EQT Corporation (EQT) Q2 2014 Earnings Report, Transcript and Summary

Good morning, and welcome to the EQT Corporation Second Quarter 2014 Earnings Conference Call. [Operator Instructions] Please note that this event is being recorded. I would now like to turn the conference over to Patrick Kane. Mr. Kane, please go ahead.

Thanks, Dana. Good morning, everyone, and thank you for participating in EQT Corporation's Second Quarter 2014 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 VP 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 today. The telephone number for the replay is (412) 317-0088. The confirmation code is 10037707. 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 was a separate press release issued by EQM this morning and there is a separate conference call today at 11:30 a.m., which creates a hard stop for this call at 11:25. If you are interested in the EQM call, the dial-in number for that call is (412) 317-6789. In just a moment, Phil will summarize EQT's operational and financial results for the second quarter 2014. Then Steve will comment on the findings of our review of our dry Utica acreage and finally Dave will provide an update on our transmission projects and GP cash flow projections and evaluation included in our updated analyst presentation, which was posted on our website this morning. 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 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 in EQT's Form 10-K for year ended December 31, 2013, filed with the SEC, as updated by any subsequent Form 10-Qs, which are on file at the SEC and are available on our website. 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. I'd now 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 second quarter 2014 adjusted earnings of $0.58 per diluted share, which represents a $0.02 per share increase versus the second quarter of 2013. The GAAP EPS was $0.73 per share in the quarter and included a $38 million gain on the asset exchange with Range, with $31 million of that gain realized at Production and the balance recognized at Midstream. As Pat reminded you, EQT Midstream Partners, or EQM's results, are consolidated in EQT's results. The impact of the noncontrolling interest in those results is a little clearer on the income statement than it is on the cash flow statement. EQM operating cash flow or adjusted EBITDA as it is defined in the EQM press release was $57 million in the quarter and is included in EQT's consolidated cash flow. However, as we have noted in the past, not all of that cash flow is available to EQT, as noncontrolling unitholders owned approximately 64% of EQM at the end of the second quarter 2014. Summarizing the quarter from an operational and financial perspective, EQT production volumes were 110 Bcf or approximately 17% higher than the second quarter last year but about 4 Bcf below our previous forecast. The shortfall versus guidance was due to the delay in the installation of a gathering pipeline, which postponed 2 multi-well pads from being turned in line, and also due to the delay in construction of well lines to another multi-well pad. In total, 22 wells were delayed and all 22 of those wells are currently flowing, which explains why we are reiterating our full year guidance of between 465 and 480 Bcf equivalent. We expect third quarter production volumes of 118 Bcf to 122 Bcf equivalent or a 9% sequential growth rate assuming the midpoint of that range. Midstream gathered volumes were also up in the quarter about 17% higher than last year. However, the volume growth at both businesses was largely offset by lower commodity prices and absolute costs that were higher than last year consistent with, but less than, the growth in volumes. Prices were obviously a big factor in the quarter. At the consolidated level EQT's average effective sales price of $3.85 per Mcf equivalent was about 10% lower than the $4.29 we realized in the second quarter last year. The average NYMEX gas price for the quarter was actually considerably higher at $4.67 per MMBtu compared to $4.09 last year. However, from a hedge price perspective, a portion of the impact of that higher NYMEX was offset by the fact that some higher price swaps rolled off in 2014. Also basis was significantly lower at negative $0.78 in the second quarter 2014 compared to basis which was basically flat with NYMEX last year. However, we were able to recover about $0.20 per Mcf equivalent in the second quarter 2014 through transporting some of our gas to higher-priced markets, and also through the resale of our unused capacity. The realized price of $3.85 included an $0.08 non-cash hedge loss on derivatives that were marked-to-market. The realized price at EQT Production was $2.92 per Mcf equivalent compared to $3.24 last year, or also about 10% lower. EQT Midstream realized $0.93 compared to $1.05 last year, as a result of a lower gathering rate, lower average gathering rate. And finally, our third-party gathering and transmission costs were $0.54 or about $0.05 per unit lower than the second quarter last year. A few brief comments on the production results. EQT production operating income, adjusted for the gain on the Range transaction was 8% higher than last year. As I discussed a minute ago, this 17% volume increase was significantly offset by lower commodity prices. The result was net operating revenue of about $322 million in the quarter, which was only 5% higher than the second quarter of 2013 despite the healthy volume growth. Operating expenses were about 1% higher. Excluding the $4.8 million legal reserve, SG&A, production taxes, and LOE were all higher, as you would expect given the volume growth, however DD&A was lower as a result of a depletion rate that is 19% lower than last year, primarily as a result of the increase in reserves at year-end 2013. Moving on to Midstream results in the quarter. Midstream operating income adjusted again for the gain on the Range transaction was up 13% due to the growth of gathered volumes and increased capacity base transmission revenue. Net revenue was $152 million, up about 16%. Gathering net revenue increased by 5%, as gathering volumes increased by 17%, but were somewhat offset by an 11% decrease in the average gathering rate. That gradual decrease in average gathering rate has been ongoing and is due to the continued increase in the Marcellus gathered volumes in the mix, which are relatively less expensive to gather and therefore, gets charged at a lower rate. Midstream transmission net revenues also increased by 33% in the quarter, driven by higher capacity reservation charges and throughput. Third-party transmission revenues were 73% higher than last year and accounted for 1/2 of second quarter transmission revenue. Storage, marketing and other operating revenue was $4.1 million higher in the second quarter, as a result of revenue from storage assets that were received as part of a consideration from the utility sale that closed in December. Operating expenses at Midstream were up 20% quarter-over-quarter, however, per unit gathering and compression expense was 6% lower, driven down by the volume growth. A couple of comments on funding and liquidity in the second quarter. As you know, we sold our Jupiter gathering system to EQM for $1.2 billion in May of 2014. There was no EQT income statement impact from that transaction, as EQT controls EQM through the general partner ownership and therefore, EQM's results are consolidated with EQT. From a tax perspective, however, EQT did realize a gain on the transaction, and we expect to pay cash taxes of approximately $100 million related to the sale of the Jupiter gathering system. A quick update on our share repurchase authorization. We bought back 300,000 shares of EQT stock during the quarter and have 700,000 shares remaining under the current authorization. And then just a couple of quick notes on the balance sheet. We closed the quarter with no short-term debt other than the $330 million of short-term debt at EQM that gets consolidated into EQT's balance sheet, and a current cash balance at EQT of approximately $1.4 billion. We also continue to have full availability under our $1.5 billion revolving credit facility. Using the current strip for the remainder of the year, our operating cash flow estimate for full year 2014 is approximately $1.5 billion. And with that, I'll turn the call over to Steve Schlotterbeck.

Thank you, Phil. As we discussed at the time of the first quarter call, we were revisiting our geologic and engineering analysis of the dry Utica/Point Pleasant potential on our acreage. As we look at the initial results of the wells drilled so far in the play by other operators, our technical teams are very encouraged that the results are basically in line with what our models would predict. Until now, we've been hesitant to drill our own well based solely on those models, given the lack of well control. But we think it is now time to drill a test well on our acreage. Based on our review, we have approximately 400,000 acres that could be prospective for Utica. There's little disagreement that there is a tremendous amount of gas in place in the play. The question is whether or not the gas can be profitably produced, as each well could cost as much as $15 million. Based on our work, we decided to drill the first test well in Greene County. The main reasons for this were: one, the geology under Greene County looks quite good; and two, we have existing pads, roads, and takeaway pipes in place that could be leveraged if we are successful. We realize that this well is an experiment and could result in a $15 million dry hole, but the upside, if successful, is tremendous. We've begun the permitting process and expect to spud the first well before year end. We'll keep you informed of our progress. Shifting gears, we published an update to our Marcellus analyst slide this morning. We updated our acreage position to add 20,000 acres that we acquired over the past few quarters. We also framed the fourth Marcellus development area in the dry window of northern West Virginia. We have 30,000 net acres in this area. There are about 300 locations and we have 46 producing wells there. The EURs are about 15% less than our wet West Virginia acreage but about 25% higher than Central Pennsylvania. We are drilling 18 wells in the area this year. We also published an upper Devonian type curve for the first time. As those of you that have listened in the past, we like to wait for data from actual wells before publishing type curves. We estimate a mid-40% return from our upper Devonian wells. Finally, we increased the average EUR of our Southwest Pennsylvania acreage to reflect better performance from the wells drilled there. With that, I'll turn the call over to Dave.

Thanks, Steve. I would like to comment on the status of our pipeline projects and the related topic of our current thoughts on the EQM GP. Before giving specifics on the status of 3 pipeline projects, however, I'd like to provide a strategic overview. With the growth in production volumes in our region, we have become quite confident that there will be many attractive Midstream investment opportunities. In fact, I believe there will be more opportunities over time than we can prudently pursue. Therefore, we need to prioritize our selection criteria and also make sure that EQT and EQM are prepared for this sustained growth. The primary drivers of our prioritization are: the overall attractiveness of the project; its fit with our existing assets; its fit with the objectives of EQT production and other Equitrans customers; its ability to access attractive markets; and the flexibility it affords in accessing multiple markets. As to specifics, at the time of our first quarter call, EQT Midstream Partners or EQM had an active open season on a project that connects our Equitrans system to pipes in eastern Ohio, the so-called Ohio Valley Connector or OVC. We announced today that we are moving forward with OVC and that it will be built by EQM as an organic growth project. This 36-mile pipeline extension will connect our transmission system in northern West Virginia to Clarington, Ohio. There, the pipeline will interconnect with both the Rockies Express Pipeline and the Texas Eastern Pipeline. The current project scope is estimated to cost approximately $300 million and will provide about 1 Bcf per day of capacity. The estimated in-service date is mid-2016. EQT has contracted for $650 million cubic feet per day of OVC capacity, and EQM has actively engaged with other shippers to firm up contracts for the remaining capacity. Next, I'd like to update you on the Ohio Express project. As you may recall, this project originated through requests from producers seeking to move gas from Clarington to liquidity points further west in Ohio. Since completing our open season, we have re-assessed our priorities and Ohio Express has slipped below other projects. So it is on the back burner at least for the near future. And finally, the third of the projects, the project supplanting that amongst our priorities, is the Mountain Valley Pipeline project or MVP, which we announced in the second quarter. MVP is designed to serve the southeast markets by extending our transmission system through West Virginia to Southern Virginia. This 330-mile pipeline is expected to have a capacity of about 2 Bcf per day and has 2 anchor shippers, including EQT Production who have already agreed to a total of 1 Bcf per day of capacity. The nonbinding open season for MVP ended in mid-July. We are encouraged by the interest expressed by shippers and are now working toward precedent agreements with those shippers. We expect MVP to be constructed and owned by a joint venture with NextEra Energy with EQT as operator and largest owner. Once the project size and scope become clearer, we will determine whether the project belongs at EQM or EQT. The reason MVP has become a higher priority is that we believe the southeast offers one of, if not the, most attractive market in terms of future natural gas demand growth, as well as an attractive price environment. We think southeast markets can support multiple Bcf per day of new supply to satisfy the expected demand growth and continue to offer strong pricing relative to Appalachian Basin pricing. We will keep you updated. Moving to the GP. As you know, our ownership of the EQM general partners entitles us to a growing proportion of the MLP distributions. Per the incentive distribution rights or IDR schedule, the GP receives 50% of incremental quarterly distributions, about $0.525 per limited partner unit. The purpose of IDR is to align the GP interest with the limited partner interest by incenting increases in quarterly distributions. We will pass this key milestone of $0.525 later this year. The quarterly LP distribution that will be paid next month is $0.52 per unit and EQM has given guidance that it plans on increasing the distribution by $0.03 per quarter through at least 2016. GP distributions are determined based on 2 variables: distribution per unit and LP units outstanding. Therefore, forecasting the cash payment to the GP is rather straightforward. In our updated analyst presentation, we laid out a schedule of GP cash flows based on assumptions for these 2 variables. One, is that the $0.03 per unit increase in quarterly distributions continues through 2019. This appears very achievable given the visibility of distributable cash flow growth at the MLP from organic growth and future accretive drop downs. The second assumption is that the rate of drops from EQT to EQM is $75 million of EBITDA each year for the next 3 years, which EQM finances using a 50-50 debt equity mix. As EQT still has almost $200 million of Midstream EBITDA, and is investing over $350 million in Midstream this year, the drop inventory needed to support this assumption is already in service or being built. If EQM continues to have success there will, of course, be new products or additional drops. Along these lines, neither OVC nor MVP is explicitly assumed to occur but we did assume a 4% terminal growth rate in distributable cash flow after 2019. We are planning for more rapid growth post 2019 than that, but this assumption is consistent with what we have seen from investment banks, so we used it as a benchmark to assess the value of GP cash flows. As you will see on the slide in the analyst presentation, the GP cash flow increases dramatically. It grows from less than $15 million in 2014 to nearly $200 million in 2019. The relatively low GP cash flow in 2014 shows why we need to be a bit patient in taking action to realize the GP value. While our estimate of the present value of the pretax cash flow was nearly $4 billion, it seems unlikely that EQT investors would pay the multiple of 2014 cash flow needed to achieve that valuation inside EQT. We believe that our GP stake is quite valuable and we are on track to decide around year end on the best path to realizing that value for our shareholders. 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 are 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 we appreciate your continued support. And with that, I will turn the call back to Pat.

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

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

A few questions here. First, maybe if you guys could just follow-on to what you were just saying at the very end there, you mentioned and I would agree with you about the material value of the GP, you mentioned by year end you would consider or look at some options for monetization. What are -- can you discuss this maybe in a little bit more detail, some things that maybe you or the board or anybody has talked about at this point? I mean certainly, there is value there, I'm just wondering if any...

Yes, I think, I'd rather not do that, Neal, other than -- well, first thanks for your question, and I'd rather not do that other than just mention that we are looking at what a lot of other folks have done but frankly, when I've gone through the list of alternatives in the past, it hasn't turned out well. So I just assume, we -- yes, you probably remember. But you just recall that we did -- we've been saying around year end for a little while and we both know that there are, we all know on this call probably, that a number of different companies have gone down this path before they picked different routes. And we've taken a look at a lot of that, and we've used some experts, some investment banks, et cetera, to try to help us think that through. But frankly, I'd just assume we'll leave it at that, if that's okay.

Maybe moving on for Steve. Steve you mentioned about the 400,000 perspective unit acreage and I was glad to see you guys finally breaking this out. Your thoughts on this first well in Greene County, Steve would you think about doing, I guess sort of commingled pads, or you would drill Utica and Marcellus on the one or is this just kind of just that step out test well? How do you foresee sort of developing some of these Utica wells with, say, the Marcellus there?

I think, Neal, first of all, we're viewing this first well as a test. So it's an experimental well. We see lots of resource potential, I mean there's a lot of gas in place. I think that's pretty clear to everybody. But there are some challenges. It will be the deepest well we've drilled. It will be the deepest Utica well drilled so far, I believe. So I think it's going to be around 13,500 feet deep. So there are some -- not so much drilling questions, but I think on the completion side we have some questions we need to answer and some tests we need to run. So for now, this is an experimental well. Our view though is, if successful, and depending on the ultimate economics of the Utica development, I think we would develop it on existing pads or in combination with Marcellus drilling. We don't see a need for separate pads or separate facilities. It could all be done in conjunction with each other.

Steve, can I ask one thing here? Does that depth preclude you from taking the lateral out further than you might otherwise or maybe if you can comment around that?

I don't think so. I don't think we're too worried about the drilling aspects. Our test well is planned to be about 6,400 feet. We feel very comfortable with that. And I think, we feel like we'll be able to go longer. Probably our biggest questions in our mind concern the pressures and the stresses, so what's the right propping. We know we won't be able to use sand, so we'll be using most likely ceramic propping. What strength do we need, what sort of pumping pressures are we going to see and pump rates can we get at this depth in those pressures. So a lot of experimentation to do. We're kind of sort of in a new frontier here in terms of depth and pressures. So there's -- we have some questions to answer on this first well.

Our next question is from Scott Hanold from RBC.

Maybe if I can follow-up since we're talking about the Utica well right now. So when you step back and look at, I know it's really early today, but given what you know on what you think the cost could be, I mean, what do you think you need to get out of this well to make it economic and then I'll say, along with that then you make it competitive with some of the higher return projects you have in your portfolio?

I think, probably the simplest way to think about it, back of the envelope, is the wells are going to cost twice as much as a Marcellus well, so they're going to have to produce twice as much to be competitive. They can obviously produce less than that to be economic. But I think our -- given the large inventory of Marcellus opportunities we have, our real goal is to make it competitive with the Marcellus, not just meet our cost to capital. So basically we're looking for double.

Okay. Got it. And I know you provided a pretty wide range on the cost expectation because, obviously, it's really -- you haven't drilled the well yet, but I mean what would be the ideal cost, maybe, is it that when you say twice the EUR, do you think twice the cost of Marcellus well is also going to be kind of the go forward thought, so if you can get your Marcellus wells down to, say, $6 million, $6.5 million, these are going always to be in that $12 million, $13 million range on the low side?

Well, I'm not sure it quite works that way. It's really, the well -- it happens to be about double our estimate but it's really based on the specifics. And because of the depth of the Utica under a lot of the most perspective acreage, they're going to be expensive. And I think that range, the range that we're providing is driven more by what strength casing we're going to need and what kind of horsepower and pressure limits on our frac equipment is going to be required. So those are things that we're going to have to drill a well to find out. But that's why there's such a big range now. And I think a lot of the costs go into higher propping, higher horsepower. So it's -- a lot of the extra costs are coming on the stimulation side. There's a little more cost because of the depth on drilling but it's really driven by increases in our frac-ing needs.

Okay, understood. And then my follow-up would be then on production. Obviously, this quarter a little bit below expectations because of well timing. Was there any other kind of constraint in the field just due to a line -- high line pressures that you may all have seen or maybe a mix shift in terms of what you completed in the quarter. And I guess what I'm getting to is even with the 4 Bcf, you guys were within your guidance, but it's pretty much been a beaten race story in terms of production historically for you all. So not to be well above, kind of, your production range was a bit of surprise.

Yes, I mean, I think when we provide guidance, we're giving you our best estimate and sometimes things go more favorably than we expect and sometimes we have some issues that we didn't expect. In this quarter as we mentioned, we had 22 wells that were delayed for a couple of different reasons, mostly around just getting them in line. But just for reference, that's 22 wells from 3 pads on average delayed about 2 weeks. So because of the large number of wells per pad and the large production per well, it doesn't take a long delay to have some fairly significant impact, positive and negative. So if things happen a little faster, our numbers can exceed pretty easily. And if they're a little bit late, they can miss. In the end of the day it's all timing. I think when you look on a calendar year basis, the impacts are pretty minimal.

Our next question is from Phillip Jungwirth with BMO.

I wanted to ask a question on the GP valuation. If I look at the LP distribution forecast for 2019, it looks like the LP is trading at a 4.8% yield. And then applying the same yield to the GP cash flow in 2019, basically gets you to the $3.9 billion base case valuation. But the GP growth rate doubles in the LP. So my question is, do you think an 8% WAC [ph] is really realistic to use for the GP base case valuation?

We based that WAC [ph] on information we got from various, as Dave mentioned, experts, investment bankers. The range is sort of 7% to 9%. We picked the midpoint, and didn't put a lot more thought into that. We did you give you a table so you could pick a different one, if you'd prefer to.

Okay. And then can you talk about what percentage of midstream EBITDA is still held at EQT Corp versus EQM?

Yes. I don't know if we talked about what percentage is there.

It's a little less than $200 million of EBITDA currently, that's still at EQT.

Roughly 40%.

Our next question is from Holly Stewart with Howard Weil.

Dave, maybe a couple of strategic questions, lots of cash on the balance sheet, can you just kind of talk about your priorities at this point for use of cash?

Really, it's just to pursue the strategy that we've had with both the upstream and the midstream. As I think we've said in the past, Holly, we've got no desire to let cash burn a hole in our pocket. I think that it hasn't in the past when we've been in this situation. I understand we went through a period of years where that wasn't the situation. But we will not, for instance, accelerate just because we have cash. It is -- we're going to make what we think are the decisions that are most likely to create value for shareholders. It does factor in a little bit in decisions on whether we build midstream projects at EQM or EQT, but realistically EQM has had access to capital markets at pretty fair pricing since it's been around. So that hasn't really factored into it too much. And we'd also like investors to have a sense that we are in fact able to continue the development programs that are -- represent the optimal development of our resource base for a period of time. That we're not constantly having to look behind the sofa cushion as it were to find extra loose change.

So no thoughts at this point on further accelerating in the Marcellus?

Not because of having cash available, no. That would be -- if we look at things with the Marcellus or the Utica or for that matter now, I guess, you would say the Permian, and we think that's the best way to create value, then we'd certainly be interested in doing that. But it isn't -- we try to studiously avoid being affected by the fact that we happen to have a lot of cash on the balance sheet. I think that's a good way to fritter away value over time, and we don't wish to do that.

You had a good segue into the Permian, maybe just some strategic thoughts there around the deal, I know that you increased the well count for 2014.

Actually, I'm happy to let Steve comment on the Permian. I think we've talked about the deal as a whole, which was that the Nora was non-core for us and we've known for a long time it was more interesting for Range than it was for us. But I think we've kind of commented on that and the Permian was at the top of our list when we looked at other basins. But as far as what we're up to there, I'll turn that over to Steve.

Yes, Holly. I think, it's the change in well count is really driven by the fact that we expect to have a rig available in the fourth quarter. And when we think it will be available and get the first well spud. We think we'll likely be able to spud 3 more wells and that well count includes a well started by Range, being finished by us, that we're actually starting a frac job today on that well. So that's well 1 of those and then, 2 or 3 more at the end of the year just to keep the rig running. All Upper Wolfcamp targets in the western part of our acreage position where we feel very comfortable about the economic returns.

I appreciate all the detail on the GP value. Maybe Dave, you can kind of give us some thoughts on EQM's appetite at this point for the remainder of the year for more drops?

Well, we're still working through that. I don't know that we have anything to announce on further drop timing right now. I will observe that EQM has had a pretty ready access to the capital markets. But for us a lot of is making sure that an asset is ready to drop also, that we have those arm's length agreements. I know we've talked about that in the past, but we've long had tariffs, but you really need to -- with separate entities, you need to make sure you have the full agreement in place and that all other legal aspects are better taken care of as well. So I don't really have any announcements on drops other than we're just going to continue to plug along.

And then my last one would be, maybe for Randy. There's some good detail in the slide presentation on sort of your end market mix and how that shifts in '15. If you could just maybe give us some color on some of those changes, it looks like your M2 exposure goes down in Midwest and NYMEX goes up?

That's right, Holly. I mean in November our team, 14 [ph] capacity comes into service, which provides us additional access to the Gulf Coast, as well as to northeast markets. And certainly, some of the capacity that we're looking for to go to Midwest that will kick in as well with the OVC into the future. So we feel pretty good around our portfolio right now.

Our next question is from Amir Arif from Stifel. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: A couple of quick questions. For the 400,000-acre Utica position, how much of that is in roughly in Greene County and West Virginia?

I believe, roughly 50,000 acres in Greene County plus or minus a little bit. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: And then the West Virginia side?

I don't have that number specifically handy, but it's 150,000 or so. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay. And are all the Utica rights held by the Marcellus production?

Actually, most of them are held by shallow production or Marcellus but they're nearly 100% held by production. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay. And the new dry gas area that you've put out there, the 30,000 acres, is that newly acquired acreage or is that acreage you had previously and you just sort of defined as Marcellus now?

It's a bit of a mix. We did acquire some acreage in that area recently. But I think the bulk of it was existing acreage. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay. And then just finally on the basis for the second half, the $1 to $1.10, could you give some granularity on what you expect in 3Q versus 4Q for that?

I don't think have the details on that but all we did for that guidance was to just take the published strip for the local basis and average it for the 6 months. So we're not really trying to make a prediction that's different than the strip. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: But Pat, generally it's wider in 3Q and then narrows in 4Q. Is that fair?

Yes.

Our next question is from Joe Allman with JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: A quick question on gas differentials. So what are you seeing so far this quarter on gas differentials and what's your expectation for the rest of the year? And I do see the market mix slide so I'm assuming that you're expecting differentials to improve in 2015?

Joe, we gave a specific forecast on what we think were differentials for the second half of the year. So from a local basis perspective between minus $1 and minus $1.10, but we think because we have capacity and are able to get to some higher-priced markets, we were able to recover $0.60 to $0.65 to kind of a net $0.50 negative. Joseph D. Allman - JP Morgan Chase & Co, Research Division: And am I correct that next year you're expecting the differentials, assuming, say, $4 flat gas to be better than 2014?

We're not really making predictions other than what the strip is. So it's hard to predict.

Yes. All you're really getting from us is a reflection of what the market shows we're guessing... Joseph D. Allman - JP Morgan Chase & Co, Research Division: And then on the GP monetization options. So is it possible that because of the ramp in cash flow that one of the options is actually to wait till some point later when you get a better valuation?

We're still working through that process. We had, early on, recognized that one of the things that we need to do as part of this process is provide a bit more transparency on GP cash flows to investors and that's the only reason that we put this out when we did. We just -- this is still consistent with our thought process of trying to get to some type of an idea of what we think makes sense by the end of the year. So I really don't have a view on timing beyond -- since we're really just kind of, I guess, you'd say almost like halfway into that process or a little more than halfway I guess. Joseph D. Allman - JP Morgan Chase & Co, Research Division: And then any comments on service cost? Are you seeing service cost pressures and any specifics around that?

No. Service cost has been holding fairly steady over the last quarter. And I think our view is we expect that to continue at least through the next quarter, hopefully, longer. I don't expect certainly any reductions, but we're not really feeling a lot upward pressure at the moment either. I would like to, while I have the microphone, clarify my previous comment. We have 65,000 acres in Greene County with Utica rights.

Our next question is from Drew Venker with Morgan Stanley.

I want to go back to the Permian, did I hear correctly you said all of the wells in the 2014 program are Upper Wolfcamp. Is that right?

That's correct.

And can you remind us how thick the Wolfcamp is there?

I'll be honest, I don't recall off the top of my head.

So thinking ahead to next year, what's the goal of the '15 program? Are you trying to delineate the whole acreage position, are you more trying to hone well design? Can you just provide some color there?

We haven't set out a '15 plan yet. But I think, generically speaking, it won't be to delineate the entire position. I think our strategy will be to -- the bulk of the investment will be focused on the Upper Wolfcamp in the areas where we feel pretty confident about the economics. With some test wells sprinkled in, perhaps, in the Lower Wolfcamp or the Cline. And also with a couple sort of testing the eastern limits, sort of to find out where that economic threshold is going to be on the acreage. But I think the bulk of the investment will be focused on areas we think we can get good returns with some delineation tests sprinkled in.

And then on the Ohio Utica, have you completed any of those wells that were waiting on completion?

We have frac-ed the wells, and they will be flowing them back shortly. As we said previously, we don't intend to provide updates, specific flow information on those wells, but they are on the previous schedule that we talked about.

Our next question is from Michael Hall with Heikkinen Energy Advisors.

All of mine have been answered at this point. But just diving into that recovery line item a little bit more and the guidance around that, the $0.60 to $0.65, positive recovery, how should we think about that kind of going forward? How much of that during the quarter was actually from better pricing versus selling capacity and how much of those prices are on a fixed basis versus floating?

It's a combination -- it's different every period, Michael. So it's really tough to give you specifics. But the intent was that separating the recovery from the expense of transmission, which is what we did in this quarter's presentation, should allow you to take the -- it would give you the sales points where we're selling our gas. So you should be able to use the weighted -- the weighting of the volumes at those points and the pricing at those points to better approximate the net of the local bases and the higher prices at the other sale points. And that would give you -- and that would be reflected in the recovery line would be the higher price portion of it and the basis is basically the first delivery point for our gas.

And generally speaking, it's -- we're going to have more opportunities when there's a lot of demand in some of those other areas. So for instance, cold weather will help, just as it did in the first quarter. And milder winters would mean that there wasn't as much opportunity, some, but not as much.

The other question I had as it relates to -- your view, if you have one on seasonality in the Northeast markets and how you see that playing out as we move into '15 and beyond given the increased volumes and the supply dynamics in the Northeast. Do you think points like M3 still exhibit a lot of seasonality going forward or does that get materially muted given the supply situation?

Michael, I mean, obviously, as David said, there's a lot contingent on the weather and the conditions and the power generation load, and in the winter, certainly, there's certain aspects of seasonality as we saw this in our first quarter results in the winter. So there's significant -- our team, and the portfolio approach that we take attempts to maximize our sales priceline by optimizing the portfolio. So I think with regard to M3, we're seeing some significant price advantages this past winter and depending on the conditions, we may very well see a similar result. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Sorry to beat on this, but in terms of those contracts. Are all those floating on a price basis or are there material amounts that are fixed price contracts as it relates to the firm transportation you guys have outlined?

Yes, as I said, we take a portfolio approach, so it changes. But we do have some fixed but we also have others that are out of floating. So that -- overall, we intend to manage our price through a mix of each. I don't have the specific percentages.

And then, I guess, on the Midstream side of things EQT Midstream, can you just review the growth outlook kind of as you see it for '15 and beyond on EQT Midstream at the EQT level?

Basically, we've been pretty much 20% growth of EBITDA for the last several years. And we haven't given a forecast for volumes for next year but certainly seem to be on track with that to continue.

That's a 20% growth relative to the growth EBITDA stream rate?

Yes, you have to kind of look at consolidated because of the dynamics of the drops. So if you look at the consolidated Midstream EBITDA, it's a pretty steady growth trajectory. Obviously, whenever you're taking, dropping $100 million or so from one entity to the other midyear, it's going to make the sub-comparison choppy. But if you look at the consolidated growth, it's pretty predictable.

So basically, it is tracking the production growth. I mean, we're obviously been having more and more that's third-party but generally speaking, we've been trying to organize it so that the projects that support nonaffiliated producers are at the EQM level. So at the EQT level, generally speaking, you're going to wind up seeing results, growth results that track EQT's production growth.

Okay. So that 20% kind of growth rates for the gross EBITDA stream is still reasonable?

It could be.

And then just I was looking for a little more color on the increase in the EUR on the southwest VA assets, just any additional color there?

Not really, just a normal update based on results seen to date. So it wasn't a big change but it was enough that we thought we'd communicate it to you. But really nothing more than that.

Due to the hard stop necessary for your next call, this concludes our question-and-answer session today. I would like to turn the conference back over to Mr. Kane for any closing remarks. Mr. Kane?

Thank you, Dana, and thank you, all, for participating.

And he disconnected.