EQT Corp (EQT) 2010 Q4 法說會逐字稿

Good morning, and welcome to the EQT year end 2010 earnings conference call.

(Operator Instructions)

I would now like to turn the conference over to Pat Kane, Chief Investor Relations Officer.

Sir, the floor is yours.

Thanks, Jill.

Good morning, everyone, and thank you for participating in EQT Corporation's year end 2010 earnings conference call.

With me today are Dave Porges, President and Chief Executive Officer, Phil Conti, Senior Vice President and Chief Financial Officer, Randy Crawford, Senior Vice President and President of Midstream Distribution and Commercial, and Steve Schlotterbeck, Senior Vice President and President of Exploration and Production.

In just a moment, Phil will summarize our financial results for the year end 2010, which were released this morning.

Then Dave will provide an update on our reserve report, development programs, and operational matters.

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

First, I would like to remind you that today's call may contain forward-looking statements.

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

These factors are listed under risk factors in the company's Form 10-K for the year end December 31, 2009, and in the company's Form 10-K for the year end December 31, 2010 to be filed with the SEC, as updated by any subsequent Form 10-Qs, which are also on file with the SEC and available on our website.

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

Please refer to the morning's press release for important disclosures regarding such measures and forward-looking statements discussed on today's call.

With that, I would like to turn the call over to Phil Conti.

Thanks, Pat, and good morning, everyone.

As you read in the press release this morning, EQT announced 2010 earnings of $1.57 per diluted share compared to $1.19 per diluted share in 2009.

Operating cash flow in 2010 also increased by $215 million, or about 50% after normalizing for changes in tax refunds.

Those results were driven by another outstanding operational year at each of EQT's business units.

Leading the way on the annual operating performance was a 34.5% increase in sales that produced natural gas at EQT Production, which represented our highest (inaudible) ever.

Gathered volumes at EQT Midstream also increased by 21%, trending up with the higher volumes in EQT Production.

Somewhat tamping down the impact of higher volumes, the EQT average well head sales price was $5.62 per Mcf in 2010, or about $0.18 lower than last year.

The realized price drop resulted from having fewer hedges in place as compared to 2009, as well as a slightly lower average hedge price, although much of the hedging impact was offset by higher NYMEX and natural gas liquids prices.

The liquids price impact is not trivial at EQT, as approximately 8%, excluding ethane, of our total production, is in the form of liquids.

For segment reporting purposes, of that $5.62 per Mcf $3.93 per Mcf was allocated to EQT Production, with the remaining $1.69 per Mcf allocated to EQT Midstream.

Now, that split represents quite a change from our historic allocation, so I will take a moment here to explain.

As you know by now, earlier this month, we announced that we are selling our Kentucky processing assets to MarkWest and entering an agreement with MarkWest to process our liquids-rich Huron gas.

That agreement reflects EQT paying a processing fee to MarkWest and retaining a majority of the frac spread.

Historically, we have reported that frac spread associated with EQT Production's natural gas liquids in the processing line of EQT Midstream's results.

Now that EQT Midstream is exiting the processing business, we have eliminated the processing line item from the Midstream segment page and going forward, the revenues from liquids produced from EQT Production's wells will be recognized in the realized price per Mcf at EQT Production.

Frac spreads associated with third party gas have been left in the Midstream segment and are reported under the Storage, Marketing, and Other, line of the recast Midstream report.

Do note that processing fees paid to EQT Midstream through the close of the sale, in other words while EQT is still in the processing business, have and will continue to show up in Midstream results in that line.

We reported full year 2010 and the recently-completed quarter in the new format.

To help you compare historic results, we have posted reconciliations to the previous presentation format on our website.

A final comment on the new presentation format.

Beginning next quarter or the first quarter 2011 in the Price Reconciliation table, including in our earnings report, the revenues to EQT Midstream deduction will no longer include processing charges associated with EQT's Production, lowering that deduction by approximately $0.08 per Mcfe.

However, MarkWest processing fees will show up in the third party gathering, processing, and transportation deduction in the table and reduce the average well head sales price to EQT by approximately $0.15 per Mcfe.

Now, back to the 2010 results.

Overall absolute costs increased as expected, given our outstanding growth rate, but on a unit basis, the total cost to produce, gather, process and transport EQT's produced natural gas and NGLs was down by about 4%.

I will go into a bit more detail on that as I briefly discuss the annual results by business unit.

I would want to point out the fourth quarter results basically mirrored the full year, so I do not intend to discuss the quarter results in detail.

However, as some of you have noticed, our interest expense in the fourth quarter was down, despite the fact that our outstanding debt has not changed much.

Interest expense decreased because we have begun to capitalize interest related to Marcellus drilling, mainly because pad drilling causes Marcellus wells to be under construction for a longer period than our traditional vertical wells.

In the fourth quarter 2010, we capitalized $7.6 million.

That was the capitalized interest costs for all of 2010.

So, it represents about $2 million of capitalized interest per quarter.

That's probably a reasonable assumption per quarter for 2011.

Moving on to the business unit results starting with EQT Production.

As has been the case for two years now, the big story in the quarter at Production was the growth in sales of produced natural gas.

As I mentioned, the growth rate was nearly 35% for the year, and was slightly north of 40% for the quarter, which, by the way, was the fourth straight quarter of more than 30% growth.

Those growth rates were achieved organically and were driven by sales from our Marcellus and Huron horizontal shale wells, which together contributed 48% of the volumes in 2010.

Contribution from the Marcellus play alone is growing rapidly and represented nearly 19% of our volume this year, up from just 3% in 2009.

The average sales of produced natural gas totaled just under 440 million per day at year end, about 41% higher than year end 2009 exit rates.

Moving on to expenses, total operating expenses at EQT Production were $79 million higher year-over-year.

Absolute DD&A, SG&A, LOE, and production taxes were all higher, consistent with the significant Production growth.

DD&A represented about $66 million of the $79 million increase.

SG&A was also about $21 million higher for the year.

Although, that is somewhat distorted by the fact that we had an $8.6 million litigation reserve reversal in the fourth quarter of 2009, and $4.5 million in charges related to the water treatment facility mentioned in previous calls during 2010.

Absolute LOE was a bit higher year-over-year.

However, volume increases have been outpacing the general trend of higher absolute expenses.

And as you would expect, unit LOE was lower in 2010, in this case by about 20% compared to 2009.

Somewhat offsetting the absolute cost increases, exploration expense was $12.5 million lower in 2010, as we reduced the size of our seismic program compared to last year.

Our norm recently has been to provide a breakdown of our Marcellus wells that are in various stages of completion.

Based on your feedback, that information is informative, so I will give a quick update on our current status.

EQT has spud a total of 143 horizontal wells in the Marcellus play to date, of which 67 are currently online.

Of the 76 wells not yet online, 8 are either currently drilling or have been top-holed,48 are drilled and awaiting a frac job, and 20 have been fracked and are awaiting pipeline hook-ups.

Another way we look at our progress internally is by frac stages online or in a system for our Marcellus wells.

As of the end of the year, 788 frac stages are online; 276 more are completed, but not yet online; 654 are planned for wells that have been drilled to total depth, but not yet fracked; and 108 are planned for wells that have been spud, but not yet drilled the total depth or fracked.

Moving on quickly to the Midstream results.

Operating income here was up 16%, consistent with the 21% growth in gathered volumes, mainly from gathering EQT Production's growing sales volumes, and combined with higher rates resulted in a 28% increase in gathering net operating revenues.

Transmission net revenues also increased by almost 10% year-over-year, as a result of added Equitrans capacity and throughput.

On the other hand, as we suggested in previous conference calls, the line item titled Storage, Marketing, and Other Net Income, was down about $17 million in the fourth quarter and about $7 million for the full year.

This part of the Midstream business relies on seasonal volatility and spreads in the forward curve, and those trended down in 2010 versus 2009.

Also, third party marketing margins and volumes for reselling unused pipeline capacity have been under pressure, resulting in a smaller premium for marketing services.

The increase in third party frac spreads during the first three quarters of 2010 partially offset those declines in the full year results for that line item.

Net operating expenses at Midstream were about $22 million higher year-over-year, consistent with the significant organic growth.

Higher O&M and DD&A expenses represented the majority of the increase in expenses, running about $21 million combined higher year-over-year.

Increased electricity, materials, and property taxes accounted for the majority of the increase in O&M.

And then finally, our standard liquidity update.

We closed the year with only approximately $54 million in net short-term debt.

As detailed in the press release earlier this month, our 2011 CapEx estimate is $970 million.

We expect to fund that with estimated operating cash flow of approximately $750 million to $800 million, plus approximately $230 million in proceeds from the recently announced and eminent sale of Kentucky processing assets.

Based on the current cash flow forecast and expected proceeds from the asset sale, we do not anticipate requiring any meaningful incremental capital to fund the announced 2011 CapEx forecast.We did also renew our $1.5 billion credit facility during the fourth quarter, and that facility now expires in 2014.

We remain in an excellent liquidity position for 2011.

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

Thank you, Phil.

2010 was a record year for EQT in that operating cash flow, sales volumes, Midstream throughput and natural gas reserves were all higher than ever before.

At EQT Production, in the fourth quarter we posted our fourth consecutive quarter of over 30% year-on-year growth in sales of produced natural gas, and our first-ever quarter over 40%.

The Marcellus continues to be our fastest growing and most important play, as well as our most profitable one.

Marcellus production accounted for 27% of our sales of produced natural gas in the fourth quarter.

Our success in the Marcellus in 2010 also drove a 28% increase improved reserves and a 70% increase in improved probable and possible, that is 3P reserves.

Marcellus proved reserves increased 270% to nearly 2.9 tcfe.

However, as we said throughout most of 2010, we do not have enough capital available to us to pursue all of our above-hurdle rate investment opportunities.

This has necessitated tougher capital allocation decisions than we have faced in the past, including a 2011 plan that scales back our development in the Huron and CBM plays.

These decisions flowed through to our year-end proved reserves, with a fair number of reclassifications from PUD to probable in those two plays.

While our west Huron development still makes a competitive return at current prices, especially for wells drilled near existing pipes, building significant additional take-away capacity for Huron drilling does not seem prudent in the current pricing environment, even though the returns are above our calculated cost of capital.

This is why we reduced our Huron PUDs, shifting those reserves into the probable category.

The story's a little different in CBM, as drilling economics there are marginal at current prices, so we took the proved undeveloped estimates for CBM to zero.

Before moving on from our reserve report, let me share a couple of statistics that you may find interesting.

As you know, proved reserve bookings are limited to reserves that are anticipated to be developed over the next five years.

Since our actual five-year development will be dependent upon the availability of capital, we have conservatively assumed that drilling capital for the next five years will be essentially flat with 2011, representing a total drilling investment of $2.5 billion.

This is a reduction of 14% from the five-year capital estimate used to prepare our 2009 reserve reports.

Obviously, increased production should lead to higher cash flows over the period, but the 2011 plan is based on using operating cash flows, plus proceeds from sales to fund investments.

It seemed prudent to use a five-year plan funded with no use of the revolver, no more asset sale proceeds, a return to lower spot prices, and also to leave room for capital for other purposes, for instance, Midstream and tactical leasing.

So that the admittedly conservative result would simply be to multiply 2011 development drilling by five.

Also, the EURs per well used in the 2010 proved undeveloped reserve report were calculated on a state-specific basis for the Marcellus.

So in Pennsylvania, it assumes 265 wells, averaging 6.3 Bcf with an average length of 4,067 feet.

In West Virginia, 201 wells, averaging 4.7 Bcf with an average length of 3,700 feet.

The Huron EUR assumption is 1.3 Bcf, for 311 wells.

Increased recovery per foot in the Marcellus play, and longer lateral projections in both plays, drove the increase from the EUR per well booked before 2009, which assumed 2.5 Bcf per Marcellus well and 0.7 Bcf per Huron well.

Extended laterals, of course, have become our standard operating procedure.

Our published decline curve was updated earlier this month to reflect the projected EUR increase from our projected increase in average lateral length.

The economics were also updated to reflect oil-field inflation, mainly for higher completion costs.

Lower Midstream cost estimates for Marcellus Midstream, which by the way are now $0.98 per Mcf, down from the previous estimate of $1.29.

Also, to reflect the frac spread associated with the wet gas production expected from much of our West Virginia acreage.

In West Virginia, drilling has been concentrated in our core area of Doddridge County, where there is existing pipeline infrastructure.

Production volumes have increased by 80% from 20 million cubic feet per day to 36 million cubic feet equivalent per day since the startup of the Saturn compressor station in early December.

EQT currently has a frac inventory of 32 wells, representing 374 stages, which will begin to be turned inline during the first quarter, filling the remaining capacity.

Total capacity in Doddridge is about 61 million cubic feet per day.

Well recoveries in Doddridge County have been averaging 1,150 Mcf per foot, with an average lateral length of 3,270 feet, for an EUR of 3.75 Bcf.

Based on our recent Doddridge results, and preliminary data from wells in Wetzel, Taylor, Lewis, and Upshur counties, EQT expects recoveries from the entire West Virginia play to average 1,300 Mcf per foot.

The average lateral length in West Virginia is expected to be approximately 5,300 feet, for an EUR of 6.9 Bcf.

The IPs in West Virginia are not as high as in Pennsylvania, but more of our West Virginia wells are high in liquids content and the decline curve is a little flatter.

In general, the economics of our West Virginia Marcellus wells are expected, as a result, to be similar to the economics of the average PA Marcellus well.

We announced the results of two prolific Marcellus wells in Pennsylvania this morning.

The Greene County well had a 30-day production rate of 23 million cubic feet equivalent per day, and was completed using the new frac geometry, which we discussed last quarter.

We still consider this frac geometry as experimental, having only completed seven wells so far.

It is looking like the IPs per foot of lateral are higher, but we will need to monitor the decline curves before the new geometry becomes our standard.

The fracking costs per well using this geometry is higher than it is for our current standard geometry, so we need to make sure that the costs are lower on a per-unit volume basis.

That is, we need to determine if we are producing more natural gas or simply accelerating production of the same volume.

We do not have enough data to be confident in the answer yet.

However, as our long-term investors already know, it is part of our culture to embrace this type of experiment, try to run it properly, and then apply the lessons.

Consistent with that, right now we plan to complete about 25% of our 2011 Marcellus wells with the new design.

That number of wells, and time, will tell the tale.

The Clearfield County well, which had a 24-hour flow rate of 8 million cubic feet per day, is shut in due to capacity constraints in that area.

As we alluded to in our press release regarding this well, its primary purpose was to help us engineer and size the build-out of Midstream assets in this area.

This impressive well result is additional evidence of the quality of our overall Marcellus acreage.

While most of our 2011 drilling is intended to produce and sell natural gas, approximately 15% of our Marcellus wells will be outside of our core development areas.

Now, obviously selling the produced gas is our priority, and that is why we signed up for processing capacity to capture the valuable liquids using a MarkWest plant being built in Patterson County, West Virginia, and expected to be online in the second quarter 2012.

Moving on to Midstream.

In 2010, our Midstream group completed the Ingram gathering system and added compression in Greene County, Pennsylvania, adding 105 million cubic feet per day of takeaway capacity.

In West Virginia, we added 65 million cubic feet of takeaway capacity, mostly in Doddridge County.

Finally, upgrades to various segments on the existing Equitrans transmission system, along with modifications to compression at the Pratt station were completed in 2010, providing about 100 million cubic feet per day.

The $15 million project provides capacity to Equitrans' five interstate pipeline connections.

Midstream has done a great job of coordinating its capacity additions in support of development plans.

Once again, we achieve the best cost structure when we can develop in a way that concentrates volumes at a handful of pads in order to allow us to build fewer, larger Midstream systems.

In 2011, Midstream plans to add 130 million cubic feet per day of gathering capacity in Pennsylvania to Production's Marcellus drilling.

To ensure that the Marcellus gas gets the market, Equitrans will be expanded over the next two years to add 550 million cubic feet per day, including a pipeline expansion from the discharge of MarkWest's processing plant.

Moving on to bigger picture topics.

The reserve report is a snapshot of the EQT reality, of which most of you are familiar.

First, the company has extensive profitable investment opportunities.

21 TCF of 3P reserves, and an RP, a reserve to production ratio, of 150 years.

Second, we have demonstrated that we are superior operators in the Marcellus and Huron shales, as evidenced by a 70% increase in 3P reserves since last year, mostly driven by improved well performance and an industry-leading cost structure.

However, and finally, we have insufficient capital to pursue all of our attractive investment opportunities.

Our capital budget is consistent with this, as we established a 2011 capital in line with our expected cash flow from operations, plus proceeds from the sale of our Kentucky processing plant to MarkWest.

We have already received Hartt-Scott-Rodino clearance for the sale and MarkWest had a successful offering to raise the proceeds to purchase the plants.

The sale is expected to close in the first quarter and could close as early as February 1.

The sale would generate $230 million of gross proceeds and result in an $18 million annual reduction in our Midstream cash flow.

While this is a good price for us, the deal also makes sense for MarkWest.

MarkWest has a much more extensive liquids business and greater processing expertise than we do, of course we only operate one processing facility.

Presumably their expertise in the fit this asset has with their other assets means MarkWest will earn more from the plant than we would have.

At EQT, we are willing and able to live within cash flow, and as we continue to work our improved Marcellus results through our model.

We believe we can do this and achieve a five-year production growth sales CAGR, exceeding 20%, significantly higher than our expected growth rate of October of last year.

The growth rate in 2011 will be significantly higher than that, estimated at about 30%.

We continue to look for opportunities to monetize some of our assets so we can redeploy the proceeds into more of our higher return projects.

Our focus continues to be on assets that earns lower returns or are perhaps worth more to others, such as Midstream assets in low growth areas or that are fully contracted, like our Big Sandy pipeline or acreage that would not be drilled in a timely manner.

Obviously the sale of that Kentucky plant fit into that category.

We remain open to the possibility of monetizations that are only attractive because of our reinvestment economics, but will prioritize situations that are attractive on a stand-alone basis, and do not require such reinvestment logic to look appealing.

In summary, EQT is committed to increasing the value of our vast resource by accelerating the monetizations of our reserves.

We continue to be focused on earning the highest possible returns from our investments and doing what we should to increase the value of your shares.

We look forward to continuing to execute on our commitment to our shareholders, and we appreciate your continued support.

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

Thank you, Dave.

This concludes the comments portion of the call.

Jill, we can now open the call for questions.

Thank you.

We will now being the question and answer session.

(Operator Instructions)

And the first question comes from Scott Hanold of RBC Capital Markets.

Please go ahead.

Thanks, good morning.

Good morning.

I know, I think last quarter when you addressed the new frac and completion geometry of some of these wells, you really didn't provide a whole lot of detail for competitive reasons.

Is there something more that you all are willing to say at this point just to kind of give us a sense of why you think these wells could, this completion could actually improve the performance?

I don't think Steve is willing to provide that, but since he's the one who will get in trouble with his staff if he provides too much, I'll let him answer the question.

Scott, I think it's still a little preliminary for us to be talking about the details, so I think we're going to leave it at what we said in the release and in Dave's comments.

And I would reiterate Dave's comments, that it's going to take us several more months to really understand the economics of the new geometry.

Clearly, we're getting higher IPs, very consistently.

We need to understand if we're accelerating reserves or whether we're improving recovery, or if it's a mix of both.

So, I think until we have a better understanding of those factors, we're going to stay pretty quiet.

Okay, fair enough.

Sorry.

That's all right.

When you all gave some of the detail behind the number of wells that you've got in inventory than in the frac stages, the thing that really stands out is that it looks like of the wells you are drilling right now, you're planning close to 20 stages on those wells.

What is the plan on these things?

I guess you talk about, you know, roughly 4,000 lateral length on some of your PUD wells.

Are they going to be close to the 20-stage fracs, or what do you have built into assumptions on those?

I think, you know, a general rule of thumb would be we plan to stage every 300 feet, so it depends on the lateral length of the well.

But -- and we modify that occasionally, but that's a pretty good average.

Okay, okay.

And one of the questions, too, on your (inaudible) reserve report.

I didn't see that you provided this information, but do you all have the pretax SEP PB10 was on that, and if you have that between PUDs and proved results, that would be helpful.

Give me one second.

We're going to provide that information in the 10-K, Scott.

We would prefer to wait for that, if you don't mind.

This is Phil Conti, by the way.

Okay, fair enough.

And one last question on asset monetization potential.

As you look out, I know you evaluated, every opportunity, whether it's a joint venture or asset sales.

Can you give us a sense on what type of progress you've made on any additional actual like EPS at monetizations?

Have you started through the process of talking to people about joint ventures, or where are you at right now?

I'd rather provide a more general comment that we are across the board, I don't want to limit it to just E&P, we are doing what we can to get a better idea of what the value of some of these assets and investment opportunities are in the marketplace, so that we can make a more intelligent decision about the best -- the best trade-offs for us to make.

I would just as soon not anticipate whether we're going to wind up getting firm offers, seeing things that we like or not like, but just that we are working -- we are working away to, to get more, a more concrete assessment that will allow us to decide what the best thing for the company is.

Okay, and then sort of on a related note--

I guess I kind of said nothing.

I apologize.

That's all right, but, no, I understand.

Looking at the utility business.

Given the size of the utility business, what do you perceive as your options if you look to sort of separate the utility from, you know, ECT and become more of a, I guess ENP pure-play, as I guess I would call it?

Is that something that would be something that could happen, or is it just logistically a little bit too difficult?

Eventually, certainly I could imagine something like that happening, but I would say the same thing about a company that looks just like us, but isn't us, you know, that's -- any company -- that old integrated gas group has kind of gone the way of the dodo, or so it seems.

Certainly I can imagine that.

I will tell you where we sit now, it would seem more likely that the eventual route would look more like the Questar approach than the sale approach, but that's because of tax basis issues and stuff like that.

And frankly, for us, there's more complications than even -- from what we could see from the outside, that what Questar had, in terms that the debt is at the parent company level and things like that.

But we continue to look at everything we can to enhance shareholder value.

Honestly, the top priority for us, though, is trying to figure out ways to continue to shift more capital into the high return projects, and it's not clear to me that that separation is way up on the list as far as things that generate additional capital.

Still, anything that's in the best interest of the shareholder is something that we are open to and that we do spend time working through.

So that's not as high a priority as the monetization stuff ,is the only message I want to you take away.

But absolutely we understand the logic, we understand why people ask, and we do take a look at it.

It's just that the sale, you know -- going way back, I think we used to say when we looked at the possibility of a straight sale, it -- the tax complications were problematical for us.

And I think we've also been saying for a while, ever since we heard about the Questar thing, that that's intriguing.

Those two facts continue to be the case.

Okay.

I appreciate it.

Thank you, guys.

Thank you.

The next question comes from Neal Dingmann of Sun Trust.

Please go ahead, sir.

Good morning, guys.

Say, just kind of questions on identified locations.

Obviously kind of looking on your slides, obviously a strong well count in Greene County and then you've obviously had that Rosborough well over in Armstrong.

Just trying to get a general sense, I guess, when you look over the next year or so, number of identified locations you've laid out in Greene versus Armstrong and some of the other Pennsylvania areas.

Neal, this is Steve.

I guess the easiest answer is in Armstrong County, you will see very little drilling in 2011.

We're designing and need to build a gathering system for that area.

So we may drill a couple more wells late in the year as that system's progressing, but we won't be focused in Armstrong County in 2011.

Probably close to half of our wells for 2011 will be in the Greene County area.

It's been one of our best areas and that's where we would like to put the bulk of our money, if we can, drilling to keep our capacity full.

Got it, and kind of on one of Scott's questions, as far as -- I don't know if it's around the geometry or just kind of in Greene County in general, do you think now -- are you still toying with the frac lengths?

Are you -- as far as the length of the laterals, is that something you're still kind of looking at on a well-by-well basis?

Is that part of the new geometry, or are you pretty satisfied with kind of the results that you see at this certain lateral length?

Well, I think our belief is, our strong belief is, that longer is better.

At least up to the, the physical limits of our, of our equipment and our frac equipment, which so far we've gone to 9,000 feet successfully.

We may attempt to push that a little longer, but we're probably getting near the, near the limits of what we'll be able to do.

But that said, longer is better, so we're going to drill the longest laterals we can, given our acreage position.

So a lot of our lease geometries don't allow us to go that long, but we'll go as long as we can.

Okay, great, great color there, Steve.

Maybe last question, just looking -- I know a competitor had come out this morning and Marcellus talked about locking in on some fracs, where the frac group for a couple of years and locking in on rigs.

Just wondering, you know, I guess for Dave or Steve, your thoughts as far as longer term commitments either to rigs and/or fracs, as we look for this year and next year.

That -- basically that's standard operating procedure from our perspective.

Absolutely that's the way to keep them, and it isn't just -- you get the cost benefits if you're willing to lock in longer, but there's some experience benefits, too, if you're keeping the same crews and you control the same crews.

So we, we see those benefits also.

So just on a crew basis, you definitely see on kind of a well-by-well basis, you've seen noticeable differences?

Well, noticeable -- certainly there's -- you can notice quality differences in crews, if that's what you're asking, yes.

Got it, got it.

Great quarter.

Thanks, guys.

Thanks.

The next question is from Philip Jungwirth of BMO Capital Markets.

Please go ahead.

Good morning, guys.

The mix, the Marcellus wells that you plan to drill in '11, it's more heavily weighted towards Pennsylvania than West Virginia compared to what you did in 2010.

Is this just driven more by having greater takeaway capacity in Pennsylvania?

Because you talked about earlier how you're achieving the same economics with the shallower declines in more liquids in West Virginia.

I think it's partially capacity.

Some of the Pennsylvania drilling will be up in the northeast part of the play in Cuyahoga County for us this year, which will be our first venture up there.

And I think with the economics being fairly equivalent, it's based on capacity, it's based on status of permits, status of water permits.

We look at the whole picture and see where we can put the most wells down the cheapest and the quickest.

So not really anything more than that.

Okay, great.

And then I assume it's too early to have an EUR for the Greene County well.

You announced today, just because it was completed using the new frac geometry.

Because the one -- the 9,000-foot lateral you announced last quarter, you had about an 18 Bcf EUR, so I was wondering if you had one for this well, which had a similar IP rate.

You're exactly right.

The reason we didn't provide an EUR, because we used the different frac geometry and we're not yet sure what the decline curve with that geometry will be.

So we expect a portion of what we're seeing is acceleration, and a portion we think is likely to be increased recovery factors, but until we gather more data, which is going to take more wells and more time, we're hesitant to quote EURs for wells completed with that new design.

How many -- I think you said it was seven or eight that you've completed with that new design.

How many are shut in?

I assume the Armstrong County well from last quarter is still shut in.

But how many are you able to produce and get a good feel for what the decline is?

Five of those seven are online.

Two are shut in.

Okay.

Is the Armstrong well still shut in, too?

Yes, that is one of the two.

Okay, and then lastly, I notice you permitted couple of wells up in Clarion County and you have a nice acreage position there.

I was just wondering when you expect to drill your first well there and be able to test it.

Not exactly sure when the rig will move there.

I'm thinking it's second quarter, before, before rigs up there.

But I'm not exactly positive.

All right, great.

Thanks, guys.

And the next question is from Michael Hall of Wells Fargo.

Please go ahead with your question.

Thanks.

First, just kind of tying into the last questions on the frac geometry and the -- of the five wells you've drilled to date, where were those -- that are still on line rather, where are those drilled?

And then do you have any maybe statistics around those, like average 30-day rate per lateral foot or something along those lines?

Give us a feel for the consistency of results.

I don't think we're at this time willing to give out that data.

Okay.

Greene County and Doddridge County and Armstrong County are where they have been drilled.

And I will say we have seen consistently higher initial rates.

That's as much as we're going to say right now.

Okay.

So what sort of recoveries do you think you're getting on your typical geometry in the Marcellus currently?

Recovery factors of gas in play?

Yeah, factors of gas in plays, yes.

We think typically we're at 35 to pushing 40% in some areas.

And so what's the kind of hopeful case, I guess, in terms of increased recoveries?

Are we talking incremental 5%, or is it 10, or is it way too early to even speculate?

Yeah, I don't think we're ready to speculate on that.

That's what we're trying to figure out.

Fair enough.

And then as you look at the backlog, it seems like maybe relative to wells drilling, the wells waiting on frac and pipeline has increased relative to prior quarters.

Is there any, any sort of frac constraints you're running into?

How many fracs per month do you have slotted?

Kind of what's the status there?

No, I don't think that's really the issue.

I think, I think it's actually held fairly flat.

I don't think it's necessary -- our backlog has increased, but a lot of that was just trying to get synched up with available capacity.

Now that capacity is online, we're moving frac crews into those areas and I think you're going to see that backlog start to drop for us, but it wasn't precipitated by any particular issue or difficulties with frac crews.

It was more just trying not to get too far ahead of capacity.

Okay.

So how many slots do you have per month?

How many fracs per month roughly can you--

We have three dedicated frac crews.

Okay.

And you think you get, what, four per month out of each of them, is that--

Three and a half to four.

Okay.

Then lastly, just on the monetization, you alluded to a lot of the detail already, but would you care to characterize or rank maybe, now that you've gotten the, part of the Midstream monetizations behind you, where the upstream relative to remaining potential Midstream JVs or sales.

How those stack up in terms of ranking, you know, what your internal thinking is currently?

Maybe I'll just restate, or reiterate that to the -- we find most attractive the opportunities where even on a stand-alone basis, that is to say if we weren't capital constrained, if the calculated costs of capital were stuff that we really thought we could easily get in the marketplace by, through the Capital Markets, et cetera.

If we ran that type of stand alone economics, and it looks attractive to us, that that type of deal is more attractive.

Practically, we may well wind up in a situation where there's transactions, potential transactions, whereby it doesn't look terribly attractive on that kind of text book basis, but we still find the transaction appealing because of the reinvestment economics.

That is to say we don't really think we can get the capital at the calculated rates right now, and as you know, we're not willing to go to the equity markets any time in the foreseeable future.

And we're not willing to sacrifice our, our investment grade rating in the foreseeable future.

So given those constraints that I guess to some extent we've put on ourselves, that makes some transactions conceivably attractive only because of reinvestments.

I think that's -- realistically, that's when you hear banter amongst companies like ourselves taking different positions on Marcellus ventures.

I think that's what you're hearing going on, is, everybody knows they are very attractive opportunities, but you have to give up an attractive opportunity to get the money.

And you need to weigh how interesting that is.

The Midstream, it's, it's more likely that there are players out there that are very different from us, that are in a midstream business in a way that we aren't, that might have lower costs of capital, et cetera, and therefore can make offers that are interesting to us on the stand-alone basis.

So that's, that's why to some extent we've prioritized some of the Midstream stuff ahead of some of the upstream.

But that's the overall philosophical issue.

If we've got a dollar bill and somebody thinks it's worth $1.10, we're interested in selling.

If they think it's only worth $0.90, but we think, "gee whiz, we can turn the $0.90 into $1.10," that's a different kind of transaction.

So we would prioritize the first type, but we might wind up doing some of the second type as well.

That's helpful.

I appreciate it.

What remains from the Midstream side in terms of potential transactions?

Would you--

I -- look, I don't mean to be trite about this, but we are a commercial enterprise.

Everything is for -- at some price, everything's for sale.

The stuff that is harder to let go of honestly are the things that are most integral to our Production business, where it's really important to be able to control our own midstream.

That's the reason that some of the FERC-regulated pipes, where you really can't have much of a special relationship with your own Production group, conceivably make more sense, just as upstream areas that seem non-core might also similarly make sense if the values were there.

Okay.

That's helpful.

Thanks very much.

Congrats on a solid quarter, guys, a good, solid year.

Thank you.

The next question is from Shin Lu of JPMorgan.

Please go ahead with your question.

Good morning, guys.

Just want to get a sense of what's in your -- you cite some numbers, how you book to reserves in the Marcellus and the Huron.

What is the average EUR for your Marcellus well again?

For the reserve report, we booked 6.3 Bcf for PA and 4.7 for West Virginia.

Okay.

So in your website, the average, the curve you give out is around 7.3.

Is that -- should we think about the average should be 7.3, or more in line with what's built in the proved reserves?

Well, the numbers that Pat was quoting was for specific locations that are incorporated in our PUDs.

And the numbers that we've referred to more broadly are economics that we expect for the play at large.

So if you're looking at economics, we would stick with the things we're talking about that were broader than just in the reserve reports.

Okay.

But if you're trying to understand what's in the PUDs, then it's the numbers that Pat just quoted.

Okay, and another pretty big factor is the average lateral length.

In our reserve report, the averages were significantly less than we expect to get as we develop the play.

So in the reserve report, I think the averages were around 4,000 feet in Pennsylvania and 3,700 feet in West Virginia.

We're expecting going forward to average closer to 5,300 feet.

So you have to normalize for the lateral length.

So if you blended what we show in that PUD, for the PUDs in the reserve report, you would be looking at 466 wells at about 3,900 feet average length, and about 5.6 Bcf EUR.

So that's what's in the PUDs.

Yes, you're right, because of mix issues and longer laterals, et cetera, we wind up with higher numbers in, for the play as a whole.

But it's not -- we don't think that's unusual.

Probably our peers are in the same situation.

The PUDs pertain to specific locations.

Okay.

So you expect the, those PUD wells to be shorter than your average?

Well, yes.

They were the first ones -- yes.

They were earlier in the evolution, if you will.

Because of a limitation on your leases?

I think some of it is -- PUDs are specific locations and frequently, you know, they are next to wells we've already drilled and they are just -- at the current time, we may not have the leases available to drill longer, but those are the locations that are specifically identified as proved.

When we look at our entire acreage position, we have areas where we can drill significantly longer laterals, and that's what goes into that average.

But some of those might be on the docket for 2011.

They just don't happen to be close enough to existing locations that allow us to book them as proved.

Got you, okay.

And in West Virginia, you mentioned that for proved basis, the EUR is higher in other counties than Doddridge.

Is there any particular reason for that?

I think it's just the geology of the Marcellus.

There's a little less gas in place per acre in Doddridge than some of the other areas in West Virginia, and certainly in Pennsylvania.

So it's not a surprise that they are a little bit lower.

The good thing in Doddridge County, with the wet gas, the EPU content's 20% higher than it is in the dry areas.

So once you get that benefit, that all sets the slightly lower per foot recovery.

Since your last reported -- Cooper well.

Have you drilled another extended lateral wells, and are those results comparable to Cooper?

Yes, we have, and the results are similar on an Mcf per foot basis.

Okay.

Thank you.

The next question is from Josh Silverstein of Enerecap Partners.

Please go ahead.

Good morning, guys.

I was just wondering again going back to the monetization, just looking at the other side and saying with the cash outflows, inflows more balanced now with the Kentucky sale.

Where on the priority list would a potential acquisition be or maybe looking at acquiring some acreage outside of the Appalachian foothold, if that would be on the priority list, or if it's a no, not something you guys were looking at right now.

I guess -- that would have to be an awful long -- on the non-Appalachian piece-- it would have to be an awful long piece of paper for that to show up on the list at all.

I don't think we spend a minute looking at stuff that's outside.

The only reason we ever look at stuff outside the Appalachian Basin, frankly, is it helps us understand what people are doing in other shales and maybe ideas that we can apply in our home base.

So that's not interesting.

On acreage, I would really differentiate between big strategic pieces, which it's -- where there would be a really high hurdle, and some of the tactical ones.

I mean, as much as we would rather not spend our limited capital on acreage, one of the things we didn't talk about even with some of those PUDs, in some of those cases, we might drill a different well if we could fill in some spaces with acreage.

It could wind up the overall economics, even of the locations we've identified, improve dramatically, if we could get -- if we could kind of fill in the so-called doughnut holes.

That's the way I refer -- I don't think there's any circumstance where it really is a doughnut hole, but that's the way I tend to think about it.

It's kind of a jigsaw puzzle.

If there are pieces we could fit in, then, you know, we're actively looking at whether there's mini-ventures or swaps or acreage leasing activities that would allow us to improve the overall economics.

Got you.

So it sounds like most of the capital that would come out would probably go back into the ground via just drilling what you have already.

Yes, or doing things that would improve the economics of that.

Right, right.

There's no doubt that one of the -- we would love to be able to expand our footprint in the Marcellus.

We would love to be able to take advantage of more of the Midstream opportunities.

We just don't have the capital to do it.

Got it, okay.

And then just on the LOE transfer for 2011, I was kind of curious on a per unit basis how you think that might trend, given the significant growth that you guys are still forecasting for this year.

I think the full year LOE, I think it was $0.24 was the average for the year, is a good number to go forward with in 2011, per unit.

Got you.

And that's -- so that's partially due to the growth and partially just due to the inflation as well?

Correct.

Okay, and then just curious, given the change in the governor and the state congress, if there's any updates that you guys have seen over the past couple of months.

No.

We -- what we've heard, and it's just out in the public is that the governor, Governor Corbett, is looking to put together, as he said he would in his campaign, a team of folks to take a look at the best way for the state to develop the Marcellus in a way that helps the state overall.

And it's in that context that we could imagine that there could be a severance tax, if that's what you're, if that's one of the things you're asking about.

Right.

But the overall driver for him would be how do we make sure this turns into a real economic boom for the state.

Well, obviously while protecting the environment, while protecting water supplies, et cetera.

How do we turn this opportunity into reality is what he's focused on, and obviously we and the rest of the industry are happy to work with him and with other interested parties to see if we can't come to some, some consensus on that.

Thanks.

The next question is from Brian Kuzma of Weiss Multi-Strategy.

Please go ahead.

Good morning, guys.

Good morning.

I had a question.

You talked about your PUD bookings.

Are you -- do you book your PUDs at a discount to your proved developed locations, or how does that typically work?

I'm not sure I understand the question.

I'm just wondering, like when you book a PUD, is it booked at the same EUR as the offset developed location?

Well, it is, it is booked per the SEC rules, which means we book the reserves that we have reasonable certainty we will recover from that location.

I would say generally speaking, they would be booked at similar Mcf per foot levels as their offsets.

I see what you're saying.

But you're assuming longer laterals with the PUDs than on the developed locations.

Well, what we're assuming with the PUDs is the length of lateral we actually could drill right now, at that location.

At that location.

At that location, very specific -- our PUDs are very specific locations, you know, very -- based very much on the specifics of where they are located.

So for instance, if there's a parcel of land and we think, you know what, we can only drill a 3,000-foot lateral here, we don't want to drill this, though, until we think there's another parcel of land that we could acquire in some way or another that could double that.

We might choose not to drill it, but we're booking a 3,000-foot lateral for that PUD.

I see, okay.

That might never be our actual plan, because we want to have a more economic well, but we put in exactly what we could actually accomplish now.

Okay.

And then help me understand, remind me again, what was the drilling, total drilling CapEx that you guys spent in 2010?

Pat, that's you.

Okay.

We have that in the release.

$888 million.

Okay.

I missed that.

Sorry.

Because I guess what I want to understand is how the 2010 program differs from the forward plan on an F&D basis, because I guess when I go through, you spent $880 million.

I've got you guys adding, let's see, your proved developed reserves went up by about 500 Bs and you produced 100 Bs, so you added about 600 Bs of developed reserves.

Seems to me like the F&D costs would be 880 divided by 600, which is like $1.50.

But I think--

I think that's a development count, not a total reserves.

You're also adding PUDs.

Yes, I know.

But what I'm trying to get at is how does that differ from the forward case?

Like how -- are things going to be -- if you have sub $1.00 development scenario going forward, how do you get there from $1.50 this year?

Is there a -- is there that big of an improvement to be made?

Well, I think some of the areas that you will see drive improvements are a higher portion of our drilling being in the Marcellus, which has the lowest development costs, drilling longer laterals, which has lower development costs than what we've historically done.

And I think some of the, some of the new techniques that we're experimenting with also have the potential to improve our development costs going forward.

So you've got the mix issue, and the other one is really what I think you're seeing from a lot of folks, at least in the Marcellus, it's the learning curve, that what you're looking at when you look at the past is what's already happened and the other things are a snapshot of where we are now.

So every time you look back, you're looking at activities that took place when we were further down the learning curve.

And obviously that could still take, you know -- there's still an inventory in 2011.

If we permitted a well at, I don't know, at 4,000 feet and we think we could go 6,000, we do have to make a judgment.

Do we want to go through the process of repermitting or just drill it?

So you do wind up with some lag in applying all of the best practices.

But if you look forward over a longer period of time, then you obviously assume that whatever we've determined will be, is best practice, will get applied to those wells.

I see.

And yes, we do see, we see ourselves, and the peers that we respect the most, at least in the industry, and I don't want to get into a list of those, but they are also, we think, seeing similar things, which is, there was a relatively steep learning curve.

We've -- we are finding our way up that learning curve, and that's showing up in the results, but it will obviously play out more fully in the future.

I got you.

So--

We're not assuming further improvement -- we're not assuming that we will have further improvements.

We're just assuming that we will apply the lessons that we've already learned.

I got you, but the cost per will the lateral foot has come down throughout the year significantly.

Yes, it's because of that, and longer laterals do contribute to that.

I got you.

And then just so I understand, on the reserve report, you guys said that you guys charged your E&P operations $0.98, and that's what flows through the reserve economics then?

Yes.

You're talking about the Midstream?

Yes, the Midstream.

Yes, that $0.98 is what would flow through the reserve economics, yes.

Got you, okay.

Thanks, guys.

Great, thank you.

Thank you.

This concludes the question and answer session.

I would like to turn the conference back over to Mr.

Pat Kane for any closing remarks.

That concludes today's call.

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Thank you for your time.

That concludes the EQT Corporation's year end 2010 earnings conference call.

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