Good morning, and welcome to the EQT Corp. 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 7-day period beginning at approximately 1:30 p.m. 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 7 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 today at 11:30 a.m. today, which creates a hard stop for this call at 11:25. If you're 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 strategic and operational matters. Following Dave's remarks, Dave, Phil, Randy and Steve will all be available to answer your questions. I'd like to remind you that today's call may contain forward-looking statements relating 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 in EQT's Form 10-K for year ended December 31, 2012, which was filed with the SEC, and were -- 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 of cash costs 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 Partners, or EQM, results in 2013 and 2 quarters of EQM results in 2012 are consolidated into EQT's results, even though a portion of EQM was owned by the noncontrolling 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…

Thank you, Phil. This morning, we announced year-end 2013 total proved reserves of 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 type curves and reduced drilling costs. Drilling capital totaled $1.3 billion, resulting in the drill bit 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 are proved developed and 431 Bcfe are proved undeveloped. This year, we've begun 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 were the removal of 58 Marcellus locations, totaling 368 Bcfe of proved undeveloped reserves due to changes in our 5-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 1 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, or the total proved, 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 for Upper Devonian as 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 on-site, thereby increasing the productivity and profitability of our acreage. We also announced a limited restart of our Huron program. This decision has 2 benefits: first, the economics of 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 3 wells were, frankly, mediocre, we are encouraged enough by initial results to try very specific changes to our drilling and completion design intended to…

Thank you, Dave. That concludes the comments portion of the call. Amy, can we please now open the call up for questions?

[Operator Instructions] Our first question comes from Neal Dingmann at SunTrust.

Steve -- a question for maybe Steve or David. David, you were talking a little bit just there about the Utica. My question is maybe on the Utica. I know some of your peers have mentioned around that Southwestern PA area I know, certainly, where you have some acreage. They've talked about potential Utica potential in that area. Just wondering, your or Steve's thoughts about that and if you would considered 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 that the depth of the formation, therefore, the economics of it, where our existing acreage position is. So that said, I think our view is, it'd be difficult for 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, the higher pressure frac-ing equipment, everything else involved with operating at those depths and pressures, we're not sure it'd be competitive. That said, I think we would -- we are -- we would think about whether a test, but more of a science test would make sense. And we haven't committed to do that yet or not to do that, but if we think it's warranted and we think we'll learn enough from a test, we might choose to do that.

Okay. And then just one follow-up, Steve. On -- obviously, the -- amount of Huron that you're getting booked -- I mean, a couple of questions on maybe first -- I'm sorry, skipping around a little bit. First, I think look at the Devonian potential. On those, would you think about sort of drilling in those wells the same way that you've been drilling the Marcellus? Or does it make sense to have maybe a shorter lateral or anything around. I'm just trying to get a sense of sort of type curves between the 2.

I think the drilling and completion techniques, for the most part, we think are similar. Now, we custom-design our frac jobs for really every well based on the geology we're in. So we wouldn't necessarily have an Upper Devonian well frac-ed 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. And I think our view right now is that we'll likely get the best stimulation of the Upper Devonian by frac-ing it at the same time as the Marcellus or within the same proximity of time, rather than waiting several years, say, down the road. So as we progress with Upper Devonian development, it'll most likely be a combined development program with the Marcellus and Upper Devonian.

Okay. And then just lastly, on the Huron. How much capital or have you said yet, will you commit to that this year or -- and sort of a percentage of total?

Let me grab that number for you.

Neal, this is Pat. We're budgeting $180 million to drill 120 drilling wells in '14.

Our next question comes from Drew Venker at Morgan Stanley.

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

No. We don't have any well results and it'll be likely mid-year before we start getting results from our revised completion program. So midyear at the earliest, I'm not sure we'll be talking about them mid-year. So I don't want to get your expectations up, but it'll be awhile before we even start to get results ourselves.

Okay. And how do the lateral lengths compare for your '14 program versus the first 3 you talked about?

For the Utica?

Right. That's right.

The lateral lengths, I think the average for the next 5 wells is...

6,500 feet is the average that we're projecting for the year.

And Pat, what was -- what were the first 3 months?

I don't know exactly. I think it's consistent.

Yes. They were just north of 6,000.

Okay. And so is the thinking of not releasing results that you kind of potentially have better results, and then you can lease up acreage. Is that the thinking?

Well, I think, yes, that's a big part of it. And 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. So the biggest driver would be, if successful, if we unlock 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 -- you mentioned it before. Do you guys have a plan to test Utica potential in West Virginia? Is there anything on the docket for this year?

No. Yes, not in the near term. Eventually, what we're probably going to do with the Utica that sits underneath our existing Marcellus is down the road at some point, 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 doesn't make any sense when we're in the midst of the development of the Marcellus and the Upper Devonian. So no near term plans for development.

The next question comes from Scott Hanold at RBC Capital Market.

Couple of questions just to clarify. So production guidance for 2014, that assumes basically your new 6:1 sort of methodology on ethane, is that correct?

Yes, that's right. That's 6:1 on the liquids.

Yes, okay. And so when we look at where you're kind of coming into -- in the first quarter and where growth could be, it seems like you all are attracting -- it seems like you're attracting well into the high end, if not a little bit higher. Can you just generally talk about just at a high level progression and more so if there are any kind of constraints for us to think about our timing that we need to think about in terms of quarterly progression or production?

At this point, it's -- of course, there's always -- in a play that's growing this rapidly or an area that's 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 -- of course there's wells being 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 certainly influenced our view for total volumes in 2014.

Okay. And just looking, obviously, at the numbers, your [indiscernible] in wells not completed, and completed and online. It's obviously at 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 to 18 months just to kind of reference?

Well, I mean, I think, as -- Scott, this is Randy. I mean, we're always staying out in front of production and we're pretty confident in our operations and plan. I would say our Sunrise Expansion that we kind of coming on in the third quarter, the compression expansion, which is on track and on time, is a major initiative for us.

Okay. Now that's helpful. And on the sales of utility, can you give us what the, I guess, net of any kind of cash tax would have been on that? And what is your cash position right now? Or...

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 had talked about back in the middle of the year. And in the release this morning, we did show that cash taxes associated with the utility sale of around $68 million, so we received $740 million and paid taxes of about $68 million on that.

Right, right. So the $110 million occurred after the year, but...

So it's not in the one $846 million. It would be additive to that. But, of course, we're [indiscernible].

But if you want to add, you just 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 it like a mini drop.

Okay. Understood, understood. And one last question here. The general partner, obviously, you guys are stepping back and kind of evaluating value within EQT overall. And can you give us your current thoughts on the general partner and kind of different directions that could go?

Sure. Let me take a shot at that. I think, hopefully, it's obvious we've been pretty focused on realizing the full value of the EQT Midstream interest that EQT owns in 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 noncore midstream assets to folks who valued them, frankly, more highly than we did. Those kind of -- those were actually buyers -- those buyers were MLPs and we noted that. We continued reforming our own MLP. And so we did that 1.5 years ago to the 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 can continues to own. Now the 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. So 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 interest, including the LP and GP interest, is not transparent in the current EQT stock price. And frankly, we tend to agree at this point. So -- and 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 industry peers have already taken similar steps. So, Scott, I'm not going to address and/or list them today. I think it's 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. So, 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's not clear that it would 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 interest, we don't want to deprive them of that value by transferring a significant portion of it to another party by acting too soon. So I hope that helps for now. That's really about as much as we want to say about that right now. Suffice it to say that it's an issue that we're studying closely.

Okay, okay. So it sounds like we'll hear more about that towards at the end of the year. Okay, fair enough.

Our next question comes from Michael Hall of Heikkinen Energy Advisors.

The -- let's see. I've got plenty to ask about. I guess, while we're on the topic of the value -- transparency of the value of the portfolio. What's the kind of latest thinking on drop downs this year? I know you're a little hesitant to talk about timing of it, but I'm just curious, like, is it one large drop down, multiple drop downs? How big of a roll moving or escalating -- potential escalation of interest rates play into that thinking? Just any update around that plan that you'd be willing to share.

I don't know if we want to talk about 1 versus 2 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're 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. And I think a lot of that is because of the transparency issue. The folks who invest in that vehicle, which is to, say, EQM, are looking for exactly that type of asset. And since it's their pistol, so to speak, they are willing to offer more favorable valuations in the marketplace for that. And therefore, that's the best home of -- for those assets. So that is the mindset that we've 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. Now what's the rate at which EQM can digest these is really more the issue.

Okay. And what would be the constraints around the rate at which EQM could digest them?

Well, part of it, of course, so they're going to fund -- there's the combination of equity and debt so the capital markets availability is one of the issues for them. Another one is that they are best off with projects typically, where every -- most of their projects be projects whereby they're already generating cash flow. So the projects where there's 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's 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 to be ones that have already been fully contracted and 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 going through EQT. Does that help?

Yes, it does. I guess, last on that, and I'll -- just it would be curious. In the outline, you've got quite a cash position already. Clearly, some outspend in the '14 budget that, that would, I guess, fund. But then you got likely some drops come in this year as well. Is that capital -- I mean, are there future capital allocations, I guess, that could come throughout the rest of the year regarding the 2014 upstream program? Or are we pretty well set and whatever capital comes in this year really just funds 2015? Just trying to think that through.

We're not setting capital programs based on cash availability. That's not up something we want to get into. I mean, obviously, we look at investment opportunities, but frankly, with this kind of cash position, you look at stock repurchases also.

Okay. And so, yes, that was kind of a follow-on. I mean, is that something that is higher up on the list than it has been, let's say, in the last 6 months?

Well just because we don't -- we certainly would not consider ourselves to be capital constrained right now. I mean, that would not be a good mindset for us to have. We could fund the attractive projects. So from that -- and probably, I don't know, before -- 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. So 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.

Yes, that's helpful. Okay. And then, I guess, the last one on my end would just be any updates or just maybe remind me on your marketing arrangements that protect around basis risk as we head into the summer? Any steps that are being taken to further protect around those risks on a go-forward basis?

Well, Michael, in terms of our capacity portfolio and really, I guess, I would comment the colder-than-normal winter has certainly been helpful in terms of increased demand and record storage withdrawals. And over this period of time, we've seen better realized pricing in the Appalachian basin. So we're more optimistic than we maybe when heading into the winter season and we have seen some support in the summer basis as the market looks to balance for power generation, as well as refill the storage. So -- but in terms of capacity, we have stressed in the past, 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've recently entered into several agreements that have added to that portfolio, and I'll go and give you few of those. Our most significant addition became effective on February of this year, February 1. That's when we added 245,000 dekatherms a day of capacity for approximately 7 years on Texas Eastern system to the M3 market and the Transco Zone 5 markets. And both of these appear stronger relative to other basins. So in total, we currently have almost 950,000 dekatherms a day of firm pipeline capacity out of the basin plus we have approximately 350,000 dekatherms per day of firm sales for a total of 1.3 million deks per day. And again, in addition to that, by the end of 2014, based on existing commitments, we'll have about 1.6 million dekatherms per day between firm pipeline capacity and firm sales. So with that, we always feel comfortable with our position in 2014 and heading into '15. And again, moving forward, we'll continue to add our firm capacity portfolio and add to the diversity of our markets, including the Midwest and the Southeast market.

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

Our next question comes from Phillip Jungwirth at BMO.

A couple of quick questions on the reserve report. That the 7.2 Bs or 1.7 per thousand lateral split, the EURs 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 2 Bs per thousand foot of your type curve in Southwest PA and Northwest Virginia?

So could you repeat that? I couldn't hear the first part of your question.

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

That's all proved reserves, 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. We don't have that data in front of us.

Okay. And then 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 $50 million to $75 million range. It will depend on commercial contracts and things like that. But that's sort of a range that we're using right now.

And 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's 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 arm's length agreements. But obviously, ahead of the drop, we're 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. And the numbers Phil gave you gives you a pretty good, decent snapshot of where we are now, but we're relooking at that in the context of the -- of prospective future drop.

That makes sense. And then is it too early to talk about the total expansion opportunity for the Ohio Valley Connector just in terms of increased capacity, capital spending? I think if I think back to Equitrans or Sunrise Expansion, you'd added about 1 Bcf a day for 300 million. How does that compare to what your expectations are for the Ohio Valley Connector?

Well, I'd say right now, I mean, it's a bit early because we're in the process of the open season. And so we're scoping that out, but I think as you think about that project and the market demand for that, we would kind of view that as similar to what we were working on to a Sunrise-type project. But it is early and we're scoping out the demand right now in terms of the size and the capital that will be spent.

And then last, just 2 quick modeling questions. On the lower DD&A, is that going to trend lower throughout the year? Or would that be the run rate beginning in the first quarter? And then also, expectations for tax rate for the year, given the minority interest from the MLP increasing?

So the DD&A rate is a flat rate for the -- that'd be a good rate for you -- use for your modeling for the full year. I don't know that we've said anything about the tax rate right now. Obviously, you're 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 anymore. It's going to obviously vary depending on a lot of factors.

The next question comes from Cameron Horwitz at U.S. Capital Advisors.

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

Yes. I don't know if I -- I still have a view that we're going to see a lot more acreage of 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 around what the landscape looks like right now. Steve, do you have anything specific that you want to...

No. Just as he said, it's typical. It ebbs and flows, and I think we're seeing more, smaller, little deals right now. But I would expect that, that'll -- deals come and go in this business. So we're not really seeing anything of note, positive or negative, in terms of a change. So I think there's still opportunities out there and we're pursuing them.

Okay. I appreciate that. And then just 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. Was it -- is there anymore color you can provide just where that was?

They were spread out a little bit. But they were more in second-tier areas where, as we've 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 -- once we have a development plan that doesn't include those, we thought it was appropriate to remove them. But they're -- from a technical standpoint, they would still qualify as PUDs. They were only removed because when we're looking at where we're going to drill based on results, but also based on available capacity and all those factors, they just didn't fit anymore. So really not much more to it than that.

And you're going to see that, I think, over the course of time. Over the last couple of years or maybe little bit more than that, the SEC has gotten a pretty strict about that, so we take that very seriously. And we'll check that with our 5-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 5-year plan that we've gotten blessed by the board at this moment, and then we'll go from there.

At this time, we show no further questions. I'd like to turn the conference back over to Patrick Kane for any closing remarks.

Thanks -- thank you, everybody, for participating.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.