EQT Corporation
Q3 2013 Earnings Call Transcript

Published: 24 Oct 2013

[Operator:]

Good morning, and welcome to EQT Corp. Third Quarter Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Pat Kane. Please go ahead.

[Patrick John Kane:]

Thanks, Chad. Good morning, everyone, and thank you for participating in EQT Corporation's Third Quarter 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, Distribution and Commercial; and Steve Schlotterbeck, Senior Vice President and President of Exploration and Production. This call will be replayed for a 7-day period, beginning at approximately 1

[Philip P. Conti:]

Thanks, Pat, and good morning, everyone. As you read in the press release this morning, EQT announced third quarter 2013 earnings of $0.58 per diluted share. Operating cash flow was just under $233 million in the quarter, or 36% higher than the third quarter of 2012. Adjusted cash flow per share was $1.92 in the quarter, up 68% versus the third quarter '12. Our operational performance was again outstanding this quarter, with 42% higher production volume growth, 43% higher gathering volume growth, while net operating expenses increased by only 23%, resulting in continued reduction per unit operating cost. EQT Midstream Partners' results, as Pat mentioned, are consolidated in EQT's results, and EQT did record $14.4 million of net income attributable to the noncontrolling interest unitholders of EQM in the quarter. Early in the quarter, EQT completed the sale of the Sunrise Pipeline to EQT Midstream Partners for total consideration of $507.5 million, plus approximately 479,000 common units and 268,000 general partnering units in EQT Midstream Partners. While there is no accounting gain from the sale on our income statement due to the consolidated reporting, EQT will recognize a federal income tax gain of approximately $475 million, resulting in cash taxes associated with that transaction of approximately $57 million. That represents a cash tax rate on the dropdown of only 12%, as we are able to use our intangible drilling cost deductions, accelerated tax depreciation and net operating loss carryforwards to reduce cash taxes for the year. These tax synergies are actually a valuable benefit of our current corporate structure as we continue to work through our inventory of dropdowns. Continuing on income tax topic for just a minute, you may have noticed we recorded a corporate effective book tax rate of 25% for the quarter, which is a little lower than normal. I should first note that the accounting for the MLP structure has the effect of reducing our book federal tax rate as all of the pretax income, including the portion that goes to the noncontrolling interest of EQM, is consolidated at EQT, while we only record income taxes on EQT's share of the pretax income. The 25% effective tax rate in the quarter is also below the expected run rate for the year due to an increase in our ability to utilize some state tax income tax deductions in the quarter compared to previous estimates. For the full year 2013, we do currently project the EQT effective book tax rate will be around 35%, or right around the level that it was last year. I will now shift gears briefly to discuss our operating results in a little bit more detail, starting with EQT Production, where sales volumes continue to grow rapidly. The growth rate in the recently completed quarter was 42% higher over the -- 42% over the third quarter of 2012. That growth rate continues to be driven by sales from our Marcellus play, which contributed approximately 75% of the volumes in the quarter. Marcellus volumes alone were 74% higher than they were in the quarter a year ago. Realized gas prices were a bit higher in the quarter, consistent with higher NYMEX prices. At the corporate level, EQT received an average of $4.20 per Mcf equivalent, compared to $4.04 per unit received last year. However, the realized price at EQT Production was $3.13 per Mcf equivalent compared to $2.85 last year. A couple of comments on our realized price specifically as it pertains to basis. Basis was a negative $25.1 million in the quarter, or a negative $0.26 per unit, compared to a negative $2 million, or essentially flat basis last year. We were able to mitigate some of the basis impact through fixed price sales, which added $6.4 million, or about $0.07 per Mcf equivalent to our realized price in the current year quarter. The impact of these sales is reported in our hedge gain line item in the price reconciliation table. As we think about investments and economics, we do focus on our projected realized price, in which basis is only one part, and our projects are still quite profitable at current levels. Moving onto the Midstream results. In the third quarter, operating income here was up 54%. The increase is consistent with the growth of gathered volumes and increased fixed capacity-based transmission charges. Net gathering revenues increased 19% to just under $92 million in the third quarter '13, primarily due to a 43% increase in gathered volumes. The average gathering rate paid by EQT Production will continue to decline as Marcellus production continues to grow as a percentage of our total production mix. Specifically, the average revenue deduction from EQT Production to EQT Midstream for gathering in the quarter of $0.84 per Mcf equivalent was $0.16 per unit lower than last year. Transmission revenues for the third quarter 2013 increased by $13.4 million or by 50%, driven by fixed capacity charges associated with Equitrans expansion projects, including Sunrise. Storage, marketing and other net revenue was up $2.8 million, primarily from unrealized gains on derivatives and inventory in the quarter. As I've -- as we've mentioned several times before, the storage and marketing part of the Midstream business realized on natural gas price volatility and seasonal spreads in the forward curve and those have continued to deteriorate year-over-year. Given current market conditions, we continue to estimate that full year 2013 net revenues in storage, marketing and other will total approximately $30 million. Operating expenses at Midstream for the quarter of $61.4 million were about $3.5 million higher than last year, consistent with our growth in the business. Just a quick note on guidance, we are currently estimating our operating cash flow for 2013 full year to be approximately $1.2 billion. We closed the quarter with no outstanding balance on our $1.5 billion credit facility and had over $400 million of cash on our balance sheet as of 9/30/2013. So we do remain in great position from both a liquidity and a balance sheet standpoint for the rest of the year and as we head into 2014. And with that, I'll turn the call over to Dave Porges.

[David L. Porges:]

Thank you, Phil. As Phil summarized, operationally, we are coming off another record quarter, with record volumes at Production and Midstream. We have discussed the lumpiness of volume growth, resulting from the timing of turning these big multi-well pads in line, midstream projects, et cetera. This was again evident in the third quarter. We exceeded our production sales guidance because some anticipated fourth quarter volumes were accelerated into the third quarter due to the turn in line timing of some pads. Much of this increase volume flowed through our gathering and transmission systems, driving the growth in those businesses also. During the quarter, we also turned in line our first 3 Utica wells. The 30-day rates were published in today's press release. We are encouraged by the results because they were in line with our expectations, and we are confident in our ability to improve well performance and reduce costs as we move up the learning curve. From an absolute volume perspective, the wells in this part of the play, the volatile oil window, are not eye-popping. However, what we still find attractive about this area are the significant amounts of high-quality oil and very high Btu gas. On a boe basis, these wells averaged 42% oil; 28% NGLs, including ethane; and 30% gas. When processing becomes available around year end, we'll receive premium pricing by stripping and selling the natural gas liquids. To put the economics in perspective, when using today's prices, the average 30-day initial production from these first 3 Utica wells is the revenue equivalent of natural gas wells with IPs of nearly 9 million cubic feet per day. We are on track to drill 8 wells this year, and we are still at approximately 14,000 net acres in our focused area within the Ohio Utica. We have not added to our position since the last call as we believe the currently high acreage prices warrant patience, certainly compared with the value we see in tack-on acreage additions near our core Marcellus hold-ups. We will keep you informed on our future well performance and our acreage position. As you also saw, we will be achieving a milestone of sorts in mid-November when the recently announced EQM distribution becomes payable. At that point, the EQM distribution will be $0.43 per unit, which is above the $0.4025 per unit threshold, at which incentive distribution rights for the general partner begin. To remind you, EQM guided its investors to $0.03 per unit per quarter increases through at least 2014, which would mean reaching the top incentive distributions split for the GP late next year. Given that there are only 2 months left in the year, we have very little to provide regarding guidance. Fourth quarter production sales volumes are expected to be flat sequentially, in large part due to those pads which were accelerated into the third quarter. This would result in 2013 production sales volumes that are 42% higher than 2012 volumes and fourth quarter volumes at 27% higher than the fourth quarter of 2012. We are in the process of developing our 2014 capital and operating budget, which will be presented to our board for approval in mid-December, so it's a little bit later board meeting than normal. At that time, we will inform you of our drilling plans, CapEx forecast, production sales guidance, cash flow guidance and midstream EBITDA guidance. This, of course, is our normal timing, given our board's authorities and the governance procedures that we have in place. We have, however, completed our annual strategy review with our board. None of what we agreed upon should surprise you, but at a high level, you should expect us to

[Patrick John Kane:]

Thank you, Dave. This concludes the comments portion of the call. Chad, can we please now open the call for questions?

[Operator:]

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

[Neal Dingmann:]

Say, David, maybe for you or Steve. Just a question, you got that big acreage Marcellus play in the Northern West Virginia area, your wet gas area there. I'm wondering in that position what are your thoughts. I know there's been chatter recently after the recent Antero and some other deals about the dry Utica potential in a part of that, and I would say maybe even a large part of that. I'm just wondering, Dave, kind of yours or Steve's thoughts about that, around that area, if that's something you would be looking at or are you going to continue to focus on the wet Marcellus there?

[David L. Porges:]

Well, eventually, we'll look at any area that has the potential for economic resources. I'll let Steve give a more specific response, but I would say, it's not top of our list right now. We've got plenty of things on -- at that top of the list, and that's not really one of them.

[Steven T. Schlotterbeck:]

Yes, I really don't have much to add. I agree. It's on our radar, but not at the top of our list. I think it's deeper. It's more expensive. It's dry gas. We're going to be focused on the more profitable Marcellus opportunity in that area for now. And we'll see what develops with the dry gas Utica, certainly there's some potential there, but not a high priority right now for us.

[Neal Dingmann:]

And then, guys, in that same area, have you picked up any acreage recently there? I've heard prices certainly recently increasing there pretty substantially. I'm just wondering if you have any thoughts on what sort of M&A deals you are going for?

[Steven T. Schlotterbeck:]

We really haven't picked up anything of any significant size. We're always continually picking up pieces to fill in drilling units and prices fluctuate, but they're more -- the small pieces we're picking up are more location-specific. So I don't know that we have much of a read on any major changes in acreage pricing in that area.

[Philip P. Conti:]

Neal, a lot of times we get a little bit better deals on acreage in the Marcellus because it is closer, the stuff we focus on, the stuff that's closer to our own development areas and probably has a little bit less value to others.

[Neal Dingmann:]

Okay, okay. And then, I guess, again, with your midstream, I know there's been, for some other people, some takeaway challenge, infrastructure challenges there. But Steve, it sounds like, I know with your company and all, it sounds like you're well on the way as far as midstream re-infrastructure there, isn't that the case?

[David L. Porges:]

Yes, but Randy is really probably a better one to comment on that.

[Randall L. Crawford:]

Yes, I mean -- Neal, this is Randy. Yes, absolutely. We're in strong shape. We have the Sunrise Pipeline that was completed last year that added incremental capacity in that area as well. And we continue to add additional infrastructure to keep ahead of the pace of Steve's team. So I think we're in solid position.

[Neal Dingmann:]

Okay. Then very last one, if I could, just very quickly. Just on that Utica acreage, 13,000 or 14,000 acres. Any thoughts on a type curve or how you, Steve, maybe feel like those wells will hold up?

[Steven T. Schlotterbeck:]

I think, obviously, it's pretty early. Those 3 wells are fairly new. I think the IPs were about where we expected given that it's our first venture into the play. I'll say they're performing much better than our first wells in the Marcellus did from a relative standpoint. And we are sure hopeful that will be able to improve our drilling completion practices, lower cost, increase productivity. So I think we're fairly encouraged. The returns, even at what the first 3 wells are doing, are not bad. So I think we're encouraged, but I think acreage prices in the Utica have been pretty high. It's a pretty competitive area right now. And I think our view is we're going to be patient and only pay what price the resource warrants. And time will tell how much acreage we're able to gather.

[Operator:]

Our next question comes from Drew Venker with Morgan Stanley.

[Andrew Venker:]

Just wondering after Devon announced its midstream transaction this week, if you would be open to considering a similar transaction if the right opportunity arose, or if you looked really at that transaction at all?

[David L. Porges:]

We've looked at it a little bit, but we actually rely on bankers, probably including colleagues of yours on the other side of the Chinese wall. They give us better feels for what those transactions entail. Because basically, we're open to anything that's going to help create shareholder value.

[Andrew Venker:]

Okay. Is there anything -- any other avenues you've looked at recently to monetize your GP interest or your other wholly-owned midstream assets that you can discuss?

[David L. Porges:]

We're monitoring all of that. We've got a notion of what our inventory, as it were, is for droppable assets. And I think, as we probably mentioned in the past, maybe not in these broad calls, but there's often a number of contracts that have to be put into place. And that we keep working on those, the ones that are at the top of the list is being the first ones to get dropped, and doing other things that are necessary to make some of the assets droppable as it were. As far as the GP, yes, eventually we're going to have to do something with that. But right now, our attitude is let's get the drops going or keep them going at a good pace. And that's what we commented on, exceeding the level that we have talked about initially of what midstream investments EQT makes. And that will be a nice problem to have, when we've created enough value there that we need to figure out ways to monetize. And we fully expect that, that is going to be a fork in the road that we reach.

[Andrew Venker:]

Okay, makes sense. And then one on the Marcellus. It looks like you guys have completed something like 80 wells year-to-date or connected 80 to shales, and if I'm not mistaken, your plan for the year is to connect or to complete 146. Can you help me with the pace of completions, I guess, in the back half of the year?

[Steven T. Schlotterbeck:]

Yes, I think our pace is always lumpy. And if you look back over the previous several quarters, you'll see the number of stages we bring online any quarter. Just so far, this year, it's varied from, I think, a low of right around 300 stages to a high of 1,500 stages. That's heavily driven by the timing of our large multi-well, multi-frac, 30-foot cluster space wells. So it's going to continue to be lumpy. I think the fourth quarter, we plan to bring on more stages than we did in the third, but we'll be far from the number we did in the second. So it will be sort of a modest quarter in terms of TILs with -- I think our projection is first quarter will likely be probably above average, when we look at the likely timing of the frac jobs and the drilling rigs.

[Andrew Venker:]

Okay. So some of the wells you are drilling this year maybe will be competed into next year, maybe a meaningful portion?

[Steven T. Schlotterbeck:]

Oh, yes, quite a -- yes, a meaningful portion.

[Operator:]

The next question comes from Michael Hall with Heikkinen Energy Advisors.

[Michael Hall:]

One of my key questions there was just on the timing of completions. And it sounds like fourth quarter '13 maybe a bump to the third quarter, but that will make up the full year. I guess, as I look at the third quarter, you tied on fewer wells than I had expected and yet had a very strong production result, implies good efficiency from the wells. Just kind of wondering if there's any updated commentary around Marcellus type curves in that context and how wells are hanging in relative to the curves you put up earlier this year and how we might think about that heading into 2014?

[Steven T. Schlotterbeck:]

Yes, Michael, we updated our curves earlier this year. And I think we tend to like to gather a lot of data before we update those. So no further update at this point other than to say we were pretty comfortable with the new curves when we put them in place and continue to be comfortable with those. So I think the wells are doing what we expected.

[Michael Hall:]

Okay, great. And then, I guess on the NGL guidance front, just a little curious on that. It's a little lighter than I had expected. Is there any continued impact from a midstream side on the NGLs in the outlook for the fourth quarter, or any sort of midstream things we're getting through or is that just...

[David L. Porges:]

The issue in the quarter was there was a MarkWest facility that ran into some operational issues. I don't know if Randy wants to provide some timing updates on that. But that would have -- if you're wondering why it was not as high as you would have thought, it was due to that type of a short -- kind of a short-term issue.

[Michael Hall:]

But that flowed into the fourth quarter then, I guess, that's what I was trying to get at. I thought that was more of a third quarter event than fourth.

[Randall L. Crawford:]

You're right, Michael. That NGL line that David referenced, the MarkWest takeaway out of the Mobley plant has been back in service and so that impact doesn't extend into the fourth quarter.

[Michael Hall:]

Okay. And then last one on my end, I guess, is we've talked about in the past, you got a lot of cash coming in. The recent -- some recent things in the market have suggested use of proceeds around share buybacks. What's your view on share buybacks in terms of using the cash that's coming in? Just curious on your thoughts there.

[David L. Porges:]

It's a good benchmark to be using when we're comparing it to other investment opportunities. And let's face it, the realistic other investment opportunities for us, as I mentioned, when I talk about strategy, are increased development in our core areas, the possibility of those tack-on acreage acquisitions and on the midstream side, those would typically be at the EQM level, projects that would -- that we tend to serve other producers. The kind of projects that are attractive with EQM's cost of capital but that EQT was never particularly interested in pursuing. So those are the things that you look at, and we just think it's a discipline, you should always be comparing those to share repurchases. We're -- and our main point was we're not afraid of what happens if we wind up with a lot of cash because we have dropped quicker than we need money or sold non-core assets before we need cash. If the right thing to do is to drop the assets at a quicker pace into EQM or the right thing to do is to sell some other non-core or less core assets, then that's what we're going to do. And we'll figure out what to do with the cash that results.

[Michael Hall:]

And as you look at that -- and that's helpful. How does share buyback, I guess, stack up in that context at present relative to the other potential uses of the cash? And are you limited somewhat in your ability to accelerate on the upstream side? And does that play into any sort thought process?

[David L. Porges:]

I don't know if I want to say that we're limited in our ability to accelerate, but we do as -- this is kind of the norm in this area, we do run into judgment calls on whether you develop now, let's say, a pad that has fewer wells, shorter laterals or whether you give it a little bit more time to try to get the acreage or the permits to be able to have more wells on a pad longer laterals, et cetera. So you do run into those kinds of timing issues. And we also don't like to be -- have artificial milestones that would inhibit us from making the right economic decision there. But more broadly, we're probably best off letting our whole capital budget process play out with our board before we get into other topics. Obviously, the preference, of course, is if we have attractive investments in our core that can create the value that we've been creating, we certainly recognize that, that is the preferred route to go. We just don't want to force it and get to the point where we're making investments that don't stack up versus share repurchases.

[Anne Cameron:]

Okay, that's helpful, appreciate it. And I guess -- actually I had one last simple one, the -- in your strategic review, just to be clear, that last bullet point you outlined, drive spending on the midstream side. Is that at the EQM level that, that spending would occur?

[David L. Porges:]

Yes, that is -- that was the point I was trying to make is that you should expect to see more of that spending at the EQM level, and we do recognize that, that means when we start more providing CapEx guidance, we're going to have to be careful to provide guidance on what spending is occurring at the EQT level versus at the EQM level because EQT's consolidated reports will include all of the EQM spending and that gets -- we recognize that could kind of get tough to sort out because the cash flow isn't really coming into or going out of EQT Corp., it's going through EQM.

[Operator:]

The next question is from Ray Deacon with Brean Capital.

[Raymond J. Deacon:]

Randy, I was wondering if I could ask you a question about pricing at the M2 hub and how you see that changing going forward relative to other places where you're selling gas.

[Randall L. Crawford:]

Sure. I mean, obviously, you saw what Phil reported today in terms of our basis, and I think he also pointed out that we had some forward sales that show up in the hedge line that contribute a positive $0.07. But overall, Ray, I mean, with respect to basis in M2, I mean, I think from a short-term perspective, short-term basis markets, I mean, they're really fundamentally driven. I think that TETCO and the M2 is a strong pipeline with access to good markets, but really any assumption for pricing for the winter, the next summer, is subject to a lot of inputs, as you know, the weather, supply disruptions of growth, really, the absolute NYMEX storage fills. But the impact of the infrastructure projects to transport the gas out that the M2 and TETCO are working on are more certain variables, and I think these projects are going to continue to help mitigate any supply and demand imbalances in the region.

[Raymond J. Deacon:]

Okay. Got you. And I was wondering, any further update on the Upper Devonian, and I was wondering if you can also talk about how development going forward might look on pads to incorporate Upper Devonian wells?

[Steven T. Schlotterbeck:]

Ray, this is Steve. No further technical update on the Upper Devonian. But -- and I think we still are looking at what we think the best development scenario for that is, regarding number of wells on a pad and timing of Upper Devonian versus Marcellus. And we haven't really concluded that study yet, we're still gathering data. But I mean, my gut feel is it's likely going to conclude that for -- especially for the bigger pads, pads where we have the potential to drill a total of 20 wells, it's most likely to look like drilling a portion of the Marcellus and a portion of the Upper Devonian and then de-mobbing rig and coming back in a year or 2 and drilling the others. Generally, it will probably be all in one direction, and then the other half in the other direction at another time. But I think our thought is that from a completions standpoint, we're going to be better off frac-ing the Upper Devonian and the Marcellus, the stack side, at the same time, rather than doing all of the Marcellus and coming back and doing Upper Devonian later. And then when we look at the economics of doing, say, 20 wells from 1 pad and the infrastructure and facility investments that would be required to handle those peak rates, I think it's going to be economically more optimum to split it into 2 pieces. So that's where I think we're headed. But we're still studying it to find out for sure. I don't know if that answer helps you or not.

[Raymond J. Deacon:]

No, that's very helpful.

[Operator:]

Our next question comes from Phillip Jungwirth with BMO.

[Phillip Jungwirth:]

Just sticking with the Upper Devonian. Have you seen any change to the performance of the 2013 vintage wells versus the well that you highlighted last quarter, which I think had EURs of 1.2 Bcf per thousand lateral foot.

[Steven T. Schlotterbeck:]

Sorry, you're asking if the Upper Devonian wells have impacted the Marcellus wells?

[Phillip Jungwirth:]

No, just the newer wells have seen improvement versus the 1.2 Bcf that you quoted.

[Steven T. Schlotterbeck:]

I don't -- we don't have enough new data to really draw any conclusions on that. So I would say no at this point.

[Phillip Jungwirth:]

Okay. And then in terms of acreage acquisitions, do you have a target in the Marcellus, such as you think you could pick up maybe 10,000 acres over the next year or 20,000 acres?

[Steven T. Schlotterbeck:]

No.

[David L. Porges:]

No, it's just whatever is economical. The only thing we're influenced by though really is that sometimes, some things more economical can alter the existing development plans. And that -- a lot of times, that depends on what opportunities are available. That certainly happened with the Chesapeake acquisition earlier this year, and that's -- those are obviously the ideal situation. But no, we have not had a target. We've tried to stay away from that because, again, our fear is that if we have targets on things like that, we'll wind up doing things that are not economical.

[Phillip Jungwirth:]

Okay. And on the 3 Utica wells, what's the average well cost in lateral length there?

[Steven T. Schlotterbeck:]

The average well cost for those first 3 wells, I believe, was around $8.5 million, but they included a significant amount of science, as we call it, so coring, specialty logging, some fairly long well lines to get to our gathering systems. So we don't think -- the well cost for the first 3 are not representative of what we expect. We expect well cost there to be in the $6.5 million per well range going forward. And the average lateral length, I'm sorry, they range from 4,500 to 6,800. I don't have the average in front of me. 5,800 feet, I think it is.

[Phillip Jungwirth:]

All right. And then last question on the midstream dropdowns. Can you just remind us of the historical guidance there? I think it has been 1 drop a year. And then, in terms of size, it would be midstream CapEx, which is around $350 million. And for accelerating net, are you talking increasing the pace of drops, the size, or both?

[David L. Porges:]

It -- well, first of all, I don't think -- I don't know that we ever guided to the number of drops per year, but the dollar amount numbers that you are quoting, that's correct, is that we were, at the time of the IPO, probably linking it to midstream CapEx at the EQT level. I guess you'd say upon further review, that is -- EQM is the better place to own some of those assets. So the timing on the drops is really set more by when an asset at the EQT level is in the position, both legally and operationally. A lot of times, it might mean you filled a lot of it up contractually as well so that we can drop it, and the capital market's access at the EQM level. But that's really what's setting it. And therefore, I don't really want to give a number on how -- or what the dollar amount would be, but you should expect that until we start running low, that we're going to be averaging well above that level of the EQT Midstream CapEx. And of course, the other moving piece is as EQM continues to grow, it's a little easier for EQM to wear projects at the EQM level, right? I mean, the main reason we haven't been doing very much investment at the EQM level is because that vehicle is very difficult to have a lot of cash in -- or a lot of investments in noncash generating projects. So that wait period from when you start putting the cash in to when you get the cash flow out from fees, that's tough. It's tough to have too much of that. But as EQM grows, it's easier to have more of that and to be able to wear more projects at that level. So that's the other thing that you should be seeing, which we probably didn't -- we talked about the possibility of that happening at the time of the IPO, but we weren't really anticipating any specific projects. And now, we're tending to look more at projects that would be at the EQM level.

[Phillip Jungwirth:]

Okay, great. And with that, should we think of any amount of CapEx, midstream CapEx, that's now being spent by EQM as being used in the upstream business? Is that a one-for-one type relationship there?

[David L. Porges:]

No. We tend to have more of the -- don't mind [ph], would be too much of a purist, but money is fungible, and you make the right investment decisions based on what you think creates the most value and you don't necessarily say money from this area goes into that area. It's much more of what do we think will create the most value. Practically speaking, we are focusing the EQM investments on projects that tend to support other producers a little bit more. And the EQT Midstream projects are a little bit more the ones that support EQT. But I think at this point, that's just kind of happenstance, it's not necessarily that there's some philosophy. The philosophy is just keep assessing how can we create more shareholder value.

[Operator:]

This concludes our question-and-answer session. I would like to turn the conference back over to Pat Kane for any closing remarks.

[Patrick John Kane:]

Thanks, Chad, and thank you, all, for participating.

[Operator:]

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