EQT Management Discusses Q4 2013 Results - Earnings Call Transcript

Feb.13.14 | About: EQT Corporation (EQT)

EQT (NYSE:EQT)

Q4 2013 Earnings Call

February 13, 2014 10:30 am ET

Executives

Patrick John Kane - Chief Investor Relations Officer

Philip P. Conti - Chief Financial Officer and Senior Vice President

Steven T. Schlotterbeck - Senior 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

Analysts

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Andrew Venker - Morgan Stanley, Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

Michael A. Hall - Heikkinen Energy Advisors, LLC

Phillip Jungwirth - BMO Capital Markets U.S.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Operator

Good morning, and welcome to the EQT Corp. Year-End 2013 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Patrick Kane. Please go ahead.

Patrick John Kane

Thanks, Amy. Good morning, everyone, and thank you for participating in EQT Corporation's Year-End 2013 Earnings Conference Call. With me today are Dave Porges, President and Chief Executive Officer; Phil Conti, Senior Vice President and Chief Financial Officer; Randy Crawford, Senior Vice President and President of Midstream and Commercial; and Steve Schlotterbeck, Executive Vice President and President of Exploration and Production. This call will be replayed for a 7-day period beginning at approximately 1:30 p.m. Eastern Time today. The telephone number for the replay is (412) 317-0088. There's a confirmation code needed. The code is 10025554. 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's a separate press release issued by EQM this morning, and there's a separate conference call today at 11:30 a.m. today, which creates a hard stop for this call at 11:25. If you're interested in the EQM call, the dial-in number is (412) 317-6789.

In just a moment, Phil will summarize EQT's operational and financial results for the year-end 2013, which were released this morning. Next, Steve will summarize the reserve report. And finally, Dave will provide an update on strategic and operational matters. Following Dave's remarks, Dave, Phil, Randy and Steve will all be available to answer your questions.

I'd like to remind you that today's call may contain forward-looking statements relating 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 EQT's Form 10-K for year ended December 31, 2012, which was filed with the SEC, and were -- have been updated in subsequent Form 10-Qs, which are also on file with the SEC. There will also be additional information in the year ended December 31, 2013 Form 10-K, which will be released 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.

Philip P. Conti

Thanks, Pat, and good morning, everyone. As you read in the press release this morning, EQT announced 2013 adjusted earnings of $2.32 per diluted share compared to $1.41 per diluted share in 2012. The high-level story for the year, as well as for the fourth quarter, was very strong volume growth and lower unit of cash costs in both the Production and the Midstream businesses.

Notably, Production volume was 43% higher than last year, natural gas liquids volume was 47% higher, and Midstream gathering volume was up by about 39%. As a result, EQT earnings and EPS for 2013 were both up considerably over 2012 by any measure. Although both years were impacted by some unusual items, that should be considered when interpreting and comparing results year-over-year. I will touch on a couple of these in my comments, and I do refer you to our non-GAAP reconciliations in today's release.

Adjusted operating cash flow of $1.25 billion in 2013 was also up considerably. It was actually 43% higher than last year. And as a reminder, a full year of EQT Midstream Partners, or EQM, results in 2013 and 2 quarters of EQM results in 2012 are consolidated into EQT's results, even though a portion of EQM was owned by the noncontrolling interest during those periods. EQT did receive a total of $33.4 million in distributions from EQM during 2013.

In the fourth quarter, as you know by now, we completed the sale of Equitable Gas and received $740 million in cash plus some Marcellus Midstream assets as consideration. And also, we entered into some commercial arrangements with the purchaser as part of the sale. The sale somewhat complicates the comparison of EPS and cash flow to last year as we estimate that we would have earned about $9 million pretax from that business over the second half of December had we still owned it. This would've increased our EPS and cash flow per share by about $0.04 for the quarter and the year.

As required by GAAP, we carved up the gain on the sale, the transaction costs associated with the sale, and the Distribution business earnings for 2013, and included those items in the discontinued operations line on the income statement. The after-tax gain on the sale totaled $43.8 million and pretax transaction costs were about $8 million for the year and $4.8 million for the fourth quarter.

Also in the fourth quarter, Midstream sold its commercial marketing and trading business for a pretax gain of $19.6 million. This gain is in Midstream's results from continuing operations, but excluded from our adjusted EPS and adjusted cash flow numbers in the table in today's release. Another adjustment that we made to our reported results was the add back of a noncash expense for hedge ineffectiveness totaling $21.3 million for the year and $16.8 million in the fourth quarter. Again, these items are detailed in the release.

Fourth quarter 2013 adjusted earnings were $0.47 per diluted share. That compares to adjusted EPS of $0.43 in the fourth quarter 2012. A significantly higher production in Midstream volumes once again drove the results. Adjusted operating cash flow at EQT was $336 million in the fourth quarter of '13 compared to $299 million for the fourth quarter of '12.

Our operational performance continued to be outstanding in the fourth quarter with 32% higher production volumes than the fourth quarter of 2012 and 6% higher sequentially than the third quarter of 2013. We also realized 24% higher gathering volume than last year and continued low per-unit operating costs.

And finally, the fourth quarter effective tax rate was 48.2%, well above the 33.6% effective tax rate for the entire year. This higher tax rate in the fourth quarter primarily results -- relates to the continued shift in the company's business to states with higher tax rates, most notably, Pennsylvania, and was partially offset by state tax benefits associated with the Distribution business sale transaction. This higher tax rate reduced EPS for the fourth quarter by $0.15 per share versus what we would have reported using the annual rate.

Now moving on to a brief discussion of results by business segment, and I'll limit my discussion to the full year results as the explanation for the full year basically apply to the fourth quarter as well.

So starting with EQT Production, and as has been the case for 4 years now, the big story in '13 at EQT Production was growth in sales of produced natural gas. As I mentioned, the growth rate was 43% for the year, driven by sales from our Marcellus wells, which contributed 73% of the volumes in '13, up from 58% in 2012. The EQT average wellhead sales price was $4.13 per Mcf equivalent in '13, $0.04 lower than last year.

For segment reporting purposes, of that $4.13 per unit of revenue realized by EQT Corporation, $3.08 per Mcfe was allocated to the EQT Production with the remaining $1.05 per Mcf equivalent to EQT Midstream.

The majority of this $1.05 is for gathering, which was -- which averaged $0.82 per Mcf equivalent for the year, down from an average of $1 per Mcf equivalent in 2012. You'll recall the Marcellus gathering rate 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 goes down.

For the full year, total operating expenses at EQT Production were $797 million or 32% higher year-over-year. Absolute DD&A, SG&A, LOE and production taxes were all higher, consistent with the significant production growth. DD&A expense represented about $169 million or 88% of that increase, and it's obviously driven by the higher volume.

Absolute LOE, exploration expense and SG&A expense were all 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 expenses were lower again in 2013.

Moving on to the Midstream business. Excluding the gains on the asset sale that I mentioned earlier, operating income here was up 30%, consistent with the 39% growth in gathered volumes. This resulted in a 16% increase in gathering net operating revenues. Transmission net revenues also increased by almost 54% year-over-year as a result of added Equitrans capacity, mainly from that Sunrise Expansion Project, as well as increased throughput.

On the other hand, the line item totaled Storage, Marketing and Other Net Operating Income was down about $9 million for the year. This part of the Midstream business relies on seasonal volatility and spreads in the forward curve and has continued to trend down in 2013.

Net operating expenses at Midstream were about 11% higher year-over-year, consistent with the growth of the Midstream business. Similar to Production, revenues grew at a much faster rate than expenses, resulting in continued reductions in per-unit expenses.

And then finally, our standard liquidity update. We closed the year in a great liquidity position with 0 net, short-term debt outstanding under our $1.5 billion revolver, and $846 million of cash on the balance sheet. And since year end, EQT received from EQM an additional $110 million in cash for the deferred piece of the Sunrise transaction that was always anticipated, following the sale of Equitable Gas.

Based on current commodity prices and assuming a 2014 average negative basis to NYMEX of $0.37 per Mcf, we continue to forecast approximately $1.6 billion in operating cash flow for 2014. So we expect to fund our $2.4 billion 2014 CapEx forecast with that expected cash flow and current cash on hand.

And with that, I'll turn the call over to Steve Schlotterbeck to discuss today's reserve release.

Steven T. Schlotterbeck

Thank you, Phil. This morning, we announced year-end 2013 total proved reserves of 8.3 Tcfe, which is 2.3 Tcfe or 39% higher than the previous year and represents a reserve replacement ratio of 738%. I'll now go into more detail around this reserve increase.

Extensions and discoveries totaled 2.0 Tcfe, which was comprised of 894 Bcfe reclassified to proved from probable and possible; 583 Bcfe from new locations, primarily from closer lateral spacing; and 524 Bcfe from newly economic locations as a result of higher gas pricing, improved type curves and reduced drilling costs.

Drilling capital totaled $1.3 billion, resulting in the drill bit finding cost of $0.62 per Mcfe. Our acquisition of properties from Chesapeake in June 2013 resulted in additions to proved reserves of 473 Bcfe, of which 42 are proved developed and 431 Bcfe are proved undeveloped.

This year, we've begun reporting natural gas liquids as a separate reserve category due to our increasing recovery of NGLs. The inclusion of NGLs added a net 536 Bcfe to our proved reserves, which was comprised of 763 Bcfe of liquids, less 227 Bcfe due to processing shrinkage. NGLs now represent 9% of our proved reserves.

The company's Marcellus proved reserves increased by 1.7 Tcfe or 39%. This increase is driven by improved recovery per well as illustrated by our 17% increase in Mcfe per foot. Additions and extensions related to the 2013 program and the aforementioned Chesapeake acreage acquisition. Offsetting those additions were the removal of 58 Marcellus locations, totaling 368 Bcfe of proved undeveloped reserves due to changes in our 5-year development plan.

We've also included 215 Bcfe of proved reserves in the Upper Devonian formation, which is comprised of 109 Bcfe of proved developed reserves and 106 Bcfe of proved undeveloped reserves. We added 350 Bcfe of proved reserves in our Huron play, reflecting 1 year of drilling, NGLs and the effective higher gas prices. We have significantly more Huron reserves that meet the standards required to book proved reserves, but they were not booked as a result of not having an established development plan for the Huron beyond 2014.

Our 3P reserves, or the total proved, probable and possible reserves, increased 10.5 Tcfe to 36.4 Tcfe, a 40% increase over the prior year. This increase was comprised of 3.5 Tcfe in the Marcellus, 4.1 Tcfe in the Huron, 2.4 Tcfe in the Upper Devonian, and 0.5 Tcf in other formations.

And finally, we are adjusting our guidance for our DD&A rate for 2014 to reflect the finalized reserve report. We now estimate our per-unit DD&A to be $1.25 per Mcfe or $0.25 lower than 2013. Also, as you will see in our 10-K that we expect to file next week our PV-10 was $3.95 billion, 84% higher than last year, reflecting both the increase in proved reserves and higher commodity prices. I'll now turn the call over to Dave Porges for his comments.

David L. Porges

Thank you, Steve. Given that the results for the fourth quarter have already been covered, I will use my time to walk through our thought process around our 2014 capital expenditure plans.

First, our largest investment is in continued development of our Marcellus acreage. This investment is our highest return opportunity and is driving our growth. We are drilling 90% of our Marcellus for development purposes on multi-well pads, about evenly split between our West Virginia liquids-rich acreage and our Southwestern Pennsylvania acreage. We are drilling 10% of our wells in Central Pennsylvania to delineate this acreage in anticipation of future development. This will assist in determining the most efficient completion techniques, spacing and appropriate sizing for the gathering systems.

We also plan to drill 30 Upper Devonian wells, again, in development mode in our core Marcellus footprint for Upper Devonian as a separate target that is shallower than the Marcellus. These wells are drilled on Marcellus pads using the same rigs and completion equipment that is on-site, thereby increasing the productivity and profitability of our acreage.

We also announced a limited restart of our Huron program. This decision has 2 benefits: first, the economics of the current strip provide an adequate return as we are using existing gathering capacity; and second, by arresting the decline of the Huron volumes, the gathering system becomes a more viable candidate to be dropped into our MLP, EQT Midstream Partners or EQM.

In our Ohio Utica play, we announced a 21 well program for 2014. The intent of this program is to see if we can crack the code in the condensate light oil window. While our first 3 wells were, frankly, mediocre, we are encouraged enough by initial results to try very specific changes to our drilling and completion design intended to improve the economics materially. If we are successful, there is significant acreage available nearby at relatively inexpensive prices largely because of the skepticism about this part of the play.

As you know, we pride ourselves on being innovative, but we need to be confident that successful innovation creates a sufficient reward and the ability to expand our Utica opportunity set economically provides that. By year end, we hope to either demonstrate sufficient improvements in which case it would make sense to add acreage, or conclude that we cannot achieve the needed improvements at this time and discontinue drilling.

On the Midstream side, we are investing $475 million. The largest pieces of this are $345 million in gathering systems to add capacity for EQT drilling in Pennsylvania and West Virginia, and $90 million in upgrades to the FERC-regulated transmission line that was acquired as part of the consideration for the Distribution company sale.

EQM is investing another $50 million in organic growth projects. As the cash flow grows at the MLP, it will be able to invest more capital intended to create organic growth.

Another project that our Midstream group is working on is the Ohio Valley Connector. While this project does not impact the 2014 capital budget, we mention it because in January, EQM initiated a FERC open season to assess interest in the project. So you may read about this proposed project in the industry press. This project extends the transmission system from West Virginia to Clarington, Ohio, thereby connecting Equitrans to Texas Eastern and REX.

In summary, EQT is committed to increasing the value of our vast resource by accelerated the monetization of our reserves and other opportunities. We continue to be focused on earning the highest possible returns from our investments and are doing what we can to increase the value of your shares. We look forward to continuing to execute on our commitment to our shareholders and appreciate your continued support. And with that, I will turn the call back over to Pat Kane.

Patrick John Kane

Thank you, Dave. That concludes the comments portion of the call. Amy, can we please now open the call up for questions?

Question-and-Answer Session

Operator

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

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Steve -- a question for maybe Steve or David. David, you were talking a little bit just there about the Utica. My question is maybe on the Utica. I know some of your peers have mentioned around that Southwestern PA area I know, certainly, where you have some acreage. They've talked about potential Utica potential in that area. Just wondering, your or Steve's thoughts about that and if you would considered testing for any of that at this point?

Steven T. Schlotterbeck

Neal, this is Steve. We certainly have studied that pretty extensively. And our current view is, we think the dry gas Utica in Southwestern Pennsylvania certainly has potential from a resource perspective. Our studies show that there could be significant amounts of gas in place. Our concerns are that the depth of the formation, therefore, the economics of it, where our existing acreage position is. So that said, I think our view is, it'd be difficult for Utica well under our existing acreage right now to be competitive economically with the Marcellus. Even if it was likely to produce significant amounts of gas, the costs, because of the depths and the higher pressures, the higher pressure frac-ing equipment, everything else involved with operating at those depths and pressures, we're not sure it'd be competitive. That said, I think we would -- we are -- we would think about whether a test, but more of a science test would make sense. And we haven't committed to do that yet or not to do that, but if we think it's warranted and we think we'll learn enough from a test, we might choose to do that.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then just one follow-up, Steve. On -- obviously, the -- amount of Huron that you're getting booked -- I mean, a couple of questions on maybe first -- I'm sorry, skipping around a little bit. First, I think look at the Devonian potential. On those, would you think about sort of drilling in those wells the same way that you've been drilling the Marcellus? Or does it make sense to have maybe a shorter lateral or anything around. I'm just trying to get a sense of sort of type curves between the 2.

Steven T. Schlotterbeck

I think the drilling and completion techniques, for the most part, we think are similar. Now, we custom-design our frac jobs for really every well based on the geology we're in. So we wouldn't necessarily have an Upper Devonian well frac-ed exactly the same as a Marcellus well below it. But I think in terms of lateral length, our view would be they're almost certainly going to be the same length. And I think our view right now is that we'll likely get the best stimulation of the Upper Devonian by frac-ing it at the same time as the Marcellus or within the same proximity of time, rather than waiting several years, say, down the road. So as we progress with Upper Devonian development, it'll most likely be a combined development program with the Marcellus and Upper Devonian.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then just lastly, on the Huron. How much capital or have you said yet, will you commit to that this year or -- and sort of a percentage of total?

Steven T. Schlotterbeck

Let me grab that number for you.

Patrick John Kane

Neal, this is Pat. We're budgeting $180 million to drill 120 drilling wells in '14.

Operator

Our next question comes from Drew Venker at Morgan Stanley.

Andrew Venker - Morgan Stanley, Research Division

Are there any new Utica wells in Ohio that you could speak about? Any new well results?

Steven T. Schlotterbeck

No. We don't have any well results and it'll be likely mid-year before we start getting results from our revised completion program. So midyear at the earliest, I'm not sure we'll be talking about them mid-year. So I don't want to get your expectations up, but it'll be awhile before we even start to get results ourselves.

Andrew Venker - Morgan Stanley, Research Division

Okay. And how do the lateral lengths compare for your '14 program versus the first 3 you talked about?

Steven T. Schlotterbeck

For the Utica?

Andrew Venker - Morgan Stanley, Research Division

Right. That's right.

Steven T. Schlotterbeck

The lateral lengths, I think the average for the next 5 wells is...

Patrick John Kane

6,500 feet is the average that we're projecting for the year.

Andrew Venker - Morgan Stanley, Research Division

And Pat, what was -- what were the first 3 months?

Patrick John Kane

I don't know exactly. I think it's consistent.

Steven T. Schlotterbeck

Yes. They were just north of 6,000.

Andrew Venker - Morgan Stanley, Research Division

Okay. And so is the thinking of not releasing results that you kind of potentially have better results, and then you can lease up acreage. Is that the thinking?

Steven T. Schlotterbeck

Well, I think, yes, that's a big part of it. And we tend to like to make sure we understand the results before we start talking about them. So sometimes, that takes a little bit of time. So the biggest driver would be, if successful, if we unlock the code in that oily part of the Utica, we want to take advantage of that knowledge before we let everybody else know.

Andrew Venker - Morgan Stanley, Research Division

Okay. I'm sorry, if I missed this -- you mentioned it before. Do you guys have a plan to test Utica potential in West Virginia? Is there anything on the docket for this year?

David L. Porges

No. Yes, not in the near term. Eventually, what we're probably going to do with the Utica that sits underneath our existing Marcellus is down the road at some point, probably measured in years, we will take advantage of the fact that we already have some infrastructure set up and that will improve the economics. But that doesn't make any sense when we're in the midst of the development of the Marcellus and the Upper Devonian. So no near term plans for development.

Operator

The next question comes from Scott Hanold at RBC Capital Market.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Couple of questions just to clarify. So production guidance for 2014, that assumes basically your new 6:1 sort of methodology on ethane, is that correct?

Philip P. Conti

Yes, that's right. That's 6:1 on the liquids.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Yes, okay. And so when we look at where you're kind of coming into -- in the first quarter and where growth could be, it seems like you all are attracting -- it seems like you're attracting well into the high end, if not a little bit higher. Can you just generally talk about just at a high level progression and more so if there are any kind of constraints for us to think about our timing that we need to think about in terms of quarterly progression or production?

Steven T. Schlotterbeck

At this point, it's -- of course, there's always -- in a play that's growing this rapidly or an area that's growing this rapidly, there's always going to be midstream constraints. There always have been and there will be until the growth rates at some point wind up slowing down. But that said, what we're really affected by more -- typically, is just the timing of turning in line these big multi-well pads. And at this point, I think, it looks like 2014 is more likely to be a year in which some of that is a bit more back-end loaded than it was, say, in 2013. You may recall that in 2012, it was also kind of back-end loaded. And then in 2013, it was a little bit more front-end loaded just the way the timing happened to work out. In 2014 -- of course there's wells being turned in line essentially every month. But as far as the proportions, it tends to be weighted often more in one direction or another. And I'd say 2014, it would be best for you to assume that it's going to be a bit more in the back end side, which in a sense will set us up well for 2015 also, but that certainly influenced our view for total volumes in 2014.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And just looking, obviously, at the numbers, your [indiscernible] in wells not completed, and completed and online. It's obviously at a pretty good peak right now. And obviously, you guys remain pretty active. Is there any midstream projects that are really key for you guys here in the next 12 to 18 months just to kind of reference?

Randall L. Crawford

Well, I mean, I think, as -- Scott, this is Randy. I mean, we're always staying out in front of production and we're pretty confident in our operations and plan. I would say our Sunrise Expansion that we kind of coming on in the third quarter, the compression expansion, which is on track and on time, is a major initiative for us.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. Now that's helpful. And on the sales of utility, can you give us what the, I guess, net of any kind of cash tax would have been on that? And what is your cash position right now? Or...

Philip P. Conti

I actually provided the cash position in my comments. We had $846 million on the balance sheet at year end. We did receive another $110 million that was a deferred piece of the Sunrise transaction that we had talked about back in the middle of the year. And in the release this morning, we did show that cash taxes associated with the utility sale of around $68 million, so we received $740 million and paid taxes of about $68 million on that.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Right, right. So the $110 million occurred after the year, but...

Philip P. Conti

So it's not in the one $846 million. It would be additive to that. But, of course, we're [indiscernible].

David L. Porges

But if you want to add, you just can't just add the operating cash flow to the $846 million. You have to add in that $110 million that we received actually from EQM as part of that, I guess, you'd call it like a mini drop.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. Understood, understood. And one last question here. The general partner, obviously, you guys are stepping back and kind of evaluating value within EQT overall. And can you give us your current thoughts on the general partner and kind of different directions that could go?

Philip P. Conti

Sure. Let me take a shot at that. I think, hopefully, it's obvious we've been pretty focused on realizing the full value of the EQT Midstream interest that EQT owns in the EQT stock price. We've really been doing that, I think, for the last several years. It started with our decision a few years ago to sell some noncore midstream assets to folks who valued them, frankly, more highly than we did. Those kind of -- those were actually buyers -- those buyers were MLPs and we noted that. We continued reforming our own MLP. And so we did that 1.5 years ago to the big drop earlier this year. We're still in the early stages of those drop downs, which we believe allow EQT to achieve a premium valuation for our midstream assets, but at the same time, maintaining control and benefiting from the accretion and value to the EQM LP units and GP interests that EQT can continues to own. Now the GP interest is probably the least visible and most often overlooked midstream interest owned by the company. But it, too, as you know, is extremely valuable. The GP cash flows to EQT are pretty small currently. They were about $2 million of GP distributions in 2013, but we expect that to grow rapidly and reach $40 million or more by 2015 and over $70 million in 2016. So while some of the parts analysis can be tricky, one can certainly make the argument and some of you on the call already have made it that the full value of EQT Midstream interest, including the LP and GP interest, is not transparent in the current EQT stock price. And frankly, we tend to agree at this point. So -- and if we do conclude that a clear value disconnect exists, there are a variety of alternatives available to us to address that. You know what they are. Some of our energy industry peers have already taken similar steps. So, Scott, I'm not going to address and/or list them today. I think it's a little premature to discuss what they are. There are a variety of factors that could cause us to go down one path versus another. So, I guess, to summarize, I would say, at this point, we expect to have a pretty good idea of what we want to do, if anything, by the end of this year. And frankly, it's not clear that it would be wise to take any significant action before then anyway. Said differently, just as we want to make sure that EQT shareholders benefit from transparency and the valuation of our midstream interest, we don't want to deprive them of that value by transferring a significant portion of it to another party by acting too soon. So I hope that helps for now. That's really about as much as we want to say about that right now. Suffice it to say that it's an issue that we're studying closely.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, okay. So it sounds like we'll hear more about that towards at the end of the year. Okay, fair enough.

Operator

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

Michael A. Hall - Heikkinen Energy Advisors, LLC

The -- let's see. I've got plenty to ask about. I guess, while we're on the topic of the value -- transparency of the value of the portfolio. What's the kind of latest thinking on drop downs this year? I know you're a little hesitant to talk about timing of it, but I'm just curious, like, is it one large drop down, multiple drop downs? How big of a roll moving or escalating -- potential escalation of interest rates play into that thinking? Just any update around that plan that you'd be willing to share.

David L. Porges

I don't know if we want to talk about 1 versus 2 for particular assets. But I will maybe reiterate that we are still thinking, unlike we were talking about at the time of the IPO, but this thinking has evolved to the point where we're still thinking that the right answer is to have a more accelerated, rather than a less accelerated drop schedule. And I agree with the premise of your question that the prospect of higher interest rates was one of the reasons for doing that. But from my perspective at least, a more fundamental reason for it is that is a lower cost of capital vehicle than the corporation. And I think a lot of that is because of the transparency issue. The folks who invest in that vehicle, which is to, say, EQM, are looking for exactly that type of asset. And since it's their pistol, so to speak, they are willing to offer more favorable valuations in the marketplace for that. And therefore, that's the best home of -- for those assets. So that is the mindset that we've got as we look at drops as opposed to, if you will, what we talked about at the time of the EQM IPO, which was sizing it to EQT's midstream capital requirements. Now what's the rate at which EQM can digest these is really more the issue.

Michael A. Hall - Heikkinen Energy Advisors, LLC

Okay. And what would be the constraints around the rate at which EQM could digest them?

David L. Porges

Well, part of it, of course, so they're going to fund -- there's the combination of equity and debt so the capital markets availability is one of the issues for them. Another one is that they are best off with projects typically, where every -- most of their projects be projects whereby they're already generating cash flow. So the projects where there's still a lot of construction going on tend not to be as good a fit for an entity that is paying out the vast majority of its cash flow in the form of distributions. And it's hard to keep up growth if you do that and, of course, we are focused on continuing to grow that distribution. So typically, they want to have these projects to be ones that have already been fully contracted and turned in line, et cetera. That said, as EQM grows, it is able to wear, if you will, a higher dollar amount in projects that are under construction. And we do think you should expect to see that as we go forward. But, of course, accelerating drops means that we more quickly get to the point where EQM can absorb bigger and bigger projects on its own and quite possibly have some of these projects especially ones that are designed to support other producers, occur at the EQM level and never having going through EQT. Does that help?

Michael A. Hall - Heikkinen Energy Advisors, LLC

Yes, it does. I guess, last on that, and I'll -- just it would be curious. In the outline, you've got quite a cash position already. Clearly, some outspend in the '14 budget that, that would, I guess, fund. But then you got likely some drops come in this year as well. Is that capital -- I mean, are there future capital allocations, I guess, that could come throughout the rest of the year regarding the 2014 upstream program? Or are we pretty well set and whatever capital comes in this year really just funds 2015? Just trying to think that through.

David L. Porges

We're not setting capital programs based on cash availability. That's not up something we want to get into. I mean, obviously, we look at investment opportunities, but frankly, with this kind of cash position, you look at stock repurchases also.

Michael A. Hall - Heikkinen Energy Advisors, LLC

Okay. And so, yes, that was kind of a follow-on. I mean, is that something that is higher up on the list than it has been, let's say, in the last 6 months?

David L. Porges

Well just because we don't -- we certainly would not consider ourselves to be capital constrained right now. I mean, that would not be a good mindset for us to have. We could fund the attractive projects. So from that -- and probably, I don't know, before -- certainly before EQM was formed, we probably would have viewed ourselves as capital constrained from the perspective of cash availability compared to the volume, the dollar volume of attractive investment opportunities. So that has changed over the course of the last 1.5 years or so. And obviously, the sale of the Distribution company furthers that. So yes, from that perspective, it is higher up. If you're referring to how attractive share repurchases would look. Yes, that is higher up than it would have been.

Michael A. Hall - Heikkinen Energy Advisors, LLC

Yes, that's helpful. Okay. And then, I guess, the last one on my end would just be any updates or just maybe remind me on your marketing arrangements that protect around basis risk as we head into the summer? Any steps that are being taken to further protect around those risks on a go-forward basis?

Philip P. Conti

Well, Michael, in terms of our capacity portfolio and really, I guess, I would comment the colder-than-normal winter has certainly been helpful in terms of increased demand and record storage withdrawals. And over this period of time, we've seen better realized pricing in the Appalachian basin. So we're more optimistic than we maybe when heading into the winter season and we have seen some support in the summer basis as the market looks to balance for power generation, as well as refill the storage. So -- but in terms of capacity, we have stressed in the past, we continue to look at and make commitments on long-haul pipelines to get gas to a variety of markets. Our goal is always to stay ahead of our production growth and not relying on just one spot market. We've recently entered into several agreements that have added to that portfolio, and I'll go and give you few of those. Our most significant addition became effective on February of this year, February 1. That's when we added 245,000 dekatherms a day of capacity for approximately 7 years on Texas Eastern system to the M3 market and the Transco Zone 5 markets. And both of these appear stronger relative to other basins. So in total, we currently have almost 950,000 dekatherms a day of firm pipeline capacity out of the basin plus we have approximately 350,000 dekatherms per day of firm sales for a total of 1.3 million deks per day. And again, in addition to that, by the end of 2014, based on existing commitments, we'll have about 1.6 million dekatherms per day between firm pipeline capacity and firm sales. So with that, we always feel comfortable with our position in 2014 and heading into '15. And again, moving forward, we'll continue to add our firm capacity portfolio and add to the diversity of our markets, including the Midwest and the Southeast market.

David L. Porges

And we remain incidentally, very happy to utilize the expertise and the assets we have in the midstream area to redirect gas flows as appropriate to meet market needs.

Operator

Our next question comes from Phillip Jungwirth at BMO.

Phillip Jungwirth - BMO Capital Markets U.S.

A couple of quick questions on the reserve report. That the 7.2 Bs or 1.7 per thousand lateral split, the EURs for the Marcellus. Does that include -- is that only PUDs or does that also include the PDPs? And then what would be the difference to the 2 Bs per thousand foot of your type curve in Southwest PA and Northwest Virginia?

Steven T. Schlotterbeck

So could you repeat that? I couldn't hear the first part of your question.

Phillip Jungwirth - BMO Capital Markets U.S.

I was just asking if the proved reserves EUR booking that you had highlighted in the press release includes the older PDPs or is that just PUDs.

Steven T. Schlotterbeck

That's all proved reserves, so including PDPs.

Phillip Jungwirth - BMO Capital Markets U.S.

Do you know what the PUDs were booked at? And then also the future development costs assumed in the PV-10 calculation?

Steven T. Schlotterbeck

I don't think we have that handy.

Patrick John Kane

Maybe I could follow-up with you after the call. We don't have that data in front of us.

Phillip Jungwirth - BMO Capital Markets U.S.

Okay. And then in the Huron, can you talk about your expectations for 2014 volumes given the renewed activity there? And then under that scenario, what would be the gathering EBITDA for that asset?

Philip P. Conti

The gathering EBITDA, I think, is in $50 million to $75 million range. It will depend on commercial contracts and things like that. But that's sort of a range that we're using right now.

Steven T. Schlotterbeck

And from a volume perspective, the program was designed to flatten the decline or to, basically, keep throughput flat with maybe a couple single-digit percent increase in throughput. But that's how the level of drilling was determined.

David L. Porges

But one of the things we have to go through as we look at a drop, just so you know, is pretty much decide what we think the right rates are because right now, probably 99% of the volumes that are flowing through those systems are EQT volumes. So there's really not an issue of having to have arm's length agreements. But obviously, ahead of the drop, we're going to need to relook at those tariffs to relook at the other contractual terms as well. And that is something actually that we are working through to make sure that what we come up with, we think is in the best interest of EQT as a whole. And the numbers Phil gave you gives you a pretty good, decent snapshot of where we are now, but we're relooking at that in the context of the -- of prospective future drop.

Phillip Jungwirth - BMO Capital Markets U.S.

That makes sense. And then is it too early to talk about the total expansion opportunity for the Ohio Valley Connector just in terms of increased capacity, capital spending? I think if I think back to Equitrans or Sunrise Expansion, you'd added about 1 Bcf a day for 300 million. How does that compare to what your expectations are for the Ohio Valley Connector?

David L. Porges

Well, I'd say right now, I mean, it's a bit early because we're in the process of the open season. And so we're scoping that out, but I think as you think about that project and the market demand for that, we would kind of view that as similar to what we were working on to a Sunrise-type project. But it is early and we're scoping out the demand right now in terms of the size and the capital that will be spent.

Phillip Jungwirth - BMO Capital Markets U.S.

And then last, just 2 quick modeling questions. On the lower DD&A, is that going to trend lower throughout the year? Or would that be the run rate beginning in the first quarter? And then also, expectations for tax rate for the year, given the minority interest from the MLP increasing?

Philip P. Conti

So the DD&A rate is a flat rate for the -- that'd be a good rate for you -- use for your modeling for the full year. I don't know that we've said anything about the tax rate right now. Obviously, you're right. It trends down because of the issue that you mentioned. I would say use a similar rate as this year for now without knowing anymore. It's going to obviously vary depending on a lot of factors.

Operator

The next question comes from Cameron Horwitz at U.S. Capital Advisors.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Dave, I was hoping can you just maybe give us a little color on the M&A landscape and kind of the deal for opportunity that you're seeing in the Marcellus, opportunities that acred similar to what you did last year?

David L. Porges

Yes. I don't know if I -- I still have a view that we're going to see a lot more acreage of the sort -- that sort of transaction come up over the course of time. But I don't know that I have anything specific to offer around what the landscape looks like right now. Steve, do you have anything specific that you want to...

Steven T. Schlotterbeck

No. Just as he said, it's typical. It ebbs and flows, and I think we're seeing more, smaller, little deals right now. But I would expect that, that'll -- deals come and go in this business. So we're not really seeing anything of note, positive or negative, in terms of a change. So I think there's still opportunities out there and we're pursuing them.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Okay. I appreciate that. And then just lastly for me. On the -- and forgive me if you said it, but the 368 that came off the books in the Marcellus, you talked about the changes in the development plan. Was it -- is there anymore color you can provide just where that was?

Steven T. Schlotterbeck

They were spread out a little bit. But they were more in second-tier areas where, as we've defined and focused our drilling, our plans have been more concentrated in certain areas than we were anticipating a few years ago when we originally booked those PUDs. And per the SEC guidelines, once we -- once we have a development plan that doesn't include those, we thought it was appropriate to remove them. But they're -- from a technical standpoint, they would still qualify as PUDs. They were only removed because when we're looking at where we're going to drill based on results, but also based on available capacity and all those factors, they just didn't fit anymore. So really not much more to it than that.

David L. Porges

And you're going to see that, I think, over the course of time. Over the last couple of years or maybe little bit more than that, the SEC has gotten a pretty strict about that, so we take that very seriously. And we'll check that with our 5-year development plan. And if something isn't in it, we'll just remove it. It doesn't mean that we think any lesser of those reserves and they presumably will show back up as proved reserves at some point in the future. But for now, all we have is the 5-year plan that we've gotten blessed by the board at this moment, and then we'll go from there.

Operator

At this time, we show no further questions. I'd like to turn the conference back over to Patrick Kane for any closing remarks.

Patrick John Kane

Thanks -- thank you, everybody, for participating.

Operator

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

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