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EQT Corp. (NYSE:EQT)

Q1 2009 Earnings Call

April 30, 2009 10:30 AM ET

Executives

Patrick J. Kane - Chief Investor Relations Officer

Philip P. Conti - Senior Vice President, Chief Financial Officer

Murry S. Gerber - Chairman and Chief Executive Officer

David L. Porges - President and Chief Operating Officer

Analysts

Scott Hanold - RBC Capital Markets Corp.

Raymond Deacon - Pritchard Capital Partners, LLC

Rebecca Followill - Pickering Energy Partners, Inc.

Shannon Nome - Deutsche Bank

Holly Stewart - Howard Weil

Operator

Good morning. My name is Samara and I will be your conference operator today. At this time I'd like to welcome everyone to EQT First Quarter 2009 Fiscal Earnings Conference Call. All lines have 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.

Patrick J. Kane

Thanks, Samara. 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 on our drilling program and other operational matters. Following Murry's remarks, we will open the phone lines up for questions.

But first, I'd like to remind you that 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 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.

Philip P. 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 compare 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 environment.

That environment impacted EQT results in three different areas, first, lower NYMEX unrealized 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 revenue in Midstream storage business.

In total, lower commodity prices resulted in about $48 million less revenue in the current quarter versus the first quarter of last year. And again I'll go into greater detail of all of 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 result that Murry will talk about that in a minute.

But the bad news of course was the volume increase was more than offset by NYMEX price that was 39% lower and an average wellhead price that was a $1.5 per Mcf lower or 20% lower than in the first quarter of last year. The difference resulted in $21 million gross revenue in the production business quarter-over-quarter.

You'd probably notice that we included two new tables in the press release in attempt to provide some more clarity to our results. This change came on the heels of some of the confusion we detected on our 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 wellhead gas price. The main point of that table is to demonstrate that as a corporation, EQT realized revenues of $5.88 per Mcf on our natural gas sales compared to the $4.60 per Mcf that shows up in the production business.

The difference between average wellhead sales price to EQT production and the average wellhead 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 on 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 non-cash, 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 the details FAS 133 comes into play for EQT because as we 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 basis 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 E&P peers include the actual cost to gather transport and processor 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 $0.54 of Midstream cost in the second table, shows 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.

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. 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.

And finally, production taxes were $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 the gathered volumes were up 14%, process volumes were up 49% and transported volumes were up 17%. Again commodity prices overrun deposit of operating results and to make it a little easier to see what 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 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 $60 million in 2009, a storage deal that settled in the first quarter of '09 had spreads that were less than half of the spreads that settled in the first quarter 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. 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 a $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 ramp 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 extended compressor fleet accounted for much of the rest. On the increased DD&A, total installed Midstream property plant and equipment at the end of the first quarter of 2009 was $1.3 billion compared to $0.5 billion at the end of the first quarter of last year as Big Sandy line making 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 the end of February when we received final approval of our previously announced settlement of the OBC's 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, our liquidity update, as you will see in the Q released later today our quarter and short-term debt was $351 million. Subsequent to 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 call. 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 to $650 million inclusive of that tax refund and 2009 year-end short term debt of between 8 and $900 million. That was all a net of any seasonal working capital swings and was based on a $5 NYMEX type of return and the $1 billion capital budget for 2009.

We estimate our 2009 operating cash flow sensitivity to be about $40 million for dollar change in NYMEX. If the lower NYMEX strip persists, we expect a lower result in cash flow to be mostly offset by lower capital and operating expenses, so we are still forecasting between 8 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.

And with that I'll turn the call over to Murry.

Murry S. Gerber

Thanks Phil. And good morning, everybody. I just want to give a couple of comments on the overall operations of the company.

First of all, importantly as Phil mentioned growth -- sales growth is up 18% quarter-on-quarter. Virtually all of that is driven by our Huron and Ba Ria play, where of course we pioneered horizontal layer drilling and this play as you all should know is just at the front-end of it's dramatic growth track.

We're still sticking to a $1 billion in CapEx this year focused on drilling. We are still planning 675 wells, horizontal wells about 375. To reiterate our breakeven 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.

Our 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. We do steel cost about a quarter and reduced drilling services and completion cost about another quarter.

I would like to talk about a new thing that we've been experimenting with and that's our fractured multilateral wells and actually stacked and fractured multilateral wells, we're calling stack and frac around here. We have spud a total of 16 multilateral wells so far and plan to drill at least 25 in 2009 and possibly more.

If you recall we first experimented with multilateral wells as an alternative completion design to complement or replace a single leg fractured horizontal well in the whole Huron and Ba Ria plays.

We did that because we thought the multilaterals were cheaper, that would have about the same EUR and we'll have about the same EURs as the single leg fractured laterals in the Huron. The data so far that we have gathered on these multilaterals confirms that hypothesis so that was all true and multilaterals turned out to be a little more efficient.

However, we've now taken a new step by both stacking and fracturing the multilaterals. 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 cost and of course to maximize the volume per pad reducing Midstream infrastructure cost.

Results so far are very new but we expect 30 day IPs, for these frac multilaterals to be twice, the standard single leg frac horizontal Huron for less than 50% increase in the cost. As an example of one of the stack and fracs that we've done, we did a Cleveland multilateral stack on top of the Huron multilateral. Each one of these wells penetrates about 13,000 feet a shale.

The Cleveland was completed naturally but lower Huron was fracked with a large six stage nitrogen frac. The 38-day IP for both wells combined was about 1.6 million cubic feet per day, that Huron contributed about 55%, Cleveland about 45%.

Total well costs for both wells combined was $2.7 million and we think the EUR is going to 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 frac wells per pad, one design we are permitting right now is for a ten 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 EURs perspective in the first pair of wells as 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 statistical anomaly. I have every reason to believe that these results maybe repeatable on a large scale.

So that's a bit of very, very good news. We are quite excited about that development here at EQT. On the Marcellus play, give you an update there, as you know we have 4,000 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 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 were in process.

As a reminder, we previously reported on a couple of horizontal wells one in Green County PA and one in Baldrige 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 Green County PA, horizontal well and our first Washington County PA horizontal well. The Green County well was turned in line in early April, 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 caught the little over $5.5 million each, but we continue to believe that we will achieve costs of between 3.5 and $4 million per well, at least we're targeting that.

Part of the reason for that enthusiasm is, we have a new rig coming online which will reduce mob and demob cost by $300,000 per well. And if you take our lowest dry hold cost which is 1.9 million and combine it with our lowest completion cost which is 2.5, some being $4.4 million, you can see that we're starting to get into line with that 3.5 to $4 million range, include this with some more learning curve benefits that we expect to get.

Based on our results so far, we think that horizontal wells are to 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 bit more expensive, but the increase associated with the shift in more horizontals will be offset by lower drilling service in midstream build-out cost, therefore no net impact on CapEx for 2009.

I'd like to make a few other comments about the Marcellus. First on capacity, midstream capacity, the critical issue for Marcellus is the high pressure midstream capacity that is the lines like making for example, down south, which take the gas from the wells and the suction systems into the interstate pipelines. You can always get into these interstate pipelines up here at Pennsylvania. You can crouch your way in and, as long as you are 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 Southwest in Pennsylvania, Marcellus spare way. 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 for the development of the Marcellus Shale. EQT is fortunate that it's Equitrans pipeline is strategically situated. While this pipeline was originally engineered to deliver over 700,000 decatherms a day in natural gas into Western Pennsylvania market in the old days when steel moulds were here.

The pipeline can be redesigned to also export significant quantities of Marcellus gas. With Interconnect, the five interstate pipelines and 63 Bcf of storage, 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 talking advantage of it's existing high pressured transmission pipes, likes of way and compression assets Equitrans pipeline can significantly expand its capacity. Equitrans just for information conducted an open season for capacity late last year and received request for over 300,000 decatherms a day and again, this is for the high pressure gathering, the critical links. Obviously, there is a lot demand out there and there is 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 of 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 case in the long-term to deal with the uncertainty there, we're using flexible good amount of processing units until we see how this is going to develop, infinitely the Equitrans is a dry system.

If there is more wet gas that system could be turned into a wet system if need be but right now we'd 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 horizontal, 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 have subscribed for 5000 wells a day capacity on a water distillation recycling plant which I mentioned earlier, which I had been mentioning earlier that should be outlined in 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, I hope it'll doesn't 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 that it was implemented a little earlier than we'd originally thought.

In the LDC, industrial demand was 25% lower than the first quarter 2009. I thought you'd be interested in that, mostly due to reductions from metal businesses and automotive cut backs where 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 an increase in industrial activity in other words one of our customers who is kind of beefing up a little bit, changing their processes a little bit which causes them to burn a little bit more natural gases is fewer than they have previously done.

But it's really not an increase in activity in the area -- the 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. 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 credit to the Pennsylvania PUC and the legislature here in having rules that really encourage people to pay their bills.

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

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

Lastly, a bit on field costs. I know everybody is interested in that, I mentioned the Huron well cost a little earlier. We are seeing some oil field deflation heal. On steel the AMM Index for unquoted 12, 16 and 20-inch line pipe peaked that 2100 hours of tonnage in September of 2008, recent pricing is down around 1,200.

Pipeline construction costs were down a similar amount, for example, bids for an 8-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 is more than doubled this year over the last year. So that bodes well for midstream cost reductions.

Finally, frac costs for 4,000 foot nine stage frac on our Huron wells are down about 10% compared to last year's peak, this year frac cost was about $255,000 per well, we didn't really see a lot of increase last year, we had contracted late in 2007. So this probably doesn't represent a general -- we can't make too many general statements out of our frac cost reductions, but in any event, they are down somewhat.

And with that Pat, I think we'll take questions.

Patrick J. Kane

That concludes the comments portion of the call. Samara, can we please now open the call for questions. Thanks.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets Corp.

Good morning.

Murry Gerber

Hi, Scott.

Scott Hanold - RBC Capital Markets Corp.

Hi, lots take any -- lots going on, Marcellus, first of all 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 has been above that -- at or above that 5 million in day rate. Have you seen stuff somewhere to that, and also on the Marcellus, with respect to where you've done from your drilling, now some of your competitors have talked about in part the Greene County that it's actually pretty good guess, 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?

Murry Gerber

On the second point first, as I mentioned earlier, we haven't seen a lot of need for processing yet, we know others have. And I think there is going to have to be more drilling done to really outline the wet dry boundary if you will. Actually we are starting to think that it's not just a line that might be a little more complicated than that. But in any event, we are 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 a 30-day IP, we haven't had headline 30-day IPs, others have had higher 30-day IPs than we have, you can make your own conclusions from that. But interestingly, our EURs are pretty much in the range with what other people have set at 3.2 Bcfe and that's reflective of what we are observing to be and this is the importance of doing 30-day rather than initial IPs. We are seeing a little flatter decline curve and I know it's early but that is somewhat encouraging.

So we don't have the headline IPs, but on the other hand our EURs are very much in line with what we are seeing and certainly within what would normally be considered natural variability in a system that's controlled by non-linear differential equation. This is not linear stuff. This is non-linear, and so we're quite encouraged by the EURs.

Scott Hanold - RBC Capital Markets Corp.

And then are you drilling and fracking in the extra Marcellus now relatively--

Murry Gerber

Yeah, 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 are going to see, 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.

David Porges

We are on the steep side of the learning curve for Marcellus horizontal right now. That's -- we don't like to yield a handful of -- folks have drilled more than that. And we are seeing improvements in result and techniques, we're still refining things. We analyze to what we see in the lower Huron and we're still making improvements in the lower Huron but that's part of what's going on with us too. So there is geographic variability and we're seeing a lot of improvements kind of on a real-time basis, they just don't show up in some of the results that we report.

Scott Hanold - RBC Capital Markets Corp.

Right.

Murry Gerber

So it's really both things. And I think Dave is right, I think the improvements and just learning curve improvements are going to have some impact on the cost, no question about it. But we should be prepared to see variability from plays-to-plays and I'm not surprised that in our wells that we have a little lower 30-day IPs, I'm very encouraged though that EUR is even with a few wells are as high as they are and so within the range of what other people are talking about.

Scott Hanold - RBC Capital Markets Corp.

Okay, okay. Good. And the prior point, we're talking on the quality of gas that--

Murry Gerber

Yeah.

Scott Hanold - RBC Capital Markets Corp.

It sounds like butane and propane hasn't been an issue for you yet and can you just give us an idea, yesterday on of your competitor indicated that they drilled in a tight spot in Greene County, what counties have you also seen similar things then?

Murry Gerber

Tight spot meaning?

Scott Hanold - RBC Capital Markets Corp.

They're drilling those pretty localized, they've really just stepped out of the whole lot in Green County?

Murry Gerber

Yeah, I mean what we're, Scott what we're going to do of course, we expect this natural variability I mean that's just the way it is. But and that is why we're 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 total and that's why our wells are going to be spread over a fairly large area. And now we're balancing that a bit with putting some wells where we've 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 given 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, where I think the horizontal well generally averages a vertical well, because that's just taking a little sample in a fairly a vertical uptick -- a fairly small sample in a small area. So I don't know if that answers your question or not.

Scott Hanold - RBC Capital Markets Corp.

Yeah, it does to a certain extent. And I am just trying to figure out how this sort of geographical anomaly, how expanded it is? Where you get sort of the good quality gas and then given the data point so far?

Murry Gerber

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, its going to be a good play, a very good play but we should expect to see some variability that's just the fact.

David Porges

Overtime all of us are going to figure out more of where those sweet spots are and obviously overtime, you are going to see us drilling a heck of a lot more wells, you see sweet spot. So I think you are going to see a bunch of us who wind up finding the various sweet spots and then we can 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 are trying to look on our acreage for where more of those, where those sweet spots are.

Scott Hanold - RBC Capital Markets Corp.

Okay.

David Porges

But we'll find the things sweet spots are obviously more than going to balance that with drilling a lot of wells--

Scott Hanold - RBC Capital Markets Corp.

Right now in same area.

Murry Gerber

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

Scott Hanold - RBC Capital Markets Corp.

Okay.

David Porges

And we don't underestimate the extend to which being close to an existing pipeline system which is more I mentioned, we are quite confident, we can re-imagine or reinvent as a Marcellus header system is going mean that the economics are further improved.

Scott Hanold - RBC Capital Markets Corp.

Okay, guys I appreciate your time. Thank you.

Operator

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

Raymond Deacon - Pritchard Capital Partners, LLC

Hey, Murry. I was wondering if you could just walk me through the economics again of a piece of frac and stack wells and what could this do to the 450 sort of breakeven economic price?

Murry Gerber

Well. I am not really ready to change that much. I mean we have had F&D cost cut in the $15 to $20 range so to speak, I really think, this is going to take it below a dollar clearly. As we tune this process up and hopefully employ this as a standard operating procedure down the road. I mean, we are 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 are going to get a 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 it.

So when you add 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 cost, I think it's going to have a pretty substantial impact on overall operating cost and F&D profitability. But so I am not ready to say it's $4 instead of $4.50 but for breakeven but it's going to be lower than in the future, if this pans out, the breakeven is going to be lower than it is currently.

Raymond Deacon - Pritchard Capital Partners, LLC

Right, okay, got it. And so your in terms of the rigs that you'll need, is there much of a change that needs to happen there, at all?

Murry Gerber

No, no, no change whatsoever.

Raymond Deacon - Pritchard Capital Partners, LLC

Got it. And I would think your recovery of gas in plays would be higher because of where you are?

Murry Gerber

Yeah, 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 in 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.

Raymond Deacon - Pritchard Capital Partners, LLC

Just one -- one more quick one with the reduction in the cost to pipelines do you look at all that -- the overall CapEx budget and think about maybe reallocating some dollars into the back into the midstream that you had cut in, I think it was December. Do you think the current allocation stays where it is?

Murry Gerber

I think we need to right now, Ray, I mean I no, 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 others -- what other producers are going to want to do, because we'd like to have them join in with us on that project. But that going to -- that's not going to occur in here right, Dave?

David Porges

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. Let me guess we're kind of focusing on now is -- we're going to go to a point where the two big priorities for us are the slower Huron play and the Marcellus. And I think you are going to see more and more of the midstream dollars supporting exactly those two priorities.

Raymond Deacon - Pritchard Capital Partners, LLC

Got it. Great, thanks.

Murry Gerber

Thanks, Ray.

Operator

Your next question comes from line of Jim Harness (ph) with Barclays Capital.

Patrick Kane

Jim? Jim, you are very quiet. Okay we take the next one please.

Operator

Just a moment please.

Murry Gerber

We've rendered Jim speechless.

Operator

Your next question comes from the line of Becca Followill with PQT.

Rebecca Followill - Pickering Energy Partners, Inc.

PQT, good morning.

Murry Gerber

Becca hi, send your resume, we're happy to consider.

Rebecca Followill - Pickering Energy Partners, Inc.

Several questions for you one on the Equitrans, it's likely 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 or is this, how far long are you?

Murry Gerber

We're to the point Becca where it is. We know what we can do physically, that is to say; we know how we would be able to change the capacity and reroute it in a way to be able accept to both serve the market here, 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 are going to present this new capital program to the regulators 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 are getting support. As I mentioned, we have a tremendous amount of interest in this high pressure gathering, that is the launch pad for the Marcellus, is this high pressure gathering. And so we expect to have a lot of partners on this, won't you say, Dave?

David Porges

Right now, as far 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, and what those discussions with the producer come in at a yield. Because as you know unlike the other areas where we operate on Kentucky et cetera, we are not the dominant producer, this stuff will move a large percentage of the volumes, would be third party volumes.

So we need to make sure that we are working closely with the producer community to figure out which of these projects make the most sense, which combination of the project make the most sense.

Murry Gerber

And the other thing, Becca is, in our 45 well expanded horizontal program, because we weren't going to drill this many horizontals in Marcellus, 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'll be both to serve our needs and others, so it's going to take a little while to suck that out.

David Porges

And just one other 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 that we presume that they would undertake those other projects, but we have to have discussions with them to get ourselves comfortable with what they're timing is versus our timing.

Rebecca Followill - Pickering Energy Partners, Inc.

So just kind of back to the original question is, the cost to do this?

David Porges

These are going to be attractive for Equitrans, but we don't really want to preempt the -- since a lot of this is jurisdictional, we'd rather not preempt that discussion.

Rebecca Followill - Pickering Energy Partners, Inc.

Okay. About the timing?

Murry Gerber

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

Rebecca Followill - Pickering Energy Partners, Inc.

And then you would make a filing and--

Murry Gerber

Yeah.

Rebecca Followill - Pickering Energy Partners, Inc.

So realistically it's probably two and a half years?

Murry Gerber

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 write-aways are there, and projects are relatively small. A lot of times Becca, we're upgrading pipe sizes where in the past they've been downgraded because of lack of activity here in Pittsburg. Pipelines have -- 8-inch pipelines have four inch replacement pieces, right? As you know, you put a four inch replacement piece in a six inch pipe or an eight inch pipe, it's now a four 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 laps.

David Porges

We'd expect, some of these projects to be underway this year. And some of these projects are just not, some of them are larger as might you say, and some of them just aren't very large at all.

Murry Gerber

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

Rebecca Followill - Pickering Energy Partners, Inc.

So it would be a reallocation of capital; some other midstream projects typically--

Murry Gerber

Yeah.

Rebecca Followill - Pickering Energy Partners, Inc.

Not incremental capital?

Murry Gerber

Yes.

Rebecca Followill - Pickering Energy Partners, Inc.

Okay.

Murry Gerber

Yes.

David Porges

Yes, that's correct. And you know you probably have the second Equitrans, it's a system of pipes. It is not one pipe. That is one when Murry mentioned Big Sandy. That's the difference. It's a system of pipes. So some projects really only makes sense, if you're also going 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 is really going to need it.

Murry Gerber

Yeah.

Rebecca Followill - Pickering Energy Partners, Inc.

Okay. And then back to the big picture question which you've kind of addressed but I wanted to hit on it again is only four horizontal Marcellus wells completed so far which means you are very early on a learning curve and everyone of course is still going to make comparisons against rates that we're seeing from capital range which are considerably higher than those rates.

Murry Gerber

Right.

Rebecca Followill - Pickering Energy Partners, Inc.

Is the higher rates a function of just want to make sure that's 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 in the IP front but you get it in the ultimate reserves or where is the delta?

Murry Gerber

I think it's all of the above plus geographic variability which you left out of those -- of that equation. I mean any of those hypothesis at this point are valid and I don't know which one is going to rise to be the most important of those three.

I will say though that as is the case with any of these play which is surely is true in the Huron that we expect to see some improvement in costs because of learning curve. That is no question and obviously that has an impact on profitability. We are also expecting to see some marginal improvement on frac techniques but nothing that would double the reserves or double the IPs and then you cut the geographic variability to consider as well. Again we are not afraid of that, its just something that you should expect to see in a play of this magnitude and in this breadth.

David Porges

Now frankly, we are confident of moving up the leaning curve more quickly than we probably even did with the horizontal program in the lower Huron because we are kind of on an island there, we were basically learning from ourselves, we tried to learn from service providers et cetera. We do -- the advantage of not being the leader in the Marcellus horizontal is that we can go to school on other folks in addition to work on our internal issues.

Murry Gerber

But all three of those hypothesis are equally valid Becca.

Rebecca Followill - Pickering Energy Partners, Inc.

Okay. And then last two clarification questions. Competing in TA, the 290 permits that were led through April 7, are those Marcellus permits?

Murry Gerber

Yes.

Rebecca Followill - Pickering Energy Partners, Inc.

Okay.

Murry Gerber

We had the stats.

Rebecca Followill - Pickering Energy Partners, Inc.

Okay. And then the cost for an eight inch pipe, you said it's going down to $400,000 a mile from what was the original?

Murry Gerber

Seven.

Rebecca Followill - Pickering Energy Partners, Inc.

700,000.

Murry Gerber

700,000 yes. Very significant decrease.

Rebecca Followill - Pickering Energy Partners, Inc.

Okay, thank you.

David Porges

One final point at the permitting just to you all. We are -- we really are pleased with where the government is, the state government is on permitting base, they have been, 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 to be supportive.

Rebecca Followill - Pickering Energy Partners, Inc.

Okay, thank you.

Murry Gerber

All right.

Operator

Your next question comes from the line of Jin Luo (ph) with JPMorgan Chase.

Murry Gerber

Hello.

Unidentified Analyst

Hi, my questions has been answered. Thank you.

Murry Gerber

Okay.

Operator

You have a follow-up question from Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets Corp.

Hi, again. On the stack and fracs the 25 you are targeting in 2009, well I guess this will be multilateral wells, how many of those are going to be stack and frac?

Murry Gerber

I am not sure what the mix is yet Scott. We're just kind of getting these things going and as I mentioned, we have got this 110 well and so 10 are going to be one Scott basically. And then we'll do as many other ones as the results, as we are led to do with the results that come from those wells.

Scott Hanold - RBC Capital Markets Corp.

Okay, okay. And--

Murry Gerber

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

Scott Hanold - RBC Capital Markets Corp.

Okay. And just to clarify you've drilled how many stack and frac so far?

Murry Gerber

We've got -- we've drilled two sets, two on one pad that I mentioned to you, 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. And then -- pardon me.

Scott Hanold - RBC Capital Markets Corp.

Okay, no, go ahead.

Murry Gerber

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 comment.

Scott Hanold - RBC Capital Markets Corp.

Okay. In the -- what kind of theory you're going on and then what you want to try to do. Would you like to frac both the pads for horizontal?

Murry Gerber

That's a good question. We're experimenting with that right now. We -- in that first second frac, the frac should the lower Huron. We took the Cleveland naturally and we believe that this remains to be seen with more production date, but we believe that the frac at Huron actually had an impact on the Cleveland, positive impact on the Cleveland. And we are 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 multilateral before the Huron frac and then we produced that after and it went up.

So we've got some work to do there and trying to understand how far these fractures are going, we are 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 0.5 million a day and I mean 0.5 million initial like first few days production.

It is not producing at about 0.5 million in the first few days, we'll go back and then fracture it.

Scott Hanold - RBC Capital Markets Corp.

Okay.

Murry Gerber

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

Scott Hanold - RBC Capital Markets Corp.

Okay. And still a thought on when your frac it -- what you do at the horizontal well with the lining and what not with the prices you're going to go right now?

Murry Gerber

What we are doing is we are drilling the multilateral well we are not actually putting the fractures into the laterals. We are just isolating each leg of the fractured multilateral and fracking all the way down on it. So from the motherboard all the way onto the lateral.

At some point in time, the guys think maybe it will get cheap enough and it really is a cost issue and maybe it will get cheap enough to be able to actually to put the packers plus tool in each one of the lateral legs and frac those frac have a multi stage within the leg we are not doing that right now. We're fracking the leg from the motherboard.

Scott Hanold - RBC Capital Markets Corp.

Okay.

Murry Gerber

So and that's really the reason we are doing it is for cost considerations right now and some it's a bit of technical there's some technical issue 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 life could be another step up, true in terms of recovery. 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.

Scott Hanold - RBC Capital Markets Corp.

Okay. And what is the exact -- rough distance between the Cleveland and the Huron if there's sort of any kind of interaction that's helping one and the other?

Murry Gerber

It's 300 feet.

Scott Hanold - RBC Capital Markets Corp.

Okay.

Murry Gerber

Yeah.

Scott Hanold - RBC Capital Markets Corp.

All right, appreciate it.

Murry Gerber

Okay. Thanks.

Operator

Your next question comes from the line of Mark Caruso (ph) with Millennium Partners.

Unidentified Analyst

I just had a two quick questions. One was I didn't hear earlier, I thought that 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 can you update your thoughts on how you're thinking about addressing any shortfall, if you take advantage, we seem some other guys take advantage of the capital markets recently on both the equity and the debt side, just want to get your update thoughts on that?

Philip Conti

The updates that I gave in my comments suggests that if we did not, which we think is the worst case to function, did not access the capital markets between now and year-end, we have short-term debt of 8 to $900 million. Some people have access to capital markets, I think they did so earlier in the year rather than later. We were tied up with 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 that.

And our preferred price to beat the end of the year is not 8 or $900 million of outstanding short-term debt. On the debt-to-capital, we are going to have a Q coming out later the day and you'll be able to get it right out there, we didn't say anything about that on the call.

Unidentified Analyst

Okay. Thanks guys.

Murry Gerber

Thank you.

Operator

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

Shannon Nome - Deutsche Bank

Hey, my name is Shannon. How are you?

Murry Gerber

Hi Shannon. We know who it was?

Shannon Nome - Deutsche Bank

Sure. I guess just to piggyback on that then I had one other question, to take the phrase that you used was terming out that debt, what's the appetite for equity at this point?

Murry Gerber

Not this year. I mean we have been consistent with shareholders on that channel; we are not backing off of that.

Shannon Nome - Deutsche Bank

Okay. And then so I apologize if you went through this I missed it, but your DD&A, it came in a little higher than I thought, LOE was a lot lower and I just wanted to get a sense of the sustainability or anything unusual about either one of those two?

Philip Conti

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

On DD&A, that should just be the math of the capital we spend and the reserves. I don't think there is anything unusual going on at all there but if you struggle to make that connection when the Q comes out later today, you got a give Pat or myself a call.

Shannon Nome - Deutsche Bank

Will do. Thanks.

Murry Gerber

Thanks Shannon.

Operator

Your next question comes from the line of Holly Stewart with Howard Weil.

Holly Stewart - Howard Weil

Hey guys, good morning.

Murry Gerber

Hey, Holl.

Holly Stewart - Howard Weil

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 in the Ba Ria has anything changed in your mind, one?

Murry Gerber

No, I'm sorry to glance over that. It is lower -- and one thing the Ba Ria in with a lower Huron, it's another zone, low pressure. It will be prosecuted with the same technology, it could be part of a stack multilateral system as well. So I'm sorry if I was unclear about that.

Holly Stewart - Howard Weil

Okay. And then do you have any update for us on the Ba Ria, I guess I would have thought that we would have maybe gone EU or is that a Ba Ria before the Marcellus, so just curious if you have an update there?

Murry Gerber

Yeah, I didn't get an update and that's probably just a myth on our part, we should do that, maybe we will do that, we'll try and do that a little bit later. We were just focusing so much on the fracs and--

Holly Stewart - Howard Weil

You can do it right now if you like.

Murry Gerber

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

Holly Stewart - Howard Weil

Okay. Fair enough. Thanks.

Operator

At this time there are no further questions. Are there any closing remarks?

Patrick Kane

Yes, thank you. That concludes today's call. The call will be replayed for seven day period beginning at approximately 1.30 PM Eastern Time today. The phone number for the replay is 706-645-9291. You'll need a confirmation code to access the replay. That code is 94253440. And the call will be replayed for seven days on our website. Thank you everyone for participating.

Operator

This concludes today's EQT first quarter 2009 fiscal earnings conference call. You may now disconnect.

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