EQT Corporation (EQT) Q2 2013 Earnings Report, Transcript and Summary

Good morning, and welcome to the EQT Corporation Second Quarter 2013 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Mr. Patrick Kane, Chief Investor Relations Officer. Please go ahead.

Thanks, Yussaf, and good morning, everyone, and thank you for participating in EQT Corporation's second 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 1:30 p.m. Eastern Time today. The telephone number for the replay is (412) 317-0088 with the confirmation code of 10025410. 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 is a separate press release issued by EQM this morning, and there's a separate conference call today at 11:30 a.m., 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, confirmation code 10025420. In just a moment, Phil will summarize EQT's operational and financial results for the second quarter, which were released this morning, then Dave will provide an update on strategic and operational matters. Following Dave's remarks, Dave, Phil, Randy and Steve will be available to answer your questions. I'd like to remind you that today's call may contain forward-looking statements related to the 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 and under Risk Factors in EQT's Form 10-K for the year ended December 31, 2012, filed with the SEC as updated by any subsequent Form 10-Qs, which were on file at the SEC as well. Today's call may 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 2013 earnings of $0.57 per diluted share, a $0.36 per share increase versus the second quarter 2012 diluted earnings per share. Those outstanding financial results were driven by another strong operating quarter at EQT. Production sales volumes in the quarter were 54% higher than last year, NGL volumes were 52% higher and midstream gathering volumes were up 50%. These very positive 2013 second quarter results were slightly offset by the impact of $16 million in noncash incentive compensation expense that was about $6.7 million higher than last year, as a result of the increase in EQT stock price, improving our share total return relative to a group of industry peers, which is a key driver for our incentive compensation plans. In addition, exploration expense was $4.3 million higher, as a result of a $5.2 million noncash lease impairment. These 2 variances lowered EPS in the quarter by $0.05 versus last year, but had no impact on operating cash flow. Operating cash flow in the quarter totaled $317 million or nearly double last year's $166 million of cash flow. As Pat reminded you, EQT Midstream Partners, or EQM, results are consolidated in EQT's results. The impact of the noncontrolling interest is a little more clear on the income statement than it is in the cash flow results. Net cash provided by operating activities at EQM was $26.1 million in the quarter and included in EQT's consolidated cash flow. However, please do note that not all of that cash flow is available to EQT, as noncontrolling unitholders owned approximately 40% of EQM during the second quarter 2013 and, currently, they hold approximately 55.4% post the recent follow-on offering. Clearly, top line growth drove the relatively straightforward financial results in the quarter, and I will now briefly summarize those by business units, starting with EQT Production. Our net Production sales volume continued to grow dramatically. As we mentioned, Production volume was 54% higher, and that growth was driven by a 111% year-over-year increase in sales from our Marcellus Shale play. Prices were also improved with the realized price at EQT Production of $3.30 per MCF equivalent, compared to $2.62 last year, or a 26% increase. At the corporate level, EQT received $4.37 per MCF equivalent, compared to $3.83 received last year. The average NYMEX gas price for the quarter was $4.09 per MCF, compared to $2.22 last year. Basis was approximately flat with NYMEX both years. Two items impact the realized price this quarter. First was the ineffectiveness of hedges, totaling about $7.5 million, which reduced our hedge gain in this quarter. Second, was the loss on the resell of unused capacity not under long-term contracts, which totaled $8.3 million in the quarter. We've been adding that number back to adjusted earnings as, initially, we saw noticeable swings from gains to losses quarter-to-quarter, however, this is the fifth quarter in a row where the loss has been relatively stable, so we stopped adding the cost back to earnings beginning this quarter. This shows up in our price reconciliation as third-party gathering and transmission. Produced NGL volume was 52% higher than last year. And as a reminder, we do not include ethane in this calculation, as it is currently sold mostly as methane. Total operating expenses at EQT Production were higher quarter-over-quarter, as a result of higher DD&A exploration expense, LOE and production taxes. At the same time, per unit LOE, excluding Production taxes, was down 20% to $0.16 per unit, further improving our cost structure that is already among the best in the industry. SG&A was also down on a unit basis. Those decreases were the result of produced volume growth that vastly outpaced higher costs. Midstream results. In the quarter, operating income here was up 21% due to the growth of gathered volumes and increased capacity-based transmission evidence. Gathering net revenues increased by $14.9 million, as gathering volumes increased by 50%, somewhat offset by a decrease in the average gathering rate of 19% due to the increase in Marcellus gathered volumes, which are relatively less expensive to gather and, therefore, get charged a lower rate. As Marcellus production continues to grow as a percentage of our total production mix, the average gathering rate paid by EQT Production and other producers will continue to decline. We expect our fourth quarter 2013 average rate to be $0.75 per MMBtu. However, EQT Midstream margins are expected to continue to be strong. Midstream transmission net revenues also increased by 81% in the quarter, driven by higher capacity charges and throughput. Storage, marketing and other net operating revenues was $9.2 million lower in the second quarter. And as I've mentioned several times before, the storage and marketing part of the Midstream business relies on natural gas price volatility and seasonal spreads in the forward curve, and those have continued to decline. Given current market conditions, we currently expect full year 2013 net revenues in storage, marketing and other will total approximately $30 million. Net operating expenses at Midstream were up quarter-over-quarter, however, as in Production, per unit gathering and transmission expense was 32% lower, driven by the tremendous volume growth. Just a couple quick notes on the balance sheet. We closed the quarter with approximately $55 million in short-term debt. But subsequent to quarter end, we received $508 million in cash, as well as some additional LP and GP units from the sale of Sunrise Pipeline to EQT Midstream Partners. Dave will go into a little bit more detail in that in a minute, but that gave us a current cash balance of approximately $400 million as of July 22. We continue to have full availability under our $1.5 billion revolving credit facility. Our operating cash flow estimate for 2013 is slightly higher, at approximately $1.2 billion, using the current strip and revised volume forecast. That's versus a CapEx forecast for the year of $1.7 billion, and that includes the asset purchase we made from Chesapeake that we announced earlier in the second quarter. So along with the proceeds we received from the sale of Sunrise, we're clearly in very good shape, from a liquidity perspective, heading into the rest of the year. And with that, I'll turn the call over to Dave Porges.

Thank you, Phil. As Phil summarized, operationally, we are coming off another record quarter, with record volumes at Production and Midstream. We hit a significant milestone in the quarter, our first day of sales above 1 Bcfe. In fact, we averaged over 1 Bcfe per day for the entire quarter. So congratulations to the EQT Production folks who made that happen, along with the Midstream folks who moved those volumes and the Commercial folks who sold them. Production volumes were higher than expected because we turned pads and lines faster than planned. We have discussed the lumpiness of volume growth resulting from the timing of turning pads and line Midstream projects, et cetera, and this lumpiness was again evident in the second quarter, with some anticipated third quarter production being accelerated into the second quarter because of the timing of some specific pads. Much of this increased volume flowed through our gathering and transmission systems, driving the growth in those businesses also. We finished frac-ing our third Utica well during the quarter. But since we were waiting for a gathering line, we just turned our first Utica well in hours ago -- turned it in line hours ago. The other 2 Utica wells should be turned-in-line next month. So while we would like to provide Utica results on today's call, we instead ask that you be a little bit more patient. We do have 4 Upper Devonian wells in line, and are quite encouraged by the early results. These 4 wells have an average EUR of 1.2 Bcfe per 1,000 feet, which is near the high end of our expected range. Put another way, a well with 4,800 feet of lateral pay would have an EUR of about 5.8 Bcfe. While the economics of the Upper Devonian wells are not quite as high as the Marcellus wells, they're still quite good with average after-tax IRRs in the mid-30s and a $4 gas price. Also, the overall economics for EQT are boosted by the efficiency involved with drilling these wells at the same time and place as Marcellus wells. Based on the early success, we are tweaking our drilling program a bit. We are increasing the Upper Devonian program by 11 wells to a new total of 22, that's in 2013. At the same time, we are reducing our Marcellus program by 11 wells to a new total of 146. We will continue to drill the Marcellus and Upper Devonian wells on the same pad, using the same rigs and completion equipment. So even though the well allocations are tweaked slightly, the overall activity is essentially unchanged. Increase in Upper Devonian wells accomplishes 2 things: it accelerates the de-risking of the play and it allows us to improve productivity by increasing the total wells per pad, leveraging the surface cost across more wells. If we had stuck with the original plan, we would have foregone some efficiencies, as we would have still drilled the Marcellus wells at those pads, but would then have moved the equipment off of those locations and would have had to incur more costs to return to the pads in the future to drill Upper Devonian wells. Shifting gears, as you no doubt saw, we completed our first drop into our MLP. Last week, we sold our Sunrise Pipeline to EQT Midstream Partners for $507.5 million in cash and $32.5 million worth of common and general partnership units. EQT Midstream Partners also agreed to pay additional consideration of $110 million to EQT upon the execution of a third-party transportation agreement that we expect to close concurrent with the closing of the utility sale. To pay for the acquisition, EQM issued 12.65 million units. Post transaction, EQT now owns 42.6% of the LP units and a 2% general partnership interest. As a reminder, EQT does have incentive distribution rights, which means once the quarterly distributions per unit hit predetermined thresholds, the percentage of incremental cash flows paid to the GP increases up to a maximum of 50% of incremental cash flows. There are 2 intermediate steps between the 2% and 50% levels, with those breakpoints being at just over $0.40 per unit -- just under $0.44 per unit, and then finally reaching the 50% split level at $0.525 per unit. Now assuming that EQT Midstream Partners increases the distribution by $0.03 per unit each quarter, from its current $0.40, EQT would be into the 50% splits before the end of 2014. Do recall that for each split, the higher share only applies on the amount above the base. So if there were ever a moment at which the distribution were exactly $0.525 per unit or that breakpoint in the 50% split, the GP would be receiving about 7.5% of that distribution plus 50% of the amount over that level. Based on our internal estimates, cash flow to EQT, just from its GP stake, is projected to be about $33 million for 2015. Applying publicly traded GP multiples to that estimate would result in potential value to EQT shareholders of around $6 per share at that time. The timing and size of EQT drops can materially impact this cash flow estimate, higher or lower, and the trading multiples seen today could be higher or lower. That said, it is clear that there is significant value in our GP stake, and that's the reason we wanted to give you some insight into how we look at that value. Switching topics, we have nothing new to report on the regulatory reviews related to the sale of our gas utility, Equitable Gas Company. As you already know, the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act expired, and we are free to proceed from a Federal Trade Commission perspective. We have also submitted filings with the Pennsylvania Public Utility Commission, the West Virginia Public Service Commission, the Kentucky Public Service Commission and the Federal Energy Regulatory Commission, each of which must approve the transaction as part of the regulatory process. There have not been any unexpected developments in this lengthy process, and we still expect to receive all necessary approvals by around year end. Finally, as has been our norm, we are providing production sales guidance for the current quarter, so that means the third quarter 2013. Based on our current pad completion schedule, we expect third quarter production sales to be flat with second quarter at 92.5 Bcfe, as new pads provide volume that offsets declines from initial production at those wells we turned-in-line during the recently completed [indiscernible]. We did increase our full year forecast between 360 and 365 Bcfe, which is 40% higher than last year's. 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 appreciate your continued support. And with that, I'd like to turn the call back over to Pat for the Q&A session.

Thank you, Dave. This concludes the comments portion of the call. Yussaf, can we please now open the call up to questions.

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

Dave, maybe just first quick question. I won't stay too long on the Utica. You mentioned about finished frac-ing the 3 well. Did you mention that you tied the first drill in the pipeline? Did I understand that right?

Yes, that was just hours ago. Yes.

And then you think on a go-forward basis now -- I mean I know there had been some midstream delays, so once you got this first one on, is it fair to say, as you and Steve start rolling out these wells, you'll be able to tie them in a sort of timely fashion?

Well certainly we'd be able to tie them in, if it were just Steve and I turning them in line.

That's good news for the shareholder, because other people are doing it.

But yes, look, the issue we're probably going to have on Midstream with the Utica is going to be the same as others do, which is we're in a window where we've anticipated that there's going to be a -- there could be some wet gas. And, of course, it will be the processing that's the issue. So as far as the pipe, yes, I think we're fine on that for our plans. And then the issue is going to be when we decide that what we really need to do to extract the most economics is to strip the liquids.

Crude oil of course, to the extent we have that, if something is coming out, if it's liquid, it's surface pressures, then it's -- that's, of course, a different story, that's a little bit easier to deal with over time.

Okay. And then I know you all have said, kind of reaching that, I don't know, if it's 50,000 what your goal is now. I mean if -- is there a certain time that if -- I know acreage is a bit tougher to come by there. What's your thoughts on that, Dave? I mean would you still sort of stick with what you have? Or is it kind of an all-or-nothing deal as you can't add a significant amount of acreage here in the near future?

Well, the 50,000 acres, of course, was always just kind of a benchmark. What we really mean is something that is an economical size. So that's -- at this point, we're encouraged that there are some pieces out there that we can look at and we'll just have to see how that plays out. I actually don't know that I'd say that acreage is not available, I think that a lot of folks are sorting through their portfolios. I mean I understand that's a routine thing to happen. Maybe it's more normal that it's happening now after a lot of people compiled portfolios, and now they're sorting through, just as we are with our portfolio, of course. What fits, what doesn't fit. And not just from a perspective of what looks good from a reserve perspective, but what helps you put together a development plan of a reasonable scale. And I think that we're all kind of going through that process. So I'm not discouraged, actually, about there being no opportunities out there.

Got it. Got it. And then turning over to, obviously, Marcellus. I was just looking at your slide, where you sort of outlined the amount of Midstream, as far as the transmission capacity, over 1.7 billion and the miles of transmission pipeline. I guess what I'm getting at is, now that you're able to turn these pads and lines faster than expected, obviously it's a nice problem to have. I guess my question is, it seems like because you guys do control your own pipeline or your own Midstream, do you have -- are you going to be ramping that up as far as how quick and how much money you'll be adding to the Midstream? Or are the plans already sufficient enough to sort of factor in this faster pads and lines coming on?

Well we certainly have plans and line that are consistent with the production plans. But it is a rapid rate, there's no doubt about that. So that does require a fair amount of hustling to keep going and it's not -- we continue to be open to moving some of our volumes through other people's lines, just as we're -- we build our facilities to often times accommodate other producers. So I guess we have kept that in mind. Now we don't, of course, control our own processing, right? So that's one where we continue to work with folks who do that to make sure that, contractually, we're able to organize enough capacity. But the volumes are going up so quickly in this neck of the woods that I'd say we're always feeling as if we're running pretty fast. So I don't know that we'd ever want to feel that we're sanguine, I think we feel optimistic that we can get things done, but I -- we can't rest on our laurels because the lines are just jumping up so quickly.

And last question, if -- I think you've said this before. Do I understand this right, as far as kind of potential for dropdown it's in the Midstream, whatever. If you are able to bring on a little more, you spend a little more in that area, is it always -- continue to drop down about 1/4 of what you have or if you could just remind us of kind of the plans on a kind of annual basis of what you potentially could drop down?

Well we don't really have a plan on an annual basis that goes out there. We have said that, over time -- let's say the floor is that we would like to be generating proceeds at the EQT level from drops that equals the amount of spending EQT has on the Midstream. But over time, of course, we will want to be dropping more into EQM than we are spending. So -- and the other thing that's taken into account when you're looking at the -- what I gather from the market's perspective was larger-than-expected drop, is a lot of these assets that we'll be dropping, when we do drop a specific project or asset, they're going to be lumpy. So some of them are going to be larger and some of them are going to be smaller. But we're -- you should not take the size of that drop to be an indication that somehow we've ramped up our decisions on spending at Midstream at EQT level. We're going to keep dropping as it looks economic to do so. And it's just that we've got this floor where, over time, we'd like to make sure we're dropping enough so that the proceeds are going to be paying for the Midstream expenditures.

Our next question comes from Phillip Jungwirth with BMO Capital Markets.

With over $1 billion in cash coming in, in the second half with -- from EQM and the utility sale and then what looks to be a minimal outspend in 2014 and beyond, how are you thinking about capital allocation between: one, accelerating in the Marcellus; two, share buybacks there; or, three, increasing the dividend?

We are looking at it -- I don't want to be trite here, but we are looking at the same way we will always look at it. We think that -- we're not -- we don't believe our decisions are being, or should be, overly influenced by what the balance sheet says. Unless, of course, we just didn't have enough money to do some of the things that we wanted. But we should be investing in the projects that create value and foregoing the projects that don't. Being temporarily a little bit more liquid, we don't feel, creates any pressure or burning holes in our pockets, et cetera. So we do examine other ways to invest the money, such as share buybacks and dividends. But we view it the same way I'd say that we always do. We compare the investment opportunities and, yes, anybody who looks at our incentive comp plans knows that the way that this management gets paid is to have our share price perform over the course of time. So hopefully, we're aligned with the shareholders in that regard. We just want to create value. And I'd say from that perspective, it hasn't changed. When I became CEO, the strategy was we need to pick what we want to invest in and what we want to offload. And I'd just say that we're kind of in the midst of that process. So we'll continue also to look at monetizing things that whereby perhaps the value is greater in the hands of others.

And then, on EQM, with the GP potentially in the high end of the split in the next 18 months, and probably -- could be earlier, assuming a lower coverage ratio of 1.1x. I mean, how would that impact the valuation and EQM's ability to raise capital to pay for future dropdowns, given that the GP will be in the high end of the split so early? And then where was the GP valued at in the $32.5 million of proceeds of EQM's stock per unit?

Actually, Phil probably has the answer to that. Or why answer the rest? [indiscernible] How much of the $32.5 million was extra LP units versus...

Yes. The units that we got back, in addition to the cash, were 480,000 limited partner units and then 268 GP units -- 268,000.

Another way to look at that would be the 400,000 LP units at the market price at that time, and then the rest is the GP. So [indiscernible] LP, and the rest, GP. Go ahead.

Okay. And then next question, can you share with us your views, both near-term and long-term, on where you see Marcellus base is going? And then how the recent weakness will impact the third quarter?

Well, that's -- for that one, I've been doing a lot of the talking. So I will turn that over to Randy. Though we -- and -- Randy, what are your thoughts on bases?

Sure. When you talk about short term and long term. In the short term, right, I mean, the influx of supply, the natural gas in the region, is -- for the purpose of blending, higher-Btu ethane, producers to put pressure on the basin. So -- but -- this is, we think, will be somewhat alleviated with the Mariner West project that just came online this week, and the ATEX project that is said to come on in early 2014. And just to close the loop on that ethane topic, EQT has a tremendous dry gas resource in Western PA, as you know, and particularly in Greene County, so that provides us the ability to blend our ethane with wet gas production for the foreseeable future. Now in regard to the long term, in the long term, we have stayed ahead of the curve in terms of planning our takeaway capacity. So currently we have almost 655 million decatherms per day of firm pipeline capacity that's out of the basin, and we have approximately 400 million decatherms per day of firm sales. And so -- for a total of about 1.05 Bcf per day. So we recognize that the basin is in its growing stage and we're remaining flexible with regard to making additional long-term commitments. And obviously with that said -- we have committed to an incremental 300 million a day pipeline capacity expansion into the Gulf Coast, in the Mid-Atlantic markets, which we have scheduled to come on in service by the end of 2014. So moving forward, we continue to add firm capacity to portfolio and we add to the diversity of markets. And so, we've been on this issue and we're continuing to look at those diversity of markets and liquidities. So in the long run, we think that including the growing Southeast markets, we should be in good shape.

Okay. Great. And then last question, real quick. Where -- on the Upper Devonian wells, did you use RCS on those?

Phil, this is Steve. We used RCS on 1 of the 4 wells that we have production date on. So the results that we're quoting are 3/4 based on our 60-foot clusters and 1/4 based on the 30-foot cluster test. So -- and our expectation is, just like we're seeing in the Marcellus, I think we'll have to test this to find out, but I think we're -- we think it's likely that the Upper Devonian will benefit from 30-foot cluster spacing. So for the wells we're drilling this year, they'll be using the 30-foot clusters.

Our next question comes from Drew Venker with Morgan Stanley.

So with your updated 2013 outlook for the higher production, do you have any update for what 2014 production will look like?

No, we haven't read -- of course, we introduced some guidance on that, but we're now getting to the point we're in the run-up to our annual capital budget and plan process, so we don't want to get out in front of our board as far as what kind of approvals we'll get for that. So at this point, this time of year typically, also, we'd just as soon stick with the guidance that we've put out there. And then, of course, we'll update that once we have a under-capital budget.

Okay. So I guess presuming directionally higher is maybe getting ahead of ourselves, I guess?

I just -- in case our board members are listening, and I don't want to presume something that assumes that they'll provide approvals to stuff that we're proposing to them but haven't actually put in front of them, yes.

That's fair enough, fair enough.

Not great timing for that, is all I'd say.

All right. Okay. That's fair, that's fair. And then you talked about reducing your Marcellus program this year by 11 wells, is that pretty evenly distributed across your development areas?

Yes, and that's really just driven by the desire to maximize our rig efficiencies and drilling more Upper Devonian wells while the rigs are on certain locations. Given the results we've seen in the Upper Devonian, we think that's the prudent thing to do. So, yes, it's pretty equally spread around.

Okay. Can you talk about initial rates on those Upper Devonian wells?

I don't think we've provided IPs but, again, the average is about 1,200 or 1.2 bcf per 1,000 feet EURs. And for these wells, we actually have a fair amount of production history. So the oldest well has been producing for 3 years and another couple for 2 years and the fourth one for a year. So I think these are not as speculative as EURs as you might have imagined that they are in terms of how much data we had to look at. I'd also say that, again, since these wells were drilled 2, 3 years ago, our drilling completion techniques in the Marcellus have improved pretty dramatically over that time. We're certainly hopeful that we'll see that same kind of improvement in the wells we're drilling today in the Upper Devonian. Time will tell if that's true or not, but we certainly are optimistic that we can improve on what we've seen.

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

I guess, a couple on my end, first, more near-term oriented. Just curious on the third quarter production volume guidance. Are there any kind of implicit assumptions around building up or drawing down of completion backlogs within that?

No, all I'd say is if -- you've probably noticed in the second quarter, we drew down the backlog pretty substantially. All of that is just driven by the timing of these large multi-well multistage pads. It just worked out that a lot of them came on in the second quarter, which means they'll probably be -- rigs will be moving to new multi-well pads, so there'll be a bit of a hiatus in new TILs in the third quarter. So I would expect that you'll see that backlog build back up somewhat in the third quarter. But it's all driven just by the timing of these big pads.

Okay. So it is somewhat assumed that you'll have some increase in backlog again in the third quarter?

Yes, I would expect that. Which is why we're projecting basically flat volumes in the third quarter over the second, but the backlog should increase.

That makes sense. And can you just remind me where -- or like how many of your rigs are in each of your key areas at this point? Meaning Northern West Virginia, Southwestern PA and then Central PA?

I believe right now we have 3 in Southwestern PA and 3 in Northern West Virginia. Pretty sure that's right. They move around a little bit, so I'm not always completely up to speed.

Okay. But that kind of 50-50 split is probably fair throughout the rest of the year, is it?

Yes, I think that would be pretty close.

Okay. Let's see -- and then I guess a lot of my others have been addressed. I'm curious on the inclusion of additional Upper Devonian wells and doing those on the same pads as the Marcellus wells, does that -- how do we think about that in terms of cycle times for those pads? Is it just going to spread things out a bit more? Although reducing the per-well cost because you're going to spread it over the pad, over more wells, is it spreading out the cycle times a bit as well?

That's a good question and I probably can't give you a great answer yet. That's certainly a topic that we are actively studying now, trying to determine what is the optimum scenario, especially for these very large pads. So if we have a 10-well Marcellus pad and the opportunity to drill another 10 Upper Devonian pads for a total of 20, we're currently modeling. Does it make sense, is it optimum to drill all 20 right now? Or does it make sense to drill 5 Marcellus, 5 Upper Devonian, leave and come back later? Or should we drill all the Marcellus now and come back? And some of the issues are just logistical in nature, but there's also some factors around -- some concerns around the effectiveness of the fracs, particularly in the Upper Devonian, if we would come back significantly later after frac-ing the Marcellus because of depletion and potential interference between the 2. So we're doing a lot of reservoir modeling combined with a lot of logistical study to sort of sort. So bottom line is, right now, I don't -- I can't tell you what the optimum is and what the impact will be. Part of the reason that we're drilling some more Upper Devonians this year on existing pads is to help us figure out how that -- what the optimum is going to be.

Okay, that makes sense. And so, I'm correct in assuming you can't -- you're not doing simultaneous completions while drilling, correct? You can't do both on the same pad?

I don't know that we're -- we're not frac-ing while drilling, but we're doing a lot of other simultaneous operations, a lot more than we used to.

Okay. And then I guess the last on my end is more of just kind of getting back to corporate structure and thinking about unlocking some of the value. As we get -- we're getting closer toward the end of the year, you've talked about a couple of other different ways to, say, monetize some latent value. You brought up in the past potentially bringing in or trying to find third-party capital around the Huron program to restart that growth. Also now with ONEOK's announcement of spinning out the utility and have a standalone GP that maybe raises some [indiscernible]. Another interesting comp around EQT in terms of unlocking value, you did highlight you'll be hitting those splits relatively soon. So I'm just trying to think through, and better understand, what current thoughts are today, particularly in the context of that ONEOK announcement.

Well the ONEOK announcement, itself, of course, doesn't really have much impact on us. We looked at the alternatives around LDC before we decided to sell, as opposed to doing some type of a spinoff and things like that. We looked at that. Well we're obviously interested to read more, as we are with any of our companies and any of our peer group, interested to read what they're up to and look at their rationale and see how it turns out for them. But the thought process we have on monetizing other assets as a best way to create shareholder value is really the same as it was. If we're not going to be able to -- or don't think it's economical for us to do the development, the optimal development of those assets, then we look at alternatives, whether it's selling to somebody else, as we've done a couple of times, or getting some other source of capital, as we have, of course, with the Midstream, with the MLP. So I don't think there's anything magic about year end for that. We're obviously not pressured from a liquidity perspective, that's in reasonable shape, I'd say. So we'll continue to work on that. I mean the -- so the urgency isn't raising capital, the urgency is doing the right thing to create value. And we continue to look at those alternatives. I mean, obviously, Nora and Huron are ones that we've talked about the possibility of having different approaches to that. With Midstream, I think the issue is going to be drops and I think a lot more of that is going to be driven by what's going in EQM than EQT, what the capacities are and things like that since, again, we do think that the best owner of a lot of those assets is probably EQM, as opposed to EQT. And then to help you figure out what we do with it, with the MLP, generally, and the GP, you're right, we started introducing the issue of how much value could be there and, frankly, we're going to be trying to being -- encouraging our shareholders to take a look at what that value is. And it's hard to tell whether there's going to be enough transparency there that things will be fine as we move through the splits or whether the right thing to do will be to do something else. The separate issue somebody else had raised about what do you do when you get into a high splits for the GP, that's a real issue for MLPs when they grow that fast. And separate from EQT corporate structure issues, when we get to that point, we will have to address that issue so that EQM is able to make acquisitions that are accretive for its unitholders.

That's helpful. Can you remind me what the timing or potential timing around when EQM would be more self-sufficient from a CapEx funding perspective?

I don't know what's...

Does that get accelerated at all, given that the size of the drop is a bit bigger than expected?

Can you help me a little bit with what you mean by self-sufficient? Because it's -- that's a market where there are -- unlike the C core [ph] market for oil and gas companies where issuing equity is not possible...

I guess what I mean is the growth -- a lot of the growth capital is being spent at EQT, currently, and then matured under EQT, and then dropped down eventually into EQM?

I think it's -- the way I kind of think of it is just -- this is [ph] very rough -- and hopefully the team doesn't view this as some kind of a revelation, but it seems, just from observation, that spending roughly 10% of one's cash flow on organic investments is something that can be worn reasonably comfortably at an MLP. The issue is more that it's able to continue to grow its distributable cash flow per unit. And that's just hard to do when you have capital tied up in long-lead-time projects. So that's really the drive, right? If we spend a lot of money at EQM on multiyear projects, it would be tough for it to increase its distributable cash flow per unit. Now obviously, quick-turnaround projects, so de-bottlenecking and things like that, there's probably no grade limit on that. But as far as bigger projects, I think it's much more, can EQM continue to increase its distribution to per unit at comps? So let's say the comps and coverage rates, with money tied up in long lead time projects. Does that...

Yes, that's helpful. I was just trying to also think through this, when -- just when we could think about breaking up the Midstream/MLP ownership within EQT from the upstream to maybe better highlight the value of the Midstream units, but [indiscernible].

I don't think that issue of EQM being able to make the investments directly as opposed to EQT necessarily get in the way of the structuring issues. Frankly, the same thing is true of the GP going to higher splits. I think those are separable issues.

Our next question comes from Becca Followill with U.S. Capital Investors (sic) (Advisors).

I have a question of what you would do with the excess cash that you have at EQT? Could you talk about your capacity to increase drilling levels in terms of the ability to get permits, crews. By how much could you increase that capacity?

Do you have a number? I think I'll punt that to Steve, since I don't have an answer.

Thanks, Dave. I don't have an answer either. I think we certainly feel like we have the capacity to expand our program. I can't give you specifics, but I will say the -- we don't really anticipate any issues on the service side. So access to rigs and frac crews and associated services, I think we don't view as really troublesome to expand that. I think the governor of our pace expansion will likely be on the land side, our ability to permit wells and put together drilling units that make sense and to drill multi-well pads. And that's a difficult thing to predict too far in the future, to get too far ahead of where we're at. But we're obviously very focused on that and doing our best to make sure we have the opportunity to expand. And I think, certainly, we can do more than we're currently doing.

And then on -- just to go back to the GP stake, I think that you said, Dave, that you're expecting $33 million from the GP stake by '15? Is that just the GP stake alone and not including the LP distribution?

That's exactly correct. That's just the GP stake, given the assumptions that I had laid out. And honestly, it was really designed to try to give a sense of where the GP value could be heading for EQT.

Got you. And then, finally, on Huron, if you were to get a JV on that, any idea of the potential for Midstream spend on that space?

I -- there certainly will be a need for Midstream whenever Huron development recommences, no matter whose money it is. You could go a little ways with very little Midstream spend. And then we're going to have to get into -- they're going to have to be spending around it. So that -- and that -- but then the issue of -- depending on what kind of structure happens at the Huron is that EQT stuff that gets dropped into EQM that go into whatever vehicle it is, that -- at this point, that's probably, from our perspective, getting a little bit ahead of it. We have observed that most producers don't -- most don't really want the Midstream, but we have observed it.

I guess I'm asking I think a little bit different question. Not so much structure, but just saying, in general, used to be when you focused on that area, there was -- if you were to grow materially, there was going to be a need for a lot more Midstream CapEx spend. And if it's -- I'm not really -- doesn't matter who spends it, but just some idea that...

That's true. That is still true. We can probably go a year or 2 without much spend or a low level of growth. You could still get by with very little spend. And if there were a material ramp up, to use your word, Becca, then you'd have to get into spending more on the Midstream again. More material money on the Midstream.

Any idea of magnitude? Couple hundred million?

No, I really haven't looked at that case very closely, to be honest.

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

Thanks, Yussaf, and thank you, everybody, for participating in today's call.

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