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EQT Corp. (NYSE: EQT ) Q3 2015 Earnings Call October 22, 2015 10:30 am ET Executives Patrick J. Kane – Chief Investor Relations Officer Philip P. Conti – Senior Vice President and Chief Financial Officer Steven T. Schlotterbeck – Executive Vice President and President of Exploration & Production David L. Porges – Chairman, President & Chief Executive Officer Randall L. Crawford – Senior Vice President and President of Midstream & Commercial Analysts Neal D. Dingmann – SunTrust Robinson Humphrey, Inc. Phillip Jungwirth – BMO Capital Markets Michael Anthony Hall – Heikkinen Energy Advisors Stephen Richardson – Evercore ISI Drew E. Venker – Morgan Stanley & Co. LLC Operator Good day and welcome to the EQT Corporation Third Quarter 2015 Earnings Conference Call. Today’s call is being recorded. And after today’s presentation, there will be an opportunity to ask questions. At this time, I’d like to turn the conference over to Patrick Kane, Chief Investor Relations Officer. Please go ahead, sir. Patrick J. Kane – Chief Investor Relations Officer Thanks, Jennifer. Good morning, everyone, and thank you for participating in EQT Corporation’s conference call. With me today are Dave Porges, President and Chief Executive Officer; Phil Conti, Senior Vice President and Chief Financial Officer; Randy Crawford, Senior Vice President and President of Midstream and Commercial; and Steve Schlotterbeck, Executive Vice President and President of Exploration and Production. This call will be replayed for a seven-day period beginning at approximately 1:30 today. The telephone number for the replay is 719-457-0820. The confirmation code is 868-2699. The call will also be replayed for seven days on our website. To remind you, the results of EQT Midstream Partners, ticker EQM, and EQGP Holdings, ticker EQGP, are consolidated in EQT’s results. Earlier this morning, there were separate joint press release issued by EQM and EQGP. The partnership’s conference call is at 11:30 AM today, which requires that we take the last question at 11:20. The dial-in number for that call is 913-312-9034. The confirmation code is 215-7781. In just a moment, Phil will summarize EQT’s results. Next, Steve will have a brief Utica update. Finally, Dave will provide preliminary thoughts on EQT’s 2016 capital budget. Following their prepared 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. 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 the year ended December 31, 2014 as updated by any subsequent Form 10-Qs which are on file at the SEC and 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 financial measures including reconciliations to the most comparable GAAP measure. Before turning the call over to Phil, I’ll walk you through one of the non-GAAP reconciliations that caused some confusion last quarter, specifically production adjusted net operating revenue presented on page seven of today’s release. This number is used as a basis for calculating our average realized sales price as presented on the price reconciliation included in this morning’s release. The average realized price is calculated by dividing the adjusted net operating revenue by total sales volumes. There is a non-GAAP reconciliation in the release that I will briefly explain. We are making two adjustments to EQT Production total operating revenues as reported on the segment page in order to provide you with operating revenues excluding the non-cash impact of derivatives and the net of transportation and processing costs. With respect to derivatives, adjustments for non-cash derivative activity have been the subject of SEC comments over the past couple of years. As a result, in accordance with what appears to be the SEC preference in this area, we adjust out the non-cash activity in three steps. First, we back up all gains and losses on derivatives not designated as hedges that were included in revenues during the period, which is the mark-to-market impact which was $160.5 million this quarter. Two, we add back the actual cash received, $33.2 million, and deducted premiums paid for derivatives that settled during the quarter, which was $1 million. This leaves us with just the actual cash received net of any premiums paid in our adjusted revenue number. The final adjustment on our non-GAAP reconciliation simply reduces the total operating revenues by $64.7 million of cost reported as expense on EQT Production segment page for transportation and processing. This provides a realized price net of transportation and processing cost which is consistent with our historic presentation. With that, I’ll turn the call over to Phil Conti. Philip P. Conti – Senior Vice President and Chief Financial Officer Thanks, Pat, and good morning everyone. As you read the press release this morning, EQT announced the third quarter 2015 adjusted loss of $0.33 per diluted share, which represents an $0.83 per share decrease from adjusted EPS in the third quarter of 2014. Adjusted operating cash flow was $156.3 million in the quarter or 46% lower than the third quarter of 2014. Results for the quarter were negatively impacted by lower commodity prices due to lower strip prices since the last quarter. We also recorded a significant non-cash gain on hedges of future production of $128.3 million during the quarter and that was some of the stuff that Pat just talked about and that’s excluded from the adjusted earnings and cash flow. I’d like to briefly take a look at our continuing investment in the recently IPO’ed EQGP. On October 20, 2015, EQGP announced a cash distribution to its unit holders of $0.104 per unit for the third quarter of 2015 or a 13% increase over the equivalent full quarter distribution in the second quarter of 2015. The third quarter distribution decision represents $24.9 million in payments which EQT will receive on November 23. These quarterly payments will continue to grow as distributions at EQGP grow, and they highlight the value of EQGP to EQT. The operational results were fairly straightforward in the third quarter, so I’ll move right into the segment results, and I will be brief. First, EQT Production continued to grow production sales volumes by 27% compared to the third quarter of 2014. However, revenues from that growth were more than offset by the lower commodity prices negatively impacting results in the third quarter. The average realized price at EQT Production was $1.21 per Mcf equivalent, a 55% decrease from $2.69 per Mcf equivalent last year, which led to adjusted operating revenues for the quarter of $188.5 million or $142.5 million lower than last year’s third quarter. There were many factors that led to the lower price but lower NYMEX and liquids prices versus last year were the primary drivers. You will find the detailed components of the price differences in the tables in this morning’s release. The adjusted operating loss at EQT Production was $72 million, excluding the non-cash gain on hedges of $128.3 million as I just mentioned. That compares to adjusted operating income of $107.9 million in the third quarter of 2014 and that was also excluding a non-cash gain on hedges. Total operating expenses at EQT Production were $325.2 million or $53.5 million higher compared to the third quarter 2014. DD&A was $30.2 million higher, transportation and processing expense was about $16 million higher, exploration expense was $4.6 million higher, and LOE, excluding production taxes, was about $1.6 million higher, all consistent with the volume growth. Production tax decreased by $3 million due to lower commodity prices in the period. SG&A expense excluding $3.5 million in rig release penalties was about $0.5 million higher. Midstream results. Here, the operating income was up 21%. The increase is consistent with the growth of gathered volumes and increased fixed capacity-based transmission charges. Gathering revenues increased 23% to $125.9 million in the third quarter of 2015 primarily due to a 24% increase in gathered volumes. Transmission revenues for the third quarter 2015 increased by $6.9 million or 12% driven by additional firm-contracted capacity added over the past year. Operating expenses at Midstream for the third quarter of $82.2 million were about $9.4 million higher than last year consistent with the growth in the Midstream business. And just to conclude with a brief note on liquidity, EQT did have $1.7 billion of cash on hand at quarter-end not including cash at EQM and EQGP, as well as full availability under EQT’s $1.5 billion credit facility. So, we remain in a strong liquidity position to accomplish our goals for the foreseeable future. Our current estimate of 2015 EQT operating cash flow is $900 million adjusted to exclude the non-controlling interest portion of EQM and EQGP’s cash flow. And with that, I’ll turn the call over to Steve. Steven T. Schlotterbeck – Executive Vice President and President of Exploration & Production Thank you, Phil. Today, I’ll provide you an update on our deep Utica well program. As discussed on the last call, we completed our first deep Utica well in July, the Scotts Run 591340. To remind you, the well’s initial 24-hour flow was 72.9 million cubic feet with an average flowing casing pressure of 8,641 psi. We’ve been flowing this well directly into the sales pipeline at a choke-restricted rate of about 30 million cubic feet per day. Except for the seven days required to install the wellhead equipment, daily sales have been steady at this rate. Casing pressure has been declining at an average of 40 psi per day. As of yesterday, sales volumes were 30.4 million cubic feet per day, and the casing pressure was 6,320 psi. Cumulative production from this well has totaled 2.6 Bcf in the first 86 days of production. Our expectation is that the daily production rate will not decline until the well pressure declines to the pipeline pressure, which is 500 psi. Based on an extrapolation of the current pressure decline rate, we estimate that we’ll reach line pressure after approximately eight months of production, which will be at late March 2016. The cumulative production at that time would be approximately 7.4 Bcf. At that point, we have a wide range of possible decline curves as we do not have any analogous decline data to rely on. Our current reservoir modeling suggests an ultimate expected recovery for this well in a range between 13.9 Bcf and 18.8 Bcf or a range of 4.3 Bcf to 5.9 Bcf per thousand foot of lateral. Using the lowest EUR of our range and assuming the high end of our cost per well target of between $12.5 million and $14 million per well we estimate returns at a $2 wellhead gas price to be north of 20% for a 5,400 foot lateral well. Since the last call, we have exploit two additional Utica wells. In August, we exploit the second Greene County well, the Pettit #593066 which is located approximately five miles northeast of the Scotts Run well. They’re currently at a depth of 12,200 feet, and we installed the intermediate casing. We’re just beginning to drill a curve on this well and expect this well to be in line before the end of the mid-year. The third well was spud in September in Wetzel County, West Virginia, the Big 190 well, and is located approximately 30 miles southwest of the Scotts Run well. We reached TD of the deep intermediate hole. The top hole rig has been moved off the well and the well is secured awaiting the Big rig to run the intermediate casing. The rest of the drilling will be completed when the Greene County rig is finished with the Pettit well, and that rig is moved to West Virginia later this year. We’re making good progress on cost reductions for these wells. Specifically at the current depth of the Pettit well, we spend approximately 22% less than we did on the Scotts Run well at the same point. As I previously noted, we expected to take several wells for us to achieve our cost target for these wells of between $12.5 million and $14 million. We are pleased with our progress so far and remain confident that we will achieve our targeted cost. We will continue to post well data from the Scotts Run well on our analyst presentation periodically, and we’ll update you on the progress of the latest two wells as warranted. I will now turn the call over to Dave Porges for his initial thoughts for next year’s capital budget. David L. Porges – Chairman, President & Chief Executive Officer Thank you, Steve, and good morning everyone. Today the topic of my prepared remarks, as Steve mentioned, is our preliminary thinking regarding EQT’s 2016 capital budget. We met with our board last week to discuss our long-term strategy, as we do every October. We will then meet in early December to approve the upcoming year’s operating plan and capital budget. A key aspect of the discussion in last week’s meeting was the impact of the emerging deep Utica play on EQT’s strategy. There have been fewer than 10 wells drilled and completed in the deep Utica around our acreage, so it is still too early to be confident that the play will be economic, but the early results are certainly encouraging. Specifically, if the Utica does work, which for us means that the returns are better than returns from the core Marcellus, we will certainly add significant resource potential to our inventory. However, the clearing price for natural gas will likely be lower in that scenario than if the Utica is less economic. As a result, some of our other inventory that requires higher prices to make economic returns would be deferred possibly for many years. So, while those of us, certainly including EQT, who have significant position in the core of the deep Utica will be the winners, if you will, the cannibalization of other opportunities will affect everyone including those of us who will net-net be much better off if the deep Utica play does work economically. Given this potential for lower long-term gas prices, we do not think it’s prudent to invest much money in wells whose all-in after-tax returns exceed our investment hurdle rates by only a relatively small amount. As a result, we are suspending drilling in those areas such as Central Pennsylvania and Upper Devonian play that are outside that core. This decision will affect our 2016 capital plan though we are just starting to develop the specifics of the 2016 drilling program that forms the core of that plan. The focus in 2016 will be on this more narrowly-drawn notion of what the core Marcellus would be assuming the deep Utica play works. We will also pursue the deep Utica play with a goal of determining economics, size of resource that midstream needs and on lowering the cost per well to our target range. Our initial thoughts are a 10 well to 15-well deep Utica program in 2016 with flexibility to shift capital between Marcellus and Utica as warranted based on our progress. Our preliminary estimate for production volume growth in 2016 versus 2015 is 15% to 20% which we will refine when we announce our formal development plan at early December. If we turn in line our fourth quarter wells in late December, as contemplated in our fourth quarter guidance, 2016 growth would likely be near the upper end of that range as those wells would contribute little if anything to volumes until early 2016. Obviously, this overall approach will result in a 2016 capital budget, absent any acquisitions that is a fair bit lower than 2015 and would result in continuing (16:28) of cash on hand as of end 2016 but we will provide specifics in December. Another strategic implication of an economic deep Utica play is the significant opportunity for EQM. A year ago, it would have been hard to imagine a more prolific play than the Marcellus. And EQM has already announced the $3 billion backlog of midstream in projects to serve the Marcellus play. Incidentally, that entire current backlog continues to make sense if the deep Utica proves economic as it either supports core Marcellus or takeaway projects that are needed regardless of the source rock for the natural gas. However, if the deep Utica works, it is likely to be larger than the Marcellus over time. The magnitude of incremental takeaway and gathering pipeline such as a play would support is significant, even net of the previously mentioned reductions in Marcellus development that would occur in this scenario. As we think about the EQT corporate structure, we are not likely to make any major decisions to change to current integrated model until we do understand the scope of a potential deep Utica development program. We have reaped much value in recent years from having the two businesses together and there is the potential that both companies would continue to benefit from the synergies into the dawn of the Utica era. Finally, the deep Utica potential has also affected our thoughts around acreage acquisitions. Given our view that our existing acreage sits on what is expected to be the core of the core in deep Utica, we are focusing our area of interest even more tightly on acreage that is in our core Marcellus and potentially core deep Utica area. As you can probably deduce from the lack of significant transaction announcements, the bid/ask spread continues to be wide. We are a patient company and believe that there will be acreage available at fair prices eventually. But the definition of fair has to contemplate the potential that the deep Utica works. We do not think that bodes well for that price of acreage concentrated in anything but the core Marcellus and core Utica. This narrowing focus also suggests that smaller asset deals are much more likely than larger corporate deals. However, as we have stated previously, we are comfortable maintaining our industry-leading balance sheet even as we look for opportunities to create value. In conclusion, EQT is committed to increasing the value of your shares. We look forward to continuing to execute on our commitment to our shareholders and appreciate your continued support. With that, I will turn the call back over to Pat Kane. Patrick J. Kane – Chief Investor Relations Officer Thank you, Dave. Jennifer, we’re ready to open the call for questions. Question-and-Answer Session Operator Thank you. And we’ll take our first question from Neal Dingmann from SunTrust. Neal D. Dingmann – SunTrust Robinson Humphrey, Inc. Morning, gentlemen. Dave, just on that last part that you mentioned on the M&A, your thoughts, and I would agree on the strong, obviously, position you have in that deep Utica. Are you and Steve thinking more bolt-on in that area? Are there some big packages you see? Anything else you could add about what you’re kind of looking at in regard to M&A in that area? David L. Porges – Chairman, President & Chief Executive Officer Steve has been closer to that. I will let him answer that question. Steven T. Schlotterbeck – Executive Vice President and President of Exploration & Production Sure. Neal, we’re – our primary focus in terms of looking at acquisitions is really focused on a pretty narrow core area. And we’ll be updating our Investor Presentation later today, and you’ll see a map that shows kind of the area most of interest to us where we’ll be focusing our development program as well as any M&A activity that we’d be interested in. So, right now, it seems like there’s – people are interested in selling assets. So far, the prices have still been a bit high. But as Dave said, we plan on being patient waiting for what we would consider fair prices before we transact. Neal D. Dingmann – SunTrust Robinson Humphrey, Inc. Right. And then the 10 to 15 wells you mentioned, Steve, in the deep Utica, your thoughts how far north – I mean, you’ve got obviously some interesting acreage all the way up in the Allegheny and given how successful CNX is, obviously, their Gott well was all the way clear up into Westmoreland. Just your thoughts on – any ideas you can give us on those 10 wells to 15 wells? Will most of those be focused down around that Greene County area, or would you take them all the way up to potentially as north as Allegheny? Steven T. Schlotterbeck – Executive Vice President and President of Exploration & Production Well, we haven’t spotted all of those 10 wells to 15 wells. So, it will depend on the results we see. But I would say, certainly into Southern Allegheny County where we have a pretty significant position and high expectations for the Utica, maybe up into the Northern Allegheny but more likely, it would be for us Southwestern Armstrong where we have an acreage position. I think our view would probably be we’ll let others define that area. Part of the reason would be more limited takeaway capacity up there, so probably not going to be in a big hurry to drill some of these monster wells up there, probably more focused from Southern Allegheny down into Southern Wetzel and maybe a bit over into far western Marion County. Neal D. Dingmann – SunTrust Robinson Humphrey, Inc. Got it. And then just the last question. Just on takeaway for the dry gas. Dave, at one time, Dave, you thought – I think you commented that really the only limitation might be just takeaway as far and maybe given how successful these wells and how economic these wells look. If you and Steve can talk about, is that – again, does that have limitations to how many wells you drill next year or by some point next year you’ll have ample Utica takeaway? David L. Porges – Chairman, President & Chief Executive Officer Geez, I think these – if the early results continue to show up – if we see things consistent with those early results in future wells, I think we’re probably going to be looking at takeaway limitations for a while. I mean, I think these wells can probably support volumes that the midstream wasn’t really designed for and it’s – I mean, we’ll probably let Randy speak to this but it would- it’s going to take a little while probably to figure out what the right midstream configuration is for the deep Utica. Randy, do you have any thoughts on that? Randall L. Crawford – Senior Vice President and President of Midstream & Commercial No. I concur. Obviously, we’ve been trying to stay out in front of the Marcellus and we’ve looked at our Ohio Valley Connector that’s coming on. But I would also say, we’re looking at Jupiter system and how we can leverage that and the infrastructure that we have in Equitrans. So, I think we’re best positioned to move a little bit of the product. But certainly, these wells are quite exciting and so that will take a lot of additional infrastructure as we develop the play. David L. Porges – Chairman, President & Chief Executive Officer Now, we do think incidentally that the cost per unit is going to be considerably less than it is for the Marcellus because of the higher volumes, and frankly, the more concentrated nature of it. I mean, it’s not just higher volumes. It’s that you can get it from a tighter area. That’s a much better answer from the perspective of unit gathering and compression costs. Actually, the compression cost, early on, is going to probably be a round number. Zero. Randall L. Crawford – Senior Vice President and President of Midstream & Commercial Yeah. Neal D. Dingmann – SunTrust Robinson Humphrey, Inc. Again, thanks, guys. Great details. Operator Thank you. And we’ll go next to Phillip Jungwirth from BMO. Phillip Jungwirth – BMO Capital Markets Hey. Good morning. Couple of questions on Utica well costs. First, wondering if you could provide us with the AFE for the second Greene County and first Wetzel County Utica wells. And then, second, your targeted well cost imply about $2,500 per foot which I know it compares to some of the smaller peers over in Belmont and Monroe County who are quoting $1,200 to $1,500 per foot. Obviously, the Pennsylvania Utica is 13,000 feet compared to 10,000. But do you think that deeper depth at higher pressures would account for all of this difference or could there be further room to bring costs down as you progress through development? Steven T. Schlotterbeck – Executive Vice President and President of Exploration & Production Phil, this is Steve. I think – I guess regarding the AFEs, I don’t have the exact numbers in front of me, but they’re in the low-$17 millions per well. That cost will be dependent on the ultimate lateral length, so we have some flexibility about how long we end up drilling these. So, I wouldn’t put a whole lot of weight on those numbers. But a significant decrease from the actual costs from our first well, which was around $30 million. And the second part of your question, remind me again. Oh, the cost per foot? I think our view is that when we sit down and do a bottoms-up analysis of what we think it should cost to drill these wells once you work through all of the problems and get the non-productive time down to a minimum that that’s where we come up with that $12.5 million. So, I think at current service costs, never say never but we don’t see a path to being significantly less than that for these wells. And I think the $14 million gives us some room to have a few unexpected problems that maybe we wouldn’t normally have on Marcellus wells, which is why we’re quoting a range right now. But our hope is to get it at the bottom end of that range but very confident we’ll get within the top end. Phillip Jungwirth – BMO Capital Markets Okay. Great. Yeah. Looks like based on the EUR math that the implied F&D is already pretty comparable to what you’re seeing in the Marcellus. Second question is on the last call you had mentioned how EQM is now more of an organic growth story. But with the narrowing of Marcellus development in 2016 and beyond, how would this impact future dropdowns given that most of the gathering of transmission assets held by EQT appear to be outside of the core Southwest PA and Northwest Virginia area? Steven T. Schlotterbeck – Executive Vice President and President of Exploration & Production Well, we’re still working through what we want to do with future drops. But the comment about what’s most economic for EQM is kind of independent of that. EQM is not well, as you know, into the high splits. And it’s just more economical for an MLP to organically develop projects than to have to pay up as long as it can afford it as long as it’s got the coverage that allows it to wear that period of time when that got assets tied up in projects that aren’t generating cash flow. So, we’ll have to work through what happens with the remaining projects, et cetera, as we go through 2016. But my comments in the past about organic growth being the preference is just because of the way it works when you’ve got all of that incremental cash flow going to the GP. Phillip Jungwirth – BMO Capital Markets Right. And then, historically EQT has always pre-funded the following year’s cash flow outspend with asset sales or dropdown. Would this also be the intention in 2016 or do you consider the $1.7 billion in cash on the balance sheet as having already accomplished that given, I think you mentioned that you held cash as of year-end 2016? A – [009Z0W-E Steve Schlotterbeck]> : I basically said we’ve already accomplished that. Phillip Jungwirth – BMO Capital Markets Okay, great. Thanks. Operator Thank you and we’ll go next to Michael Hall from Heikkinen Energy Advisors. Michael Anthony Hall – Heikkinen Energy Advisors Thanks. Good morning. I guess, I just wanted to touch a little bit on the backlog, kind of get your updated thoughts around how that progresses over time, if that materially year-on-year continued to grow sequentially? And just trying to think through kind of what the strategy is there when you think that this ever would ultimately be drawn down and how’s that contemplated in the 2016 plan? Steven T. Schlotterbeck – Executive Vice President and President of Exploration & Production Yeah, Michael. This is Steve. Yeah. The backlog in terms of frac stages complete but not online grew a bit this quarter, as you saw. Our expectation is that the fourth quarter will be a pretty big quarter for new TILs. Most of those will be in the back half of the quarter, so it won’t affect volumes in the quarter very much but should be coming on late. So, I think you will see a fairly significant drop back to more historic levels when we – on the next call when we’re talking about Q4. Michael Anthony Hall – Heikkinen Energy Advisors Okay. And so, is there is any thought process of continuing to draw that down even further in 2016 or is that moving in following quarters kind of do you think that could to a place where you’re more kind of at a run rate (29:37). Steven T. Schlotterbeck – Executive Vice President and President of Exploration & Production I think that will be more the typical run rate. If you look back over our history, you go back two, three years or so, I think we’ve been giving these numbers you’ll see it’s always very lumpy. The biggest driver behind that backlog is just the timing of the rigs and the number of wells and the number of fracs per well for every pad we are on. So, it tends to be very lumpy. Right now, we haven’t been taking any heroic efforts to get wells online superfast. So, that maybe drives the backlog a little bit this quarter. But again, you’ll see by next quarter, we’ll be back in the more of closer to the mean over the past few years. Michael Anthony Hall – Heikkinen Energy Advisors Okay. And any indications around capital associated with that 2016 outlook? David L. Porges – Chairman, President & Chief Executive Officer Geez, only that it would be less than 2015. I mean, that’s – but it’s a fallout of this narrowing focus. Michael Anthony Hall – Heikkinen Energy Advisors Okay. David L. Porges – Chairman, President & Chief Executive Officer But I feel uncomfortable putting numbers out there when we’re still what six weeks away from putting numbers in front of our own board. But if you’re looking for directional, it would be – clearly we’re heading less than 2015. Michael Anthony Hall – Heikkinen Energy Advisors That’s helpful. Okay. And then, I guess, just wanted to – last question on my end. Think about the fourth quarter a little bit, and I think you kind of alluded to it in your comments about the back-loaded nature of the completions. But just the implications backing off the first, three quarters of the year kind of flat to down on a quarter, What are the sensitivities around that from an operational perspective, how should we think about what might put you on one end of the range or the other? David L. Porges – Chairman, President & Chief Executive Officer The rate for the fourth quarter… Michael Anthony Hall – Heikkinen Energy Advisors Right. David L. Porges – Chairman, President & Chief Executive Officer I think we just stick with what Steve said which is, we’re kind of aiming towards a lot of those pads getting tilled really at the end of the quarter and therefore having very little impact on the fourth quarter volumes. And so that results in the guidance being what it is. But we get asked a lot about our response to current prices at any one point in time. And as Steve was alluding to, in this price environment, it doesn’t seem like the right time to be going through any type of heroic efforts to get things turned online any more quick. Michael Anthony Hall – Heikkinen Energy Advisors Yeah. David L. Porges – Chairman, President & Chief Executive Officer Right. So the notion that we’ve reflected in the guidance that those TILs are going to drift backwards is just not troublesome. Michael Anthony Hall – Heikkinen Energy Advisors Okay. David L. Porges – Chairman, President & Chief Executive Officer …because they still get TILs. Michael Anthony Hall – Heikkinen Energy Advisors Right. David L. Porges – Chairman, President & Chief Executive Officer It’s just the question is whether it affects December volumes or January volumes is really the issue. Michael Anthony Hall – Heikkinen Energy Advisors Fair enough. And in the past you guys – just kind of brought up another question I had. In the past you guys talked about a pretty substantial kind of spud to turn to sales time of, I’ll call it, I think nine months or so, and therefore 2015 spending is really kind of baking in the 2016 growth rate. Given that, I mean, is that still in place, which I imagine is? Is there really a price at which in 2016 you would be able to really slowdown the production? Or how do you tactically respond to gas prices in 2016 if they continue to kind of remain at these low levels on a realized basis? David L. Porges – Chairman, President & Chief Executive Officer We’ll look at that as 2016 plays out. Obviously, part of the consideration, as you mentioned, is what the prices are. But really, the midstream is a big part of the consideration too. If you have some midstream flexibility, you can slowdown and kind of make it up later if you want to. And when the midstream is more full then you have to decide, you either want it or you don’t. You want the volumes or you don’t want the volumes because you can’t really make it up on the back end, right? It’s quite a ways down the road before you can make up those volumes. But we certainly take prices into account while making our decisions about capital expenditures and what type of efforts to go through to try to accelerate or otherwise turning lines for wells. Michael Anthony Hall – Heikkinen Energy Advisors Okay. That’s helpful. And then, I guess, sorry, one last one. On the gas processing side, do you have any increases in commitments around volumes from gas processing contracts that we ought to be keeping in minds, given how low NGL prices are? Philip P. Conti – Senior Vice President and Chief Financial Officer Michael, there’s a little bit more coming on in January of less than 5% of where we are. Michael Anthony Hall – Heikkinen Energy Advisors Okay. Great. Thanks. Operator Thank you. And we’ll go next to Stephen Richardson from Evercore ISI. Stephen Richardson – Evercore ISI Hey, good morning. Philip P. Conti – Senior Vice President and Chief Financial Officer Good morning. Stephen Richardson – Evercore ISI David, as you think about the strategy and kind of just went through some of these thoughts with the board. So, is there any evolution in your thoughts in terms of what the right mix of upstream versus midstream capital is here in terms and I’d appreciate that EQM is funded to some extent organically. But in terms of returns and how to optimize that beyond 2017 just considering the gas outlook versus the gathering outlook from what you see from the different horizons here? David L. Porges – Chairman, President & Chief Executive Officer Well, first of all, just kind of to reiterate, my belief is, the further out in the future you look, the clear – and you mentioned beyond 2017 the clearer it is in my mind that capital expenditures for midstream should be at the EQM level. We want to protect that IDR and the way to do that is to have the most attractive midstream projects possible so that they can afford to pay the incremental cash flow to the GP, which is kind of the core value of that IDR where we stand now. So, that’s going to be the mindset. Strategically it’s going to be midstream expenditures should occur at EQM. Now, if you’re trying to get at what’s more valuable, generally, midstream or upstream, I guess, that’s a bigger picture question than just one company and we’ll see. We’re trying to position ourselves so that we can be agnostic so that we can take advantage of wherever the value is in the value chain. I agree that with the prospects of the Utica and issues like that it’s not clear what the value chain will look like several years down the road but we think that the reason EQT is such an attractive investment is because EQT will participate no matter where the most value shows up in that value chain. Stephen Richardson – Evercore ISI Right. And can you just remind us, as you think about upstream like the right capital allocation at EQT Production for next year appreciating this 9 months or 12 months gap between when you deploy capital and when it shows up in production? Like what is the – is it a wellhead hurdle rate, is it a corporate return, is it a burden return? What’s the right return on capital? David L. Porges – Chairman, President & Chief Executive Officer Yeah, we look at all-in return. All-in after-tax returns is the way we tend to look at things. But that overlay that I mentioned in my prepared remarks was we just think we need to bear in mind what if the deep Utica works and what does that mean for clearing prices, et cetera, and therefore we should be particularly cautious about investing in anything but the core Marcellus which does stand up still in those environments and in the core Utica. So, it’s more of that. There’s always uncertainty about what prices are going to be. But whenever you have a new low-cost supply source in any commodity business, you’ve got to start being wearier of where one wants to invest one’s money. So, I think there’s a certain amount of caution that we’re taking that we’re talking about because of that unknown because of not knowing yet the extent to which the deep Utica will work. But our feeling that if it works the way it’s looking like it might that the core areas for Marcellus and Utica are simply going to be narrower. I mean, we’re going to be able to supply a big portion of North America’s natural gas needs from a relatively small geography. Stephen Richardson – Evercore ISI Right. And – sorry, just final question from me is, have you and maybe it’s for Randy in terms of conversations or thoughts on what the third-party opportunity is at this horizon? So again, we’re all assuming that if this is economic and it is lower cost and it isn’t just a zero-sum game in terms of different capital going to the Utica but is EQM particularly well-positioned to capture a larger proportion of potential third-party volumes in these areas than you have in the Marcellus? Is this a big piece of forward growth beyond the $3 billion CapEx number? Randall L. Crawford – Senior Vice President and President of Midstream & Commercial This is Randy. Yeah, I think we have a significant opportunity with the well results that we’re seeing. In fact, I think Dave and Steve both mentioned that the core of the core Utica actually appears to sit right on top of our EQM assets, both at Equitrans and with the gathering assets along Jupiter and Northern West Virginia. In our projects that we have embarked on currently, which is the Ohio Valley Connector and our Mountain Valley Pipeline I think position us quite well to both move – to be competitive and move gas to both affiliate as well as third parties. So, I think we’re very competitively well positioned. Steven T. Schlotterbeck – Executive Vice President and President of Exploration & Production Yeah. And, look, to your point, probably we weren’t as well positioned as you move a little bit outside of the core Marcellus from a midstream perspective. So, this emergence of the Utica is from a competitive and a comparative perspective a positive for EQM. Stephen Richardson – Evercore ISI Great. Thanks very much. Operator Thank you. And we’ll go next to Drew Venker from Morgan Stanley. Drew E. Venker – Morgan Stanley & Co. LLC Good morning, everyone. Could you speak to the 2016 program could change if we have a warm winter and gas prices are well below the Strip (40:20) I’m thinking something around $2.25 for 2016. I’m particularly interested whether that would significantly reduce your appetite to delineate the Utica in 2016? I guess, and conversely, if prices are higher, would that change that Utica program at all? David L. Porges – Chairman, President & Chief Executive Officer At that point though you are just talking about what 2016 prices would be? I mean, the norm in commodities, and I understand there does tend to be in the investor community short-term focus. I recognize that people need to make money each quarter. But actually, lower prices near term tend to lead to more robust recoveries later. So, our view is much more the low-cost opportunities are going to be the ones that went out and you want to make sure that you’re – especially if you think prices are going to be stressed at all that you’re focusing on only going after the lowest cost opportunities and not letting yourself kind of get drawn into investing in opportunities that are other than that. So, I’d say that’s our focus anyway. And, look, in a lower price environment because we’re talking about the deep Utica perhaps helping to create that obviously becomes even more important. Drew E. Venker – Morgan Stanley & Co. LLC Right. So, I guess, Dave, it sounds it’s not – probably not much change. David L. Porges – Chairman, President & Chief Executive Officer Well, change -yeah, but the thing is we’re not telling you what our 2016 plan is yet because we haven’t gotten it approved from our board. Drew E. Venker – Morgan Stanley & Co. LLC Right. David L. Porges – Chairman, President & Chief Executive Officer So, it’s – I’m not even sure how I go about telling you what the change would be versus the plan that we can’t even discuss with you. Drew E. Venker – Morgan Stanley & Co. LLC Fair enough, Dave. And then…. David L. Porges – Chairman, President & Chief Executive Officer But yeah, well if prices are lower then we’d probably over time will spend less money and if they’re higher we’ll probably spend more money over time. But we’re already talking about 2016 being below – fair a bit below 2015 as it is. Drew E. Venker – Morgan Stanley & Co. LLC Right. Right. I was thinking, Dave, you mentioned maybe, 10 wells or 15 wells at the Utica in 2016 that’s really what I was thinking about (42:18) program. David L. Porges – Chairman, President & Chief Executive Officer Yeah, that’ll be governed by how attractive it looks because those will still be more economical wells than anything else get probably that could get drilled anywhere in the country. So… Drew E. Venker – Morgan Stanley & Co. LLC Okay. And then maybe you were speaking to probably wanting to build out another gathering system for the Utica. Does that delay how quickly you want to move into development mode there? I guess thinking let’s fast forward and say, you’re very happy with the results or maybe even more pleased than what you’re seeing today? Would you still need to put a gathering system in place before you could accelerate in 2017? David L. Porges – Chairman, President & Chief Executive Officer Yeah. We’re… Drew E. Venker – Morgan Stanley & Co. LLC Or it’s too early even to think about that? David L. Porges – Chairman, President & Chief Executive Officer Yeah. Well, no, it’s not too early to think about it but we haven’t actually settled on what that approach will be. Our bias is that a fair bid of the gathering for Utica is probably going to be separate because of the pressures involved. Drew E. Venker – Morgan Stanley & Co. LLC Right. David L. Porges – Chairman, President & Chief Executive Officer But as far as the specifics and exactly where it is and exactly how much money gets spent that we haven’t. We’re not ready to disclose that stuff. We’re only just in the midst of even discussing that internally with our own board. Drew E. Venker – Morgan Stanley & Co. LLC I guess and maybe another way to ask would be would you be interested potentially to have lower activity levels so you’re not putting those very high pressures into your Marcellus gathering system? David L. Porges – Chairman, President & Chief Executive Officer We’re not going to put it into our Marcellus gathering system and that’s – well, go ahead, Steve. Steven T. Schlotterbeck – Executive Vice President and President of Exploration & Production Actually, in the short-term, Drew, we can put it into the Marcellus system. It’s not the most optimum situation long term for the Utica because the gathering – the unit gathering cost for the Utica in a dedicated system will be significantly lower than the cost of moving through a Marcellus system. But for the next couple of years until we figure out exactly what the optimum systems are and get them built, we can, and the likely impact, if we were doing that because the Utica was looking so good would probably be a shift from Marcellus investments to Utica which is how – which is where the capacity in those systems would effectively come from. We’ve replaced Marcellus gas with Utica. And as we build Utica systems, at that point, we would start to get the benefits of the lower unit cost. Drew E. Venker – Morgan Stanley & Co. LLC Okay. All right. That’s really helpful color. Your answers were great, I wasn’t try to talk too bad or anything. Thanks a lot, guys. David L. Porges – Chairman, President & Chief Executive Officer All right. Thank you. Operator At this time, I’ll turn it back over to our speakers for any additional or closing remarks. Philip P. Conti – Senior Vice President and Chief Financial Officer Thank you, Jennifer. As Steve mentioned, we will be posting a new analyst presentation to our website later today, so that will be available some time after 4:00. And I’d like to thank you all for participating. Operator And that does conclude today’s conference. Thank you for your participation.