well as on our website.

Any required reconciliations are included in today's press release, and are posted on our website.

With that, I'll 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 2009 earnings per diluted share of $0.55, which compared with earnings per share of $0.57 in the first quarter of 2008.

The first quarter was a strong operational quarter for the Company, and I'll get into the details of that in a couple of minutes.

However, quarterly results were obviously negatively impacted by the current commodity price requirement.

That environment impacted EQT results in three different areas.

First, lower NYMEX and realized gas prices reduced EQT production revenues.

Second, lower NGL prices reduced revenues in EQT Midstream's processing business; and third, seasonal -- lower seasonal spreads reduced revenues in the Midstream storage business.

In total, lower commodity prices resulted in about $48 million less revenue in the current quarter versus the first quarter last year.

Again I'll go into greater detail of all that in a minute, when I briefly discuss results by business unit.

The other main variance to keep in mind when comparing our results to Q1 last year is the $40 million reduction in incentive compensation expenses.

So starting with EQT Production operating results, the big news in the first quarter at EQT Production was the 18% increase in average daily sales volumes versus the first quarter of last year.

We continue to reap the benefits of all the work we did in 2008 and into 2009, and we continue to be very encouraged by the sales growth results, and Murry will talk about that in a minute.

But the bad news, of course, was the volume increase was more than offset by a NYMEX price that was 39% lower, and an average well head price that was $1.05 per Mcf lower, or 20% lower than in the first quarter of last year.

The difference resulted in $21 million less revenue in the production business quarter-over-quarter.

You probably noticed that we included two new tables in the press release, in an attempt to provide some more clarity to our results.

This change came on the heels of some of the confusion we detected on the last call.

Because of how we report our Midstream business, it may have been difficult to interpret and make comparisons between our results and those of our E&P peers, and our hope is that the new tables will help in that regard.

The first table reconciles the difference between NYMEX and our realized average well head gas price.

The main point is to demonstrate that as a corporation, EQT realized revenues of $5.88 per Mcf on our natural gas sales compared to the $4.16 per Mcf that shows up in the production business.

The difference between average well head sales price to EQT Production and the average well head price to EQT Corporation is the charge EQT Production pays to our midstream business to gather, process and transport our equity production, and that charge amounted to $1.72 in the current quarter as you saw in the table.

One other item I should point out in the first table is the line titled "Hedge Impact," which was a positive $0.57 per Mcf in the current quarter.

The actual impact of our hedge portfolio on sales in the first quarter was $19.3 million or a positive $0.84 per Mcf, but netted against that is a $6.2 million or $0.27 per Mcf FAS 133 ineffectiveness loss.

That loss is noncash, it's related to future periods, and it did have the effect of lowering EQT earnings by approximately $0.03 per share.

Without boring you too much with of the details, FAS 133 comes into play for EQT because, as we've discussed in the past, we hedge NYMEX but not basis.

So a FAS 133 gain or loss occurs when basis moves in the opposite direction of NYMEX.

In this quarter the forward curve for basic dropped, while the forward curve for NYMEX is actually still higher than it was when we put certain swaps in place in 2004.

In the second table, we provide a bit more granularity on production unit operating expenses.

It seems to us that most of the E&P peers include the actual cost to gather, transport and process their equity production in their production operating expense.

For EQT, that cost was $0.54 in the current quarter, and because of our three segment approach it shows up in our Midstream business.

So to try to summarize, the difference between the $1.72 of revenues to EQT Midstream in the first table and the $0.54 of Midstream costs in the second table show up in the Midstream segment results and covers depreciation, taxes and return on our Midstream investment.

Hopefully that additional information helps you with your cash flow and earnings models.

A final point on production, operating expenses were higher than Q1 2008 primarily due to higher DD&A, which reflects our increased drilling and production levels.

The Company also invested $3.3 million in the quarter for the purchase and interpretation of seismic data, which shows up as exploration expense in the financial results.

Finally, production taxes were is $1.4 million lower, reflecting lower NYMEX prices.

Moving on to the Midstream business, operating income here was down 19.5% despite the fact that gathered volumes were up 14%, processed volumes were up 49%, and transported volumes were up 17%.

Again, commodity prices overwhelmed the positive operating results, and to make it a little easier to see where that impact shows up, we did add some revenue detail to the Midstream segment results.

In summary, revenues from higher gathered volumes and revenues associated with the Big Sandy pipeline, including asset optimization activities, were offset by unfavorable market conditions for storage spreads and natural gas liquids.

Lower seasonal spreads in the natural gas prices reduced the net operating revenue in our storage business by $16 million in 2009, as storage deals that settled in the first quarter of '09 had spreads that were less than half of the spreads that settled in the first quarter of 2008.

Although you should know that storage spreads have recovered considerably, and we expect to recover a good portion of that reduction in the fourth quarter of 2009.

Natural gas liquid prices were also down quite a bit.

The average liquid price in our Midstream processing business was $0.67 per gallon in the first quarter, or about half of what they were in the first quarter of 2008, and resulted in $10.3 million less net revenue -- operating revenue quarter-over-quarter.

Overall, lower storage spreads and liquid prices in the first quarter resulted in approximately $26 million less revenue than the first quarter of 2008 at Midstream.

Operating expenses at Midstream were about $11 million higher than last year as a result of our ramped up activity level, the majority of which was planned as we prepared to continue to move record production volumes to market.

DD&A accounted for $5 million of the $11 million increase in expenses, while increased electricity and labor to run our expanded compressor fleet accounted for much of the rest.

On the increased DD&A, total installed Midstream property plan and equipment at the end of the first quarter of 2009 was $1.3 billion, compared to about $500 million at the end of the first quarter of last year, as Big Sandy, Langley and Mayking were all put into service since that time.

Moving on to distribution, operating income at distribution was $43.9 million in the first quarter, or about $6 million higher than in 2008.

Approximately $3 million of the increase was due to higher rates effective at end of February, when we received final approval of our previously-announced settlement of the LDC Pennsylvania base rate case.

The projected annual revenue increase from the new rates is $38 million, although only a little more than half of that will show up in 2009.

And then finally, a liquidity update.

As you will see in the Q released later today, our quarter end short-term debt was $351 million.

Subsequent to the quarter end, we did receive a $99 million IRS refund, which was -- which is consistent with what we told you we expected to receive on previous calls.

So our short-term debt balance as of yesterday was less than $300 million.

During the fourth quarter conference call, we forecasted 2009 operating cash flow of $600 million to $650 million inclusive of that tax refund, and 2009 year-end short-term debt of between $800 million and $900 million.

That was all net of any seasonal working capital swing, and was based on a $5 NYMEX price at the time and the $1 billion capital budget for 2009.

We estimate our 2009 operating cash flow sensitivity to be about $40 million per dollar change in NYMEX.

If the lower NYMEX strip persists, we expect the lower resulting cash flow to be mostly offset by lower capital and operating expenses, so we are still forecasting between $800 million and $900 million of outstanding debt under our revolver, and that assumes the worst case that we are unsuccessful terming out all or part of that short-term debt between now and year-end.

With that, I'll turn the call over to Murry.

Thanks Bill, and good morning, everybody.

I just want to give a couple of comments on the overall operations of the Company.

First of all, and importantly, as Phil mentioned growth -- sales growth is up 18% quarter on quarter.

Virtually all of that is driven by our Huron and Berea play, where of course we pioneered horizontal air drilling; and this play, as you all should know, is just at front end of its dramatic growth track.

We're still sticking to $1 billion in CapEx this year focused on drilling.

We're still planning 675 wells, horizontal wells about 375.

To reiterate, our break even price is $2.50 at NYMEX and we make 8% after-tax IRR at $4.50 NYMEX.

First, I'll talk about the Huron play.

As you all recall, the Huron play has multiple zones.

So far this year we've spud 57 gross horizontal wells.

So far since the inception of this play, we've got 540 horizontal air-drilled wells under our belt, so we're really getting the benefit of that knowledge in our activities.

On drilling efficiency, for example, we continue to make progress here.

In 2008 a single leg completed Huron well cost roughly $1.2 million.

In 2009, we're expecting that same well to cost roughly $1 million.

These cost savings are mainly attributed to learning curve, which is about half of that savings; reduced steel costs, about a quarter; and reduced drilling services and completion costs, about another quarter.

I would like to talk about a new thing that we've been experimenting with, and that's fractured multi-lateral wells, and actually stacked and fractured multi-lateral wells, we're calling stack and frack around here.

We've have spud a total of 16 multi-lateral wells so far, and plan to drill at least 25 in 2009, possibly more.

If you recall, we first experimented with multi-lateral wells as an alternative completion design to complement or replace a single leg fractured horizontal well in the Huron and Berea plays.

We did that because we thought the multi-laterals were cheaper, that would have about the same EUR -- and would have the same EURs as the single leg fractured laterals in the Huron.

The data so far that we've gathered on these multi-laterals confirms that hypothesis.

So that was all true, and multi-laterals turned out to be a little more -- turned out to be a little more efficient.

However, we've now taken a new step by both stacking and fracturing the multi-laterals.

The overall objective of taking this next step is to improve productivity, meaning lower the unit F&D by increasing both initial production rates and EURs, with low marginal increases in well costs; and of course to maximize the volume per pad, reducing Midstream infrastructure costs.

Results so far are very new, but we expect 30-day IPs for these fracked multi-laterals to be twice the standard single leg fracked horizontal Huron, for less than 50% increase in the cost.

As an example of one of the stack and fracks that we've done, we did a Cleveland multi-lateral stacked on top of a lower Huron multi-lateral.

Each one of these wells penetrates about 13,000 feet of shale.

The Cleveland was completed naturally; the lower Huron was fracked with a large six-stage nitrogen frack.

The 30-day IP for both wells combined was about 1.6 million cubic feet per day.

The Huron contributed about 55%, the Cleveland about 45%.

Total well costs for both wells combined was $2.7 million, and we think the EUR is going to be in the 2.5 Bcf range.

Costs will go down, and the unit F&D for this technology is likely to settle well below $1 per Mcfe.

,We plan to expand this concept, and drill more stack and frack wells per pad.

One design we are permitting right now is for a 10-well pad; five wells at two levels, with 160,000 lateral feet of shale penetrated on the pad.

And hopefully this pad will be five times better from an IP and an EUR prospective than the first pair of wells I previously mentioned.

This new technology application has the potential in my mind to be another big step change elevation in the reserve potential and the profitability of the Huron play.

I don't believe these early results, because of our extended experience here, are unique or a statistical anomaly.

I have every reason to believe that these results may be repeatable on a large scale.

So that's a bit of very, very good news.

We're quite excited about that development here at EQT.

On the Marcellus play, I'll give you an update there.

As you know, we have 400,000 acres in the play.

On the drilling side, we have spud 31 Marcellus wells to date, 11 horizontal and 20 vertical.

19 of those wells are in line with at least 30 days of production data.

For the vertical wells, 15 of those with 30 day IPs average about 400 Mcfe per day.

Actual well costs are about $2 million, but we expect those to go down to $1.7 million.

And EURs are up to 1.3 Bcfe, averaging a little more than half of that.

Obviously, all of this based on fairly limited data.

On the horizontal side we have 11 wells; four horizontal wells are completed and flowing with 30 day IPs, two are completed but shut in, and five are in process.

As a reminder, we previously reported on a couple of horizontal wells, one in Greene County, PA and one in Doddridge County, West Virginia.

We haven't had headline IPs from our wells.

The 30-day IPs of the four wells range between 1.3 and 2 million cubic feet per day.

However, EURs are averaging about 3.2 Bcfe, and we're seeing a bit flatter decline curve for the horizontal Marcellus wells than we had previously anticipated.

So that's good news.

Earlier this month, we completed our second Greene County, PA horizontal well, and our first Washington County, PA horizontal well.

The Greene County well was turned in line in early April and the Washington County well is currently flowing back, but we don't have 30-day IPs for either of those wells yet.

The two most recent wells cost a little over $5.5 million each, but we continue to believe that we will achieve costs of between $3.5 million and $4 million per well, or at least we're targeting that.

Part of the reason for that enthusiasm is we have a new rig coming on line which will reduce mob and demob costs by $300,000 per well.

And if you take our lowest dry hole cost, which is $1.9 million, and combine it with our lowest completion cost, which is $2.5 million, some being $4.4 million, you can see that we're starting to get into line with that $3.5 million to $4 million range.

Included is some more learning curve benefits that we expect to get.

Based on our results so far, we think that horizontal wells will be more profitable than the verticals, and are shifting our emphasis to horizontals.

We plan to drill between 40 and 45 Marcellus wells in 2009; four will be vertical and the balance will be horizontal.

The horizontal wells are a bit more expensive, but the increase associated with the shift to more horizontals will be offset by lower drilling service and Midstream buildout costs; therefore, no net impact on CapEx for 2009.

A would like to make a few other comments about the Marcellus.

First on capacity, Midstream capacity, the critical issue for Marcellus is a high pressure Midstream capacity; that is, the lines like Mayking, for example, down south, which take the gas from the wells and the suction system into the interstate pipeline.

You can always get into these interstate pipelines up here in Pennsylvania.

You can crowd your way in, and as long as you're willing to be a price taker on interstate pipeline capacity, that's not difficult to do.

The problem is the high pressure gathering capacity.

We have about 70 million cubic feet per day, sufficient to service our drilling this year and probably some next year as well.

Beyond that, though, a couple of things.

First of all, our Equitrans pipeline goes -- which is a high pressure line, goes through much of our West Virginia and Pennsylvania acreage, and is located in the heart of the Southwestern Pennsylvania, Marcellus fairway.

As I've said before, additional Midstream infrastructure to access the Northeast pipeline is critical, particularly the high pressure gathering, and it's going to be critical to the development of the Marcellus shale.

EQT is fortunate that its Equitrans pipeline is strategically situated.

While this pipeline was originally engineered to deliver over 700,000 dekatherms a day of natural gas into the Western Pennsylvania market in the old days when the steel mills were all here, the pipeline and ca be redesigned to also export significant quantities of Marcellus gas.

With interconnect, the five interstate pipelines and 63 Bcf of storage, the Equitrans pipeline can essentially be reinvented as a header system that is designed to serve as a high-pressure gathering system link between Marcellus shale wells and the large interstate pipelines.

By taking advantage of its existing high-pressure transmission pipes, rights of way and compression assets, the Equitrans pipeline can significantly expand its capacity.

Equitrans, just for information, conducted an open season for capacity late last year, and received requests for over 300,000 dekatherms a day; and again, this is for the high-pressure gathering, the critical link.

Obviously there's a lot of demand out there and there's a lot of need out there for this high-pressure gathering.

We're currently meeting with producers regarding the specifics of their Marcellus development plans in order to optimize this expansion opportunity, and in some we're being very proactive on this high-pressure gathering.

It is the critical link, and we're prepared not only to be able to develop this for our own drilling but for those that are willing to commit, to participate, they will also get the benefit our Equitrans pipeline expansion.

So that's on capacity.

We feel pretty good about that for EQT.

On the wet gas side, so far none of our Marcellus gas wells have needed to be processed, but we don't think that's going to be the case in the long-term.

To deal with the uncertainty there, we are using flexible skid-mounted processing units until we see how this is going to develop.

Incidentally, the Equitrans system is a dry system.

If there's more wet gas, that system could be turned into a wet system if need be, but right now we would be expecting that gas would be processed at the downstream end of the suction systems, and would be delivered into Equitrans dry, or any of the other high-pressure pipelines dry.

On permitting, in 2009 our well permitting is progressing pretty nicely and will not impact our drilling program.

For your information, the Commonwealth of PA has increased its pace of Marcellus permitting a bit this year.

So far there have been 293 permits let in Pennsylvania through April 7th, with 153 permits for horizontal wells.

This compares to a total of 471 Marcellus wells permitted last year, and 167 of those were horizontals.

So they have picked up the pace.

On water, we have sufficient access to water, and importantly, we have access to water disposal for our 2009 wells.

We are subscribed for 5,000 barrels a day capacity on a water distillation recycling plant, which I mentioned earlier -- which I've been mentioning earlier.

That should be on line this summer, and that will reduce the amount of water that needs to be injected into disposal wells by 80%, and if necessary this plant can be expanded, and hopefully it will need to be expanded.

So that's really all I wanted to say about Marcellus.

A few other items that might be of interest, obviously we're very pleased with the LDC rate case, and the fact it was implemented a little earlier than we had originally thought.

In the LDC, industrial demand was 25% lower than the first quarter 2009, I thought you would be interested in that, mostly due to reductions from metal businesses and automotive cutbacks.

We have some industries here that serve the automotive industry that we also serve.

For EQT, the margin that we get from distribution is relatively small from these customers, so it hasn't really impacted our results all that much.

We do expect Q2 demand to increase somewhat over Q1, due to a change in manufacturing process by a major customer but not because of industrial -- because of increased in industrial activity.

In order words, one of our customers is kind of beefing up a little bit, changing their processes a little bit, which causes them to burn a little bit more natural gas as fuel than they had previously done, but it's really not an increase in activity in the area; activity we expect to be flat or possibly even down.

On the conservation side, interestingly, we did not see a major impact on first quarter results from conservation, but we think there will be more as stimulus money and energy reduction initiatives targeting decreased electric demand are implemented, you know, that's going to have an impact on gas demand I suppose.

But strictly speaking, conservation wasn't a big deal in the first quarter.

We were a little surprised about that.

It was pretty cold here.

On collections, also despite the current economic activity, the Company hasn't experienced deterioration in customer collections.

That's also interesting.

It's a credit to the Pennsylvania PUC and the legislature here in having rules that are -- really encourage people to pay their bills.

Also, we have been increasing our activities to -- our outreach activities to customers who can't pay, and we've enrolled a lot more people in the various customer assistance programs.

Bad debt was only 1.26% of residential revenues in the first quarter in 2009, versus 1.16% in 2008, and the utility has done a really good job in enrolling those customers as I mentioned.

Lastly a bit on field costs, I know everybody is interested in that.

I mentioned the Huron well costs a little earlier.

We are seeing some oil field deflation.

Steel, on steel the AMM index for uncoated 12, 16 and 20-inch line pipe peaked at $2,100 a ton in September of 2008.

Recent pricing is down around $1,200.

Pipeline construction costs were down a similar amount.

For example, bids for an eight-inch pipeline last year were around $700,000 a mile for us.

This year bids for similar projects are coming in around $400,000 per mile, and this price includes steel and construction.

Also interestingly, the number of bids per project has more than doubled this year over last year, so that bodes well for Midstream cost reductions.

Finally, frack costs for a 4,000-foot nine-stage frack on our Huron wells are down about 10% compared to last year's peak.

This year, frack costs us about $255,000 per well.

We didn't really see a lot of increase last year.

We contracted late in 2007, so this probably doesn't represent a general -- can't make too many general statements out of our frack cost reductions, but in any event they are down somewhat.

And with that, Pat, I think we will take questions.

That concludes the comments portion of the call.

Tamara, can we please open up the call to questions?

Thanks.

(Operator Instructions)

Your first question comes from the line of Scott Hanold with RBC Capital Markets.

Good morning.

Hi, Scott.

Hi, a lot to take in here, it looks like you got a lot going on.

Marcellus first all of, I know you guys don't like to sort of cite IP rates, but can you kind of give a little bit of color on some of the recent wells, what you've been seeing?

I think the industry's been at or above that $5 million a day rate.

Have you seen stuff similar to that?

And also on the Marcellus, with respect to where you've done some of your drilling, you know, some of your competitors have talked about in parts of Greene County that it's actually pretty good gas, where you don't have the processing to do in there.

Are you seeing the same thing, and how widespread do you think this could be?

On the second point first, as I mentioned earlier, we haven't see a lot of need for processing yet but we know others have, and I think there's going to have to be more drilling done to really outline the wet/dry boundary, if you will.

Actually, we're starting to think that it's not just a line, that it might be a little more complicated than that.

But in any event, you know, we're cautiously optimistic that not as much processing is going to need to be required as perhaps others had thought previously.

On IPs, I think Scott we're sticking to our 30-day IP.

We haven't had a headline 30-day IP.

Others have had higher IPs than we have, you can make your own conclusions from that.

But interestingly, our EURs are pretty much in the range of what other people have said, at 3.2% Bcfe, and that's reflective of what we're observing to be, and this is the importance of doing 30-day rather than initial IPs, we're seeing a little flatter decline curve, and I know it's early but that is somewhat encouraging.

So don't have the headline IPs, but on the other hand our EURs are very much in line with what we're seeing, and certainly within what would be normally be considered natural variability in a system that's controlled by nonlinear differential equations.

This is not linear stuff; this is nonlinear, and so we're quite encouraged by the EURs.

And are you drilling and fracking in the actual Marcellus now, versus --

Yes we are, but I'll tell you what, it hasn't made much difference to be honest with you, one way or the other.

It's made a little difference.

And I think on the margin fracturing techniques can help, but I think you're going to see, you know, a reasonable amount of variability, but I think the wells we've got, particularly if we can get these costs down to 3.5 to 4, which our guys are sure they can do, we'll make for a very good play.

You know, we are on the steep side of the learning curve for Marcellus horizontal right now.

That's -- we've only drilled a handful of them.

There are folks who have drilled more than that.

And we are seeing improvements in results in techniques, we're still refining things.

You know, we analogize to what we see in the lower Huron, and we're still making improvements in the lower Huron, but that's part of what is going on with us, too.

So there's geographic availability, and we are seeing a lot of improvements on about a real-time basis; they just don't show up in some of the results that we report.

Right.

So it's really both things.

I think Dave's right.

I think the improvements in -- just learning curve improvements are going to have some impact on the costs, no question about it.

But we should be prepared to see variability from place to place, and I'm not surprised that in our wells that we have a little lower 30-day IPs.

I'm very encouraged, though, that our EURs, even with a few wells, are as high as they are, and certainly within the range of what other people are talking about.

Okay.

And the prior point we were talking on the quality of the gas, it sounds like butane and propane haven't been an issue for you yet, and can you just give us an idea, because I know your competitor indicated that they had drilled in a tight spot in Greene County.

What counties have you also seen similar things in?

A tight spot, meaning?

You know, their drilling was pretty localized.

They haven't stepped out a whole lot in Greene County.

Yes, I mean -- what we're -- Scott, what we're going to do -- of course, we expect this natural variability.

That's just the way it is, but -- and that is why we are committing to a much broader program of horizontals, the 45, to see how much this geographic variability -- see what it is.

We're not scared of it.

We just want to understand it in toto, and that's why our wells are going to be spread over a fairly large area.

Now we're balancing a bit with putting some wells where we have got suction systems being developed, and where we have existing high-pressure gathering, because we want to get this gas to market so we can watch it flow for a while.

So we're sort of balancing drilling close to infrastructure and that goal, we're balancing that goal with the goal of testing geographic variability.

And even on our vertical program we saw a lot of wells that had tight spots, if you will, and that's the reason why we think that horizontals are the right way to go.

We think the horizontal well generally averages -- more than a vertical well can, because that's just taking a little sample in a fairly -- a vertical well takes a fairly small sample in a small area.

So I don't know if that answers your question or not?

Yes, it does to a certain extent, and I'm just trying to figure out how this sort of geographic anomaly, how expanded it is, where you have good quality gas and obviously limited data points so far.

What I think is, I think -- my view is, and you can take it or leave it, my view is the play is going to be fine, it's going to be a good play, a very good play, but we should expect to see some variability.

That's just what -- just the fact.

Over time all of us are going to figure out more of where those sweet spots are, and obviously over time you're going to see us drilling a heck of a lot more wells where we see sweet spots.

So I think you're going to see a bunch of us who wind up finding the various sweet spots and then we see -- you see a lot of concentration of drilling around there.

That's just not where we think it's best for us to go right now.

We're trying to look on our acreage for more of those -- where those sweet spots are.

But, you know, if we find the sweet spots, obviously we're then going to balance that with drilling a lot of wells right in that same area.

But bottom line is if we get 3.2, 3.5 Bcfe per well on average, I'm confident that our team is going to get the cost down to make that a very, very profitable play.

We don't understatement the extent to which being close to an existing pipeline system, which as Murry mentioned we are quite confident we can reimagine or reinvent as a Marcellus header system, is going to mean that the economics are further improved.

Okay, guys, appreciate your time.

Thank you.

Your next question comes from the line of Raymond Deacon with Pritchard Capital.

Hey, Murry, I was wondering if you could just walk me through the economics again of these frack and stack wells?

And what could these do to the $4.50 sort of break-even economic price?

Well, I'm not really ready to change that much.

We've had F&D costs kind in the $1.15 to $1.20 range, so to speak.

I really think this is going to take it below $1, clearly, as we tune this process up and hopefully employ this as a standard operating procedure down the road.

I mean, Ray, we're pretty excited about this, particularly in light of the fact that we have so much capacity down South to be able to feed this gas into, and the fact that we're going to get a the lot more gas per pad and have a lot fewer -- a lot lower need for gathering lines.

We are going to have bigger -- fewer, bigger gathering lines, and that is a tremendous benefit to the Southern Appalachian region, which is quite hilly and difficult to operate in.

So when you add the -- the straight line lower F&D costs for drilling, and the efficiencies that you get by having more gas per pad with the lower gathering costs, I think it's going to have a pretty substantial impact on overall operating costs, and F&D and profitability.

But -- so I'm not ready to say it's $4 instead of $4.50 but -- for break-even, but it's going to be lower than in the future if this pans out.

The break-even's going to be lower than it is currently.

Right.

Okay.

Got it.

And so -- in terms of the rigs that you'll need, is there much a change that needs to happen there?

None.

No change whatsoever.

I would think your recovery of gas in place would be higher because I know --

Yes, that's going to take some time, exactly.

I hope so too, Ray, I really do.

I would be okay if we're just getting higher initial rates and the same reserves, that would be good, but I think it's going to take some time and watching these wells for a while to determine how much extra EUR or, as you said, how much extra recovery efficiency will be gained by this new technique.

So that's going to take some time to figure out.

Right.

Just one more quick one.

With the reduction in the cost of pipelines, do you look at all the overall CapEx budget and think about maybe reallocating some dollars back into the Midstream that you cut in -- I think it was December.

Do you think the current allocation stays where it is?

Yes, I don't think we need to right now, Ray.

I mean -- no is the short answer.

We've got this -- the reinvention of Equitrans might require -- is going to require some capital, no question about that.

We're not -- Dave and I aren't quite ready to make the big commitment there.

Obviously we want to see what other producers are going to want to do, because we would like to have them join in with us on that project.

But that's not going to be until late in the year, right, Dave?

It won't be, and at this point we're really concentrating more on -- our working hypothesis right now is reallocation within the Midstream segment, rather than -- because really what we're kind of focusing on now is we're getting to the point where the two big priorities for us are this lower Huron play and the Marcellus.

And you know over -- I think you're going to see more and more of the Midstream dollars supporting exactly those two priorities.

Great.

Thanks.

Thanks, Ray.

Your next question comes from the line of Jim Harness with Barclays Capital.

Jim?

Jim, you're very quiet today

Can we take the next one, please?

Just one moment, please.

We've rendered Jim speechless.

Poor Jim.

Your next question comes from the line of Rebecca Followill with EQT.

Not with EQT, but good morning.

Rebecca, fine, send your resume in.

We're happy to consider.

Several questions for you, one on the Equitrans stuff you talked about.

What's the cost to do this?

What's the timing to do it?

How do you handle your existing [firm] transportation customers?

Is this conceptual?

Is this -- how far along are you?

We're to the point where it is -- we know what we can do physically.

That is to say we know how we can change the capacity and reroute it in a way to be able to accept -- to both serve the market and accept Marcellus gas.

We have a lot of work to do on the regulatory side, let's put it that way, to figure out how we're going to present this new capital program to the regulators, you know, and just figure out all the pieces of it.

And frankly, we need to make sure that we've canvassed the producers appropriately to make sure that we're getting support.

As I mentioned, we have a tremendous amount of interest in this high-pressure gathering.

That is the lynchpin for the Marcellus, is this high-pressure gathering, and so we expect to have a lot of partners on this, wouldn't you say, Dave?

Right now we've -- as far as the conceptual issue we haven't really begun construction of most of the things we need, but we have identified about a dozen and-a-half specific projects, some of them not very expensive, some of them more expensive.

And which ones you -- which ones we undertake first, and what kind of combinations we undertake, are going to depend, as Murry said, on what those discusses with the producer community yield.

Because, as you know, unlike the other areas where operate down in Kentucky, et cetera, we're not the dominant producer.

This stuff will move -- a large percentage of the volumes that would move would be third-party volumes.

So we need to make sure we're working closely with the producer community to figure out which of these projects make the most sense, which combinations of the projects make the most sense.

The other thing, Rebecca, is in our 45-well expanded horizontal program, because we weren't going to drill this many horizontals in the Marcellus but we are now, we are intending to use that program also, as Dave mentioned, to scope out where we think the hot spots are in the play, and that will direct us to which Equitrans pipeline projects we want to undertake, too.

So it will be both to serve our needs and others.

So it's going to take a little while to suss that out.

Because one of the things we've identified is that there are some interstate transmission companies that also have some -- what we would think would be economical expansion opportunities, depending on -- they just don't need to undertake them right now.

But depending on what we choose to undertake with Equitrans, we presume that they would undertake those other projects but we have to have discussions with them to get ourselves comfortable with what their timing is versus our timing.

So just to come back to the original question, does is cost to do this?

This is going to be attractive for Equitrans, but we don't really want to -- since a lot of this is jurisdictional, we would rather not pre-empt that discussion.

Okay.

How about timing?

Time, I think -- by the end of this year I think we'll be in a position to have a firm plan on exactly what is going to happen on Equitrans.

And then you would make a filing, and so realistically it's probably 2 and-a-half years?

No, no, no.

We're not -- I should have probably mentioned that earlier.

Some of these projects could be very expensive, but the good news is the right-of-ways are there, and the projects are relatively small.

A lot of times, Rebecca, we're upgrading pipe sizes, where in the past they've been downgraded because of lack of activity here in Pittsburgh.

Pipelines have -- 8-inch pipelines have 4-inch replacement pieces, right, that -- as you know you put a 4-inch replacement piece in a 6-inch pipe or an 8-inch, it's now a 4-inch pipe, the whole thing.

So there are replacements like that, small interconnects, looping.

And there are some big projects, don't get me wrong, some very expensive big projects that are needed as well, but it's not like a Big Sandy-type greenfield project.

This is a brownfield project, and therefore cheaper to do probably, less time lags.

We would expect some of these projects to be underway this year.

Some of these projects are just not -- some of them are larger, as Murry said, and some of them just aren't very large at all.

So we'll start doing construction this year but the time lag, even on the big one, is not going to be more than a year or so.

So it would be a reallocation of capital from other Midstream projects to this Midstream project, not incremental capital?

Yes, that's correct.

And you probably have to think of Equitrans, though, as a -- it's a system of pipes.

It is not one pipe.

That was -- when Murry mentioned Big Sandy, that's the difference.

It's a system of pipes, so some projects really only make sense if you're also going to undertake other projects.

That's where the discussions with the transmission companies on one side and the producer community on the other need to be undertaken.

We don't want to even undertake inexpensive projects if no one's really going to need it.

Okay.

And then back to the big picture question, which you kind of addressed but I wanted to hit on it again.

Only four horizontal Marcellus wells completed so far, which means you're very early on the learning curve, and everyone, of course, is still going to make comparisons, again, just rates we're seeing from [cap and range] which are considerably higher than those rates.

Right.

Is the the higher rates a function of, I just want to make sure, where you are in the learning curve?

Or is it your completion technology is where you think that maybe you don't get as much on the IP front but you get it in the ultimate reserves, or where's the delta?

I think it's all of the above plus geographic variability, which you left out of those -- that equation.

Any of those hypotheses at this point are valid, and I don't know which one is going to rise to be the most [audio dropout].

We're also expecting to some marginal improvement on frack techniques, but you know not -- nothing that would double the reserves or double the IPs.

And then you have the geographic variability to consider as well, which -- again, we're not afraid of that, it's just something that you should expect to see in a play of this magnitude and this breadth.

Frankly, we're confident of moving up the learning curve more quickly than we probably even did with the program in the lower Huron, because we were kind of on an island there.

We were basically learning from ourselves.

We tried to learn from service providers, et cetera.

We do -- you know, the advantage of not being the leader in the Marcellus horizontal is that we can go to school on other folks, in addition to working on our internal issues.

But all three of those hypotheses are equally valid, Rebecca.

Then I'm sorry, the last two clarification questions.

Permitting and PA, the 290 permits that are let through April 7th, those are Marcellus permits?

Yes, we understand.

And then the cost for an 8-inch pipe, you said it's gone down to $400,000 a mile from -- what the original?

$700,000.

A very significant decrease.

Okay, thank you.

One final point on the permitting, just for your -- we really are pleased with where the Government -- the State Government is on permitting.

They have been -- I mean it is a long road.

They haven't had to do this before, but they are trying to be supportive of the industry.

They're trying to understand the industry's needs and issues, and they're trying to be supportive.

Okay, thank you.

All right.

Your next question comes from the line of Xin Liu with JPMorgan Chase.

Hello?

My question has been answered.

Thank you.

Okay.

You have a final question from Scott Hanold with RBC Capital Markets.

Hi again.

On the stack and fracks, the 25 you're targeting in 2009, I guess those would be multi-lateral wells, how many of those are going to be stack and frack?

I'm not sure what the mix is yet, Scott.

We're just kind of getting these things going, and as I mentioned we've got this one 10-well pad, so 10 are going to be in one spot basically, and then we'll do as many ones as the results -- as we're led to do with the results that come from those wells.

Okay.

A good percentage of them will be stacked and fracked, yes.

Okay.

And just to clarify, you have drilled how many stack and fracks so far?

We've got -- we've drilled two sets of -- two on one pad that we mentioned, two on another pad that had been drilled, and we're just now getting some of the results from those.

So two sets of two so far.

Okay and then --

Pardon me?

Okay, no go ahead.

And then we're going to expand one of those pads to include more wells, and then we've got this 10-well pad basically that I mentioned in my comments.

Okay and in -- what kind of theory are you going on in what you want to try to do?

Would you like to frack both the stacks horizontal?

That's a good question.

We're experimenting with that right now.

We -- in that first stack and frack, we only fractured the lower Huron.

We took the Cleveland naturally, and we believe -- and this remains to be seen with more production data, but we believe that frack of the Huron actually had an impact on the Cleveland, a positive impact on the Cleveland, and we're not sure we understand that exactly.

We know it did have an impact, we just don't understand why it had an impact, because we had produced the Cleveland multi-lateral before the Huron frack, and then we produced it after and it went up.

So we've got some work to do there to try to understand how far these fractures are going.

We're doing some more technical work to try to understand that a bit better.

But the current theory, the current working hypothesis is that we probably fracture both zones unless one of them is producing a natural of above a half a million a day.

And I mean a half a million initial, like the first few days production.

If it's not producing at about a half a million in the first few days, we'll go back in and fracture it.

But that's just a rule of thumb now, and it has little deterministic scientific background to back it up.

That's just our current rule of thumb.

Okay.

And so is the thought on when you frack it or not -- I mean, what you do with the horizontal well bore with lining and what not, with -- the process you're undergoing right now?

What we're doing is we're drilling the multi-lateral well.

We're not actually putting the frack tools into the laterals.

We're just isolating each leg of the fractured multi-lateral and fracking all way down it, so from the mother bore all the way into the lateral.

At some point in time the guys think maybe it will get cheap enough, and it really is a cost issue, maybe it will get cheap enough to be able to actually put the [packers plus] tool in each one of the lateral legs and frack those -- have a multi-stage frack within the leg.

We're not doing that right now, we're fracking the leg from the mother bore.

The reason we're doing that is for cost considerations right now, and some -- and there's a bit of technical -- there's some technical issues of [isolation] also that we have to overcome, but that's our current hypothesis.

But I'm glad you raised the question, because fracking the individual lateral legs could be another step up, too, in terms of recoveries.

So we've got a lot more to do on this Huron play, and the team has just done a fabulous job in bringing us as far as they have.

Okay.

And what is the exact -- you know, rough distance between the Cleveland and the Huron?

Is there sort of any interaction that helping one and the other?

It's 300 feet.

Okay.

All right, appreciate it.

Okay.

Thanks.

Your next question comes fruit line of Mark Caruso with Millennium Partners.

I just had two quick questions.

One was, I didn't hear earlier, I apologize if I missed it, what the debt to cap ended up this quarter?

And the second question is just you mentioned earlier the operating cash flow and the short-term debt, and I just wanted to get your updated thoughts on how you're thinking about addressing any shortfalls?

If you take advantage -- we've seen some other guys taking advantage of the capital markets recently on both the equity and the debt side.

I just wanted to get your updated thoughts on that?

The update that I gave in my comments suggested that if we did not, which we think is the worst-case assumption, did not access the capital markets between now and year-end, we would have short-term debt of $800 million to $900 million.

You know, some people have access to capital markets.

I think they did so earlier in the year rather than later.

We were tied up with the S&P ratings process, and when we came out of that process the market wasn't quite as good in March, but we're watching it, and our preferred place to be at end of the year is now $800 million or $900 million of outstanding short-term debt.

On the debt to cap, we're going to have a Q coming out later today and you'll be able to get it right out of there.

We didn't say anything about that on the call.

Okay.

Thanks, guys.

Thank you.

Your next question comes from the line of Shannon Nome with Deutsche Bank.

Hey Mark, it's Shannon, how are you?

We knew who it was.

Sure.

I guess just to piggyback on that, and I had one other question.

I think the phraseology you used earlier was terming out that debt.

What's the appetite for equity at this point?

Not this year.

We've been consistent with shareholders on that, Shannon.

We're not backing off of that.

Okay.

And then -- so I apologize if you went through this and I missed it, but your DD&A rate came in a little higher than I had thought.

LOE was a lot lower.

And I wanted to get a sense of the sustainability or anything unusual about either one of those two.

I think LOE could be a little bit seasonal, Shannon, I think our inclination would be that -- the last year number was a better number, that tends be a little bit seasonal.

On DD&A, that should just be the [path] of the capital we spend and the reserves.

I don't think there's anything unusual going on at all there, but if you struggle to make that connection when the Q comes out later today, give Pat or myself a call.

Will do, thanks.

Thanks, Shannon.

Your next questions in from the line of Holly Stewart with Howard Weil.

Hey guys, good morning.

Hey, Holly.

Two quick ones.

You guys mentioned your two biggest priorities being the lower Huron and the Marcellus.

I think if I had to nail it down, I would have said the lower Huron and the Berea.

Has anything changed in your mind, one?

No, I'm sorry to gloss over that.

It is lower -- I'm lumping the Berea in with the lower Huron, because it's another zone low pressure, it will be prosecuted with the same technology.

It could be part of a stacked multi-lateral system as well, so I'm sorry if I was unclear about that.

Okay, and then do you have any update for us on the Berea?

I guess I would have thought that we may have would have maybe gotten EURs out of the Berea before the Marcellus, so just curious if you have an update there?

Yes, I didn't give an update, and that's probably just a miss on our part.

We should do that.

Maybe we'll do that -- we'll try to do that a little bit later.

We were just focusing so much on the fracks.

You can do it right now if you would like?

I just doesn't have the numbers -- all of the well numbers exactly in front of me, so I don't want to do that.

Okay.

Fair enough.

Thanks.

At this time there are no further questions.

Are there any closing remarks?

Yes, thank you.

That concludes today's call.

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This concludes today's EQT first quarter 2009 fiscal earnings conference call.

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