EQT Corporation (EQT) Q4 2012 Earnings Report, Transcript and Summary

Good morning, and welcome to the EQT Corporation 2012 Earnings Conference Call and Webcast. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Mr. Patrick Kane. Please go ahead.

Thanks, Amy. Good morning, everyone, and thank you for participating in EQT Corporation's year-end 2012 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. today. The telephone number for the replay is (412) 317-0088 with the confirmation code of 10006617. The call will also be replayed on our website for 7 days. As you already know, this is the second quarter for EQT Midstream Partners, ticker EQM, and its results are consolidated in EQT's results. There's a separate press release issued by EQM this morning, and there's a separate conference call today at 11:30, which creates a hard stop for this call at 11:25. If you are interested in the EQM call, the dial-in number is (412) 858-4600. In just a moment, Phil will summarize EQT's operational and financial results for the year-end 2012, which were released this morning. Then Dave will provide an update on our strategic operational matters. Following Dave's remarks, Dave, Phil, Randy and Steve will be available to answer your questions. But first, I'd like to point to a new table that was included in today's press release. This is a revenue recognition table found on Page 12 titled EQT Corporation Price Reconciliation and details the company's production revenue per product. This new table will replace the historically published price reconciliation table, which is also included on Page 5 of today's release. For your modeling purposes, we published the last 4 quarters using the new price reconciliation format on our website. I would also 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 on today's press release under Risk Factors in EQT's Form 10-K for the year ended December 31, 2011, which was filed by the SEC and updated by any subsequent Form 10-Qs, which were also on file with the SEC and available on our website, and in the company's Form 10-K for year-end December 31, 2012, when it's filed. Today's call may also contain certain non-GAAP financial measures. Please refer to the morning's press release for important disclosures regarding such measures including reconciliations to the most comparable GAAP financial measure. With that, I'll turn the call over to Phil Conti.

Thanks, Pat, and good morning, everyone. As you read in the press release this morning, EQT announced 2012 adjusted earnings of $1.49 per diluted share compared to $2.19 per diluted share in 2011. The high-level story for the year and the fourth quarter was very strong volume growth and lower unit cash costs in both the Production and the Midstream businesses, which was overcome throughout the year by significantly lower commodity prices. Reported earnings for 2012 and 2011 were also impacted by several somewhat unusual items that should be considered when interpreting and comparing results. With the exception of some items in the fourth quarter, which I will touch on in a moment, we have discussed these items on prior calls. Rather than to repeat those explanations, I will refer you to the detailed list on our non-GAAP reconciliation table on Page 7 of today's release. Operating cash flow was $832 million in 2012 or about $55 million lower than last year. Just as a reminder and Pat touched on it, the full-year 2012 results included 2 quarters of results from our MLP. As you will recall, EQT Midstream Partners results are consolidated in EQT Corp. results and EQT recorded $13 million of net income attributable to the noncontrolling interests or $0.09 per diluted share. So again, in short, 2012 was a strong operating year at EQT. Production volumes were 33% higher than last year. After gas-liquids volumes were 13% higher, Midstream gathering volumes were 30% higher and transmission capacity reservation revenues grew by 27%. However, commodity prices were 21% lower than last year, which again meant we were fighting an uphill battle on operating income and cash flow results throughout the year in 2011 -- for 2012 versus 2011. Fourth quarter 2012 adjusted earnings were $0.48 per diluted share. That compares to EPS of $0.59 in the fourth quarter of '11. A significantly higher production sales volumes were again overcome by lower commodity prices and higher absolute cost, along with $5.5 million of revenue reductions related to the capacity resell of the El Paso 300 line and $4.3 million of unrealized losses at Midstream, both of which we also experienced in prior quarters this year. The fourth quarter adjusted earnings number also excludes 4 items that did not occur in the prior quarters: a $23.3 million expense related to an interest rate hedge; approximately $4.5 million in transaction expenses associated with the sale of Equitable Gas; a $4.5 million lease impairment reported in exploration expense; and a positive $2.5 million regulatory reserve reversal at Midstream. Again, these items are detailed in the release. But before moving on, a moment on the interest rate hedge. During the third quarter of 2011, the company entered into an interest rate hedge in anticipation of refinancing $200 million of long-term debt scheduled to mature in November 2012. We subsequently entered into several transactions including the formation, an IPO, of EQT Midstream Partners, MLP and the announcement of a definitive agreement to sell Equitable Gas. These capital-raising transactions improved the company's current and projected liquidity position to such an extent that not only was there no need to refinance that 2012 debt. It became unlikely that any debt financing will be required in 2013 as well. So the interest rate hedge position was closed without resulting in the recognition of $23.3 million expense. Operating cash flow at EQT was $268.9 million in the fourth quarter 2012, compared to $243.7 million for the fourth quarter of '11. Our operational performance continued to be outstanding in the fourth quarter with 44% higher production volumes for the fourth quarter '11 and 12% higher sequentially than the third quarter of '12. We also realized 43% higher gathering volumes than last year and continued low operating -- low per-unit operating cost in both businesses. However, commodity prices were 16% lower than the same period last year, resulting in lower operating income and cash flow despite the operational accomplishments. In the fourth quarter, EQT recorded $8.2 million of net income or $0.05 per diluted share, again, related to the noncontrolling interest unitholders at EQM. Also in the fourth quarter, EQT announced that we have entered into a definitive agreement for the transfer of our natural gas Distribution business, Equitable Gas Company, to Peoples Natural Gas. We will receive cash proceeds of $720 million subject to certain purchase price adjustments and select midstream assets and commercial arrangements, which are expected to generate at least $40 million in EBITDA. We and Peoples Natural Gas are working very hard to receive the necessary regulatory approvals by year-end 2013. But of course, many factors can influence that timing. So we will keep you apprised as we move through the process. Concurrent with the announcement, we also reduced the EQT dividend to reflect the blend of EQT's 2 remaining core businesses: a dividend-supporting Midstream business and a capital-intensive rapidly growing Production business. Now moving onto a brief discussion of results by segment, and I will limit my discussion to the full-year results as the explanation for the full year also tend to apply to the fourth quarter. And starting with EQT production operating results. As have been the case for 3 years now, the big story in '12 at EQT production was the growth in sales of produced natural gas. As I mentioned, the growth rate was 33% for the year driven by sales from our Marcellus wells, which contributed 58% of the volumes in 2012, up from 42% in '11. The EQT average wellhead sales price was $4.26 per Mcfe in 2012, or $1.11, lower than last year. The realized price drop resulted from lower NYMEX natural gas prices and lower liquids prices, which were only partially offset by an increase in our hedging gains. For segment reporting purposes, of that $4.26 per Mcfe of revenue realized at EQT Corp., $3.5 per Mcf was allocated to EQT Production and the remaining $1.21 per Mcf to EQT Midstream. The majority of this $1.21 at Midstream is for gathering, which averaged $1.02 per Mcf for the year, and $0.99 for the fourth quarter of 2012, down from an average of $1.11 per Mcf in 2011. The Marcellus gathering rate, as you know, is significantly lower than the rates in our other plays. So as Marcellus volumes grow as a percentage of the total, the average gathering rate tends to go down. This downward path will continue this year, and we expect the rate to trend down to an average of about $0.85 per Mcf in the fourth quarter of 2013. The unit realized price for EQT Production was 25% lower than last year, again, primarily driven by lower NYMEX prices. The impact of higher volumes and lower realized price in '12 resulted in EQT Production revenues of just under $794 million, which was essentially flat with 2011. On the other hand, total operating expenses of production were $202 million higher year-over-year. Absolute DD&A, SG&A, LOE and production taxes were all higher, consistent with the significant production growth. DD&A represented about $152 million or 75% of that increase in total operating expenses at production and was driven by the higher volume and higher depletion rates. Consistent with prior quarters this year, production SG&A expenses were up in the year-over-year comparison as a result of higher corporate overhead and commercial services allocations, which were adjusted in 2012 to more closely track activity and the importance of this segment to the company. Absolute LOE was a bit higher year-over-year. However, volume increases have been outpacing the general trend of higher absolute expenses and as you would expect, per unit LOE was lower again in 2012 by about $0.02 per unit or 10% to $0.18 per Mcfe for 2012. As you model full-year 2013, we expect DD&A expense to be $1.54 per Mcfe in 2013. Moving on to the Midstream business. Excluding gains on asset sales in 2011, operating income here was up 11%, consistent with the 30% growth in gathered volumes that resulted in a 21% increase in gathering net operating revenues. Transition net revenues also increased by almost 16% year-over-year as a result of added Equitrans capacity, mainly from the Sunrise Expansion Project and increased throughput. On the other hand, the line item titled Storage, Marketing and Other Net Operating Income was down about $22 million for the year. This part of the Midstream business as you now realize on seasonal volatility and spreads in the forward curve and those continued to trend down in 2012 versus 2011. For 2013, we expect revenues from Storage, Marketing and Other to be approximately $30 million. Net operating expenses at Midstream were about 11% higher year-over-year, consistent with the growth of the Midstream business. About $10.3 million of the increase is as a result of a favorable property tax reserve adjustment in 2011. So absolute costs were up a bit. However, we continue to experience the benefits of scale as unit gathering and compression expenses at Midstream were lower than in 2011. Finally, our standard liquidity update. We did close the year in a great liquidity position with 0 net short-term debt outstanding under our $1.5 billion revolver and $182 million of cash on the balance sheet. Based on current commodity prices, we continue to forecast approximately $1 billion in operating cash flow for 2013. We expect to fund our $1.5 billion 2013 CapEx forecast with that cash flow and cash on hand at year end and available liquidity, as well as proceeds from Midstream assets sale drop downs to EQM later in 2013. And with that, I'll turn it over to Dave Porges.

Thank you, Phil. As Phil summarized, operationally, we are coming off another record year with record volumes at Production and at Midstream, and the forecast of another record year in 2013. Of course, our report of 2012 earnings again makes it apparent that there are many transaction gains and transaction-related charges that probably create some challenges for investors seeking to analyze normalized results. In the past 2 calendar years, we sold the processing plant, sold a FERC-regulated pipeline, formed the master limited partnership and executed an initial public offering of its units, issued $750 million of long-term debt and announced the sale of Equitable Gas Company subject to regulatory approval. These transactions have all fit into our overall strategic theme that we needed to make some tough decisions to reallocate capital in order to provide transparency for us, as well as for investors, for the financing of our growth opportunities for this foreseeable future. To summarize where we stand as a result of all that, we have $182 million in cash on hand at year end as Phil said. We have visibility of a sizable drop into our MLP in the second half of this year, which will provide another cash infusion to EQT. And we expect proceeds from the utility sale within about a year. Of course, the MLP is expected to provide an ongoing source of capital, which would result in the Midstream operations being self-funded. So our core businesses are growing profitably and rapidly. Our MLP is growing profitably and rapidly. We've addressed our funding concerns for the foreseeable future and our operational performance has been on or above plan for at least 12 quarters. We will continue to look at capital allocation decisions aggressively, but now with a more single-minded focus on longer-term improvement of the shareholder value proposition and less influenced by near-term funding needs. Switching to operational matters, we announced the 12% increase in proved reserves over last year, all coming from the Marcellus, and there were some ins and outs as to what was bought. Some Tier 3 wells previously booked our uneconomical last year's average price, which for NYMEX was under $3 as you know and were therefore moved from PUD to probable, while we added new Tier 1 and Tier 2 wells into proved. We also booked 23% higher EURs on average on 25% of our wells to reflect the 30-foot reduced cluster spacing. We also reduced our spacing between laterals proportions of our Greene County acreage to 500 feet from 1,000 feet. Though all of the things being equal, that down spacing also had the effect of some small decrease in average EUR, which was more than offset by increasing well counts and reserves. On a 3P basis, Marcellus reserves increased by 18%. The other notable change was we booked 2.4 Tcf of 3P reserves for Upper Devonian and a very small amount of 3P for Utica, our first booking of reserves from these plays with all of the Utica bookings pertaining to our small Ohio position. We are drilling wells in both plays this year to better estimate the reserve potential. From a sales volume guidance standpoint, we reiterated our 2013 production sales volume estimate of 335 to 340 Bcfe, 31% higher than in 2012. Liquids volumes in 2013 are projected between 3.9 million and 4 million barrels, significantly higher than our previous guidance. Our original guidance had 2 significant conservatisms or conservative assumptions. First, even though the Mobley plant was being commissioned at the time we were completing our business plan, we did not want to presume a flawless startup process at the plant. We were somewhat conservative about our schedule to fill the plant. As it turns out, MarkWest was able to quickly get the plant running efficiently. Secondly, we have been able to accelerate that schedule for filling the new capacity. Our current forecast is based on our existing firm capacity contracts even though we are working to secure additional interruptible capacity. The forecast assumes no interruptible capacity so there may be some upside if we are successful on that endeavor. For the first quarter 2013, we are forecasting a daily production sales rate that is pretty flat with the rate we experienced in the fourth quarter of 2012, possibly a little bit higher. Of course, maintaining that fourth quarter daily rate would result in first quarter 2013 volumes being well over 35% higher than the first quarter 2012. In fact, as you saw last year, the volume growth at EQT can look pretty consistent when full-year averages are examined. It is quite lumpy when looked out over shorter periods of time due to our use of multi-well pads to develop our acreage in addition to the normal issues regarding the turning in light of new infrastructure projects. As we examine our till dates for multi-well pads and infrastructure projects, sequential growth is expected to tick up into the double digits again in the second quarter of 2013, which would be a result in the growth pattern for 2013 not being as back-end loaded as it was in 2012. Each quarter, we will give you some feel for the following quarter so you can better model those quarterly results. In anticipation of your questions, I would like to update you on a couple of previously discussed topics. First, MLP drop downs. We are currently targeting a sizable drop down in the second half of 2013 to fund 2013 Midstream CapEx. We do also continue to evaluate the possibility of a very small drop down in the first half of this year to work through the logistics of a drop. But the entire purpose of such a small transaction would be to serve as a sort of dry run. The size of such a drop if it does occur would be pretty immaterial to EQT's results. Second, the Tioga sale. As we mentioned, we have approximately 8,300 acres in Tioga County, Pennsylvania. We ran a data-room process, and we're not persuaded by the biz that the right answer currently is to sell. Given our strong liquidity position, we have the luxury of not needing to transact in the near future and we will keep the acreage in our portfolio at least for now. As we have stated many times, we are not bothered by the prospect of stopping a sale process if we do not like what we see in the market. Often, a formal process is the only way to test market value. And we believe that we do transact enough to convince prospective buyers so that we do not habitually get cold feet. Finally, we finished drilling our first Utica well in Ohio this month. We are scheduled to move the rig to drill a second Utica well this quarter then plan to move that rig to West Virginia while we permit the other Ohio drilling locations. The first Utica well is scheduled to be frac-ed in mid-February, and we are certainly interested to find out what we have, but we will not have pipes of the well until about mid-year. 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 are in strong financial shape and have visibility on sourcing the needed capital. We look forward to continuing to execute on our commitment to our shareholder and appreciate your continued support. And with that, I'll turn it -- the call back over to Pat.

Thank you, Dave. This concludes the comment portion of the call. Amy, can you please now open the call for questions?

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

A couple of questions. First, guys, just on M&A when you look at, obviously, you're in pretty strong financial position now. How aggressive beyond kind of what you said and then maybe in conjunction with that, you've obviously established a nice little footprint thus far in the Utica, just wondering I guess that's something you'll continue to pursue.

Yes, we'll -- look, we'll continue to look at whatever opportunities we think make the most sense for the company. On the -- look, on the acreage side, the real focus is trying to build up more contiguous position to wherever we have acreage, whether it's the Utica or in Greene County, et cetera. On the sales side of that equation, we would still classify the CBM as being noncore for us. We don't really see when we'll develop it. So there's kind of a timing issue there and at some point, we continue to feel that the right answer on the Huron is to get some form of other people's money. So we continue to look at both sides of that M&A equation.

Okay, and then just secondly, lastly, just on you guys continue to just do a fantastic job on cost containment and just wondering for maybe yourself or Steve, just wondering how much costs can continue to come down we look at this year maybe for guidance or how should we think about it for modeling just on kind of typical LOEs? I guess going forward, I mean, there should be more pad drilling or how should we look at it?

Well, Steve is going to be the one who has to explain whatever comments we make to for the folks in production. So I'll let him answer the question.

Well, Neal, I can't give you specifics on LOE targets, but I will say, as always, we continue to focus on finding ways to be more efficient, drill and produce these wells as efficiently as we possibly can. And I think as a result of our strong growth that we expect to continue, you just get some inherent economies of scale. So I just think naturally, you'll -- we should continue to see our unit costs decline. And I think without giving you specifics, I think what you've seen in the past, that's the reason to believe we can continue in the future for quite -- for some time.

Our next question comes from Scott Hanold at RBC Capital Markets.

Maybe I'll be a little bit more direct to one of the questions that Neal asked. On the Utica, you have 13,000 acres there. Obviously, considering the size of EQT, that's not very material necessarily, but I mean, how competitive is out there and what do you think likelihood is of you adding a significant acreage position and what appears to be the core in that play?

Well, Neal -- or I mean, Scott. Sorry. I think we agree of 15,000 acres is fairly immaterial to EQT at this point. Our view going in was we really need to have a minimum of 50,000 acres for us to feel like the effort was worthwhile. So I think we continue to look at it. I think step 1 for us is to get the results from these test wells, understand a little better what the economics of the play are in the area that we've targeted. Obviously, it's an area that we're excited about. Competitive results have been good. Geologically, it's at the area that we chose to focus on. So I think conceptually, pending results, we think a minimum of 50,000 acres is what will make sense. However, if we find that we can't get there or disappointed in the results, I think we'd be willing to step back from that as well. So -- but I think clearly, holding a 15,000-acre position for the long term likely doesn't make sense for EQT. So we will either increase or it'll go to 0.

And in context, Scott, as you probably recall, that's the same logic we had when we got into the Tioga position and we wound up concluding that for a variety of reasons and a lot of them being competitive reasons. It was going to be tough to get that sort of position in Tioga, which is the reason that we started backing away from the idea of it being a potential core area.

Yes, how sensitive to you are on acreage cost? I know a lot of companies will take a look at paying $20,000 an acre, for example, and you do the math on no resources in place and it can look a little bit more immaterial. So I mean how sensitive to you are kind of some of those kind of a high-level acreage numbers?

Well, I think we're sensitive to economics. So in the specifics of individual plays drive what numbers make sense. So I wouldn't say any particular number we view as high or low. It's got to be within the context of the economics. I will say just to reflect back a few years, I remember when $500 an acre in the Marcellus felt crazy high to us until we understood what the Marcellus was all about and obviously, $500 an acre now would feel like a steal. So we don't set particular per-acre targets. We look at the economics and what kind of returns we think we can generate.

But of course, we haven't done anything close to the numbers that you've talked about, Scott, and those kinds of numbers though would probably make most sense not just for us, but for others, at least in this area, if you're trying to fill in a position. It's hard to place what the value is if you're filling in the proverbial doughnut hole so that you can -- it completely changes your development plan versus when you're getting into a newer area.

Okay, all right. That's fair enough. I appreciate the color. One quick question for Phil. Did you say cash at the end of the year was $182 million because I think...

Yes.

Wasn't it like $600-and-some-odd million at the end of third quarter? So I'm just trying to square the circle on that one.

To be honest, I don't recall the third quarter number, but it's obviously, it's available in the Q in the third quarter. As I mentioned in my comments, we used $200 million of our liquidity to pay off that maturity of the debt that we didn't end up using the interest rate hedges up on.

Okay, but there's no cash like in investment or anything else that's the cash position is $182 million.

That's our cash position, right? No short-term debt and a $182 million on the...

But again, the biggest reason for the reduction from September 30 would have been paying off that $200-some-million what had been long-term debt, but of course was listed as a current maturity by the time we paid it off.

The next question comes from Phillip Jungwirth at BMO Capital Markets.

Wanted to ask about down spacing in Greene County. I believe your prior 1,300 Tier 1 location count was based on 1,000 feet spacing between laterals. If you're able to go down to 500 feet spacing, is it fair to assume that this Tier 1 location count could double at least in Greene County and then can you quantify what the impact to the EUR would be?

Well, I think it's a little early for us to conclude that 500-foot spacing works everywhere in Greene County. So it was only portions of Greene County where we've done that. We're going to continue to test down spacing. We're testing 750 feet. We're testing 500 and we'll use what's appropriate. But certainly, I think the fact that we've concluded that 500 works in certain areas, it certainly makes us optimistic that we'll find that some form of down spacing works more broadly.

Okay. And then is there any reason why the Marcellus PDP didn't increase more year-over-year given the 309 Bcfe of additions that you have there?

Yes, there is a reason. This year when we were looking at our booking methodology based on longer laterals, reduced cluster spacing, multi-well pads, we're finding that a higher percentage of our costs are being spent on the completion phase versus the drilling phase. So previously, when we had TD to well, we would book that well as proved developed either nonproducing or PDP if it was frac-ed and in line, but generally, it's proved developed nonproducing. Based on the higher ship to cost later in the process, we thought it was more appropriate this year to start booking wells as proved non -- proved develop nonproducing after they've been frac-ed. So there's a significant amount of less reserves in the proved developed nonproducing category this year, which is really a one-time shift. So you shouldn't see this again next year. But there's about 400 Bcf less PDP reserves this year than there was last year as a result of that.

Our next question comes from Ray Deacon at Brean Capital.

Steve, I just want to ask one follow-up on that. Is -- do you provide how many uncompleted wells that were at year-end '12 versus year-end '11? And also how many of the locations you drill in 2013 would you expect to have reduced cluster spacing and in the higher reserve number?

I don't think we provide the first number you asked for, Ray. The second one, if I can find the specific number, it's 88% of our Marcellus wells we expect to use 30-foot cluster spacing. I think that's 132. I might be off 1 or 2.

Our next question comes from Bob Parija at Soc Gen.

Just as a follow-up, could you provide a split between the PDP and the PUD bookings? You gave an average for the quarter -- sorry, for the year.

Not sure I follow it.

The split between the PDP reserves and the PUD reserves that's sort of a follow-up to questions previously announced.

Split the proved reserves into PDP, PUDs.

PDP versus PUD?

In the Marcellus.

In the Marcellus. I don't know if I have -- do you have Marcellus specifics?

Yes, the proved developed Marcellus total was 1.1 T the proved undeveloped was 3.2.

And actually, what was the EUR assumption on each of those?

They're both in line with the average. That's why we didn't break it up.

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

Thank you, Amy, and thank you, everyone, for participating.

The conference is now concluded. Thank you for attending today's event. You may now disconnect.