EQT Corporation (EQT) Q4 2014 Earnings Report, Transcript and Summary

Patrick Kane - Chief Investor Relations Officer Philip P. Conti - Chief Financial Officer and Senior Vice President Steven T. Schlotterbeck - Executive Vice President and President of Exploration & Production David L. Porges - Chairman, Chief Executive Officer, President, Member of Executive Committee and Member of Public Policy & Corporate Responsibility Committee Randall L. Crawford - Senior Vice President and President of Midstream & Distribution

Phillip Jungwirth - BMO Capital Markets Canada Michael A. Hall - Heikkinen Energy Advisors, LLC Andrew Venker - Morgan Stanley, Research Division Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Joseph D. Allman - JP Morgan Chase & Co, Research Division John J. Gerdes - KLR Group Holdings, LLC, Research Division Stephen Richardson - Deutsche Bank AG, Research Division Cameron Horwitz - U.S. Capital Advisors LLC, Research Division Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Good day, and welcome to the EQT Corporation Year-end 2014 Earnings Conference Call. Today's call is being recorded. [Operator Instructions] At this time, I would like to turn the conference over to our Chief Investor Relations Officer, Mr. Pat Kane. Please go ahead, sir.

Thanks, David. Good morning, everyone, and thank you for participating in EQT Corporation's Year-end 2014 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, 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 (888) 445-1112 with the confirmation code of 8636267. The call will also be replayed for 7 days on our website. To remind you, the results of EQT Midstream Partners, ticker EQM, are consolidated in EQT's results. There was a separate press release issued by EQM this morning, and there is a separate conference call at 11:30 a.m. today, which requires us to take the last question at 11:20 on this call. If you're interested in the EQM call, the dial-in number is (913) 312-9034, the confirmation code is 8851668. In just a moment, Phil will summarize EQT's operational and financial results for the year-end 2014. Next, Steve will summarize the capital budget revisions and the reserve report. Finally, Dave will provide a summary of our strategic and operational matters. Following the 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 related to future events and expectations. You can find factors that could cause the company's actual results to differ materially from these forward-looking statements listed in today's press release under Risk Factors in the EQT's Form 10-K for the year ended December 31, 2013, which was filed with the SEC; and is updated by any subsequent Form 10-Qs, which were on file at the SEC and available on our website; and the company's Form 10-K for year-end December 31, 2014, which is scheduled to be filed with the SEC next week. Today's call may also contain certain non-GAAP financial measures. Please refer to this morning's press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measure. With that, I'd like to turn the call over to Phil Conti.

Thanks, Pat, and good morning, everyone. As you read in press release this morning, EQT announced 2014 adjusted earnings of $3.40 per diluted share compared to $1.97 per diluted share in 2013. A high-level story for the year as well as the fourth quarter was a very strong volume growth and overall lower unit cash cost. Notably, Production volumes were 26% higher than last year and Midstream gathering volumes were up by 27%. As a result, adjusted EQT earnings, EPS and operating cash flow for 2014 were all up considerably over 2013 by any measure, although both years were impacted by some unusual items that should be considered when interpreting and comparing results. I will touch on a couple of these items in my comments, but I do refer you to our non-GAAP reconciliations in today's release for more details. Also, adjusted operating cash flow of $1.4 billion in 2014 was up considerably at 19% higher than 2013. As I mentioned, we have several unusual items impacting earnings during 2014. In the second quarter, EQT completed an exchange of our Nora assets with Range Resources Corporation for 73,000 net acres in the Permian basin. We did record a $34 million gain at the time on that transaction. In the fourth quarter of 2014, EQT recognized pretax impairment charges of $162 million on our Ohio Utica shale properties, where estimated ultimate recoveries, or EURs, were significantly below our expectations; and also, a $105 million impairment on our Permian basin properties as a result of the decline in oil prices. Also in the fourth quarter, EQT contributed $20 million to our charitable foundation. Fourth quarter 2014 adjusted earnings were $0.96 per diluted share. That compares to adjusted EPS of $0.39 in the fourth quarter 2013. A significantly higher Production and Midstream volumes, once again, drove results. Adjusted operating cash flow at EQT was $390 million in the fourth quarter compared to $314 million for the fourth quarter of 2013. Our operational performance continued to be outstanding in the fourth quarter with 33% higher Production volumes than the fourth quarter 2013. We also realized 40% higher gathering volumes than last year and continued low per unit operating cost in both businesses. Finally, in the fourth quarter, effective tax rate was actually negative as the full year 2014 effective tax rate of approximately 30% ended up lower than the 33%, which we had applied to the first 3 quarters of 2014. The lower full year rate resulted from several factors, including some state tax planning that was implemented in the fourth quarter. The continuing impact of blending and the growing nontaxable EQM partnership earnings are consolidated with EQT and low pretax income as a result of the impairments in the fourth quarter. Now moving on to a brief discussion of results by business segment. I will limit my discussion to the full year results as the explanations for the full year, for the most part, apply to the fourth quarter as well. So starting with EQT Production operating results. As has been the case for many years, now the big story in '14 at EQT Production was the growth in sales of produced natural gas. As I mentioned, the growth rate was 26% higher for the year, driven by sales from our Marcellus wells. 2014 was our fifth straight year of more than 25% sales volume growth. The EQT average realized sales price was relatively flat at $4.16 per Mcfe, and 14 -- about $0.04 lower than it was in 2013. For segment reporting purposes, of that $4.16 per Mcfe realized by EQT Corporation, $3.23 was allocated to EQT Production with the remaining $0.93 to EQT Midstream. The majority of this $0.93 at Midstream is for gathering, which averaged $0.73 per Mcfe. I'd like to summarize a few changes that we made to our price reconciliation table, which should help in understanding the buildup of our realized price, which excludes noncash impacts. First, we applied the processing deduction directly to the liquid sales rather than averaging those deductions across all gas and liquids volumes. And secondly, we moved the Btu uplift to the natural gas sale section of the table to reflect the fact that on average, our gas has a higher Btu content than the NYMEX spec, primarily as a result of ethane that is sold as methane. Because of that higher Btu value, we realized a higher price per Mcf at NYMEX, which is reflected on the table. And then finally, we added an average differential line. The average differentials include the impact of local basis, recoveries received from selling some of our natural gas into higher-priced markets, recoveries from the resale of unused capacity and the impact of cash settled basis swaps. With these changes, it better explains the sales price that we received for our gas. For the full year, total operating expenses at EQT Production were 600 -- $867 million, excluding the impairment charges of 9% higher year-over-year. Absolute DD&A, SG&A, LOE and production taxes were all higher, again, consistent with the significant production growth. Moving now to the Midstream business. Operating income here was up 17% year-over-year, mainly as a result of the continued growth on gathered volumes and the subsequent entries in gathering total operating revenues. Transmission net revenues also increased by almost 41% year-over-year as a result of an increase in firm-contracted capacity. Net operating expenses at Midstream were about 17% higher year-over-year, and that, again, was consistent with the growth in the Midstream business. Finally, our standard liquidity update. We closed the year in a great liquidity position with 0 net short-term debt outstanding under EQT's $1.5 billion unsecured revolver and about $950 million in cash on the balance sheet, and that excludes cash on hand at EQM. Based on current commodity prices, we forecast approximately $1 billion in operating cash flow for 2015 at EQT, and that is, again, excluding the noncontrolling interest portion of adjusted EQM EBITDA. So we expect to fund our roughly $2 billion, 2015 CapEx forecast, again, excluding EQM, with that expected cash flow and current cash on hand. With that, I'll turn the call over to Steve Schlotterbeck to discuss the reduction in our CapEx forecast as well as today's reserve release.

Thank you, Phil. As you read in today's press release, we were lowering our 2015 CapEx budget by $450 million or 18% in response to the current economic environment. This consists of $425 million in EQT Production and $25 million in EQT Midstream. Of the $425 million reductions at EQT Production, $400 million is related to reductions in our drilling and completions budgets. We're reducing our Permian program to 5 wells, which were required to hold our acreage. And in the Marcellus, we are narrowing our focus to our highest-return Marcellus development areas. And the remaining $25 million reduction is in G&G and facilities expenditures. These cuts do not assume any service cost deflation. While we expect to realize significant service cost reductions, we are currently in negotiations with all of our suppliers and do not want to forecast specific savings until those negotiations are concluded. Moving on to our dry gas Utica well. As you know, we spud this county [ph] well in November. During the drilling of the curve, we encountered higher-than-expected reservoir pressures. Based on the pressures observed, we needed to significantly increase our mud weight. However, the mud system on the rig is not rated high enough for what's required to continue drilling. Therefore, we are now bringing in a rig with a higher-rated mud system, which has caused us to be behind our original schedule. We expect that rig to be on location toward the end of February. But despite this minor timing setback, we continue to be excited and optimistic about our dry gas Utica potential beneath our acreage. Finally, I'd like to discuss our reserve report. This morning, we announced year-end 2014 total proved reserves of 10.7 Tcfe, with a 2.4 Tcfe or 29% higher than the previous year and represents a reserve replacement ratio of 590%. Extensions in discoveries totaled 3.3 Tcfe, which included 939 Bcfe of crude reserves from 220 wells that were unproved in 2013, but they were drilled and completed in 2014. This is consistent with the company's history of continuing to expand its footprint and develop areas that we believe to be economic even when they do not meet the SEC's definition of proved reserves. Another piece of the 3.3 Tcfe of extensions in discoveries was 1.4 Tcfe of previously probable and possible reserves that we plan to drill over the next 5 years that were moved to proved undeveloped due to expansion of the geographic area classified as proved, longer-planned laterals and improved type curves. Additionally, 954 Bcfe from new locations, primarily as a result of acreage additions, were booked as PUD reserves. And one final comment on proved reserves, 790 Bcfe of proved undeveloped reserves were converted to crude developed in 2014 as a result of our drilling and completion program. Our 3P reserves, or the total of proved, probable, and possible reserves, increased 6.4 Tcfe to 42.8 Tcfe, an 18% increase over the prior year. This increase was mostly in the Marcellus and does not include any dry Utica. And finally, we are adjusting our guidance for our DD&A rate for 2015 to reflect the finalized reserve report. We now estimate our per unit DD&A to be $1.17 per Mcfe or $0.05 lower than 2014. Also, as you see in our 10-K that we expect to file next week, our after-tax PV-10 was $4.8 billion, 22% higher than last year, driven by the increase in crude reserves. This reflects a NYMEX price calculating in accordance with the SEC requirements that was $0.70 per dekatherm higher than in 2013. However, a decrease in regional basis of $0.71 per dekatherm led to an effective wellhead price that was $0.01 lower than last year. I'll now turn the call over to Dave Porges for his comments.

Thank you, Steve. Given the straightforward results for the fourth quarter, I will limit my prepared remarks to a discussion of our 2 announcements back on December 8, our 2015 operational forecast and our intent to form a second master limited partnership, or MLP. As you know, this is our first conference call since we've made those announcements, and we thought there might be some interest in hearing us elaborate on those topics as both pertain to our contemplated activities in 2015. Let's cover the MLP first. Our intent with this new vehicle is that it will own EQT's general partner, or GP, interest in EQT Midstream Partners, or EQM, including the incentive distribution rights. And it will also own the $21 million EQM common units that are owned by EQT. EQT will be the general partner of the new MLP. And as a result, EQT will continue to operate both MLPs, a distinct advantage as we execute on our development plans. Once EQM's 2014 Form 10-K is filed and the results are incorporated into the draft prospectus, we intend to file that document, the S-1, with the Securities and Exchange Commission during the first quarter. This will begin the iterative process of review by the SEC in response by us, so we hope to be ready for an IPO by about midyear, but the timing will depend upon that review process. We do not believe that the rapidly growing GP cash flows are being fairly valued in the EQT stock price. As we reviewed our alternatives to rectify that situation, we concluded that we wanted to be a vehicle that was publicly traded; had favorable tax attributes, such as those offered by an MLP; retains effective operational control by EQT, as long as that seems optimal; and that would allow a tax-efficient separation from EQT should we decide to affect one in the future. To be clear, we do believe there are significant operational synergies between a midstream and upstream business during this time of rapid growth. We recognize that this period will not continue indefinitely, and we need to be quite comfortable, but the chosen structure would not preclude a tax-efficient separation should that become desirable. As tied to the announcement, we received a few offline questions as to why we chose the MLP structure over the structure known as Up-C. We did give that latter structure significant consideration but concluded that the age of a significant portion of the EQM assets precluded favorable tax treatment offered by the Up-C structure. Also, we concluded after much in-depth discussion with tax experts that a tax-efficient separation was every bit as feasible for a standard MLP as for an Up-C. Moving on to our operational forecast for 2015. You have read about the specific statistics in the December release and revisions in today's earnings release and heard more about this just now from Steve. What I would like to add in the discussion is more about our thought process, especially how it relates to our financial situation and philosophy. As Phil mentioned, we ended 2014 with $950 million in cash at the EQT level and investment-grade rating from the 3 major rating agencies: 0 drawn on a $1.5 billion unsecured revolver; $200 million of Midstream EBITDA still owned by EQT Corp; our plan to drop our Northern West Virginia gathering assets to EQM in 2015; and proceeds expected from the previously discussed GP IPO. In that context, when we announced our budget in December, we were comfortable with a CapEx estimate that was about $1.2 billion higher than our operating cash flow estimate for 2015. Frankly, my expectation was that the GP IPO proceeds would not be touched in any of that. That money would remain in the bank account as of the end of 2015. Since that time, the 2015 NYMEX strip for natural gas, crude oil and NGLs has declined significantly. Using current prices, we estimate that our operating cash flow for 2015 will be approximately $300 million less than we anticipated at the time of that release in December. As a result, we decided to lower our activity level to more than match the decline in operating cash flow. So if things play out as planned, we expect to end 2015 with significant cash on hand, nothing drawn on the revolver, et cetera. In other words, with this revision, our current expectation is that we will be in a better position from a financial liquidity perspective than we expected at the time of the December release. In times of financial stress such as these, we think the prudent approach is to be conservative financially. Whatever happens over the course of the rest of this year from a financial perspective, quicker recovery or slower recovery, the presence or absence of opportunities created by overextended peers, et cetera, we believe we are better off with cash on hand, strong credit position and strong equity position. In my opinion, it is too early in the cycle for us to know how this will play out. But no matter what happens, we are confident that having a strong balance sheet will create shareholder value. At the least, it feels good to know that we already have clear line of sight for funding robust, value-accretive drilling programs this year as well as, at least, the next couple of years. I believe that our strong balance sheet will differentiate EQT during this low-price environment, as we will be able to continue to efficiently and profitably develop our acreage over a multiyear period and emerge from the cycle stronger than when we entered it. In summary, EQT is committed to increasing the value of our vast resource by intelligently accelerating the monetization of our reserves and other opportunities. We continue to be focused on 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.

Thank you, David. That concludes today's prepared portion of the call. David, can we please now open the call for questions?

[Operator Instructions] We'll take our first question from Phillip Jungwirth with BMO.

On the third quarter call, you guys have talked about it being most economical to develop the core Marcellus and Upper Devonian. That it's fast. It's practical and yet, midstream [indiscernible] commitment to support mid-20% growth for over the next couple of years, obviously, is the one that's changed since then. But I was just wondering if you could provide any update to the longer-term growth outlook and the reduction '15 CapEx, and whether you could provide a range of sensitivities such as at $4 gas, we can grow mid-20s. But with at $3 gas, I think it's more prudent to target a mid-teens growth rate.

We're all looking at each other. We haven't actually gone through all of those sensitivities. It is fair to say that if we spend less, then the growth rates will be a little bit less. But frankly, we would still think that they would have approached the levels that we have talked about previously if the strip remains what it is at. I mean, it's -- at the current strip, you're probably looking -- you might be looking at more like mid to high teens for the next couple of years, but we have tried to position ourselves so that we could ramp up, as Steve mentioned, pretty quickly if need be. I mean, that's part of the benefit of having cut back more than cash flow would have dictated that we needed to. But we haven't really run through a variety of sensitivities in this kind of volatile market to give you a good answer to your question about what the growth rate would be at different NYMEX prices. Over the course of the next couple of months, we probably will run through those types of sensitivities, and certainly, we'll share those as we do.

Okay. I know you guys haven't provided '16 guidance. But how would the reduced '15 activity plan impact your ability to ramp back up? I know you've always talked about there being a 9-month lag and spud to sale. So for 2015, should we think about that just taking the sequential run rate in the back half of the year extrapolating that into '16? Or is there the potential to ramp back up any increase in wells but could still impact '16?

Yes. Phil, this is Steve. Yes, we continue to have a fairly long lag time from TIL -- or from spud to TIL, that will continue. So what that means is most of the changes in '15's CapEx plan will affect 2016 production, and we've announced no impact on 2015. We'll maintain the ability to ramp up fairly quickly if the current price environment would approve and dictate that, that's a prudent thing to do. So we could change our plans fairly quickly. But given the plan that we just announced with the CapEx reductions, we think it's safe to say that we expect to be in the mid- to high-teens production growth in 2016. And again, if things improve and we can ramp back up, then that number would go up as well.

Okay, great. And then last question, has anything in the last couple of months, such as gas prices or land activity levels, changed your thinking on the GP valuation, which I think last quarter you expect at $4.6 billion. And I know there's a range based on terminal growth and the discount rates, but the publicly traded EQM LP units have actually been pretty resilient. I want to think that [ph] but I just want to make sure.

Well, the -- our inside counsel who is in the room are staring at us with what feels like daggers, and they have -- they reminded us before the call that given that we've announced our intention to file a prospectus, an S-1, that we really shouldn't be commenting on such things. So I hope you will understand our reluctance to answer that question. I will comment that I think other people's GP opportunities have not necessarily been impacted by this if they're in a -- an area that has a favorable -- relatively favorable cost structure such as the Marcellus, Utica.

We'll take our next question from Michael Hall with Heikkinen Energy Advisors.

I guess a couple of questions on my end, some were kind of hit on already. But you all mentioned that there were no assumed cost reductions in 2015 budget as of yet. I guess, number one, where are you? I guess, in the process ahead of those conversations, any indications around quantifying what those might look like? And then secondarily, to the extent they do come in, in a material -- how should we think about that as it relates to the capital budget? Should we expect you to accelerate with those excess savings? Or would that -- it sounds like maybe more likely accrued to the balance sheet.

Michael, we're right in the middle of that process. I can tell you, we have contacted all of our suppliers requesting a reduction, and we are starting now to get responses. And we're pretty happy with what we're seeing so far. But again, it's in the middle of the process, and we're hesitant to really comment in detail on it because we don't want that compromise any of our negotiations. But I think over the course of the next 3 or 4 weeks, we should conclude the bulk of that and have a better idea of exactly how much savings we expect to get.

And given the -- to your question about spending the money, frankly, given our ample liquidity and forecast liquidity, getting extra money doesn't really affect our thought process. I mean, we will be making decisions about the pace of development as we look at the market more broadly, not based on having a few bucks. I mean, we've -- we're not uncomfortable at all. Because I think we've been saying ever since we started the drops of the MLP a couple of years ago, we are not at all uncomfortable with having extra cash in the balance sheet. We don't think that, that prudence has hurt us in the past. There's nothing about the market that makes us think that, that's not -- that, that's an inappropriate approach. So we're going to stick with that.

Okay, helpful colors. And then the kind of resale of excess term has helped you out in the last few quarters or several quarters. How long do you guys project having the ability to do that? Meaning like, do you eat up that firm in 2015 time period? Or is that something you'll have in your back pocket, if you will, through the course of 2015?

Michael, this is Randy. Certainly, we think that the capacity portfolio that EQT holds has value, value in the long run. And so we would expect that to continue for an extended period of time. But I would also point out that a great deal of the benefit that we're getting is our ability to get to further downstream markets and to pick up feel-better pricing as a result.

So in other words, it's -- we're happy -- we're just as happy with the money that we get from selling our own gas into a premium market, as we would be to sell to right to move the gas, sell that right to somebody else. We still get the benefit. And of course, we continue to add capacity, basically, every year from now for the next couple or 3 years, 4 years.

Okay. Yes, that's helpful. And then it might be something I need to wait for, but as it relates to the second MLP, I don't know if this has been discussed in the past or not, but is the intention -- like you said, you're alone on the GP on that, or maybe I'm ahead of myself, but is there an intention to have IDRs on that GP as well?

Yes.

What was -- what if we...[ph]

Now there's the -- the new -- the GP IPO, or the GP MLP will not have an IDR structure.

Compounding IDRs.

Yes. The IDRs from the existing MLP end up in the new MLP. But they won't have a similar structure.

We'll take our next question from Drew Venker with Morgan Stanley.

You had mentioned that first Utica test and encountering higher pressure. Can you provide any color on just how much the pressure exceeded your initial expectations?

What I'll tell you is we had the mud up to 18.7 pound per gallon mud, which indicates an extremely high pressure gradient. And we were several pounds per gallon below that.

Okay. And where was that well?

That's in Greene County, Southwestern Pennsylvania.

And can you remind us where you're planning to drill the other tests in 2015?

The next test will -- is planned for Wetzel County. And beyond that, it will depend on the results we see from the first 2.

Okay. So is it the idea to delineate primarily West Virginia this year aside from the Greene County well? Or is there a lot of potentially drilling tests in this first run within Pennsylvania as well?

I think it's going to be strictly dependent on what we find, so we have -- we don't have a lot of direct geologic data. So these are -- they are first tests, so we're going to gather a lot of data. And depending on what we see, we'll determine where we need to go. So first one, Southwestern Pennsylvania, second one, Northern West Virginia and beyond that will be determined by those first 2.

All right. Can you give us a sense of when we might get results from those first 2 tests?

Well, I hesitate to say that given that these are exploratory wells, and as we've already seen, unexpected things can happen, so we expect to be back drilling the curve in the lateral on the first well in late February. So that should take a few weeks, and then we'll be fracking the well, so that pushes it out probably another month. But with these kinds of wells, it's hard to predict. So -- but in this early spring, we would hope to start getting some results.

And you might share those at that time or maybe it may depends on what you see?

Yes, I think it depends.

We'll take our next question from Neal Dingmann with SunTrust.

Steve, for you or the guys, wonder -- I know the production -- or I guess I should say the EBITDA cash flow guidance out there, I think you are assuming some differentials that were certainly a bit higher than what you've seen last quarter. Just want to know how you think about that. I think, as far as what you're thinking now on cash flow, I think you had for the quarter, I would call, what's roughly around $0.40-or-so differential. Just, I guess, your thoughts on 2 things. One, what are you kind of -- you're thinking about differentials here for the next, I guess, the remainder of this year? And how does that impact that cash flow or EBITDA?

Neal, we have this in the press release that's under guidance. So the differential for the year, we're projecting at between negative $0.40 and negative $0.50. And for the first quarter, we expect it to be positive $0.10 to $0.15.

That -- I guess I understand that path. I mean, I think back in December, you're looking -- on a higher differential number, you had, I thought, virtually the same sort of estimate for cash flow. So it's like -- I guess what I'm getting at is just the difference between the -- the difference in the [indiscernible] differentials, the new change in production, is that what offsets this?

No. The differentials is -- they were less than $0.05 better than in December, about $0.05 better. It's the NYMEX price that mainly is impacting the cash flow.

Okay. You just make sense on that. I got you, I got you, okay. And then lastly, just on takeaway, you guys continue to do an outstanding job as far as being ahead of the curve there. I know versus some of your peers that still lack ample takeaway in the Utica. Just your thoughts, maybe for Steve or any of the guys, when -- I guess depending on the success of some of these dry gas Utica wells, is it suffice to say you'll have ample takeaways in that region if those come on as well?

Neal, I think it's a little early to really try and project, really, what's going to happen with dry Utica, given that we haven't even finished our first well. So I think we're going to hold off even commenting on that until we've got some test results and really can quantify what we think the impact of a success in the dry Utica might be.

Next question comes from Joe Allman with JP Morgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: So I know that this morning, you lowered your planned CapEx budget for 2015, but I just want to compare the new CapEx budget to what you spent in 2014. So if we're talking about just exploration and development, is your new CapEx budget for 2015 higher than what you spent for E&D in 2014? Or is it flat or lower? And what does that mean for where your rig count goes from here?

Joe, it is up a little bit. I don't actually have the number right in front of me, so we're checking on that to tell you how much. But it is an increase over '14.

Yes. So '14 for development, we were at $1.7 billion.

$1.85 billion this year.

And $1.85 billion this year, so. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. And so from here, does that mean an increase in rig count or?

Well, the rig count, we -- for the bulk of the year, we expect to have 8 big rigs running and 4 topple rigs, so a total rig count of 12. I think we’re currently at 15 as we stand today, but that will be ramping down here shortly. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Got you. Okay, that's helpful. And then the reduction in CapEx, at least on the production side, I think your old budget was $2.3 billion, and now you're at $1.85 billion, so that's a 20% decline in CapEx. Your well count is down by 33% in the Marcellus and the Permian from what you plan in December. So could you just help me understand the -- why the CapEx drop is not proportionate with the well drop?

Yes. There's a lot of CapEx that's -- for completing wells that we're spud last year. So you have a -- your CapEx, it goes against well spud against last year. And then wells are spud this year, there'll be CapEx associated with those that carry into next year as well. So it's very normal to have a disconnect there.

Remember that the majority -- the clear majority of what we spend on any well is spent after we've -- after the drilling rig itself has moved off the location. And yet our account is typically for spuds.

Right. But what's the inventory of wells that you drilled that you haven't yet completed as of December 31, 2014?

[indiscernible] the release. We'll get back in a second. So we had 722 wells spud, and 531 of those were online at the end of the year. And then there's 23 that were complete, but not online.

Next question comes from Stephen Richardson from Deutsche Bank.

David, I was wondering if you could -- at risk of raising the ire of your General Counsel, I was wondering if you could talk about your comments about the tax-efficient separation potential of this new HoldCo? And are there any restrictions on -- are there any requirements on EQT -- C corp's ownership of this structure going forward?

Yes, there will be with any of these things. It's not specific to our situation. But the requirements have more to do with how much kind of indirectly, I guess, you'd say, how much of the ownership of the underlying operating assets that we have. So that's -- it wouldn't be specifically EQT's ownership of this GP HoldCo. It would be more related to that ownership x the HoldCo's ownership of EQM. That would really be more of what would be looked through. So exactly how any such entity goes about optimizing that is kind of depends on the circumstances. We'd -- and we'll be taking a look of that. But that's really the issue. It's not the standard C corp, C corp, where you think about you need to add about 80% ownership, 80% -- and then -- and spend 80%, if that's what you're getting at. It's a much lower thresholds, but your requirements are tied to what that underlying -- the ownership of the underlying operating businesses.

Got it, okay. And is there any -- as you think forward, acknowledging the synergies between these 2 businesses in the next couple of years, certainly, as you think forward to certainly building potentially the MVP pipeline, are there -- do you think there's a relationship between when the timing of this potential tax-efficient separation would come and the funding needs of EQM building new projects? Are those 2 issues related? Or are they independent? How do we kind of think about that in terms of timing?

I haven't really thought that EQM's funding needs are necessarily related to that, so I would grant you, that given what we just talked about, the -- when you need more funding, that you too can get to the point where you'd dilute the parent company's ownership sufficiently that you'd say, "Geez, you better make a move before you pass through that threshold." So certainly, that would -- that could factor into it. But there's a variety of ways that one could deal with it in the meantime. More broadly, but really just looking at what's the best way to create shareholder value for EQT shareholders. That's the governing issue. But the comment that you're making about EQM's ultimate growth is certainly a fair one. It does impact the -- that is one of the factors that one would look at.

Got it. Okay. If I could follow up just a little quick one for Steve, the decision to cut back in the Marcellus. Can you talk a little bit about where you're going to be focusing activity? I would assume that this would be less C county drilling certainly and more Greene and Wetzel drilling in terms of the core program for '16. How do you balance that with what's going on with your processing margin and some of the issues right now in the NGL market in the Southwest? If you could just talk to that a little bit, it'd be useful.

I think you actually answered your own question. So our focus is definitely going to be in our core Southwestern Pennsylvania, Northern West Virginia areas. Until recently, the Northern West Virginia development has a slightly higher return in our Southwestern PA even though the Pennsylvania wells were a bit more productive because of the liquid uplift. The current liquids market, that's flip flopped a little bit. So the southwestern PA dry gas area is back on top with Northern West Virginia close second, but pretty much pulling back everywhere else. So yes, the C counties, no drilling and some of the step-out wells we were doing, especially some of the dry areas of West Virginia is where we're cutting back.

Next question comes from Cameron Horwitz with U.S. Capital Advisors.

Just a real quick question for me, does your production guidance bake in any expectation for production shut-in, in the next rollout period just due to pricing at all?

No, we're expecting any shut-ins.

And we'll take our next question from Michael Hall, with Heikkinen Energy Advisors.

I'm just -- I was curious as it relates to the 2015 plan in wells put on the production. Any guidance or on how many wells you would expect to put on production in 2015 average lateral length? And if there's any nuance as to the timing of those wells coming on given the trajectory coming out of 2014?

Michael, I don't have the specific numbers in front of me. But regarding the timing, I think you're likely to see production in the second and third quarters to sort of moderate a bit. So this year will be a first in 4 quarters it'd be where our growth has been. And if you look back over our history, you'll see that, that moves around. But we generally have a couple of quarters every year with bigger sequential growth than the other 2 quarters. This year is more likely to be first and fourth, sort of [ph] bigger increases, just based on the timing of our drilling plan.

We'll take our next question from Michael Rowe with Tudor, Pickering, Holt & Co. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I was just wondering if you could maybe just expand a little bit on your comments earlier regarding the current liquids market fundamentals in West Virginia, and just how those have deteriorated a little bit since -- even just a month or 2 ago? I just wanted to see if you could expand on that maybe a little bit and then provide any insights into your NGL realization for 2015.

We have a slide in our presentation that shows what's usually called the liquids uplift, and now we call it the liquids impact. Because essentially, the price that you get -- you still get a higher price per Btu for the liquids, but we take out the processing fee, you end up back at even with the gas price. So right now, they're being priced on par net of fees.

But we're not experiencing anything any different than others. We just -- I mean, we have less wet gas, obviously, than some of our peers, so we don't -- the impact is more muted for us. So it's probably better, folks, for you to ask about that question. But -- so we don't have anything, really, to offer other than what you see in the market, which is that ethane prices are very weak, especially netted back to the wellhead, especially. And propane, because of the storage situation, is also quite weak. And there's a variety of takeaway projects that are in the market, that are just designed to mitigate some of that. But it's -- when oil prices have dropped as much as they have, it's really swimming upstream. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, that makes sense. And I guess just the last question is, it looks like -- I look at your new February analyst presentation, the EQT gathering -- from EQT Midstream gathering CapEx has come down, probably 35%, 40% from your prior guidance. And so that's just related to fewer wells being drilled and potentially, fewer wells being brought online?

That only came down by $25 million on a 2.5 -- $250 million budget, so it's about 10% reduction. And that just ties to gathering systems that were being built where the drilling that's been cut that we won't need it as soon.

It refers to what Steve has talked about in the C counties and stuff like that.

And we have no further questions in queue at this time. I would like to turn the conference back over to Mr. Pat Kane.

All right. Thank you, David, and thank you, all, for participating.

That does conclude today's conference. We thank you for your participation.