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PVR Partners, L.P. (NYSE:PVR)

Q4 2012 Earnings Call

February 20, 2013 11:00 am ET

Executives

William H. Shea - Chief Executive Officer of Penn Virginia Resource GP LLC, President of Penn Virginia Resource GP LLC and Director of Penn Virginia Resource GP LLC

Bruce D. Davis - Executive Vice President of Penn Virginia Resource GP LLC, Secretary of Penn Virginia Resource GP LLC and General Counsel of Penn Virginia Resource GP LLC

Keith D. Horton - Co-President of Coal - Penn Virginia Resource GP LLC and Chief Operating Officer of Coal - Penn Virginia Resource GP LLC

Mark D. Casaday - Executive Vice President of Penn Virginia Resource Gp Llc and Chief Operating Officer of Midstream for Marcellus-Penn Virginia Resource Gp Llc

Robert B. Wallace - Chief Financial Officer of Penn Virginia Resource GP LLC and Executive Vice President of Penn Virginia Resource GP LLC

Stephen R. Milbourne - Director of Investor Relations - Penn Virginia Resource Gp Llc

Analysts

Gabriel P. Moreen - BofA Merrill Lynch, Research Division

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Noah Lerner

Matt Niblack

Michael J. Blum - Wells Fargo Securities, LLC, Research Division

Elvira Scotto - RBC Capital Markets, LLC, Research Division

James Spicer - Wells Fargo & Company

Mark A. Levin - BB&T Capital Markets, Research Division

William N. Adams - Fiduciary Asset Management, LLC

Operator

Good morning, and welcome to the PVR Partners 2012 Full Year and Fourth Quarter Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded.

I would now like to turn the conference over to Bill Shea, CEO. Please go ahead

William H. Shea

Thanks, Emily. Good morning, everyone. Thanks for joining us for the PVR Partners fourth quarter and full year 2012 earnings call. With me today is Rob Wallace, Executive VP and CFO; Bruce Davis, Executive VP and General Counsel; Mark Casaday, who heads up our Midstream business; and Keith Horton, who runs our Coal and Natural Resource Management business; Forrest McNair our Controller; Houston Ross [ph], our Treasurer; and Steve Milbourne, our Investor Relations Manager.

Before I start, I'd like to have Bruce give the forward-looking statement. Thanks.

Bruce D. Davis

In the course of our remarks and the subsequent Q&A session, we may be making some forward-looking statements. For purposes of facilitating a good discussion, I'll refer you to the forward-looking statements as referenced in this morning's press release, noting that our business is subject to a variety of risks and uncertainties. For a fuller discussion of these and other risks that could cause our results to change, please see PVR's Form 10-K most recently filed with the SEC.

William H. Shea

Thanks, Bruce. I'd like to start with a few brief comments, then have Keith and Mark provide some additional color to their business segments. After their comments, we'll open up the call for questions.

To start, I think you also are aware of the recent Midstream management change. As of mid-December, Mark Casaday is responsible for both the Midcon and Eastern Midstream business segments. We'll continue to operate and report as 3 segments. Also, as you know, the distribution was increased to $0.55 per unit and was paid on February 14. The annualized distribution is $2.20 per unit. The increase represents a 1.9% increase versus the third quarter of 2012 and a 7.8% increase versus the fourth quarter of 2011.

Regarding our fourth quarter results, adjusted EBITDA was $67.8 million compared to $58.9 million in the fourth quarter of 2011, a 15.1% increase. DCF was $34 million versus $36.7 million in the fourth quarter of 2011, an 8% decline. Our average daily natural gas throughput volume was 1.388 Bcf as compared with 683 million cubic feet per day in 2011, and our Coal royalty tons were 6.6 million versus 8.9 million, a 25.8% decrease from the fourth quarter of 2011.

We continue to demonstrate solid growth in the fourth quarter in the Eastern Midstream segment. The volume gains and increased operating results were a result of the continuing build-out of our existing systems in Lycoming County, increased throughput in the Mehoopany system in Wyoming County, well connects in Wyoming County as a result of the Chief acquisition and the start-up of the Wyoming County trunkline at the end of the third quarter of 2012.

The Eastern Midstream segment adjusted EBITDA in the fourth quarter was $33.1 million versus $8.9 million in 2011, again due to the further development of our existing systems and the Chief acquisition.

Quarterly average volume in the Eastern Midstream segment increased to 967 million cubic feet a day versus 243 million cubic feet a day in 2011. This growth is reflective of the growth throughout the entire Eastern segment.

In the Midcon Midstream segment, adjusted EBITDA was down $1.1 million to $14.2 million. The decline was due to low commodity prices, the continued migration to more ratable but lower margin fixed fee-based contracts and the sale of our Crossroads system, offset in part by increased volumes in the Midstream Midcon segment.

Throughput in the Midcon was up 28 million cubic feet a day, excluding the 47 million cubic feet a day impact of the Crossroads sale, which closed on July 3 of 2012.

Coal adjusted EBITDA was $20.5 million versus $34.6 million in 2011. Production and pricing both impacted results. Royalties per ton were down 20% to $3.47 per ton versus $4.33 last year. And as I said earlier, the coal tonnage was 6.6 million tons versus 8.9 million in 2011. During the quarter, we invested $209.4 million on internal growth projects in our Midstream business, $175.8 million in the Eastern segment.

Full year internal growth CapEx totaled $528.8 million, including $410.6 million in the Eastern segment and just about all of the remaining $118 million was invested in the Midcon Midstream segment, except for about $1 million in the Coal area.

At year end, we had $402.1 million available and outstanding borrowings of $590 million on our $1 billion revolver.

In the Eastern Midstream segment, the phase 3 extension in the Canton Lateral of our Lycoming County trunkline and waterline became operational at the end of the quarter. These facilities will initially serve Southwestern Energy and Shell. We are also delivering volumes from a new Lycoming County system for Inflection Energy. We continue to build out this system in a phased approach, where we follow Inflection's drilling program and invest in extensions based on well performance.

Based on our current expectations, we are updating 2013 guidance. Adjusted EBITDA for the Eastern Midstream segment is expected to be $190 million to $230 million, $70 million to $80 million in the Midcon Midstream and $75 million to $85 million in the Coal segment.

Maintenance CapEx is expected to be $14 million to $18 million, and internal growth capital is in the $350 million to $400 million range, essentially all in the Midstream businesses.

We are discontinuing providing guidance regarding DCF. Of course, our guidance is based on numerous assumptions about future events and conditions and therefore, could vary materially from our actual results.

Before I turn it over to Mark and Keith for their comments, let me say that I believe our anticipated results are achievable, and continue the transformation of PVR to a predominantly midstream company. We have survived the dramatic decline in our Coal segment, we weathered low gas and NGL prices in our Midcon Midstream segment and believe these operations have stabilized to some degree, especially in the Coal business. Keith will touch on this in a minute.

We've executed on the growth and expansion of the legacy Marcellus assets in Lycoming County per our plan. In the 8 months since the Chief acquisition, we have experienced a few start-up and development issues, such as brief delays in well connects, minor system build-out delays and the occasional small operating problem. These types of issues, I believe, are customary in any large development project, and I have to say our management team has done an excellent job in resolving the issues on a timely basis. However, when they do occur in a rapid growth business, like our Eastern Midstream segment, the impact produces greater volatility and financial impact due to the timing of cash flows.

When we completed the Chief acquisition in May of 2012, we realized the year would consist of 2 primary challenges: integrating Chief assets with our legacy assets and completion of the Wyoming trunkline by October 2012, which was the key to the acquisition. We accomplished both. We expected 2013 to be the year to ramp up growth in EBITDA and DCF. We firmly believe this will happen based on our knowledge of what our producers are planning for the year.

We expect our quarterly volume growth anticipated -- with the quarterly volume growth anticipated and the accompanying EBITDA and DCF, that our coverage ratio will be greater than 1x for 2013 on an as-paid basis.

Also remember that our results are somewhat seasonal, with the first quarter being a little lighter, due predominantly to weather that impacts well hookups and a general slowdown in activity levels. The second quarter will resume the growth, and the second half is anticipated to be strong.

We believe the Chief acquisition validated our transformation to a midstream growth MLP. We are the first mover midstream company in the best dry gas basin in the country. The production economics for the producers are very attractive, even at current prices. The dedicated acreage has 4,000 or more available drilling locations in a blanket formation, of which less than 15% of the wells have been drilled to date.

I am confident that we are on the right track and that we'll continue to grow and achieve the results contained in the guidance.

At this time, I'm going to turn it over to Keith to briefly discuss the Coal segment. He'll hand it off to Mark, who will then bring it back to me. Keith?

Keith D. Horton

Thank you, Bill. The coal market has continued to remain very challenged at this stage. Natural gas hovering around $3.40, continues to be the primary competitor on the coal side of the business. We've seen generation drop nationally on the coal side of the equation from -- in the high 40s down to around 36%. Last year, overall electrical generation was down about 1.8% and about 2% in the Coal segment.

Currently, we're seeing contracted lessee pricing in the $70 to $76 range for steam coal and $63 to $65 in the spot side of the business. The met business continues to -- from our properties, continues to hold up reasonably well. We're seeing prices anywhere from $118 to $140 on the high-volume met A&B [ph] sort of product or type product. The Illinois basin coal prices on contract remain about $45, however, depending on sulphur spot prices, are down substantially in the high 30s.

Transportation continues to be a major factor as it relates to the export markets last year. There was about 125 million tons of exported coal from the U.S. and that was split. About $70 million of that was metallurgical quality coal, although during the latter half of the year, the amount of met coal export diminished substantially. As China reduced their take, et cetera, they changed global dynamics. And we're seeing now, with the slowdown in Europe, we're seeing some coal out of South Africa move into Europe again. But we're not seeing Colombian coal as they are currently on strike. So that's about 1 million tons a week out of the market. So that's a substantial plus.

We don't really see -- as long as gas prices hold around $3.40, we don't really see any substantial driver for upside in pricing. There were very few contracts signed by our lessees in the latter half of 2012, only about 1.5 million tons of new business was signed during that time period, and we will wait and see. Second half coal inventories remain at our utility plants around 165 million tons. That number is a little sketchy, I think, but depends on utility in the individual plant. And we'll see how the summer burn goes to see how the contract environment is in the third and fourth quarter. And with that, Mark, I'll turn it over to you.

Mark D. Casaday

Thanks, Keith. Let me begin with the Eastern segment. Let me give everybody some numbers first. We have -- to date, we have 234 wells online and flowing in our total Eastern segment. For 2013, we project 91 wells total. 13 of those wells have been connected from the beginning of the year to date. We have 78 remaining wells. Out of those 78 remaining wells, we -- 24 of them are waffled [ph] , or as I call, they're waiting on the pipeline connection. They are drilled and frac-ed. In our total areas of dedication and pipelines feeding us, we have 16 total rigs working today. And we just had one of our producers, Chief Oil & Gas, a private company, just added an additional rig beginning March 1 of this year. We see -- we still see continued volume growth throughout 2013, and I fully expect to exit the year at about 1 Bcf of gas a day. Currently, we're moving about 1.1 Bcf.

Our SRS system will be fully online by the second half of this year. We've seen good production results and volumes from Southwestern. Shell is just coming online, March 1, at lower volumes until they build up to their full FT commitments on July 1. We also are working on our Clinton County deal, which is our range area of dedication, where we're doing a master deal to connect 4 wells that are originally drilled and frac-ed and expand that system for growth in 2014. We continue our development activity in the Utica, along the same vision and growth that we originally envisioned in our Lycoming County system, making good progress there. And one point that I want to add is that our Wyoming pipeline still has its second phase to come online. We expect that phase to be online in June of this year. The pipeline portion of that phase is already installed and tested. We are just waiting on the compressor station phase. That adds about $85 million -- or 85 million a day of firm FT demand contracts.

If I flip over to the Midcon, we currently have 100 wells that are in various stages of right-of-way, pipeline and connection phases. This is primarily in our Panhandle system. We do expect in the Panhandle system, based on current pricing trends and our planning mode, to be in full ethane rejection throughout the 2013 calendar year.

As you might know, our Crescent system and our Hamlin system. Our Crescent system is underlined by the Mississippi Lime formation, and we are starting to see a ramp-up of development along our Crescent plant. That's a 30 million a day plant, capacity-wise. And our Hamlin system, located in West Texas, is underpinned by the Cline Shale, and we see significant activity in the Cline Shale in 2013. We don't expect any significant earnings or growth from those until 2014 fiscal year. Since I've taken over the Midcon, I've kind of changed our philosophy. I'm not a big fan of the commodity business and I have taken our philosophy based on some of the success we've had in the East, where we've bundled our services and our success in our waterline service, which is in operation in Lycoming County. We've continued and focused our growth in both the Cline and the Mississippi Lime formations around our Hamlin and Crescent plants on a bundled service basis, where we can win and offer not only gas processing services but also water and condensate pipeline services.

Hopefully, this bundled service approach will be as successful as it was in our Eastern operations.

Speaking of our water service, our first -- we've had a good year last year. I don't -- we moved quite a few gallons, which were right on our budget projections, and our services completely build out to all our major producers: Range, EXCO, Shell, Southwestern, and we expect quite a -- we expect movement of our water volumes this year now that our system is completely built out.

And other than that, I don't have anything else to add, Bill. Back to you.

William H. Shea

Great. Thanks, Mark. Thank you very much. I did touch on liquidity and CapEx in total on the guidance, but Rob, do you have any comments you'd like to make before we go to Q&A?

Robert B. Wallace

Sure, Bill. Thanks. I think I'll just touch a little bit on the capital and on the guidance for capital.

We're looking at $350 million to $400 million as guidance for 2013. And the breakdown of that is basically 3/4 in the East or about $308 million, and the remaining $104 million or so is going to the Midcon area. And then, we've got some extra projects in there as well. But essentially, the growth capital will be broken down 3/4 in the East and 1/4 in the Midcon. In the East, about 1/3 of that is on the Lycoming County assets, which were our base assets before we bought Chief. Another $100 million or so will be in Wyoming County, one of the most prolific counties in the dry gas area in PA. And the remainder in the East will be for various projects involving compression, well connects and then our Aqua joint venture.

In the Midcon region, as Mark had discussed, we see some good growth in Crescent and the Hamlin areas, and so a large part of that growth CapEx will be for well connects and then for growth projects in Crescent and Hamlin as well.

I think that it's fair to say that any increase in the growth capital that we're expecting for 2013 is from our expectations last year, due to additional opportunities that we're seeing to invest our capital in the areas we operate and are not related to any overruns on any projects that we've been building out over the last 12 to 18 months.

And then one other point of clarification, Mark had mentioned that he thought that we'd exit the year in the East at about 1 Bcf a day. Actually, based on the way we measure our volumes, we would be expecting, and you'll be seeing this measurement quarter-by-quarter, we expect to be leaving the year at about 1.8 Bcf a day in the East. And remember, that's from starting at 0 in 2010.

And then just one other point on the overall guidance for EBITDA, we've -- it's a decline from -- or it's a decrease from where we were in July, when we last commented on the 2013 guidance. We're down 20% from there in Coal, which I think is probably not -- is not unexpected. We're down about 12% in the Midcon, and we're down about 20% in the East. Again, our view on the East, I don't think our overall view has changed at all. I think we're being a little bit more careful on the guidance, and we're also reacting to what's actually happening on the ground after we acquired the Chief acquisition. But remember, we haven't even owned the Chief assets for 12 months yet.

So I think, Bill, with that, I think we can open it up for questions.

William H. Shea

Okay, thanks. Emily, would you open up the lines, please?

Question-and-Answer Session

Operator

[Operator Instructions] And the first question will came from Gabe Moreen of Bank of America Merrill Lynch.

Gabriel P. Moreen - BofA Merrill Lynch, Research Division

A question on the decision not to give DCF guidance. I mean you've given us adjusted EBITDA, you've given us maintenance CapEx. And I think Bill commented that you expect your coverage would be north of 1x on a paid basis for '13. Just curious about the decision not to give DCF guidance given most of the variables being out there. And second of all, based on that coverage being north of 1x on a paid basis, I'm wondering -- I know you don't give guidance on distributions, but I was wondering if you could comment on sort of distribution policy for '13, just broadly speaking?

Robert B. Wallace

Bill, I'll take the DCF guidance question. And Gabe, I think we gave you all the pieces to do the DCF, but they're a little -- the way you do -- we handle derivatives, and we don't have -- and we only have 1 derivative contract that we put in place in January, all others expired at the end of last year, and the equity earnings. And we just felt that people -- the analysts weren't doing it on the same basis across the board. So we gave you all the tools to do it, and all you have to do is your own estimates for interest expense and you'll have the number. So it was just -- we just thought it was a little bit confusing, so we left it at EBITDA, and we gave you all the other pieces.

William H. Shea

On the distribution question, Gabe. We don't have a formal distribution policy, other than that our Board of Directors takes a look at that issue every quarterly board meeting. And when they get the update from management as to what the future looks like, they make a decision as to what the distribution should be, whether to increase it or keep it the same. And a lot of that is based on the forward-looking optimism that we all have as management in the results for PVR. So while we don't have a strict policy, it is looked at closely every quarter, especially looking towards the future in terms of the growth in EBITDA and DCF, whether or not it will sustain an increase in the distribution or not.

Gabriel P. Moreen - BofA Merrill Lynch, Research Division

Got it. Okay. And then if I can ask a question on the guidance on Eastern Midstream, basically trying to drill down how much of that is subject I guess -- and I appreciate Rob's clarification on the 1.8 Bcf in volumes at year end, but how much of that is subject to, let's call it escalation in -- from transportation agreements where you're not volume sensitive versus how much your -- assuming the current rig count holds, your waffles [ph] get hooked up? If I could just get a sense of kind of what can go right at the higher end and what you're assuming kind of at the lower end in that guidance.

Robert B. Wallace

That's a tough question, Gabe. I think what I'll do is, on the firm transport side, of course as you know, because of the firm contracts in Lycoming County and Wyoming County on the trunklines, we do have a nice base of revenue from the firm contracts. But clearly, the majority is from gathering and transporting molecules, and not under firm contracts in a bunch of the areas. But Mark, I think, if I could, could you try to address a part of this issue on what could go right on the upside of our guidance?

Mark D. Casaday

Well, yes. What could go right is we see volumes in excess of our FT-budgeted amounts. Currently, our FT contracts make up about 46% of our revenues. So our upside is we think we have captured all the wells and we know the time that it takes to connect them, but what we will see is increased volumes through CDP points, which feed into our pipelines which have our FT contracts. CDPs are central delivery points. So that's the real upside.

Operator

Our next question comes from Adam Leight of RBC Capital Markets.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

I guess first question is on the Eastern Midstream guidance change. Are there producer-specific plan changes? Are there timing differences or changes in well completion or hookup inventory? Is that part of the change in assumption?

Robert B. Wallace

You know, Adam, there are probably some pluses and minuses there. But I would say, the biggest minus that has impacted our guidance in the East relates to one producer, and it's EXCO. They have -- and it's a timing issue in our view. Their acreage that they have, we still think is great acreage. The results they've gotten on the wells they've drilled and completed is terrific, but their scheduling has fallen behind our expectations when we acquired the Chief assets. And otherwise, on the rest of the case, we've had some pluses. There's pluses on Chief in their expectations. We've had some timing issues in Lycoming County, but again, we think they're just timing issues. And again, I'd ask Mark if you want to add anything on the flavor for what the miss has been as it pertains to EXCO or others.

Mark D. Casaday

No, EXCO has just been short. And as we've said on our last 2 calls, our Bradford County system had a permit timing issue, and we have most of that resolved right now. So I think by the end of the fourth quarter, that will be -- or end of the first quarter, excuse me, that will be completely resolved and up to service. But other than that, those are the only 2 identifiable misses, if you want to call them that.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

So is there any discrepancies now versus prior on hitting all the stacked rates? Is that an issue or are those coming in as you expected?

Robert B. Wallace

Mark, why don't you take that? I think that if you could comment a little bit on the high margin -- or on the stacked rates we were to receive from EXCO in the original projections, in addition to the overall stacked rate concept, that would help.

Mark D. Casaday

Well, remember, our EXCO East Lycoming system feeds directly into the interstate pipeline system, but it is high-margin gathering rates. Our stacked rate component feeding into the Wyoming and Lycoming system is primarily Range, Chief and Chesapeake and Enerplus on the Wyoming pipeline system. So as far as -- when Chief tells me they're going to add another rig in a stacked rate environment, we were happy about that because that is full margin gathering and trunkline rates. And that's reflective of what Bill earlier described as that Susquehanna/Wyoming corridor, which just has produced tremendous well results.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Okay. And are you getting the volumes on the Wyoming pipeline which you anticipated, timing-wise?

Mark D. Casaday

Well, yes, remember that's subscribed by FT contracts, Adam. But, yes, barring normal -- real, real cold weather is great for us because it means a lot of gas demand. But it also creates operational problems as far as well freeze-ups. But barring normal operation upsets, yes, we are seeing the volume that we anticipated there.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Okay. Let me jump to some financials. On the CapEx side, how much of your budget is committed, how much is left for build-out of the Chief system?

Robert B. Wallace

You know, Adam, it's actually of the, let's say, $350 million to $400 million, there is room to reduce that capital budget on projects that we don't move ahead with. It's not -- it's clearly not 100% committed. Again, they're all projects that we're working on. There may be some movement in those. There are -- I can think of a couple in the $20 million to $25 million range that we're negotiating now that may or may not come true. But we threw them in the budget because we believe there's a better than half chance they'll happen this year. And again, there's a little bit of a lag on that. When you have internal growth, there's going to be a lag on when you get to EBITDA. So you're probably looking at the major contribution to a bunch of that capital we invest this year, you won't get the EBITDA from that until 12 months later or so, it ranges, but it's going to be a lag.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

And any discussion on how you might plan to fund the cash flow gap between spending and getting?

Robert B. Wallace

Well, we've got -- we have budget in our available capacity on our revolver. It's clear that we're going to need additional capital to fund our growth projects. And as I've said on every call over the last 3 years, we'll fund it with the appropriate mix of debt and equity as we need it.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Okay. And then lastly, can you give us what the covenant adjustment was and the ratio for the bank facility? And do you think you're going to be in compliance at the end of March?

Robert B. Wallace

Just a quick review on the debt covenants. As part of the Chief acquisition, we amended our debt, our revolver to give us cushion. It has to get back down to 5.25 in March of this year. In our view, it's going to be close to get to that, but we're undergoing an amendment of the revolver right now that we're very confident will come through. We're practically there as of right now, and that's going to provide us an increased room under the revolver through the end of the year. But I think that for the first quarter, we could make the step down, but it's going to be close. But in either case, because of the growth projects that we have during the year, we're going to go and get more room under the revolver for the remainder of this year.

K. Adam Leight - RBC Capital Markets, LLC, Research Division

Okay. And you don't have the adjustment for '12, and what it might look like for '13?

Robert B. Wallace

For '12, actually I do have that. If you have another question, I can find that, I can get that. If not, I can speak to you afterwards. I'm sorry.

Operator

Our next question is from Noah Lerner of Hartz Capital.

Noah Lerner

Some of my thoughts and questions were actually kind of somewhat addressed, but I figured I may just throw it out anyway. In the Eastern Marcellus region, where those Midstream assets are, the drilling that's going on, in your conversations with the drilling companies, how much of that is being -- is activity to hold the acreage right now versus still continuing just their overall drilling plans?

Mark D. Casaday

I can take that. We are almost -- after this year, very little is the answer, is to HBP any more leaseholds. Chief, by adding an additional rig, will complete all of their HBPs, they've told us, by the end of this year. But we've seen a significant shift in their philosophy back to pad drilling. So when you start to pad drill, based on the reserves, you're drilling because the returns are attractive enough for you to produce the gas. So I'm not sure -- or I'm pretty sure that our HBPs, by the end of this year, will be almost completely out of the picture.

Noah Lerner

Okay. And then I guess as a follow-up to that, in your discussions with these companies, clearly -- obviously, it was interesting that EXCO was slowing down, and was it Chief, added the rig. But I'm just curious as to, do these companies, do they share with you kind of at what price of natural gas they would think about slowing down? At what price do they envision adding additional rigs and speeding up and taking advantage of high prices? I'm just trying to get the plus and minus of the gas range and how that might impact drilling and your volumes going forward.

Robert B. Wallace

Mark, you want to take that one?

Mark D. Casaday

Yes, I mean, different producers obviously have different cost levels and thresholds. But some have told us at $2, they still drill. Less than that, they probably slow down. And others have told us, once it hits $4 level, they take off. So I think in the $2 to $4 range. I mean, we have 91 projected wells this year. 13 have already been drilled year-to-date, and we have 78 remaining. And 24 out of that 78, 24 are waffles [ph] . So I mean, to me, that's still pretty good activity up in that area.

Operator

Our next question comes from Matt Niblack of HITE.

Matt Niblack

You've given the commentary that you had on volumes in the Eastern Midstream largely being about timing. What's your sort of end of year 2013 view on that? Is most of the guidance decline because of the earlier quarters, and by the end of the year you think you'll be kind of where you thought you'd be originally, or how can we think about that?

Robert B. Wallace

Well, I think that based on the EXCO numbers, the fact is, those wells don't -- aren't -- we don't budget those wells that we originally thought would be on to come on. So I don't think we're back to where we were back last April. But clearly, there's growth throughout the year. But -- and there are timing issues with other producers, essentially in Bradford County as an example. But I don't think timing is 100% of the fix as a result of EXCO.

Matt Niblack

Okay. But would it be fair to say that as the years -- as the quarters move on, that you get closer to where you expected to be, if not all the way? But the gap is sort of widest in the early part of the year given the timing?

Robert B. Wallace

Yes, that's fair to say, for sure. And I think that, again, on EXCO, the timing issue is less of a this year timing issue than it is a longer-term timing issue in my view. And then also, on that question that Adam Leight had asked about our debt to EBITDA for the end of the year, it came in at 5.3x. Remember that as part of our debt covenants, we're allowed to take a material project adjustment, which means that we get some EBITDA credit for capital that is being put to work now, before our project is done. So at the end of the year, it was 5.3x.

Operator

And our next question will come from Michael Blum of Wells Fargo.

Michael J. Blum - Wells Fargo Securities, LLC, Research Division

I guess just a further clarification on the changing guidance in the Eastern segment. If I go back to your original slide presentation when you bought the Chief assets, you said that 2013 volumes would be at somewhere north of 1.5 Bcf a day, which seems like, based on your commentary today, is still going to be the case. So I'm trying to reconcile that with your commentary that most of this downward revision is due to EXCO, when it seems like it's more margin related than volume related. So I'm just hoping you can try to help me understand that a little better.

Robert B. Wallace

Thanks for the question, Michael. That's a good question that I wanted to mention, how we are measuring our volumes. It has changed from where we were in April. We have changed kind of our methodology in the East, based on the fact that we had these 2 trunklines in Wyoming County and in Lycoming County. What we're doing is we're measuring gathered volumes and trunkline volumes. You can see that on our income statement. We thought that was a better breakout for the analysts and for the public. But what that does do is it double counts some volumes, volumes that are both moved on the trunkline and gathered, some of those are counted twice. And so, although we get -- so we get our gathering fee on one volume. The same volume moves through the trunkline, and it gets a trunkline fee. Some volumes are just gathered and put right into the interstate pipeline. So that was a little different. So going back to the volumes back last April, it's not going to be a very good comparison, and actually, we've been talking about how we can go back and reconcile that. And maybe I can work on posting some information up on our website that would do that for you.

Michael J. Blum - Wells Fargo Securities, LLC, Research Division

Okay. Great. That will be very helpful. Can you also just talk about the decision to increase the distribution in the fourth quarter, just given where the guidance is going and where the fourth quarter numbers came in?

William H. Shea

Sure, Michael. This is Bill, I'll take that one. Again, as I stated earlier, the Board of Directors takes a look at that issue every single quarter, and based on management's view of the future in terms of our ability to generate EBITDA and DCF to pay the distribution, and taking a look at our ratability and consistency of EBITDA and cash flow that we expect throughout 2013 and beyond, the decision was made to increase the distribution and continue the distributions that have occurred over the past several quarters. So I think the -- while the guidance has come down, the confidence level in the increase in EBITDA and DCF growth is there and supports the distribution increase on an as-paid basis. And as you know, the other units will be paid as of, I think, the middle of 2014. And at that point, we should be in a good shape to cover those as well.

Robert B. Wallace

And just, Bill, just a little more flavor on the DCF. Two points. One is the reserve replacement capital that we had indicated in the past on the calculation of DCF is no longer going to be involved. That was related to the Coal business. We felt that, across The Street, analysts weren't dealing with it the same, besides the fact that we're not going to be reinvesting additional capital into the Coal business. So we've taken that out of the calculation of distributable cash flow. And then just as an update from last quarter, when I said that the coverage ratios on the distribution would be increasing quarter-to-quarter, we're still sticking with that. And on an as-paid basis, we expect to be in excess of 1x for the whole year on an as-paid basis.

Michael J. Blum - Wells Fargo Securities, LLC, Research Division

And that's based on the current distribution run rate for the year?

Robert B. Wallace

Yes.

Michael J. Blum - Wells Fargo Securities, LLC, Research Division

Okay. And then the last question is just, can you just remind us -- you're spending a lot of capital this year. How should we think about average returns on capital?

Robert B. Wallace

Well it -- again, we've got a lot of projects out there. But it's, generally speaking, I would say -- and Mark, please interrupt me, but I'm thinking that on the Eastern projects that we've approved, the large projects, we're looking at returns with very low multiples, with IRRs in the mid to high teens, low 20s. And so it's in excess of our cost of capital, and then -- but there are -- and then there's a bunch of capital that's at lower returns, well connects or additional pipe or compression. But in general, we're looking at, I think, probably on a blended basis, around 6x, I think, on all of it, maybe.

Operator

Your next question comes from Elvira Scotto of RBC.

Elvira Scotto - RBC Capital Markets, LLC, Research Division

Just a couple of quick follow-up questions for me. So in terms of the distribution policy, the coverage ratio, are you still targeting kind of a 1:1 coverage ratio over time? Maybe just walk through your thoughts there.

Robert B. Wallace

Well, it's gotten a little complicated with the pick units that we issued in the Chief acquisition. So what we have to look at first is the coverage ratio on an as-paid basis and then on a diluted basis. And on a long-term goal, yes, it's our goal on a long-term basis to be at 1.1x on a diluted basis. Given the growth ramp-up with Chief, a little bit of slippage in the numbers. It's going to take a little bit longer to get there. But on as-paid basis, that's certainly achievable, and that is our goal for the full year of 2013 on an as-paid basis. And I think it's kind of a longer term on the diluted basis, and that's -- that wasn't exactly the timing we were looking for. It should have been a little quicker, but that is why we structured the Chief deal with the pick units, so we'd have that flexibility. So I guess, the short answer is yes, 1.1x is our long-term target, and it's our short-term target on the as-paid units.

Elvira Scotto - RBC Capital Markets, LLC, Research Division

Okay, great. That's helpful. And then just circling back to the growth CapEx guidance for 2013. So what's new in the guidance? Is that the Midcontinent growth CapEx or is there new CapEx on the Eastern Midstream?

Robert B. Wallace

It's broken out, again, 3/4 in the East and 1/4 in the Midcon. In the Midcon, there are -- that's about $100-plus million, there are a couple of new potential proposed projects that relate to Hamlin and Crescent, based on the growth we're seeing there. No guarantees that they'll be completed or done, but they're in the budget and we expect to wrap up deals to back up that growth capital. In the East, it's carryover from the Chief acquisition. Remember, we did -- we had about $400 million to $500 million of capital in addition to the acquisition price. We didn't spend all of that, or invest all of that capital last year. So there's a rollover in Wyoming County for this year. And then there are additional projects, which some were announced last year, the SRS project in Lycoming County, the gathering project with Inflection in East Lycoming County, and then there are just various other growth projects that we're seeing. So again, I just want to make it clear that it's not anything due to any cost overruns. All of our capital, at least for the most part, has been on budget, on time for us with no material changes to that.

Elvira Scotto - RBC Capital Markets, LLC, Research Division

Okay, understood. And then on the Midcontinent Midstream. So can you talk about your contract mix now? And are you moving more towards fee-based? And then as you look at growth projects there, are you looking at them as fee-based projects?

Robert B. Wallace

Mark, why don't you take that question? I know that's a hot topic for you.

Mark D. Casaday

As I stated earlier, I hate the commodity business. And so what we've tried to do is target some large existing customers in the Panhandle to limit or minimize the commodity exposure in the Panhandle. And our Crescent and Hamlin expansions, if successful, have no commodity or very little commodity exposure as we grow those systems. Again, we have to be successful and the marketplace has to accept that, but our initial indications are that we think we have the right mix there. And again, what we're also doing in those 2 growth systems is trying to bundle services so that we were not just a gas processor, but we are a water and a condensate pipeline company also.

Robert B. Wallace

And Elvira, just a quick breakdown, as I've said before, based on our expectations for 2013 in the Midcontinent, we're looking at 10% keep-whole, 54% POPs and the rest is fee-based. And then combined with our Eastern operations, which are 100% fee-based, clearly, we're moving to the fee model.

Elvira Scotto - RBC Capital Markets, LLC, Research Division

Absolutely, absolutely. And then just one last question for me. So in the guidance provided on the Midcontinent, given that there's still some commodity price exposure there, what are you baking in as sort of your commodity NGL price assumption for '13?

Robert B. Wallace

That's a great question, a lot of discussion around that. We settled on using the curve at the end of January. So the midpoint of that range is basically the curve as it was in January, and we'll see where pricing goes throughout the year. Everybody's got a view on where it is, but we took the curve for NGL pricing and gas and crude.

Operator

Our next question comes from Jim Vine [ph], a private investor.

Unknown Attendee

I just wanted to ask a real simple question. I noticed on February 14, that there was a filing made by Neuberger or something like that, and they have over 10% of the stock of Penn Virginia through some of their clients. Is that a new filing?

Stephen R. Milbourne

This is Steve Milbourne, Investor Relations. I think that was their customary 13F filing. Neuberger has been a substantial unitholder for quite some time, and their filing did not represent a material change in their holdings. I think they did increase by a few units, but it was not a substantial change. So there was -- we don't see any significance in that filing. That's a routine regulatory filing that they're required to make, on a quarterly basis, disclose their position.

Operator

Our next question comes from James Spicer, Wells Fargo.

James Spicer - Wells Fargo & Company

Just a couple of quick clarifications. I think, earlier in the conversation, Mark had mentioned 46% of the Eastern Midstream being under firm transportation in terms of contract exposure. Just what's that 46% a percent of?

Robert B. Wallace

James, that is -- what we've done is we've taken the firm volume commitment by producers, we've assumed that they moved the volumes under their firm commitments, and we've -- and if it includes a stacked rate, and we've included that. So that percentage represents the percentage of total revenue in the Eastern business, that represents demand charges and the minimum volumes and the fees related to those volumes to meet those commitments.

James Spicer - Wells Fargo & Company

And that's over the LTM period or sort of the 2013 estimate?

Robert B. Wallace

It's for 2013, estimate.

James Spicer - Wells Fargo & Company

Okay. Great. That's helpful. Secondly, just given that a big part of the reduction in the Eastern Midstream guidance was due to EXCO, wondering if you can provide a little bit of color as to how much of the business EXCO represents today and other large customer concentrations? And I know the range in Chief, but if there are any numbers you could put around those, that would be helpful.

William H. Shea

Mark, you want to take a stab at that?

Mark D. Casaday

I think -- let me answer it this way. When we completed the Chief acquisition, EXCO represented, I believe, in the 40% to 45% range of our combined business. I believe today, that number is between 10% and 12%. So by virtue of the Wyoming pipeline coming online, SRS and continued growth in our other systems, we have greatly reduced that EXCO's impact on our operations.

James Spicer - Wells Fargo & Company

Okay. And just on an order of magnitude basis, would range in Chief be lower than that or higher than that?

Mark D. Casaday

It would be higher than that. And I would say that, again, the larger names you're dealing with, which I think you named already, Range, EXCO, Chief, Chesapeake, are the larger names.

James Spicer - Wells Fargo & Company

Okay. That's helpful. And then, one last one. Given that end of the year, you have about close to $600 million borrowed under the $1 billion credit facility. What's your comfort level in terms of the amount of liquidity you like to maintain under the credit facility in terms of cushion?

Robert B. Wallace

That's kind of the same question that was asked before. But we've got about that amount of capital, or potential capital to be invested this year. So we clearly need -- we'll need the liquidity at some point during the year. It will be -- we'll reduce the outstandings under the revolver to provide that liquidity through debt and equity, long-term debt and equity. That's about all I can tell you.

Operator

Our next question is from Mark Levin of BB&T Capital Markets.

Mark A. Levin - BB&T Capital Markets, Research Division

I think most of my questions have been asked, so I'll just leave it there.

Operator

And our next question is from William Adams FAMCO.

William N. Adams - Fiduciary Asset Management, LLC

I just want to get a little more clarification on the Eastern Midstream where you reduced your guidance. How much of that was due to the lower volumes at EXCO, and was there -- is there a lower expectation for lower tariffs than you have previously looked for, I guess, last summer?

William H. Shea

Go ahead, Rob.

Robert B. Wallace

I was going to say that I would say that 3/4 of the miss in guidance was due to EXCO. But Mark, why don't you comment on the rates?

Mark D. Casaday

I would say that our market rates and tariffs that we have -- our gathering rates we have on our system are exactly in line with our expectations.

William N. Adams - Fiduciary Asset Management, LLC

Okay. And then what's the other 1/4 of the miss then? If 3/4 are volumes of EXCO, what's the other 1/4?

Mark D. Casaday

It's spread out among a couple of other producers. It's probably a timing issue in Lycoming County for a chunk of it, and then the timing in Bradford, and then, it's kind of small misses here and there.

Robert B. Wallace

Yes. I think it's primarily due to timing, yes.

William N. Adams - Fiduciary Asset Management, LLC

Okay. And then can you give a little more color on your reduced guidance in the Coal segment? Is that lower volumes or are you assuming lower loyalty rates? Could you give us more color there?

Robert B. Wallace

Sure, and it's actually both. And just as an example I had, we did about 30 million tons this year, down about 8 million tons from last year. We're going to do -- we're probably looking at 25, 26 million tons, 24, 25 million tons for 2013. Basically, it's the fourth quarter kind of annualized. We're not expecting it to get much worse, but it's not going to get much better.

William N. Adams - Fiduciary Asset Management, LLC

Okay. And then, can you -- are you going to give us any guidance on interest expenses then for this year?

Robert B. Wallace

No. It's pretty -- we have $900 million of notes outstanding, so you know what that interest rate is. And then on the revolver, you know what LIBOR is and you know our current spread.

Operator

Our next question from Andrew Ebersole [ph] of National Life [ph] .

Unknown Analyst

I was wondering -- you talked about how a big impact was with EXCO, and I'm just wondering where you get the confidence that EXCO will eventually produce according to your original expectations? And then what do you think the timing is behind the delay of that production?

Robert B. Wallace

Mark, why don't you take a stab at that?

Mark D. Casaday

Well, for all the indications that we've seen in the well performance, you're talking to EURs of around 8 to 10 in the East Lycoming area. So what EXCO has told me in numerous meetings is that, at current gas prices, they can earn an acceptable rate of return at those levels. So I have to -- their business is drilling. So I have to believe that they will continue to drill over there. They've had great success in West Lycoming, with some wells that have even exceeded some of the high volume range wells that we have. So their results have been good. I'm just hopeful that they'll pick up their operations here in the third and fourth quarter of this year.

Robert B. Wallace

But I would say, Mark, that there hasn't been a material increase in our expectations for EXCO in our numbers for this year or even our preliminary plan for next year. It's really our confidence in the acreage where they operate, that if it's not drilled by them, it's got to be drilled by another party maybe.

Mark D. Casaday

That's right. Today, we've seen great results over in East Lycoming from Inflection. And XTO has drilled 3 wells the fourth quarter of this past year, which are connected online, and all performing wells. So the reserves in that area, as with all Lycoming County, are there.

Unknown Analyst

So you're saying that it's not a discretionary reduction in production? It was more structural or they were facing just some issues themselves that prevented them from producing as planned?

Mark D. Casaday

I won't speculate on what their internal issues were.

Operator

[Operator Instructions] And at this time, I'm not showing any questions. So that will conclude our question-and-answer session. I'd like to turn the conference back over to Mr. Shea for any closing remarks.

William H. Shea

Thanks very much, Emily. Thanks again, everyone, for joining us. We will speak to you at the first quarter 2013 call. Have a great day. Thank you.

Operator

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

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