EQT Corp (EQT) 2013 Q4 法說會逐字稿

Good morning, and welcome to the EQT Corporation year-end 2013 earnings conference call.

(Operator Instructions)

Please note, this event is being recorded.

I would now like to turn the conference over to Patrick Kane.

Please go ahead.

Thanks, Amy.

Good morning, everyone, and thank you for participating in EQT Corporation's year-end 2013 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 and Commercial; and Steve Schlotterbeck, Executive Vice President and President of Exploration and Production.

This call will be replayed for a seven-day period beginning at approximately 1:30 PM Eastern time today.

The telephone number for the replay is 412-317-0088.

There's a confirmation code needed; the code is 10025554.

The call will also be replayed for seven days on our website.

To remind you, the results of EQT Midstream Partners, ticker EQM, are consolidated in EQT's results.

There's a separate press release issued by EQM this morning, and there's a separate conference call at 11:30 AM today, which creates a hard stop for this call at 11:25 AM.

If you are interested in the EQM call, the dial-in number is 412-317-6789.

In just a moment, Phil will summarize EQT's operational and financial results for the Year-End 2013, which were released this morning.

Next, Steve will summarize the reserve report.

And finally, Dave will provide an update on the strategic and operational matters.

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

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

You can find factors that could cause the Company's actual results to differ materially from these forward-looking statements.

Listed in today's press release under risk factors and EQT's Form 10-K for year ended December 31, 2012, which was filed with the SEC, and have been updated in subsequent Form 10-Qs, which are also on file with the SEC.

There will also be additional information in the year ended December 31, 2013, Form 10-K, which will be released next week.

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

Please refer to this morning's press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measure.

With that, I'd 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 2013 adjusted earnings of $2.32 per diluted share, compared to $1.41 per diluted share in 2012.

The high-level story for the year, as well as for the fourth quarter, was very strong volume growth and lower unit cash cost in both the production and the midstream businesses.

Notably, production volume was 43% higher than last year, natural gas liquids volume was 47% higher, and midstream gathering volume was up by about 39%.

As a result, EQT earnings and EPS for 2013 were both up considerably over 2012 by any measure, although both years were impacted by some unusual items that should be considered when interpreting and comparing results year over year.

I will touch on a couple of these in my comments, and I do refer you to our non-GAAP reconciliations in today's release.

Adjusted operating cash flow of $1.25 billion in 2013 was also up considerably.

It was actually 43% higher than last year.

And as a reminder, a full year of EQT Midstream Partner's, or EQM, results in 2013, and two quarters of EQM results in 2012 are consolidated into EQT's results, even though a portion of EQM was owned by the non-controlling interest during those periods.

EQT did receive a total of $33.4 million in distributions from EQM during 2013.

In the fourth quarter, as you know by now, we completed the sale of Equitable Gas and received $740 million in cash, plus some Marcellus midstream assets as consideration.

And also we entered into some commercial arrangements with the purchaser as part of the sale.

The sale somewhat complicates the comparison of EPS and cash flow to last year, as we estimate that we would have earned about $9 million pretax from that business over the second half of December had we still owned it.

This would have increased our EPS and cash flow per share by about $0.04 for the quarter and the year.

As required by GAAP, we carved out the gain on the sale, the transaction costs associated with the sale, and the distribution business earnings for 2013, and included those items in the discontinued operations line on the income statement.

The after-tax gain on the sale totaled $43.8 million, and pretax transaction costs were about $8 million for the year and $4.8 million for the fourth quarter.

Also in the fourth quarter, Midstream sold its commercial marketing and trading business for a pretax gain of $19.6 million.

This gain is in Midstream's results from continuing operations, but excluded from our adjusted EPS and adjusted cash flow numbers in the table in today's release.

Another adjustment that we made to our reported results was the add-back of a non-cash expense for hedge and effectiveness, totaling $21.3 million for the year, and $16.8 million in the fourth quarter.

Again, these items are detailed in the release.

Fourth quarter 2013 adjusted earnings were $0.47 per diluted share.

That compares to adjusted EPS of $0.43 in the fourth quarter 2012.

A significantly higher production in Midstream volumes once again drove the results.

Adjusted operating cash flow at EQT was $336 million in the fourth quarter of 2013, compared to $299 million for the fourth quarter of 2012.

Our operational performance continued to be outstanding in the fourth quarter, with 32% higher production volumes than the fourth quarter of 2012, and 6% higher sequentially than the third quarter of 2013.

We also realized 24% higher gathering volume than last year and continued low per unit operating costs.

And finally, the fourth quarter effective tax rate was 48.2%, well above the 33.6% effective tax rate for the entire year.

This higher tax rate in the fourth quarter primarily relates to the continued shift in the Company's business to states with higher tax rates, most notably Pennsylvania, and was partially offset by state tax benefits associated with the distribution business sale transaction.

This higher tax rate reduced EPS for the fourth quarter by $0.15 per share versus what we would have reported using the annual rate.

Now moving on to a brief discussion of results by business segment; and I will limit my discussion to the full-year results, as the explanation for the full year basically applies to the fourth quarter, as well.

Starting with EQT production, and as has been the case for four years now, the big story in 2013 at EQT production was growth in sales of produced natural gas.

As I mentioned, the growth rate was 43% for the year, driven by sales from our Marcellus wells, which contributed 73% of the volumes in 2013, up from 58% in 2012.

The EQT average wellhead sales price was $4.13 per Mcf equivalent in 2013, $0.04 lower than last year.

For segment reporting purposes, of that $4.13 per unit of revenue realized by EQT Corporation, $3.08 per Mcf was allocated to EQT production, with the remaining $1.05 per Mcf equivalent to EQT midstream.

The majority of this $1.05 is for gathering, which averaged $0.82 per Mcf equivalent for the year, down from an average of $1.00 per Mcf equivalent in 2012.

You recall, the Marcellus gathering rate is significantly lower than the rates in our other place.

So as Marcellus volumes grow as a percentage of the total, the average gathering rate goes down.

For the full year, total operating expenses at EQT production were $797 million, or 32% higher year over year.

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

DD&A expense represented about $169 million, or 88% of that increase.

And it is obviously driven by the higher volume.

Absolute LOE, exploration expense, and SG&A expense were all a bit higher year over year; however, volume increases have been outpacing the general trend of higher absolute expenses.

And as you would expect, per unit expenses were lower again in 2013.

Moving on to the midstream business, excluding the gains on the asset sale that I mentioned earlier, operating income here was up 30%, consistent with the 39% growth in gathered volumes.

This resulted in a 16% increase in gathering net operating revenues.

Transmission net revenues also increased by almost 54% year over year as a result of added Equitrans capacity, mainly from the Sunrise expansion project, as well as increased throughput.

On the other hand, the line item total storage marketing and other net operating income was down about $9 million for the year.

This part of the midstream business relies on seasonal volatility and spreads in the forward curve, and has continued to trend down in 2013.

Net operating expenses at midstream were about 11% higher year over year, consistent with the growth of the midstream business.

Similar production revenues grew at a much faster rate than expenses, resulting in continued reductions in per unit expenses.

And then finally, our standard liquidity update.

We closed the year in a great liquidity position, with zero net short term debt outstanding under our $1.5 billion revolver, and $846 million of cash on the balance sheet.

And since year-end, EQT received from EQM an additional $110 million in cash for the deferred piece of the Sunrise transaction that was always anticipated following the sale of Equitable Gas.

Based on current commodity prices, and assuming a 2014 average negative basis to NYMEX of $0.37 per Mcf, we continue to forecast approximately $1.6 billion in operating cash flow for 2014.

So we expect to fund our $2.4 billion 2014 CapEx forecast with that expected cash flow and current cash on hand.

With that, I will turn the call over to Steve Schlotterbeck to discuss today's reserve release.

Thank you, Phil.

This morning we announced year-end 2013 total proved reserves of a 8.3 Tcfe, which is 2.3 Tcfe, or 39%, higher than the previous year, and represents a reserve replacement ratio of 738%.

I'll now go into more detail around this reserve increase.

Extensions and discoveries totaled 2.0 Tcfe, which was comprised of 894 Bcfe reclassified to proved from probable and possible; 583 Bcfe from new locations, primarily from closer lateral spacing; and 524 Bcfe from newly economic locations as a result of higher gas pricing, improved tight curves, and reduced drilling costs.

Drilling capital totaled $1.3 billion, resulting in a drillbit finding cost of $0.62 per Mcfe.

Our acquisition of properties from Chesapeake in June 2013 resulted in additions to proved reserves of 473 Bcfe, of which 42 Bcfe are proved developed and 431 Bcfe are proved undeveloped.

This year, we have gone to reporting natural gas liquids as a separate reserve category due to our increasing recovery of NGLs.

The inclusion of NGLs added a net 536 Bcfe to our proved reserves, which was comprised of 763 Bcfe of liquids, less 227 Bcfe due to processing shrinkage.

NGLs now represent 9% of our proved reserves.

The Company's Marcellus proved reserves increased by 1.7 Tcfe, or 39%.

This increase is driven by improved recovery per well, as illustrated by our 17% increase in Mcfe per foot, additions and extensions related to the 2013 program, and the aforementioned Chesapeake acreage acquisition.

Offsetting those additions was the removal of 58 Marcellus locations, totaling 368 Bcfe of proved undeveloped reserves due to changes in our five-year development plan.

We've also included 215 Bcfe of proved reserves in the Upper Devonian formation, which is comprised of 109 Bcfe of proved developed reserves and 106 Bcfe of proved undeveloped reserves.

We added 350 Bcfe of proved reserves in our Huron play, reflecting one year of drilling, NGLs, and the effective higher gas prices.

We have significantly more Huron reserves that meet the standards required to book proved reserves, but they were not booked as a result of not having an established development plan for the Huron beyond 2014.

Our 3P reserves of the total approved probable and possible reserves increased 10.5 Tcfe to 36.4 Tcfe, a 40% increase over the prior year.

This increase was comprised of 3.5 Tcfe in the Marcellus, 4.1 Tcfe in the Huron, 2.4 Tcfe in the Upper Devonian, and 0.5 Tcf in other formations.

And finally, we are adjusting our guidance for our DD&A rate for 2014 to reflect the finalized reserve report.

We now estimate our per unit DD&A to be $1.25 per Mcfe, or $0.25 lower than 2013.

Also, as you will see in our 10-K that we expect to file next week, our PV-10 was $3.95 billion, 84% higher than last year, reflecting both the increase in proved reserves and higher commodity prices.

I'll now turn the call over to Dave Porges for his comments.

Thank you, Steve.

Given that the results for the fourth quarter have already been covered, I will use my time to walk through our thought process around our 2014 capital expenditure plans.

First, our largest investment is in continued development of our Marcellus acreage.

This investment is our highest return opportunity and is driving our growth.

We are drilling 90% of our Marcellus for development purposes on multi-well pads, about evenly split between our West Virginia liquids-rich acreage and our Southwestern Pennsylvania acreage.

We are drilling 10% of our wells in Central Pennsylvania to delineate this acreage in anticipation of future development.

This will assist in determining the most efficient completion techniques, spacing, and appropriate sizing for the gathering systems.

We also plan to drill 30 Upper Devonian wells, again in development mode, in our core Marcellus footprint, where Upper Devonian is a separate target that is shallower than the Marcellus.

These wells are drilled on Marcellus pads using the same rigs and completion equipment that is onsite, thereby increasing the productivity and profitability of our acreage.

We also announced a limited restart of our Huron program.

This decision has two benefits.

First, the economics at the current strip provide an adequate return, as we are using existing gathering capacity.

And second, by arresting the decline of the Huron volumes, the gathering system becomes a more viable candidate to be dropped into our MLP, EQT Midstream Partners, or EQM.

In our Ohio Utica play, we announced a 21-well program for 2014.

The intent of this program is to see if we can crack the code in the condensate light oil window.

While our first three wells were, frankly, mediocre, we are encouraged enough by initial results to try very specific changes to our drilling and completion design, intended to improve the economics materially.

If we are successful, there is significant acreage available nearby at relatively inexpensive prices, largely because of the skepticism about this part of the play.

As you know, we pride ourselves on being innovative; but we need to be confident that successful innovation creates a sufficient reward.

And the ability to expand our Utica opportunity set economically provides that.

By year end, we hope to either demonstrate sufficient improvement, in which case it would make sense to add acreage, or conclude that we cannot achieve the needed improvements at this time and discontinue drilling.

On the midstream side, we are investing $475 million.

The largest pieces of this are $345 million in gathering systems to add capacity for EQT drilling in Pennsylvania and West Virginia, and $90 million in upgrades to the FERC-regulated transmission line that was acquired as part of the consideration for the distribution company sale.

EQM is investing another $50 million in organic growth projects.

As the cash flow grows at the MLP, it will be able to invest more capital intended to create organic growth.

Another project that our midstream group is working on is the Ohio Valley connector.

While this project does not impact the 2014 capital budget, we mention it because in January, EQM initiated a FERC open season to assess interest in the project.

So you may read about this proposed project in the industry press.

This project extends the transmission system from West Virginia to Clarington, Ohio, thereby connecting Equitrans to Texas Eastern and Rex.

In summary, EQT is committed to increasing the value of our vast resource by accelerating the monetization of our reserves and other opportunities.

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

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

With that, I will the call back over to Pat Kane.

Thank you, Dave.

That concludes the comments portion of the call.

Amy, can we please now open the call for questions?

(Operator Instructions)

Neal Dingmann, SunTrust.

Steve, a question for Steve or David.

Dave, you were talking a little bit there about the Utica.

My question is maybe on the Utica, some of your peers have mentioned around that southwestern PA area, certainly where you have some acreage, they have talked about Utica potential in that area.

Just wondering your or Steve's thoughts about that, and if you would consider testing for any of that at this point?

Neal, this is Steve.

We certainly have studied that pretty extensively.

And our current view is, we think the dry gas Utica in southwestern Pennsylvania certainly has potential from a resource perspective.

Our studies show that there could be significant amounts of gas in place.

Our concerns are the depth of the formation, and therefore the economics of it, where our existing acreage position is.

So that said, I think our view is it would be difficult for a Utica well under our existing acreage right now to be competitive economically with the Marcellus.

Even if it was likely to produce significant amounts of gas, the costs, because of the depths and the higher pressures, and the higher pressure fracking equipment.

And everything else involved with operating at those depths and pressures, we're not sure it would be competitive.

That said, I think we would think about whether a test, but more of a science test, would make sense.

We haven't committed to do that yet or not to do that, but if we think it is warranted and we think we will learn enough from a test, we might choose to do that.

One follow-up, Steve.

Obviously, the amount of Huron that you are getting booked, a couple questions on maybe first -- I'm sorry, skipping around a little bit -- first, look at the Devonian potential.

On those, would you think about drilling those wells the same way that you've been drilling the Marcellus, or does it make sense to have a shorter lateral or anything around?

I'm just trying to get a sense of type curves between the two.

I think the drilling completion techniques, for the most part, we think, are similar.

We custom design our frac jobs for really every well, based on the geology we are in.

So we wouldn't necessarily have an Upper Devonian well fracked exactly the same as a Marcellus well below it.

But I think in terms of lateral length, our view would be they're almost certainly going to be the same length.

I think our view right now is that we will likely get the best stimulation of the Upper Devonian by fracking it at the same time as the Marcellus.

Or within the same proximity of time, rather than waiting several years, say, down the road.

As we progress with Upper Devonian development, it will most likely be a combined development program with the Marcellus and Upper Devonian.

Lastly, on the Huron, how much capital, or have you said yet, will you commit to that this year, as a percentage of total?

We will grab that number for you.

Neal, this is Pat.

We are budgeting $180 million to drill 120 drilling wells in 2014.

Okay.

Very good.

Thank you all.

Drew Venker, Morgan Stanley.

Are there any new Utica wells in Ohio that you could speak about?

Any new well results?

No, we do not have any new well results.

And it will be likely mid-year before we start getting results from our revised completion program.

Mid-year, at the earliest, and I'm not sure we'll be talking about a mid-year, so I do not want to get your expectations up.

But it will be a while before we even start to get results ourselves.

Okay.

How do the lateral links compare for your 2014 program versus the first three you talked about?

For the Utica?

Right, that's right.

The lateral length, I think the average for the next five wells is --

6500 feet is the average that we are projecting for the year.

Pat, what were the first three wells?

I do not know exactly.

I think it is consistent.

They were just north of 6000.

Okay.

So is the thinking of not releasing results that you potentially have better results, and then you can lease up acreage?

Is that the thinking?

I think, yes.

That is a big part of it.

We tend to like to make sure we understand the results before we start talking about them, so sometimes that takes a little bit of time.

The biggest driver would be, if successful, if we unlocked the code in that oily part of the Utica, we want to take advantage of that knowledge before we let everybody else know.

Okay.

I'm sorry if I missed this, and you mentioned it before, you guys have plans to test Utica potential in West Virginia?

Is there anything on the docket for this year?

No, not in the near term.

Eventually, what we are probably going to do with the Utica that fits underneath our existing Marcellus is down the road at some point, and probably measured in years.

We will take advantage of the fact that we already have some infrastructure set up and that will improve the economics.

But that does not make any sense when we are in the midst of the development of the Marcellus and the Upper Devonian.

But no near-term plans for development.

Scott Hanold, RBC Capital Markets.

A couple questions, just to clarify, so production guidance for 2014, that assumes basically your new six-to-one methodology on ethane, is that correct?

Yes, that is right.

That is six-to-one on the liquids.

When we look at where you are coming into first quarter and where growth could be, it seems like you all are tracking -- it seems like you are tracking well into the high end, if not a little bit higher.

Can you generally talk about, at a high level progression, more so if there are any constraints for us to think about, or timing that we need to think about in terms of quarterly progression of production?

At this point, it's -- of course there is always, in a play that is growing this rapidly, or an area that is growing this rapidly, there's always going to be midstream constraints.

There always have been, and there will be until the growth rates at some point wind up slowing down.

But that said, what we're really affected by more, typically, is just the timing of turning in-line these big multi-well pads.

And at this point, I think it looks like 2014 is more likely to be a year in which some of that is a bit more back-end loaded than it was, say, in 2013.

You may recall that in 2012 it was also kind of back-end loaded, and then in 2013, it was a little bit more front-end loaded, just the way the timing happened to work out.

In 2014 -- there is one thing turned in-line, essentially every month, but as far as the proportions, it tends to be weighted often more in one direction or another.

And I'd say 2014, it would be best for you to assume that it's going to be a bit more in the back-end side, which in a sense will set us up well for 2015 also.

But that's certainly influenced our view for total volumes in 2014.

Okay.

Just looking, obviously, at with the numbers you're spud and wells not completed and completed not online It is obviously -- it looks like a pretty good peak right now, and obviously, you guys remain pretty active.

Is there any midstream projects that are really key for you guys here in the next 12 months to 18 months, just to reference?

I think -- Scott, this is Randy.

We are always staying out in front of production, and we are pretty confident in our operations and plan.

I would say our Sunrise expansion that we have coming on in the third quarter, the compression expansion, which is on track and on time, is a major initiative for us.

Okay.

That's helpful.

On the sale of the utility, can you give us what the net of any kind of cash tax would have been on that, and what is your cash position right now?

I actually provided the cash position in my comments.

We had $846 million on the balance sheet at year-end.

We did receive another $110 million that was a deferred piece of the Sunrise transaction that we'd talked about back in the middle of the year.

In the release this morning, we did show that cash taxes associated with the utility sell around $68 million.

So we've received $740 million and paid taxes of about $68 million on that.

Right, right.

So the $110 million occurred after the year, but --

It is not in the one $846.

It would be additive to that.

Of course, we're -- Steve's spending some money, and Randy is, too, so we're -- (multiple speakers)

But if you wanted to add, you can't just add the operating cash flow to the $846 million.

You have to add in that $110 million that we received actually from EQM as part of that, I guess you'd call, mini-drop.

Okay, understood And one last question, the general partner, obviously, you guys are stepping back and evaluating value within EQT overall.

And can you give us your current thoughts on the general partner and different directions that could go?

Let me take a shot at that.

Hopefully, hopefully it is obvious we've been pretty focused on realizing the full value of the EQT Midstream interest that EQT owns, and the EQT stock price.

We've really been doing that, I think, for the last several years.

It started with our decision a few years ago to sell some non-core Midstream assets to folks who value them, frankly, more highly than we did.

Those were Baxley buyers.

Those buyers were MLPs, and we noted that.

We continued with forming our own MLP, so we did that 1.5 years ago.

We did a big drop earlier this year.

We're still in the early stages of those drop-downs, which we believe allow EQT to achieve a premium valuation for our Midstream assets.

But at the same time maintaining control and benefiting from the accretion and value to the EQM LP units and GP interests that EQT continues to own.

That GP interest is probably the least visible and most often overlooked Midstream interest owned by the Company, but it, too, as you know, is extremely valuable.

The GP cash flows to EQT are pretty small currently.

They were about $2 million of GP distributions in 2013, but we expect that to grow rapidly and reach $40 million or more by 2015, and over $70 million in 2016.

While some of the parts analysis can be tricky, one can certainly make the argument, and some of you on the call already have made it, that the full value of EQT Midstream interests, including the LP and GP interest, is not transparent in the current EQT stock price, and frankly, we tend to agree at this point.

If we do conclude that a clear value disconnect exists, there are a variety of alternatives available to us to address that.

You know what they are.

Some of our energy peers have already taken similar steps, so Scott, I'm not going to address them or list them today.

I think it is a little premature to discuss what they are.

There are a variety of factors that could cause us to go down one path versus another.

I guess, to summarize, I would say at this point we expect to have a pretty good idea of what we want to do, if anything, by the end of this year.

And frankly, it is not clear that it will be wise to take any significant action before then, anyway.

Said differently, just as we want to make sure that EQT shareholders benefit from transparency and the valuation of our Midstream interests.

We don't want to deprive them of that value by transferring a significant portion of it to another party by acting too soon.

I hope that helps.

For now, that is really about as much is we want to say about that right now.

Suffice it to say, that it's an issue that we are studying closely.

Okay.

So it sounds like we'll hear more about that toward the end of the year.

Okay, fair enough.

I appreciate it.

Thank you.

Michael Hall, Heikkinen Energy Advisors.

I've got plenty to ask about.

While we're on the topic of the value -- transparency of the value of the portfolio, what is the latest thinking on drop-downs this year?

I know you are a little hesitant to talk about timing of it, but just curious, is it one large drop-down, multiple drop-downs?

How big of a role is moving or escalating -- potential escalation of interest rates play into that thinking, and just any update around that plan that you would be willing to share?

I don't know if we want to talk about one versus two for particular assets, but I will maybe reiterate that we are still thinking, unlike we were talking about at the time of the IPO.

But this thinking has evolved to the point where we are still thinking that the right answer is to have a more accelerated rather than a less accelerated drop schedule.

And I agree with the premise of your question, that the prospect of higher interest rates was one of the reasons for doing that.

But from my perspective, at least, a more fundamental reason for it is, that is a lower cost of capital vehicle than the corporation.

I think a lot of that is because of the transparency issue.

The folks who invest in that vehicle, which is to say to EQM, are looking for exactly that type of asset.

Since it fits their pistol, so to speak, they are willing to offer more favorable valuations in the marketplace for that.

And therefore, that is the best home for those assets.

So that is the mindset that we have got as we look at drops.

As opposed to, if you will, what we talked about at the time of the EQM IPO, which was sizing it to EQT's Midstream capital requirements.

What is the rate at which EQM can digest these is really more the issue.

Okay.

What would be the constraints around the rate at which EQM could digest them?

Part of it, of course, is they're going to fund this with a combination of equity and debt, so the capital market's availability is one of the issues for them.

Another one is that they are best off with projects, typically, having most of their projects be projects whereby they are already generating cash flow.

So the projects where there is still a lot of construction going on tend not to be as good a fit for an entity that is paying out the vast majority of its cash flow in the form of distributions.

And it is hard to keep up growth if you do that, and of course, we are focused on continuing to grow that distribution.

So typically, they want to have these projects be ones that have already been fully contracted, turned in line, et cetera.

That said, as EQM grows, it is able to wear, if you will, a higher dollar amount in projects that are under construction, and we do think you should expect to see that as we go forward.

But of course, accelerating drops means that we more quickly get to the point where EQM can absorb bigger and bigger projects on its own.

And quite possibly, have some of these projects -- especially ones that are designed to support other producers -- occur at the EQM level and never having gone through EQT.

Does that help?

Yes, it does.

Last on that, and I'll -- just would be curious, you outline, you have got quite a cash position already, clearly some outspend in the 2014 budget that that would fund.

But then you have got likely some drops coming this year, as well.

Does that capital -- are there future capital allocations that could come throughout the rest of the year regarding the 2014 upstream program?

Or are we pretty well set, and that whatever capital comes in this year really just funds 2015?

Just trying to think that through.

Were not setting capital programs based on cash availability.

That is not something we want to get into.

Obviously, we look at investment opportunities, but frankly, with this kind of cash position, you look at stock repurchases, also.

Okay.

That was -- a follow-on, then, is that something that -- higher up on the list than it has been with analysts, six months?

Just because we certainly would not consider ourselves to be capital constraint right now.

That would not be a good mindset for us to have.

We can fund the attractive projects.

So from that -- and probably -- certainly, before EQM was formed, we probably would have viewed ourselves as capital constrained from the perspective of cash availability compared to the volume, the dollar volume of attractive investment opportunities.

That has changed over the course of the last 1.5 years or so, and obviously the sale of the distribution company furthers that.

So, yes.

From that perspective, it is higher up.

If you're referring to how attractive share repurchases would look, yes.

That is higher up than it would have been

That's helpful.

The last one on my end would be, any updates, or maybe remind me on your marketing arrangements that protect around basis risk as we head into the summer?

And any steps that are be taken to further protect around those risks on a go-forward basis?

Michael, in terms of our capacity portfolio, and really I guess I would comment that the colder-than-normal winter has certainly been helpful in terms of increased demand and record storage withdrawals over this period of time.

We have seen better realized pricing in the Appalachian basin.

We are more optimistic than we maybe -- when heading into the winter season, and we have seen some support in the summer basis as market looks to balance for power generation, as well as refill of storage.

But in terms of capacity, we have stressed in the past, and we continue to look at and make commitments on long-haul pipelines to get gas to a variety of markets.

Our goal is always to stay ahead of our production growth and not relying on just one spot market.

We have recently entered into several agreements that have added to that portfolio, and I can give you a few of those.

Our most significant addition became effective on February of this year, February 1. That is when we added 245,000 decatherms a day of capacity for approximately seven years on Texas Eastern system to the M3 market and to Transco's own five markets.

Both of these appear stronger relative to other basins.

So in total, we currently have almost 950,000 decatherms a day of firm pipeline capacity out of the basin.

Plus, we have approximately 350,000 decatherms per day of firm sales, for a total of 1.3 million decs per day.

In addition to that, by the end of 2014, based on existing commitments, we will have about 1.6 million decatherms per day between firm pipeline capacity and firm sales.

So with that, we feel comfortable with our position in 2014 and heading into 2015.

And again, moving forward, we will continue to add our firm capacity portfolio and add to the diversity of our markets, including the Midwest and the Southeast markets.

And we remain, incidentally, very happy to utilize the expertise in the assets we have in the midstream area to redirect gas flows, as appropriate, to meet market needs.

Yes, always been very good at that.

Appreciate that, guys.

Thanks for the color.

Phillip Jungwirth, BMO.

A couple quick questions on the reserve report.

The 7.2 Bs, or 1.7 per thousand lateral foot, the URs for the Marcellus, does that include -- is that only PUDs, or does that also include the PDPs?

And then, what would be the difference to the two Bs per thousand foot of your type curve in Southwest PA, Northwest Virginia?

Phil, could you repeat that?

I couldn't hear the first part of your question.

I was just asking if the proved reserve EUR booking that you had highlighted in the press release includes the older PDPs or is that just PUDs?

That is all proved reserve, so including PDPs.

Do you know what the PUDs were booked at?

And then also, the future development costs assumed in the PV-10 calculation?

I don't think we have that handy.

Maybe I could follow up with you after the call.

SW do not have that data in front of us.

In the Huron, can you talk about your expectations for 2014 volumes, given the renewed activity there?

And then, under that scenario, what would be the gathering EBITDA for that asset?

The gathering EBITDA, I think is in the $59 million to $75 million range.

It would depend on commercial contracts and things like that, but that is sort of a range that we are using right now.

From a volume perspective, the program was designed to flatten the decline, or to basically keep throughput flat, with maybe a couple single-digit percent increase in throughput.

But that is how the level of drilling was determined.

But one of the things we have to go through as we look at a drop, just so you know, is pretty much decide what we think the right rates are.

Because right now, probably 99% of the volumes that are flowing through those systems are EQT volumes.

So there's really not an issue of having to have arms' length agreements.

But obviously, ahead of the drop, we are going to need to relook at those tariffs, to relook at the other contractual terms, as well.

And that is something, actually, that we are working through to make sure that what we come up with we think is in the best interest of EQT as a whole.

The number Phil gave you -- gives you pretty decent snapshot of where we are now, but we are relooking at that in the context of prospective future drop.

Okay, makes sense.

Is it too early to talk about the total expansion opportunity for the Ohio Valley connector, just in terms of increased capacity, capital spending?

If I think back to Equitrans or Sunrise expansion, you had added about a Bcf a day for $300 million.

How did that compare to what your expectations are for the Ohio Valley connector?

I would say right now, it's a bit early, because we are in the process of the open season, so we are scoping that out.

But I think, as you think about that project and the market demand for that, we would do that as similar to what we were working on to a Sunrise-type project.

But it is early, and we are scoping out the demand right now in terms of the size and the capital that will be spent.

Last, just two quick modeling questions on the lower DD&A, is that going to trend lower throughout the year, or will that be the run rate in beginning in first quarter?

And then also, expectations for tax rate for the year, given the minority interest from the MLP increasing?

The DD&A rate is a flat rate for the year.

That would be a good rate for you to use for your modeling for the full year.

I don't know that we have said anything about the tax rate right now.

Obviously, you are right, it trends down because of the issue that you mentioned.

I would say, use a similar rate as this year for now without knowing any more.

It's going to obviously vary, depending on a lot of factors.

Great.

Thanks, guys.

Cameron Horwitz, US Capital Advisors.

Dave, I was hoping -- can you maybe give us a little color on the M&A landscape and the deal for opportunity that you're seeing in the Marcellus, opportunities to add acreage, similar to what you did last year?

Yes, I still have the view that we are going to see a lot more acreage up the sort, that sort of transaction come up over the course of time.

But I don't know that I have anything specific to offer on what the landscape looks like right now.

Steve, do you have anything specific that you want to -- ?

No, just as is typical.

It ebbs and flows, and I think we're seeing more smaller little deals right now.

But I would expect that will -- deals come and go in this business.

So we are not really seeing anything of note, positive or negative, in terms of a change.

I think there are still opportunities out there and we are pursuing them.

Okay, appreciate that.

Lastly for me, on the -- and forgive me if you said it -- but the 368 that came off the books in the Marcellus, you talked about the changes in the development plan.

Is there any more color can you provide, where that was?

They were spread out a little bit, but they were more in second-tier areas, where as we have defined and focused our drilling.

Our plans have been more concentrated in certain areas than we were anticipating a few years ago when we originally booked those PUDs.

And per the SEC guidelines, once we have a development plan that doesn't include those, we thought it was appropriate to remove them.

From a technical standpoint, they would still qualify as PUDs.

There were only removed because -- when we're looking at where we are going to drill, based on results, but also based on available capacity and all those factors, they just didn't fit anymore.

Really not much more to it than that.

You're going to see that, I think, over the course of time.

Over the last couple of years, or maybe a little bit more than that, the SEC has gotten pretty strict about that, so we take that very seriously.

And we will check that with our five-year development plan, and if something isn't in it, we'll just remove it.

It doesn't mean that we think any lesser of those reserves.

And they presumably will show back up as proved reserves at some point in the future.

But for now, all we have is the five-year plan that we have gotten blessed by the Board at this moment, and then we will go from there.

Makes sense.

Thanks a lot, guys.

At this time, we show no further questions.

I'd like to the conference back over to Patrick Kane for any closing remarks.

Thank you, everybody, for participating.

The conference is now concluded.

Thank you for attending today's presentation.

You may now disconnect.