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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, General Counsel of Penn Virginia Resource GP LLC and Secretary of Penn Virginia Resource GP LLC

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

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

Analysts

Gabriel P. Moreen - BofA Merrill Lynch, Research Division

James Spicer - Wells Fargo & Company

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

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

James Jampel

Heejung Ryoo - Barclays Capital, Research Division

PVR Partners, L.P. (PVR) Q2 2013 Earnings Call July 24, 2013 2:00 PM ET

Operator

Good afternoon, and welcome to the PVR Partners' Second Quarter 2013 Results Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Bill Shea, President and CEO. Please go ahead, sir.

William H. Shea

Thanks very much. Welcome, everyone. Thanks for joining us this afternoon. Here with me today are Rob Wallace, CFO; Mark Casaday, EVP and Chief Operating Officer of our Midstream Operations; Keith Horton, who's our EVP and Chief Operating Officer of Coal and Natural Resource Management; Bruce Davis, our EVP and General Counsel; Steve Milbourne, our Director of Investor Relations; and Forrest McNair, Controller.

Before we get started, Bruce, would you like to give us the forward looking statement warning?

Bruce D. Davis

Thanks, Bill. In the course of our remarks and the subsequent Q&A session, we may be making 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. Today, the Board of Directors declared a distribution of $0.55 per unit, unchanged from the first quarter of 2013, and a 3.8% increase from the second quarter of 2012. The distribution is payable on August 14, 2013, to unitholders of record at the close of business on August 7.

Our second quarter results produced $76.1 million of adjusted EBITDA compared to $57 million last year and $76 million last quarter. Distributable cash flow was $49 million versus $32.9 million last year and $49.9 million last quarter. Average daily volume in the Eastern Midstream Segment was 1.3 Bcf in the Eastern Midstream Segment and 0.4 Bcf in the Midcontinent Midstream.

Despite our second quarter results being consistent with our first quarter results and significantly ahead of 2012's second quarter results, I am disappointed with our results. Our results are below our expectations, primarily due to our producers delaying well connections in our Eastern Midstream operations. We did have 13 well connects during the second quarter and have connected 47 wells year-to-date.

Wells originally scheduled by our producers to be connected to our pipelines in the second quarter have been delayed until later this year. 8 wells originally scheduled to be connected in the second quarter were delayed, 6 of those are expected to be connected before the end of July, with anticipated average daily volumes for those wells around 36 million cubic feet per day. The other 2 wells will be connected in the fourth quarter.

We regularly receive drilling and well connection schedules from our producers, and we base our projections on these schedules among other things. Producers delay drilling and well connections for many reasons, including testing new drilling and frac-ing technologies, rig availability, unexpected drilling conditions, permitting delays, [indiscernible] conditions, et cetera. When a producer changes its schedule, however, it has a material impact on our results quarter-to-quarter. But over the long term, we expect these delayed wells will be drilled and connected and producing revenues in line with our expectations.

Simply put, we believe it's a short-term timing issue, not a long-term business issue. We believe in the long-term future of the Eastern Midstream, and our belief is supported by the strong results of the wells that have been drilled, completed and turned into our pipelines within our areas of operations.

Currently, there are 5 rigs drilling in our areas of dedication and another 25 rigs in our areas of operation. So the activity level is still good. As of June 30, we had 15 wells waiting on pipeline.

Based upon the revised well connection schedules that we've received from our producers, we expect total daily Eastern Midstream's throughput volumes at year end to be in the range of 1.6 Bcf to 1.8 Bcf a day, in line with our expectations of the year-end run rate.

Our Eastern Midstream Segment adjusted EBITDA results were $38.1 million compared to $17.7 million last year and $37.7 million last quarter. Volumes for the quarter were 1.3 Bcf per day versus 0.5 Bcf per day last year and 1.2 Bcf per day last quarter.

In our Midcon Midstream Segment, we've produced $14.9 million of adjusted EBITDA versus $12.7 million last year and $15.7 million last quarter. During the quarter, we invested $110.9 million on internal growth projects in our Midstream businesses, $97.5 million of that was spent in our Eastern Midstream Segment.

Let me take a few minutes to discuss a couple of the development and build-out growth projects that we have ongoing in the Marcellus, Utica, Cline and Mississippian Lime. Construction of the new Severcool compressor facility and central delivery point on the Wyoming County trunkline was completed and began operation during June. Completion of these facilities added 85 million cubic feet a day of firm volume commitment to the Wyoming trunkline beginning July 1, 2013.

The new interconnection into the Wyoming trunkline for Carrizo Oil & Gas and Reliance Group began service during June. The second phase of the new Lycoming gathering system, for which Inflection Energy is the primary shipper, was completed and began service in the second quarter. Work on additional phases of this system continues.

As I mentioned, we completed 13 new well connections in the Eastern Midstream Segment during the second quarter. Construction of the initial phase of our gathering system in Greene County, Pennsylvania has been completed. Volume on the system during the second quarter averaged 12 million cubic feet a day. Early-phase development work continues on a proposed new trunkline and gathering system in the Utica Shale. And finally, we completed 52 new well connections in the Midcontinent Midstream Segment during the second quarter.

The Coal and Natural Resource Segment earned $23.1 million in adjusted EBITDA on the second quarter as compared to $26.7 million last year and $22.7 million last quarter. Based on our current expectations, we are updating our adjusted EBITDA guidance for 2013. Full year 2013 adjusted EBITDA for the Eastern Midstream Segment is now expected to be in the range of $160 million to $185 million, and the Midcontinent Midstream Segment is now expected to be in the range of $60 million to $70 million. The Coal and Natural Resource Segment remains unchanged at $75 million to $85 million. Full year maintenance CapEx will be in the $13 million to $15 million range, and internal growth CapEx remains unchanged at $350 million to $400 million.

Let me break down the reduction in expected EBITDA in the East from our old guidance to our new guidance. The midpoint of the East EBITDA range under the old guidance was $210 million versus $172.5 million under our revised guidance. Of the $37.5 million variance, about 25% or $8 million to $10 million of the variance is from lower water deliveries under our Aqua joint venture. This variance was driven by 3 factors: one, the delay in well connections that I've already discussed; two, the use of reclaimed water by one of our producers that was greater than originally budgeted; and three, lastly, expectations for water demand this year have just not materialized.

About 10% or $3 million to $5 million of the variance is due to the higher-than-expected operating cost, some of which may be one-time expenses incurred due to weather during the colder months of the year. With the cold weather in the Northeast this past winter as an example, we had greater-than-expected use of methanol to prevent pipeline freeze-offs.

45% or $16 million to $18 million was driven by producer delays in drilling and well connects. As I've mentioned earlier, even though our run rate on volumes in the East at year end is expected to be in the range of 1.6 Bcf to 1.8 Bcf a day, our average daily volumes for the whole of 2013 are expected to be about 115 million cubic feet a day less due to timing changes in well connects.

Based on average revenue of about $0.39 per Mcf, times the 115 million cubic feet per day, times 365 days, the lower amount of gas moved per day equates to an EBITDA impact of about $16 million for the year. The remainder of the variance between the old and the new guidance in the East reflects the inclusion of some conservativism, which reflects the fact that PVR depends on producer estimates and timetables, which are, for the most part, out of our control.

At this time, I'd like to turn it back to Denise for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] The first question will come from Gabe Moreen of Bank of America Merrill Lynch.

Gabriel P. Moreen - BofA Merrill Lynch, Research Division

Questions in terms of, I guess, the shift in well connects inter-quarter. And Bill, you mentioned, I think some of the potential motivating factors. But from your perspective, obviously, frontline gas prices also made a pretty significant shift during the quarter, too. I mean, do you think it was really gas prices that motivated the delay here in well connects? And I guess, can you speak to whether there's a risk here if the front end of the curve shifts down again for whatever reason, that things could get pushed out even further?

William H. Shea

Gabe, I'm not sure I know exactly how the producers are viewing that. We still believe that the economics are very, very good in the counties that we operate in, in Northeastern Pennsylvania. And so while the gas prices did move down, I'm not convinced that, that changed any of the connection patterns that the producers had. They're just items -- operational items for the most part that -- my belief anyways that create the delays in the well connections. Mark, do you have anything to add now?

Mark D. Casaday

No, I think that's spot on. We've seen no results or we've seen no curtailment in production that the producers told us because of pricing.

Gabriel P. Moreen - BofA Merrill Lynch, Research Division

Okay, got it. And then if I can ask a question on the Aqua JV and I think the results there. Can you remind us sort of what your investment there is in the facility, what your kind of return expectations are and, I guess, the confidence that based on some of the issues you're experiencing, you'll kind of get the demand showing up? And is it strictly your tariff or is that strictly volumetric? Or do you have a take-or-pay component there?

Robert B. Wallace

Mark, describe the deal then I can help with the financial.

Mark D. Casaday

Yes, Gabe, this is Mark. There are no volumetric commitments on the pipeline as there are in our gas line and FT charges. There are areas of dedication similar to our Midcontinent drilling type things where -- like for example, all freshwater used in Lycoming County by Range Resources has to come through our pipeline. So that's the structure of most of our deals.

Gabriel P. Moreen - BofA Merrill Lynch, Research Division

Okay. And then, is there a risk, I guess, to the extent that Range or whomever is basically using more recycled water that your return expectations there went over? And if you can speak to the capital spend, I think Rob might have -- if I heard you correct, Rob, in the background, you might have been trying to address that?

Robert B. Wallace

Yes. And the $50 million of our share of the project has been invested to date, and our view on volumes was we were going to do a considerable bit more volumes this year than we've actually seen. And again, part of it is from the well connects and the drilling activity and the reclaimed water, which, frankly, came as a kind of a surprise to us. But we do believe that the reclaimed water is not going to be a permanent impact to us. It may happen from time to time, but generally speaking, I think we'll get back on the freshwater use over the next few years, I would imagine.

Mark D. Casaday

Yes. And Gabe, let me explain the recycled water why it was such a high usage during the first quarter. Last year, Range drilled approximately 50 to 60 wells. And they had a -- and I'll specifically speak to Range. They had a disposal issue where the cost per barrel and the actual place to take the water, there was a bottleneck. So they literally stored water in over 300 frac tanks on well pads throughout our geographical area. This year, as we projected, they drilled 15 wells, had all this water to get used and used it as a disposal method in their fracs. So I think that it was just an unusual, high usage of recycled water. We projected in our normal budgeting process, when we evaluated the water system, about 20% usage based on historical flowbacks from these wells. We think long term that, that is the trend. We think we had a short-term issue with the volume and activity levels in Lycoming County, specifically with Range.

Operator

Our next question will come from Adam -- I'm sorry, James Spicer of Wells Fargo.

James Spicer - Wells Fargo & Company

Just a couple of questions for you. In terms of the delayed well connects, was it -- were there any concentrations in terms of the producers? Was it just 1 or 2 producers delaying or did you see it sort of across the entire position?

Robert B. Wallace

Mark, I can take a stab at that. And I think the answer is that we generally saw it across the system. But I will say that as far as the financial impact and if you look at the margins that we get from certain producers, as an example, I think everybody knows that Chief and Range are some of our larger producers with the larger margin, because we do gather and transport their gas. So when they have issues or delays, it impacts us a little bit more. So I think the absolute number of wells that were delayed or -- are going to be connected later in the year across the system. But the ones that had a material impact on us are probably from Range and Chief. Is that fair, Mark?

Mark D. Casaday

Man, that was spot on.

James Spicer - Wells Fargo & Company

And do you have estimates at this point as to how many well connects you're expecting to see in Q3 and Q4?

William H. Shea

Yes, James, we do. And of course, I can't find it.

Robert B. Wallace

No, we have it right here in front of us, Bill. We expect to do 106 well connects for the whole year. And that -- and then from today through the end of the year, we expect to do another 59 to get there. So we've connected a few in July already.

James Spicer - Wells Fargo & Company

Okay, that's great. And can you remind me what the firm transport commitments you have right now on both the Lycoming -- the Wyoming and Lycoming trunklines, and where you are today in terms of volumes relative to those commitments?

William H. Shea

James, our total commitments on the Lycoming trunkline as of the 1st of July are a little over 400 million cubic feet, and they'll ramp to about 460 million by October. And on the Wyoming trunkline, it's about 460 million as of July 1. I'm sorry, what was the second part of that question?

James Spicer - Wells Fargo & Company

And then where are you today in terms of volumes on those?

William H. Shea

Hold on one second, we'll see if we can get you the correct answer. On the Lycoming trunkline, we're at about 340 million; and on the Wyoming trunkline, about 358 million.

James Spicer - Wells Fargo & Company

Okay. So your firm transportation commitments are in excess of your volumes on both systems right now?

Mark D. Casaday

Yes, hardly.

William H. Shea

Mark, did I give the wrong answer there?

Mark D. Casaday

Oh, no, you're good.

William H. Shea

Okay.

James Spicer - Wells Fargo & Company

Okay, great. And then last one from me. Can you tell us what your leverage was at the end of the quarter per your credit facility calculations with all the various add-backs?

Robert B. Wallace

Yes. Based on our calculation, we'll be at 5.4x. And the test, just to remind you, for this quarter, it's 5.75x.

James Spicer - Wells Fargo & Company

Okay. Do you expect -- do you sort of look at this quarter as sort of the high point and declining from here, given the ramp-up in cash flows in the second half of the year?

Robert B. Wallace

At the high point or equal to, yes.

Operator

Our next question will come from Adam Leight of RBC Capital Markets.

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

I don’t want to beat a dead horse here, but on the operational items that you talk about, Mark, or goal, can you give a little bit more color on that? Was that weather or did you get any color from your customers as to what cause those delays?

William H. Shea

Are you talking about the well connect delays or the operating costs?

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

Well connect delays, you said operational issues.

William H. Shea

Mark, you want to go through a couple of the reasons?

Mark D. Casaday

Is he talking about the increased stock costs?

William H. Shea

No, he's talking about the delay in well connects.

Mark D. Casaday

It is a shift in various things. It's if they schedule a frac for 1 week and then it's delayed 3 weeks from them. So you have frac delays, we've had issues with perforations in cementing jobs further delaying. And it just seems if you could list everything that couldn't -- could go wrong and is delayed off of schedules, we've had a whole variety of things that obviously impact the producer, but more importantly, impact us as far as timing of when we predict it and when it actually is online.

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

So I guess what I'm trying to get out here for second half, what's going to drive the recovery or the acceleration, I guess, and give you confidence that things are going to move on time?

Robert B. Wallace

Well, here's how we've looked at this over the last few weeks or month is that we've been speaking with the producers, and we have our people in the field to speak to the producers. And as Bill had mentioned on the call, we're looking at 106 well connects, which is a little bit more than what we had expected back 3 or 4 months ago, but they're back-end loaded. So as far as cash flow goes, our average daily rate is going to be less than what we expected, but we still feel very confident that we'll exit the year at that 1.6 to 1.8 area. And so as far as what's going to move them, there are -- of the wells that we're waiting on, I think Bill had mentioned this, that 14 are waiting on pipeline, which is the highest probability wells. There are 33 wells that are in some store -- in some stage of drilling across all of our areas. And we've got 12 wells that are going to be drilled and completed and put online over the next 5 months. So we've got these schedules from producers. And I have to admit, that Bill also made one little comment, that we have a bit of cushion in our guidance because, well, they've changed their plans before to minor extents. And the point of Bill's math on the EBITDA impact is that small changes in production every month do have an impact -- a meaningful impact on our EBITDA.

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

Okay. That, I guess, will suffice. On the Midcontinent, just last quarter, you had some weather delays, ethane rejection, natural decline and volumes still seems to decline too some this quarter, this last quarter. Can you give us a sense of what direction things are going if you did connect a lot of wells? What do you think you're going to see?

William H. Shea

Well, first, let me just -- you mentioned ethane rejection. We're still in an ethane rejection mode and most likely, given our view of pricing, we will be for the entire year. We did connect about 50 wells in the Midcontinent in the second quarter. A lot of those wells were in the Mississippian Lime, so into our Crescent System. And those are wells that are producing less gas than, say, a Granite Wash well does. There's a lot of liquids associated with the Mississippian Lime well. So while we connected a fair number of wells, we're getting less gas from them and then, of course, we have the natural decline of the Granite Wash wells in particular.

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

Okay, that makes sense. And contract mix, is that still roughly the same as it has been?

Robert B. Wallace

Yes.

William H. Shea

Yes.

Mark D. Casaday

Yes.

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

Okay. And then on CapEx, it doesn't sound like you're changing your thoughts on what you plan to spend for growth this year. Can you remind me how much is left to spend on building out the rest of the system?

Robert B. Wallace

Well, hopefully, the system will never be complete, and we'll be adding CapEx to it for years with growth. But for this year, we probably got a little less than half of what we've already -- I mean, a little less than what we spent for the 6 months to date to spend through the rest of the year. And actually, we've rationalized our CapEx since we last spoke, but we've also added other growth projects, which have added some capital through the end of the year. So we would've hit our high margin, our high point on capital this quarter -- or I should say for the June quarter, but that's been moved out a little bit. So we'll spend a comparable amount next quarter, and then it will drop off at the end of the year.

Operator

[Operator Instructions] The next question will come from Michael Blum of Wells Fargo.

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

Just a follow-up, another question on the debt covenants. So Rob, if I heard you right, it sounds like you don’t think you'll need to go back and -- effectively go back and get another temporary waiver or change what you have in place? What you think what you have in place in terms of the waivers, on the debt covenants should be -- should suffice for the balance of the year?

Robert B. Wallace

Based on our plans on how we're going to finance our business, yes.

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

Okay. And then on the ethane rejection question in the Midcontinent, can you quantify that?

Robert B. Wallace

We can quantify it by saying we're rejecting 100%. And then as far as the financial side of the equation, actually, in some cases, it's kind of a positive for us on the operating side, on the financial side, because we can buy ethane cheaper than what it's being -- and what we have to return to producers. And so we get more value in the value of the natural gas. So I can't quantify that specifically as to what the benefit is, but there is a small benefit there. And I just did want to make one mention on the debt agreement, that's an amendment, not a waiver. So that amendment is permanent through the first quarter of next year.

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

Okay. And then last question, just kind of taking a step back in the Eastern segment. When you made the acquisition, if I remember correctly, if you looked out, and I don't remember exactly what year it was, but 5 years out or whatever, once you finished your entire build-out, you thought the all-in multiple would come down to something like a 6.5, if I remember correctly, EBITDA. Can you update that where you think that is going to ultimately end up now in terms of when you finish spending all the capital in that system, I know you said you hope never to finish, but at least what you had planned at acquisition and what the all-in multiple will look like?

Robert B. Wallace

Michael, that's going to be pretty difficult to come up with at this point. But what I will say is that the 5x to 6x multiple that we had hoped to get 1.5 years ago or 1.25 years ago when we made the acquisition gave us plenty of cushion to still make it. And even if it went up to a slightly higher multiple, it gave us a good cushion to have at a very attractive multiple. It's hard to say because we went out 2 years on those projections at the time we acquired Chief, and things have maybe pushed back a little bit more, plus there have been other growth projects which we've added to the area. But my off-the-cuff, because I don't have the exact facts in front of me, about where we'll be in 2 years, would be greater than 6, but honestly, not a whole lot more. We're still that confident about the business.

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

Okay. So if I think about the delays you've experienced in 2013, should I just think of that as kind of pushing that trajectory out, but probably getting close to the fees that you thought you would.

William H. Shea

Michael, this is Bill. Yes, that's the way we view it, because the CapEx that we're spending now isn't finishing the build-out of at least the initial system that we have contemplated. So the CapEx going forward ought to be less, and it ought to be more focused on well connects. So we should start to see a reduction or a lowering of the multiple of the overall project.

Operator

Our next question will come from Matt Niblack of HITE.

James Jampel

It's actually James Jampel from HITE. Can you remind me how much of the EBITDA guidance revision was due to the water joint venture?

Robert B. Wallace

About $8 million to $10 million.

James Jampel

I assume...

Robert B. Wallace

And that's a considerable portion of what our expected EBITDA was supposed to be for the year in the water business.

James Jampel

So the current view for the year is a 0 EBITDA from the water business?

Robert B. Wallace

No, but it'll be a lot less than what we had expected. And I think for the year, I'm not -- off the top of my head, I'm sorry, James, I'm not sure what we're currently projecting and after the decline.

James Jampel

I see. And of the $8 million to $10 million in decline, I mean, how much of that do you think is due to the one-off things like the reuse of water? And how much of that do you think is more permanent?

Robert B. Wallace

Well, I can't answer that. Today, as we speak today, we're delivering about 1.5 million gallons. So...

Mark D. Casaday

Per day.

Robert B. Wallace

Per day, excuse me. 1.5 million gallons per day, which is about half of our system capacity, which is 3 million gallons. We have just seen a tremendous pickup in the last 2 weeks from basically a dry first half of the year. And we expect that to continue for the near-term future here up until mid-September at least, and then it'll be rescheduled. So it's a hard business to predict, but it's picked up right now in the short term.

Mark D. Casaday

And I think I can put some brackets on this business. I would think that what we have left is probably about 1/3 of what we had expected, a little more than 1/3. So the $10 million is probably 2/3 of what we had expected roughly.

James Jampel

Which is that you're getting 2/3 of the expected EBITDA this year?

Robert B. Wallace

I think we were about $15 million, that was our share of EBITDA for the year is what we expected. And now, we're down probably $8 million to $10 million from that.

James Jampel

Okay, okay. But -- and then, so you say it's a difficult business to predict. And so how should we go about thinking what a good run rate for the water business is?

William H. Shea

Well, the run rate is really going to depend on the estimated well connects that occur. And so what we do is we're in the producer's office weekly, making sure that we have the latest information that they'll provide us in terms of well connects. And we'll go through the budgeting process in the fall with the producers and, again, trying to get their commitment to the wells that they'll drill and the wells that they'll complete and the wells that they'll connect to the pipeline system. So -- and also, the volume that would be used per well. So it's an ongoing process with the producers that -- it just coincides, at least, in Lycoming County, with the wells that are going to be drilled.

James Jampel

Okay. Now on the coal business, has there been any change since last quarter regarding what will happen when the San Juan volumes roll off?

William H. Shea

No, there's been no change in terms of that. I think we're looking at the end of the first quarter or so of next year for those volumes to be completed. And I don't know if you want to talk a little bit about the current state of the coal business, Keith?

Keith D. Horton

Well, basically, it's pretty well steady at this point in time. All the volumes moving are contracted volumes from previous periods. We're -- everybody is sort of maintaining the status quo on the thermal side. The met coal side is taking a bit of a hit in terms of pricing, so we've seen a little erosion there in terms of our royalties coming from the met coal operations and some reduction in production, partially offset, though, by some thermal production that has advanced onto our property that was initially unbudgeted. So as we go, we're running pretty well as projected and it is doing so for the remainder of the year.

Robert B. Wallace

Yes, and just a quick comment on coal. The volumes are up against last quarter, which is good. The royalty rate per ton is down, and that reflects the market in pricing. And then we also had the one-time $2.2 million in the numbers, which won't be repeated. So for this year, I think we're good with the guidance we have outstanding.

James Jampel

Right. So that was a $2 million benefit that's a 1-quarter one-off?

Robert B. Wallace

Yes.

James Jampel

Okay. And then lastly, on financing, going forward, can you take us through a little bit of your thought process about that, in particular, the things you might do in alternative to a common unit offering?

Robert B. Wallace

I think, James, all I'll say is that we're looking at a lot of alternatives. And we typically don't talk much about the financing, at least in advance of the financing.

Operator

[Operator Instructions] The next question will come from Helen Ryoo of Barclays.

Heejung Ryoo - Barclays Capital, Research Division

A couple of follow-ups. So out of the $532 million of revolver availability, how much can you actually use given your debt covenant limitation?

Robert B. Wallace

Well, it depends on when it gets used and what the EBITDA is. But for right now, it's all available. I mean, it depends on what you use it for, assuming you grow your EBITDA at the same time or you get growth EBITDA between now and whenever we would use that. So as far as I'm concerned, it's all available.

Heejung Ryoo - Barclays Capital, Research Division

So for the remainder of the year, I guess, the remaining CapEx needs could be...

Robert B. Wallace

The liquidity on the revolver -- I understand your question. The liquidity under the revolver today is sufficient to manage our capital through the end of the year, based on our debt covenants.

Heejung Ryoo - Barclays Capital, Research Division

Okay, got it. Okay. Do you have an ATM program?

Robert B. Wallace

Actually, we do. We just filed one for $150 million last month, at the end of last month to the beginning of this month.

Heejung Ryoo - Barclays Capital, Research Division

And have used any of that?

Robert B. Wallace

No, we haven't, not yet. It's a new toy.

Heejung Ryoo - Barclays Capital, Research Division

Okay, got it. And then just maintenance CapEx reduced a little bit. Was that just well connect delays related adjustment?

Robert B. Wallace

No. I think that was just actual results on maintenance capital.

Heejung Ryoo - Barclays Capital, Research Division

Okay. So your guidance has come down a little bit, and that's just because you're doing better on your maintenance CapEx?

Robert B. Wallace

We're spending a little bit less, and we're investing a little bit less than we had expected at the beginning of the year, yes.

Heejung Ryoo - Barclays Capital, Research Division

Okay, all right. And then just lastly, your Class B Units, I guess, they're going to start to convert to common next year. And I was just wondering -- I guess that's with Riverstone. But if your coverage becomes light, is that a reasonable scenario for that unit to get picked for a longer period of time than the current plan?

William H. Shea

Helen, this is Bill. I would consider it reasonable. I'm not sure how Riverstone would react to that. We haven't -- it's way too early for us to approach them on something like that. So I guess if the time came and we have to do that because of the coverage ratio and the ability to pay the distribution, we would go to them.

Operator

Our next question will be a follow-up from James Spicer of Wells Fargo.

James Spicer - Wells Fargo & Company

Just a follow-up from me. I think you said that as of July 1, your firm commitments on the Wyoming system and the Lycoming system were both at 460 million. I just wanted to clarify that, that was correct. And then wondering what were those commitments during the second quarter.

William H. Shea

First, let me go back to Helen's question about the Class B Units, because I want to make sure that you're clear, that we don't anticipate having to go to Riverstone for any kind of extension. That would not be part of our plan or part of our strategy for next year. So I just wanted to clarify that. James, your question, the Lycoming trunkline is at about 430 now, and it's going to go to 460 in October. And on the Wyoming trunkline, on July 1, it was 460.

James Spicer - Wells Fargo & Company

And so what was Wyoming during the second quarter, was it at 460 as well? I'm just wondering what the incremental firm commitment is in the third quarter versus the second quarter.

Robert B. Wallace

You have to subtract that at 100 for the compression station that came on in June, right? So it would be 360?

William H. Shea

It was 360 in the second quarter. We had a compression facility come online that added to the FT.

Robert B. Wallace

So that is 100 to the FT. So we're now at 460, and then we were -- it added 85, excuse me. So 460 minus 85, is that right?

James Spicer - Wells Fargo & Company

Okay, I think I got it. And so if your firm commitments are in excess of the volumes going through the systems, if you're hooking up additional wells, where are you realizing the economics? Is that in the gathering and processing fees?

Robert B. Wallace

Mark -- and I think what you're asking is if the firm transportation requirements are the tail end of the movement, and so actually, we do get the margin from the gathering, the de-hy, the compression and the compression on the trunkline, which is not included in the firm transportation fee. Is that fair to say, Mark?

Mark D. Casaday

That's it.

Robert B. Wallace

And so that's where you'll get the margin. There are some people who have a set amount of firm transportation and aren't moving volumes to equal that. And as they add more volumes, we get much more margin than just the transportation fee that they are required to pay, whether they ship or not.

Operator

And ladies and gentlemen, that will conclude our question-and-answer session. I would like to turn the conference back over to Bill Shea for his closing remarks.

William H. Shea

Everyone, thanks very much for joining us on the second quarter call, and we will be talking to you again at the end of the third quarter. Thanks very much, and have a great afternoon.

Operator

Ladies and gentlemen, the conference has now concluded. We thank you for attending today's presentation. You may now disconnect your lines.

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