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Access Midstream Partners, L.P. (NYSE:ACMP)

Q2 2013 Earnings Call

July 31, 2013 9:00 am ET

Executives

Alyson Gilbert

J. Michael Stice - Chief Executive Officer of Access Midstream Partners GP LLC, President of Access Midstream Partners GP LLC and Director of Access Midstream Partners GP LLC

David C. Shiels - Chief Financial Officer of Access Midstream Partners GP LLC and Principal Accounting Officer of Access Midstream Partners GP LLC

Analysts

Darren Horowitz - Raymond James & Associates, Inc., Research Division

TJ Schultz - RBC Capital Markets, LLC, Research Division

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Paul Jacob

James Jampel

Heejung Ryoo - Barclays Capital, Research Division

Operator

Good morning, and welcome to the Access Midstream Partners ACMP's 2Q '13 Earnings Call. Today's conference is being recorded. At this time, I will turn the call over to Alyson Gilbert in ACMP Investor Relations. Please go ahead.

Alyson Gilbert

Thank you, operator. Good morning to everyone. Thanks for being with us this morning as we discuss our second quarter results. With me today are Mike Stice, Chief Executive Officer; David Shiels, Chief Financial Officer; and Bob Purgason, Chief Operating Officer.

Please note that if you do not have a copy of the press release issued yesterday, please visit www.accessmidstream.com, where you will find it in the News section. Today's discussion will include information regarding non-GAAP financial measures, such as adjusted EBITDA and distributable cash flow. Please refer to the Investor Relations section of our website for SEC-required reconciliations of these measures.

Finally, today, we will discuss forward-looking statements that give our current expectations or forecasts of future events. They may include, but are not limited to, estimates of expected volumes, future operating expenses, planned capital expenditures and anticipated asset acquisitions and sales. They may also include statements concerning anticipated cash flow, liquidity, business strategy and other plans and objectives for future operations.

Although we believe the expectations and forecasts reflected in these forward-looking statements are reasonable, we can give no assurance they will prove to be correct. Please see our 2012 Annual Report on Form 10-K for a listing of factors that could cause actual results to differ materially from expected results.

With that, we'll get started, and we'll turn the call over to Mike.

J. Michael Stice

Thanks, Alyson and good morning, everyone. We appreciate you being with us once again. As usual, Dave and I will start with some prepared remarks in our second quarter results, and then Bob will join us in answering any questions you might have.

Our operational performance in the second quarter was outstanding. We continued to execute on our operating plan, and we are realizing the financial reward previously forecast by that plan. In the Marcellus, we have decreased WOPLs, or wells waiting on pipeline, from over 250 at the end of last year to less than 115 as of June 30. As a direct result, we have been recording daily throughput records in the Marcellus. Recently, I was able to visit the Marcellus North team and celebrated exceeding 2 billion cubic feet of gross daily throughput in that region. This is incredible to note that our Marcellus North operations would be one of the largest gathering and processing MLP's in the sector if it were a standalone company.

In the Southern Marcellus, the rich part of the basin, we are also delivering record volumes with over 300 million cubic feet of gross daily throughput. The Marcellus is a highly prolific, proven basin and a significant success story for Access Midstream.

Another significant achievement occurred in the Eagle Ford, where our teams connected more than 230 wells to our gathering systems in the first half of 2013. These 2 examples are merely highlights, as our operations teams in all of our operating regions had made significant progress in the first half of the year. And it this progress that contributed to our strong financial performance year-to-date.

After celebrating with our team in the Marcellus North, I traveled to our Utica region to see firsthand the construction efforts that are ongoing in that area. Here we have a partnered with M3 to build a world-class gathering, processing and fractionation business. The gathering business is operated by Access Midstream under the name Cardinal Gas Services and includes our partners, Total and Intervest. The processing fractionation business is operated by M3 under the name Utica East Ohio Midstream, and the partnership includes Access, M3 and Intervest. Collectively, we are building capacity to gather and process 800 million cubic feet per day of rich gas and fractionate the related NGL products.

On Monday this week, UEOM announced that the first phase of the processing of fractionation operations in Kensington, Ohio was placed in service, processing liquid-rich Utica shale production, producing natural gas liquids and redelivering residue gas to downstream interstate markets. This is the first such operation to be placed in service in East Ohio. These world class facilities are on time and on budget to meet our growing customers' needs.

Customer diversification continues to be a primary focus for us. Our goal is to reduce our exposure to Chesapeake to less than 50% by the end of 2015, from 75% today. This decrease can be changed -- achieved in several ways: First, we will continue to benefit as Chesapeake completes asset sales to other producers; second, we may make bolt-on acquisitions that creates synergies within our existing footprint, expanding our customer base. We are a leading midstream provider in each of the basins we serve and are often a natural fit for acquisition opportunities within our current footprint. Third, we have the ability to sell our midstream services to other producers within that existing footprint. Each of these activities would generate new producer customers for Access. As recent examples, we added RKI as a new producer of customer with the closing of the Jackalope transaction in the Niobrara basin and added EXCO with the sale of Chesapeake's acreage in the Haynesville. Customer diversification is a critical step in achieving an investment grade credit rating that will reduce our already low cost of capital.

Yesterday, S&P acknowledged our progress by increasing Access Midstream's corporate credit rating from BB- to BB due to our increase in size and diversity and improvements in Chesapeake Energy's credit profile.

On the corporate front, we are nearing completion on separating our back-office infrastructure from Chesapeake, creating a self-supported, standalone company. We are nearly 90% complete with the transition. The remaining work is primarily related to the transition of our IT environment. We expect to be substantially complete with this process by the end of the year.

With regard to core values, Access continues to be committed to conducting our business in the safest and most environmentally sound manner possible. In the second quarter, we had no lost time incident. However, we incurred one OSHA recordable incident during the quarter. While our total recordable incident rate, or TRIR, was 0.36 and reflects that we are one of the safest companies in the industry, our goal continues to be 0 recordable and 0 environmental instance.

With that and before we take questions, Dave has some commentary on the second quarter financial results. Dave?

David C. Shiels

Thank you, Mike. Good morning, everyone. Our second quarter was outstanding from both an operational and financial perspective as we continue to generate consistent, predictable and high-growth financial performance from our best-in-class business model.

Second quarter 2013 adjusted EBITDA totaled $207 million, an increase of $86 million, or 71% compared to the 2012 second quarter. Distributable cash flow totaled $153 million in the 2013 second quarter, up 76% compared to 2012 second quarter. The resulting distribution coverage for the second quarter was 1.56X.

Gathering volumes for the second quarter totaled 3.67 bcf per day, an increase of 28% over the 2012 second quarter. As a reminder, these throughput amounts include volume from our equity investments, primarily in the Marcellus, but revenue does not include Marcellus results. All the revenue and expense impacts from our equity investments are included in the income from unconsolidated affiliate line on the income statement.

Revenue for the second quarter was $247 million, an increase of $98 million or 66% over last year's second quarter. If we include revenue from equity method joint ventures in the revenue line on the income statement for both periods, our consolidated revenue would have increased 67% versus second quarter last year.

Total CapEx spending was $425 million during the second quarter. The primary driver of capital spending were the Utica, where we spent $172 million; the Eagle Ford, where we spent $83 million; and the Marcellus, where we spent $76 million. Our total capital expenditures in the second quarter kept us in line with our total year public guidance of $1.7 billion to $1.8 billion for 2013.

We continue to spend significantly in our liquids-rich regions, and those liquids-rich regions should account for about 80% of our total capital investment and 50% of our EBITDA by the end of this year.

The Eagle Ford is the most mature of our new assets, and the capital spent in the Eagle Ford helped connect 119 new wells to our gathering systems in the second quarter, with more than 230 wells connected in the first 6 months of 2013. Eagle Ford throughput in the second quarter averaged 243 million cubic feet per day, generating revenue of $68 million. Marcellus throughput averaged 930 million cubic feet per day for the second quarter, net to ACMP's interest, an increase of almost 50% year-over-year. While a small amount of this volume is attributable to the Marcellus assets acquired in December 2012, the vast majority of the increase in throughput is related to our original equity investment in the Marcellus.

Chesapeake continues to exceed its EBITDA commitment for the Marcellus equity investment, therefore we did not recognize any income associated with the commitment in the quarter.

In the Barnett Shale, average throughput decreased from 1.27 bcf per day in the second quarter last year to 1.05 bcf per day this year due to a decrease in drilling activity by Chesapeake and Total. In the first quarter, we provided a range of $35 million to $40 million for the amount of revenue we expect to record in the fourth quarter associated with the Barnett MBC. We are now increasing that range to $40 million to $45 million and have adjusted EBITDA by $11.25 million in the second quarter. Adding this amount to the $8.75 million we reflected in adjusted EBITDA in the first quarter, we have now adjusted EBITDA for $20 million for the first 6 months of the year, or half of the low end of the new range of revenue we expect to record at the end of the year.

Haynesville throughput averaged 695 million cubic feet per day in the first -- in the second quarter, an increase of almost 100% compared to the 2012 second quarter, as volume from the Mansfield system acquired in December of last year, more than offset a volume decrease in the Springridge system. Cost management continues to be a significant focus in the dry gas regions, like the Haynesville and the Barnett, where we have seen reduced activity by our producer customers. Both the Haynesville and the Barnett have long-term volume protection through MBC and fee redetermination mechanisms.

Mid-Continent average throughput was 608 million cubic feet per day, a 5% increase compared to the second quarter 2012. A combination of 2.5% annual fee escalation and rate redetermination effective January 1, 2013, contributed to a 33% revenue increase in the Mid-Continent.

On July 26, we announced an increase on our quarterly distribution from $0.4675 per common unit to $0.485 per unit. The distribution represents an increase of 15.5% versus the second quarter last year and a 3.7% increase versus the first quarter this year. The distribution will be paid on August 14. As I mentioned earlier, our DCF provided a very strong distribution coverage ratio of 1.56x.

The balance sheet is in fantastic shape. As of the end of the second quarter, leverage on a year-to-date annualized basis was 3.6X debt to EBITDA. During the second quarter, we amended our revolving credit facility, extending the maturity date to May 2018 and increasing the aggregate commitment from $1 billion to $1.75 billion. The increased size of the facility gives us greater liquidity and allows us to continue to be optimistic as we fund our capital program in 2013 and beyond. The partnership had over $1.5 billion of liquidity at June 30.

In June, we filed an S-3 with the SEC that we intend to use to launch in at-the-market, or ATM, program. The SEC declared the S-3 effective last week. We believe this program could be an effective tool for opportunistically funding a portion of our growth capital requirements.

Finally, at our Investor and Analyst Meeting in May, we extended our guidance through 2015. We anticipate growth CapEx of $800 million to $900 million in 2015 and EBITDA of $1.2 billion to $1.3 billion in 2015. We did not change our 2013 and 2014 guidance that had been previously issued. All of our guidance information is included in our investor presentation located on our website.

Operator, we would like to open the call for any questions. Thank you.

Question-and-Answer Session

Operator

[Operator Instructions] We'll go to Darren Horowitz with Raymond James.

Darren Horowitz - Raymond James & Associates, Inc., Research Division

I've got a couple of questions for you about the growth progression in the back half of this year and more specifically, into 2014. Mike, you've talked about more Utica process and more gathering in the liquids-rich areas, certainly around the Eagle Ford in the Mid-Con, but I'm wondering more specifically how you think about the liquids opportunities in the Niobrara Wattenberg, if you will, the greater DJ basin, and your ability to extend downstream either on the NGL side or possibly even start dealing with that growth in condensate supply.

J. Michael Stice

Right. Thanks, Darren. Well, you can say, we're in the very early stages of the development of the Niobrara, but the producer excitement out there just continues to be outstanding. We partnered, as you heard about, with RKI, and are building 120 million a day processing facility, which will not come on line this year, it will be in 2014. So as you answer your question about the back half of 2013, there'll be nothing material other than increasing capital spend. We are ramping up that processing. Your point is a valid one. Today, the producer is interested in rail offloading. Both RKI and our friends at Chesapeake are exploring other options because, as you know, there are some pipeline activity up there that could potentially give some additional liquid offtake options. We would be in line with other midstream companies, frankly, to participate in getting that connectivity to some of that pipeline infrastructure. As you know, we've got Williams up there at Echo Springs. You've got ONEOK coming up through the Bakken. There's a number of older assets out there, ConocoPhillips has a pipeline asset that's being considered. But generally speaking, the initial plan is a rail solution. And then I think the pipeline alternatives as the production increases will develop and evolve potentially, 2015, 2016 time period.

Darren Horowitz - Raymond James & Associates, Inc., Research Division

Mike, when you guys are talking to producers and recognizing it's very, very early on in the thought process. But do you have any idea what the scale scope or possible CapEx of the solution would have to be? Just because it seems there's so much production coming, and it's almost as if the magnitude or slope of that production increase is going to far outpace the ability to add incremental capital and build out the infrastructure to keep pace. So I'm just wondering how you scale your way into that?

J. Michael Stice

Yes. I don't have a number for you. But I will tell you that this is turning out to be much bigger than just the Niobrara. There's -- in continued enthusiasm in the Frontier, in the Parkman. As they go north, there were some disappointments by the producers to the south on the Colorado border in the DJ basin. But as they continue to go North and explore the prospectivity, especially in our Jackalope gas gathering system and our Sage Creek AMI, they're seeing lots of upside. And then there's further producers, other than Chesapeake and RKI, that are exploiting the Parkman in the north, but still in the Converse County area. I think your thesis is correct. The amount of production, the amount of rich, processable gas, is going to overwhelm anything you and I currently have in place to remove liquids from that region, which means that there's going to be further projects developed. And yet I think the producers are being prudent to consider the rail options first, defined the size of the price, and then develop the long term pipeline solution fit for purpose based on that size. Honestly, it's just too early for me to describe for you what I think that capital commitment is going to be or what I think that actual solution is going to be. I wish I had that answer, but I really don't at this stage. And I don't think anybody does, even though a lot of us are very interested in providing that solution for the producers.

Operator

And we'll take our next question from TJ Schultz with RBC Capital Markets.

TJ Schultz - RBC Capital Markets, LLC, Research Division

I guess you could just expand a little bit on the opportunities within your footprint for some of the bolt-on acquisitions, I guess if you will, that you talked about. Specifically, what type of assets are the likely targets? Is this primarily E&P operators looking to monetize and redeploy capital and maybe when you would expect to facilitate some of this consolidation?

J. Michael Stice

Yes, TJ, first, good morning. And if you go around our existing basins, as you know, we're in every unconventional play in North America with the exception of the Bakken. So the opportunities exist virtually everywhere. But to add a little additional color, the concentration that we see, there's some significant opportunities, as you said, by producer gatherers in the Marcellus. There's some opportunities in the Haynesville. I won't name these, these are some ongoing discussions. I think that there's some opportunities for some consolidation in the Mid-Continent, what we call the Mid-Continent, which is broadly -- includes the Permian midline [ph], Granite Wash. There's even some opportunities in the Eagle Ford, and I know it's early stages for that. But there's a number of assets trading early in the life, which could create some upside there. But generally speaking, I think you can obviously -- to do a deal, you got to have a motivated seller and a good synergistic story for the buyer. And I'm actually seeing the dry gas part of that portfolio. These things that I would be more interested in, so the Marcellus and the Haynesville. Some of the stuff in the liquid-rich play, it's pretty rich, if you know what I mean by that rich price wise. And so you've got to be very careful about the kinds of deals that you pursue and be very disciplined about making sure that you buy it right as well as can execute on the synergies that you're projecting.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Great, thanks Mike. And I guess just one more switching gears a little bit. In the Utica, at the Analyst Day, you discussed exploring the ability to move into some of the condensate gathering and stabilization. Just wondering if you had any update there on any traction that you're getting or how you view that condensate market.

J. Michael Stice

We're very excited about the condensate market. As you know, the NGO facility that's being built there at the Harrison hub is truly world class. And we have installed an enormous amount of rail infrastructure. We've installed an enormous amount of storage. And the ability to stabilize what you and I would call the natural gasoline part of the stream. But if the condensate comes in to that facility, we're going to be able to do some additional things with the condensate that comes from the wellhead. Producers have not defined a condensate pipeline system as yet, as one of their need. They continue to consider trucking as their primary option. My view of that, over time, is it will become economic to have central delivery points, not wellhead-by-wellhead gathering, but central delivery points where you will minimize the cost of trucking and optimize the netback. We're not at that stage yet. We obviously have a tremendous competitive advantage to provide that service. We can put that pipeline in the very same ditch that we put all our gas gathering pipelines for those facilities. So we see that as upside, not currently projected. So we're excited about being able to do that. And our partners are equally excited, because we've got the facility that can do the stabilization already built.

Operator

And we'll take our next question from Sharon Lui with Wells Fargo.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

A question about the OpEx expenses. So the expense rate remained pretty flat sequentially, even with the ramp in volumes. Just wondering if you think there's additional opportunities to drive that OpEx cost further lower?

J. Michael Stice

Well, Sharon, I think you have to really look at it basin by basin. We've been really pleased with the progress that we made in the Haynesville in terms of controlling cost there since we really got not a volume growth story there. And in the process, Barnett is very much the same way. But you will see a ramp-up in operating cost. I guess, here's the challenge, right? You will see a ramp-up in operating cost for Marcellus, except it's an equity investment. So you don't really see the operating cost ramp-up that we're incurring as those volumes increase. So our SEC accounting kind of clouds the picture a little bit. But I can tell you, basin by basin, we're very pleased with our cost progress in the dry basins. And yes, our operating costs in Eagle Ford will continue to grow as the volumes grow. And that's really kind of the story in the top side of the financials. Dave, you have anything else?

David C. Shiels

No, I think that's exactly right. We're having tremendous success in the Barnett and the Haynesville in terms of managing costs. Those are consolidated, so you see that, that comes through the P&L. Marcellus is a tremendous growth area that's accounted for differently. You're not going to have visibility to that. So you don't see the growth in OpEx there. But I think -- so Bob is exactly right. Operationally, our focus is on the dry gas areas and controlling the cost, and we're doing a great job at that.

J. Michael Stice

I'd probably add 2 points. One would be sharing the brag on Bob a little bit. One of the things that I think he and his operating team have done extremely well is they've redeployed their people resources from the areas where the activity has reduced. So as an example, he's taken a good contingent of his Barnett talent, which was fair to delivering on the growth when the Barnett was growing, and he redeployed into the Marcellus. And that -- used that in such a way that the cost was not a burden. They were part of the growth story. And so I thought that was an incredibly positive thing that he was doing. And then I'll give further credit to Dave and the way we're managing G&A overhead and watching carefully what we're intending to do here in headquarters. The transition from Chesapeake has delivered some, what I consider to be pleasant surprises as we've been able to rebuild the infrastructure. And as a result, we're not going to see the same G&A burden that we have seen previously.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay, thank you. That's very helpful. And I guess also for the UEO system, what is the, I guess, anticipated volume at startup? And how do you forecast, I guess, the ramp in volumes throughout the year?

J. Michael Stice

So you're referring to Utica, right?

Sharon Lui - Wells Fargo Securities, LLC, Research Division

I am.

J. Michael Stice

So as you've heard in our comments and probably read in UEOM's press release on Monday, the first train started up in July. We didn't really count on that happening quite so early. There were lots of peer companies that took much longer to kind of get to this stage. I'm really proud, M3 is our operator, who ultimately delivered that on-time schedule. The way to think about that, Sharon, is they have a 200 million a day plant, basically coming off on every 3 months. And so, you got one in July. You got one 3 months later, the next one 3 months later, et cetera, until we get to roughly 800 million a day, which is the Phase 1, 2, 3 and 4 commitments. From our perspective, we had to bet that kind of UEOM's view, so they're expecting the second train to come on between now and the end of the year. These are very complex facilities, and they have a tendency to slip. And so -- but if you factor in 3 to 6 months for each one of those trains, that would be how I'd forecast.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay. And in terms of those facilities being filled, what can we anticipate from the utilization?

J. Michael Stice

100% utilization. I mean, my view is they'll ramp up. And like today, we started the plant with around 100 million a day. But the producers are sitting on the gas. So it's just a matter of the timing it takes to bring the well connects and the infrastructure in place to bring it across . It will be a very short period of time that these facilities will be underutilized until we get everything to them. The producers in the Utica are seeing tremendous success. And so, the opportunity in the number of WOPL, either way I would refer to it as if the gas is behind pipe. And the only challenge we're going to have is the challenge of timing of when does compression come on, when is the gathering connecting, when does the processing come on? And so there's going to be some ebb and flow, but we'll get to 100% utilization very quickly.

Operator

[Operator Instructions] We'll take our next question from Paul Jacob with Credit Suisse.

Paul Jacob

So the first question is can you just provide a sense in terms of where you are on your well connections in Niobrara? And kind of how you see that landscape developing over the coming months, particularly, as the new party takes up the other 50% interest in that project.

J. Michael Stice

Well, Paul, here's the way I put it in perspective. We've got something like 30 or so wells waiting on pipeline, about 10 rigs running in the area. But you really need to be thinking about Niobrara from a profitability perspective. There's a 2015 growth story for us. This year, it's been all about the Eagle Ford and continued Marcellus. Next year, it's the Utica as it comes on. But Niobrara will make an impact in our financials in 2015. Now, we're building a processing facility there, and when that facility gets built, we expect additional rigs. But right now, the producers are essentially just building an inventory of wells and delineating the field. And we're building out that infrastructure, but it will be mid to late next year before we have significant volumes beginning to flow.

Paul Jacob

Okay, that's helpful. And then just turning back to TJ's question about your M&A activity. What's your appetite for dry gas assets with gas prices turning a bit higher right now? I mean, would you look at something in the Haynesville on the assumption that maybe you could get a little bit cheaper than a wet gas asset right now?

J. Michael Stice

You bet. From my standpoint, any A&D opportunity or acquisition opportunity has to consider the full value proposition. And part of that value proposition is being able to buy it right. And so some of the dry gas assets, the pipe expectations aren't as high as some of the more active liquid-rich areas, and so that's a plus. But your point is still a valid one, it's a negative isn't it, if you think it's going to be a while before the development. So you got to be very disciplined about how you forecast the rigs coming back and making sure that the kind of contract you put in place allows you to manage any risks that come with an acquisition in the dry gas basin. But the short answer to your question is I like dry gas. And in the medium term, I expect -- I'm bullish on gas prices; on the short term, I'm bearish. So you have to put that into consideration when you consider an acquisition opportunity in these currently inactive dry gas state.

Paul Jacob

Okay. And then turning to the Marcellus, in terms of the volumes, it looks like obviously, they've been outperforming your expectations over the last couple of quarters. Is that sustainable in your opinion?

J. Michael Stice

Well, keep in mind that we are drawing down a large inventory. And so that inventory, as we catch up, isn't going to repeat itself. We're going to be able to maintain pace, if you will, with our producer customers. However, there is a number -- I mean the Marcellus is a huge basin. I can't describe it in any bigger terms. I mean when you think about it, 2 counties of Pennsylvania are producing 2 bcf a day. I mean that's an enormous play. And the Marcellus, as you know, goes from Northern Pennsylvania up in the New York and all the way to the West Virginia. So the producers have just begun to tap this enormous resource. So -- and we've got a large AMI and with a lot of acreage dedication well beyond these 2 counties. And so, I'm really looking forward to seeing what's next from an upstream standpoint here. But I mean every time we turn around, the producers are uncovering another success story in the Marcellus.

Paul Jacob

Okay and then last question for me is can you just remind us where your current leverage is at Chesapeake volumes and where you are in terms of your strategy to reduce that to 50% by 2015?

J. Michael Stice

So we're trying to get to 50%. We were, I think, 77% on our the last call, we're at 75% now. We haven't factored in the recent deal that EXCO did in the Haynesville, where they will become shipper. Unfortunately, the deal that EXCO did in the Eagle Ford, Chesapeake will still be the shipper. So that, that deal didn't really give us any uplift on the diversification. So we're currently at 75% exposure. We are obviously pursuing the strategies that I described in my opening remarks. It's a little slow going. There's a couple of things that we have on the horizon that I feel confident that we'll get to the 50% by 2015, but it's going to come lumpy in transactions, like we described. So I would say to you that the progress to date has been minimal. We've taken it from -- we actually went the other direction when we did the CMO deal at the end of the year. But we got it back down to 75%, which is where we were before that deal. And then we'll ultimately need to see some additional transactions by Chesapeake, some additional bolt ons by ourselves. And it's the lumpiness of those transactions that are going to give us the 50%. The -- we are doing -- we have built out an organization inside of Bob Purgason's shop that's knocking on doors and basically, playing the gas supply role, producer by producer. And we're getting some traction there, but the volumes are small, and it moves the needle very slowly.

Operator

And we'll take our next question from James Jampel with Hite.

James Jampel

With the very high coverage you're running and the institution of the ATM, do you think you'll be able to avoid staying out of the -- avoid the equity markets for the remainder of the year?

David C. Shiels

Well, James, this is Dave Shiels. We -- it's all going to depend on CapEx timing. Our short-term leverage targets, which we don't guide to, obviously, in market conditions. So we like the ATM like, I think, everybody else does. And it's just another tool, tool kit to help us manage to specific short-term leverage targets. But clearly, when you look at your financials as you point out, certainly over the long term, our equity requirements are very minimal. So, I can't tell you specifically. It's all going to depend on the factors I just spelled out and the timing of how the buildout transpires.

J. Michael Stice

And James, Dave is answering that question from the context of organic growth and the capital that we have in our current portfolio. Obviously, any deal would influence our need directly.

Operator

And we'll take our next question from Helen Ryoo with Barclays.

Heejung Ryoo - Barclays Capital, Research Division

And just a follow-up from the previous question. So on Utica, the UEOM joint venture, did I understand you correctly when you said 3 to 6 months would be the ramp-up period for each plant that comes online? And once they -- after the 3 to 6 month period, that these plants are expected to run close to 100% utilization?

J. Michael Stice

Correct.

Heejung Ryoo - Barclays Capital, Research Division

Okay, great. And then could you just talk about the downstream side of the infrastructure? Where the products, where the products are going? And also on the ethane side, I always think you're not covering ethane, but what are you doing with -- how are you thinking about the ethane outlet going forward?

J. Michael Stice

Just to clarify, we own no commodity and have no commodity price risk, but we have none of the NGO barrels. We simply provide a service to our upstream customers. But obviously, the -- we provide the physical asset solution that takes those NGL barrels away. So at each of these facilities that we're building, 2 locations, one in Leesville, one in Kensington, where we have 600 million a day processing at Kensington, 200 million a day planned at Leesville, a total of 800 million a day. And the NGL byproduct of those 2 plants is what we refer to as the Y grade. Y grade is a mixed stream of ethane, propane, butane and condensate. That mixed stream goes to Harrison hub, which is a large fractionator. Helen, that's a facility that you might want to go and see, it's pretty impressive. That facility turns this mixed stream of NGL into its purity component. And we specifically are today designed to create purity ethane, purity propane and mixed butane. So we're not planning to split the isobutane from the normal butane today and then the natural gasoline stream, okay? Now there is some condensate that comes in to the separators at the gas plant that's stabilized, so you could argue there's another liquid stream there. The offtake for each of those products are different. The planned offtake for ethane that the producers have pursued is the ATEX Pipeline that Enterprise is in the process of doing, should be up and running by the end of the year. Propane is planned to be railed, so there's a large rail facility, as is the butane and the natural gasoline. So those are the current offtake solutions for each of those products.

Heejung Ryoo - Barclays Capital, Research Division

Thanks, that's very helpful. And then the other question was the acreage, the Chesapeake asset sales to EXCO. So if I'm understanding you correctly, I guess you're gathering, contracts gets transferred to EXCO and the acreage dedication also transfers with the EXCO deal. So now you're getting acreage dedication from EXCO, but Chesapeake is the shipper on your gathering line. Is that sort of -- am I understanding that correctly?

J. Michael Stice

That's true for the Eagle Ford. EXCO will be the shipper for the Haynesville. So there's actually 2 different transactions. There was a $680 million acquisition in the Eagle Ford and a $320 million acquisition in the Haynesville. In the Haynesville, we have a fixed-fee relationship. And in that situation, EXCO's going to take custody of the gas at the wellhead, ship and give us some diversification of supply. Granted, EXCO'S credit rating is actually lower than Chesapeake's. So that doesn't come with an increase in credit rating exposure. But it does come with diversification. And what we like about that deal is EXCO is basically one of the masters of the Haynesville. And they plan to bring a lot more rigs back. And we love the fact that we were going to have a very exciting and active producer with a large drilling budget they can commit to the Haynesville. So we're really looking forward to EXCO'S development of the Haynesville and their expertise. On the Eagle Ford, the situation is a little different. That's a cost of service mechanism, and that mechanism is complicated by the fact that they sold just part of the acreage footprint, not all. And so Chesapeake, effectively, is sleeving [ph] that deal. Chesapeake is the shipper and then openly, will be our person that we'll be looking to for both credit exposure as well as the fee calculation. And then they've done a deal with EXCO directly to ultimately be that shipper for EXCO. So EXCO will be doing the drilling and the production at the wellhead, and then Chesapeake will be taking it over and then shipping across our pipeline and will be ultimately our customer and our counter-party.

Operator

At this time, there are no further questions. I would like to turn the conference back over to Mike Stice for any additional or closing remarks.

J. Michael Stice

Well, thanks again for everybody's participation in our second quarter earnings call. We're very excited about the results. We hope you can see the progress that we're making in virtually in all areas. As I mentioned in my opening remarks, we're particularly excited about the record-breaking volumes that we're seeing in the Marcellus Shale and the performance that we're realizing in the capital growth areas of the liquid-rich areas of Utica and the Eagle Ford and soon-to-be the Niobrara. We're thrilled to be doing all of this with the kind of capital discipline that produces the results that -- and the earnings that we can proudly report in this quarter. And we appreciate everybody's time. And look forward to another quarter next -- another positive quarter next quarter. Thank you very much.

Operator

This concludes ACMP's 2Q '13 Earnings Conference Call. Thank you.

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Source: Access Midstream Partners, L.P. Management Discusses Q2 2013 Results - Earnings Call Transcript
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