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Executives

Joshua Hallenbeck

Frank M. Semple - Chairman of MarkWest Energy GP LLC, Chief Executive Officer of MarkWest Energy GP LLC, President of MarkWest Energy GP LLC, Chief Executive Officer of MarkWest Hydrocarbon and President of MarkWest Hydrocarbon

Randy S. Nickerson - Chief Commercial Officer of Markwest Energy Gp L.L.C. and Senior Vice President of Markwest Energy Gp L L C

John C. Mollenkopf - Chief Operations Officer of MarkWest Energy GP LLC and Senior Vice President of Southwest Business Unit of Markwest Energy GP LLC

Nancy K. Buese - Chief Financial Officer of Markwest Energy GP LLC and Senior Vice President of Markwest Energy GP LLC

Analysts

Cathleen King - BofA Merrill Lynch, Research Division

TJ Schultz - RBC Capital Markets, LLC, Research Division

Louis Shamie

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

Heejung Ryoo - Barclays Capital, Research Division

John Edwards - Crédit Suisse AG, Research Division

MarkWest Energy Partners, L.P. (MWE) Q2 2012 Earnings Call August 3, 2012 12:00 PM ET

Operator

Welcome, and thank you for standing by for our Second Quarterly Conference Call from MarkWest Energy Partners. [Operator Instructions] Today's conference is being recorded. If anyone has any objections, you may disconnect at this time. Now I'd like to go ahead and turn today's call over to Josh Hallenbeck. Sir, you may begin.

Joshua Hallenbeck

Thank you, Julie, and welcome to those that have joined us on the conference call. Our comments today will include forward-looking statements, which involve risks and uncertainties and are not guarantees of future performance. Actual results could vary significantly from those expressed or implied in such statements.

Although we believe that the expectations expressed today are reasonable, we can give no assurance that the expectations will prove to be correct. And we caution you that projected performance or distributions may not be achieved.

Factors that could cause actual results to differ materially from their expectations are included in the periodic reports we file with the SEC. We encourage you to carefully review and consider the cautionary statements and other disclosures made in those filings, particularly those under the heading, Risk Factors.

With that, I will turn the call over to Frank Semple, Chairman, President and Chief Executive Officer.

Frank M. Semple

Good morning, and thanks to everyone for joining us on the call today. As indicated in our earnings release, we had another solid quarter. We continue to enjoy strong volume growth and performance from our high-quality Midstream assets despite the challenging natural gas liquids pricing environment.

Our total year-over-year processed volumes have increased 18%, driven largely by our Liberty operations. We continue to focus on our announced organic growth projects including the expansion of our Liberty segment and the completion of the first phase of our Utica projects, which we expect to drive future cash flow and distribution growth for years to come. We continue to maintain a strong balance sheet and remain well positioned to execute on our development plans going forward.

Now during the call today, I'll discuss our financial performance, provide a commercial and operational update, including an update on our Marcellus and Utica growth projects. I'll also discuss the recent press release regarding our new agreement with XTO Energy in the Marcellus and our northeast propane exports.

Due to recent NGL market conditions, I'll take a few minutes to also discuss our view of the supply and demand environment for NGLs and their current pricing. And finally, I'll review our balance sheet and discuss our current 2012 DCF forecast and CapEx guidance. As always, we're going to leave time at the end to respond to your questions.

Now beginning with a high-level overview of our financial performance. Distributable cash flow was $91.2 million during the second quarter, an increase of 10% compared to the second quarter of 2011. Adjusted EBITDA was $130.5 million, and segment operating income was $146.3 million. In July, we announced a second quarter distribution of $0.80 per common unit, an increase of over 14% compared to the second quarter of 2011 while maintaining a distribution coverage ratio of 1.03x.

Now moving to the operational update, we continue to focus on expansion projects in rich gas resource plays, and throughout our discussion today, you'll hear how gas volumes continue to grow in our core areas. So let me begin with our Southwest business unit, which includes Texas and Oklahoma, and contributed 50% of our total segment operating income during the second quarter.

In Western Oklahoma, which includes both our Foss Lake and Granite Wash operations, gathered volumes increased 13% and processed volumes increased almost 40% when compared to the prior-year quarter. Primarily, this was driven by strong performance of our producer customers in the Granite Wash. This increase was supported by the recent expansion of our Arapaho plant in Oklahoma, which is operating near capacity.

In Southeast Oklahoma, gathered volumes remain strong at more than 500 million cubic feet per day. And while gathered volumes were generally flat compared to the first quarter, processed volumes were nearly 120 million cubic feet per day, an 18% increase from the first quarter, and a 9% increase from the second quarter of last year. This significant increase is the result of the recent drilling success of our producer customers including PetroQuest Energy. We expect processed volumes in both Western and Southeast Oklahoma to continue to grow as rich gas wells are brought online and offset the decline of dry gas production in those areas.

In our Carthage system at East Texas, processed volumes increased by 11% compared to the first quarter of this year and 17% compared to the second quarter of last year. Our previously announced 120 million cubic feet per day Carthage expansion is moving forward on budget and ahead of schedule, and we now expect it to come online by the end of this year. This expansion is anchored by new rich gas volumes from the Haynesville Shale, and we expect our processed volumes in East Texas to grow by as much as 20% in 2012, with continued growth in 2013 and beyond.

Our producer customers have continued to be successful in our Southwest operations, and we have been able to attract new customers and grow our volumes despite the low commodity price environment. Our Javelina plant in Corpus Christi, Texas continues to perform well and accounted for 8% of our total segment operating income during the second quarter. The plant continues to operate near capacity, with processed volumes remaining relatively flat when compared to last quarter and the second quarter of 2011.

Our addition of a fourth inlet compressor in the third quarter of this year at Javelina will allow us to provide even better reliability to our refinery customers, and allows us to increase long-term fee-based revenue. We expect Javelina to remain a solid performing asset, providing a steady source of operating income.

Now let's move to our Northeast segment, which serves the Huron shale and the Southern Appalachian Basin. Processed volumes were up 3% when compared to the second quarter of 2011 and 2% when compared to last quarter. Excluding Marcellus volumes, which are now being fractionated at our Houston complex, our fractionated volumes increased slightly from the last quarter and remain flat when compared to the second quarter of 2011.

Our Langley processing expansion is in Southeast Kentucky and it's on schedule, and it's expected to come online during the fourth quarter of this year. We expect processed volumes in the Northeast segment to remain relatively flat during the remainder of 2012.

Now moving to our Liberty segment, which includes our Marcellus operations in Pennsylvania and West Virginia. Total volumes increased by almost 50% compared to the second quarter of 2011 and over 10% compared to last quarter. More importantly, our Liberty segment now contributes 26% of total company operating income and is largely fee-based.

In Pennsylvania, our primary focus continues to be the expansion of our gathering system in Washington County to support a range of resources, highly successful development program in the rich gas area, the Marcellus Shale. As a result, gas volumes will grow significantly as new wells are brought online during the second half of this year. And by year end, we expect our total Marcellus volumes to increase to nearly 1 billion cubic feet per day, with the connection of new wells in Southwest Pennsylvania and the start of our Mobley and Sherwood plants in Northern West Virginia.

This week, we announced a significant long-term fee-based agreement with XTO Energy in Northwest Pennsylvania to transport fractionate and market NGL from XTO's 125 million cubic feet per day processing plant in Butler County, which is expected to be completed by the end of 2012. We will initially transport the liquids by trucks to our Houston fractionation complex.

As we previously announced, we are extending our Marcellus NGL gathering pipeline north from our Houston complex to our Keystone facilities in Butler County. This agreement includes the further extension of the NGL gathering pipeline from our Keystone facilities to the XTO processing plant. And that pipeline, which is expected to be completed by the end of 2013, will complete that connection.

When we announced the Keystone acquisition, we've discussed the significant opportunity in Northwest Pennsylvania for both the rich Marcellus and Utica shales. The expansion of our NGL gathering system into Northwest Pennsylvania will provide these rich shale plays with critical access to our significant fractionation and marketing infrastructure and all of the announced northeast ethane projects. And we are delighted to add XTO to our list of producer customers in the Marcellus.

Today, we are in various phases of installing 10 new cryogenic processing plants in the Marcellus, in addition to the 7 processing facilities that we currently operate. In 2014, when all of our announced processing facilities are completed, our total processing capacity in the Marcellus will be more than 2.5 billion cubic feet per day. All of these new processing plants are supported by long-term contracts, the large majority of which are fee-based, with very active producer customers. And we're very proud of our customer relationships. Our customer list includes Range, Antero, Chesapeake, Chevron, CONSOL, EQT, Magnum Hunter, Noble, Rex, Stone and Statoil.

In addition to the significant gathering and processing expansions, we continue to move forward with the construction of 3 de-ethanization facilities at our Majorsville and Houston complexes, with combined capacity to produce 115,000 barrels per day of purity ethane. We are also constructing a 40-mile pipeline to transport purity ethane recovered at our Majorsville, Mobley, Sherwood plants to our Houston complex and a 44-mile purity ethane pipeline that will become part of the Mariner West system when it's completed.

In addition, we are nearing completion of a large 200-car rail facility at our Houston complex, which is another important milestone in our operating capabilities.

Industry analysts are now predicting that the Marcellus Shale will be the largest producing gas field in North America within the next 2 years, and MarkWest is constructing a significant majority of processing, fractionation at NGL facilities in this enormously perspective field. We have discussed for a number of years the need for these rich gas resources in the Marcellus Shale and now the Utica Shale to access worldscale processing and fractionation facilities and fully integrated NGL marketing solutions. Our processing facilities, NGL gathering system and the Houston and future Harrison fractionator will provide this critical infrastructure and allow the Northeast shales to reach their full potential.

Now let's move over to the Utica, where we have partnered with the Energy & Minerals Group to develop Midstream solutions for our producers. In June, we finalized agreements with Gulfport Energy Corporation to provide fee-based gathering processing fractionation and marketing services in the liquids-rich window of the Utica Shale. Gulfport is one of the most active drillers in the rich gas area of the Southern Utica, and we're working diligently to connect their initial wells to the first phase of our large gas gathering system in Harrison, Belmont, Guernsey and Noble counties. This gathering system will deliver liquids-rich Utica gas to our Harrison County processing complex, where we are finalizing construction of an interim 60 million cubic feet per day refrigeration plant.

Also, our 125 million cubic feet per day cryogenic facility is under construction at the Harrison complex, which is scheduled for completion in January 2013. The rich gas window in the Southern Utica appears to be very prospective, and our Harrison County complex is designed to accommodate an additional 200 million cubic feet per day plant, which could be installed as early as the fourth quarter of 2013.

As you can imagine, we are in active discussions with a number of producers that are developing acreage in the area of our new gathering system. Additionally, we are constructing 100,000 barrels per day of ethane and heavier fractionation capacity in Harrison County, which is initially expected to be online in late 2013. This new facility will be connected through an extension of our Marcellus NGL gathering system to our Houston fractionation complex in Pennsylvania and allows us to cost-effectively expand our Marcellus fractionation capacity under long-term contracts while creating world-class Midstream facilities in the heart of the Utica.

The Houston and Harrison County facilities will be the 2 largest fractionation complexes in the Northeast and will provide tremendous operating flexibility and reliability, as well as market access. The Harrison fractionator will be jointly owned by MarkWest Liberty and the Utica joint venture with EMG. And the capital required to build the complex will be shared accordingly.

In addition to our Harrison processing facility, we are developing a second processing complex in Noble County that includes the installation of a 45 million cubic feet per day refrigeration plant in the fourth quarter of this year, followed by a 200 million cubic feet per day cryogenic plant in mid-2013.

In order to provide early cryogenic processing in Noble County, we expect to commit the 2 processing complexes through a large high-pressure gas header by the end of 2013. All of the Noble County NGLs will be transported through an NGL pipeline to the Harrison fractionation complex. And MarkWest has been a leader in marketing NGLs in the Northeast for many years, that we have designed and constructed our fractionation complexes to provide us with multiple marketing options for the NGLs. These marketing options give us the ability to maximize the value of NGLs, which is critical for our producer customers. Over the long term, we also believe that NGL exports to international markets are a key component to maintain the supply and demand balance in the Northeast.

We announced yesterday in our earnings release that in late June, we began exporting propane internationally from Sunoco's Marcus Hook facility near Philadelphia. MarkWest is currently delivering propane, fractionated at our Houston complex to Marcus Hook, where Sunoco is loading the propane onto vessels bound for international markets. We also plan to utilize rail deliveries in the next several months as Sunoco expands its rail and loading capabilities.

In addition, MarkWest is purchasing propane from Sunoco that is produced at their Marcus Hook and Philadelphia refining facilities, and we are marketing the combined string of propane to international markets. We believe that the export of Northeast propane is critical to ensuring that our producer customers continue to achieve premium pricing. This project underscores the benefit and importance of the plant at Mariner East project and the expanded marketing and transportation capabilities that it will provide to MarkWest and our customers.

Before moving to our financials, I'd like to spend a few minutes discussing our NGL pricing forecast. As we all know, ethane and propane in particular, has faced significant headwinds during the first half of 2012. For ethane, the large number of steam cracker turnarounds during the first half of this year reduced demand by approximately 250,000 barrels per day and contributed to a steep decline in prices. As the steam crackers have come back online, ethane demand appears to be recovering. Ethane prices at Mont Belvieu have increased by 25% during the last month.

Low propane prices have also placed pressure on ethane as some of the crackers switched between propane and ethane as a feedstock. Low ethane prices have given U.S. ethane crackers an enormous advantage over foreign crackers that utilize naphtha as a feedstock. And based on recent announcements, it appears that as many as 5 world-class ethane crackers could be completed in the U.S. Gulf Coast beginning in 2016. The Marcellus and Utica shales will be critical sources of supply for this new cracker.

For propane, the historically warm winter is the primary cause of the significant price decline during the first half of 2012. This has also caused storage volumes to reach a 5-year high. Now the good news is that there are a number of projects under development, and significant propane solutions should arrive very soon.

First and foremost, the announced Gulf Coast export expansion projects will come online in late 2012 and 2013 and will increase export capacity by as much as 175,000 barrels per day. Over the long term, we believe significant new demand will be added by a number of previously announced propane dehydrogenation plants that are waiting to be built. These combined projects, coupled with a more normal winter, should help prices increase beginning in late 2012.

So now, turning to our financials. The balance sheet continues to be a key area of focus for us given the slate of our current projects and growth opportunities. In May, we completed an equity offering of 8 million units and the proceeds of $427 million were used to partially fund our previously announced acquisition of Keystone Midstream Services. In June, we increased the borrowing capacity of our revolving credit facility by $300 million to $1.2 billion total and extended its maturity to September 2017. Today, we have available liquidity of nearly $1 billion.

As of June 30, our debt-to-total-capital was 46%, our leverage ratio was 3.3x and our interest coverage ratio was a healthy 5.6x. Given our distribution objectives and the variability of the foreign market, we continue to consistently hedge our future commodity positions. For 2012, we are hedged at approximately 65%. And for 2013 and '14, we are hedged at approximately 60% and 15%, respectively. Our hedged transactions have been executed utilizing crude oil swaps and collars and direct product swaps.

Our crude oil swaps for the next 3 years average approximately $91 per barrel. Our crude oil collars have an average floor of $85 and an average ceiling of $105 over the next 3 years. Our 2013 and 2014 NGL swaps have an average price of approximately $1.50 per gallon.

Our hedging strategy incorporates the use of crude oil proxy hedges and direct product hedges. We continue to evaluate a larger percentage of our commodity exposure utilizing direct product hedges, and we've already entered into direct product hedges for 2013 and '14. In addition this quarter, we have the opportunity to monetize a portion of our 2014 crude hedges, and we fully expect to opportunistically increase our 2014 hedge positions using direct products and possibly, crude oil. Currently, about 50% of our 2014 hedges are completed using direct product hedges.

In addition to our active hedging program, we continue to make progress on our goal of increasing our fee-based margin. Currently, 44% of our net operating margin is fee-based. Almost all of our growth projects are supported by fee-based contracts. And as these projects come online, we expect fee-based margin to increase to 50% by the end of 2012 and 60% by the end of 2014.

Before concluding, I want to discuss our current guidance for 2012. We estimate the DCF will be in the range of $400 million to $440 million. Now the low end of our guidance assumes that commodity prices remain at their current low levels through the end of this year. And the midpoint assumes prices, will gradually recover through the end of the year. At the midpoint of our guidance, the coverage ratio will be 1.2x for the full year, which gives us room for continuing the growth of our distributions and delivering strong total returns for our unitholders.

At the low end of our DCF range, the coverage ratio will be 1.13x at our current units outstanding and distribution. And we included as always in our press release, the usual commodity price sensitivity table that shows projected 2012 DCF based on a range of crude and natural gas prices.

Our capital forecast remains unchanged in a range of $1.1 billion to $1.5 billion, and this is to fund our high-quality growth projects primarily, the vast majority of which are fully contracted and announced. As a reminder, this range does not include the Keystone acquisition and is also net of the capital requirements for the Utica JV that will initially be funded by EMG up to the first $500 million.

So in summary, 2012 is on track to be another solid year with recently announced agreements and continued organic growth. While the current NGL pricing environment remains challenging, our guidance for 2012 will provide strong year-over-year growth. With our diverse set of assets in growing rich gas resource plays, we continue to be very well positioned to develop efficient and effective Midstream solutions for our producer customers. These growth opportunities, coupled with the strength of our balance sheet and our long-term focus on growth of fee-based margins, will support our primary objective of providing superior and sustainable total returns for our unitholders.

So with that, Julie, let's go ahead and open up the call to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Gabe Moreen and Cathleen King.

Cathleen King - BofA Merrill Lynch, Research Division

It's Bank of America Merrill Lynch. Yes, this is Cathleen in place of Gabe. First question, just around the propane exports that you mentioned, Frank. So are you guys seeing increased demand for project Mariner East now given the higher propane inventories in the Northeast and I think the fact that propane prices are trading at somewhat of a discount to Mont Belvieu? So the first question, and also I'm curious for more detail on the customers that you're exporting that propane to and which countries the propane is going to as well?

Frank M. Semple

Cathleen, let me start with my answer, and then I'll ask Randy Nickerson to fill in the gaps that I might leave. But in terms of your first question, as I mentioned in my formal comments, the development of the rich gas shales in the Northeast and all of the processing capacity has come online, and will need to continue to come online over the next several years, is obviously increasing the production of propane in the Northeast. And we, like you, know, have been analyzing the supply-demand balance in the Northeast for all of the natural gas liquids, the purity products that are going to be produced up there. And it's pretty clear to us that we need to continue to develop the projects that we've announced. The Mariner East project is really critical to complement the Mariner West project and the announced enterprise, ATEX Pipeline, down to the Gulf Coast for ethane. For propane, we believe that, as I've said publicly, that exporting propane out of the Northeast will be a critical part of the equation. It needs to happen. Mariner East, as we've announced publicly, is -- our relationship with Sunoco has allowed us to evaluate the ability to actually move an EP, an ethane-propane mix, over to Marcus Hook potentially as a part of that project. And we think that by getting propane and ethane over to the Philadelphia area and supporting exports, both those purity products will help maintain a strong pricing environment for propane and ethane out of the Northeast. So that's really critical. And as far as, let me just answer, Randy, the -- that make a short answer to the last question, which is who are we, as far as the export terminaling project that I mentioned in my formal comments, our marketing team has done a great job of putting together this project over the last 6 months or so. And we are real pleased with the ability, working with Sunoco to set up the logistics. Part of that effort has been the marketing effort to find international customers for propane. But right now, we're not going to be talking about the specific customers. The customer is obviously buying the propane from us. It's a large multinational LPG company, and we are continuing to evaluate other opportunities for international sales of propane. So Randy, should you want to add anything to that?

Randy S. Nickerson

No, I think that's a great summarization.

Cathleen King - BofA Merrill Lynch, Research Division

Okay. And just a follow-up on that. Are you guys seeing any constraints on the ships when you're looking to do the propane exports?

Frank M. Semple

Cathleen, by constraints, are you talking about physically how much can be loaded onto the transports?

Cathleen King - BofA Merrill Lynch, Research Division

Yes. We just heard initially that some of the delays on project Mariner East might have been related to the ability to get ships in adequate amount for the demand. I'm just wondering if that was an issue in your ability to export the propane?

Frank M. Semple

Well, 2 different issues. And I'm slow, Randy, go ahead and answer that. 2 different issues relative to the Mariner East ship reflagging issue than this recent transportation project for the propane. But Randy, you want to go ahead and answer that?

Randy S. Nickerson

Yes. Probably, the one point that's worth noting is, in addition to the fact that, of course, Mariner East is a Sunoco Logistics project, we've, like Mariner West, sort of worked with them to sort of develop, make sure that our producer customers have access to that, which is really our job. But Mariner East is a Sunoco project and so we want to be very careful anytime, sort of we're describing what they're doing. However, having said that, one of the key parts from our understanding of Mariner East is that the propane exports would be able to be into semi-refrigerated or fully refrigerated vessels. The fact of the matter is that going to international markets, when you have semi-refrigerated or fully refrigerated projects like the Gulf Coast has, you have a lot larger number of ships in markets that you can deliver to. When you're doing what we're doing right now, sort of delivering pressurized into ships or cooling it as you go into ships, it's much more challenging to find a wide array of vessels. So this is a short-term operation. It shows that exports in the Northeast are valuable. They're critical. They're doable. It sort of proves out the concept in a great way. But certainly long term, if the Mariner East project happens and Sunoco is successful, the marketing options under Mariner East would be much greater than what we are working on right now.

Frank M. Semple

And Cathleen, just again, clarify. The ethane transportation ship issue, that was an issue 6 months ago that we had talked a lot about, which was a critical part of Mariner East ethane transportation, has been -- as we understand, has been solved because of the reflagging of those available vessels.

Cathleen King - BofA Merrill Lynch, Research Division

Got it. And then just one more for me. We heard Range Resources talk on their call about some permitting delays around Southwest Pennsylvania. I'm just wondering if there are impacts to you guys from that commentary?

Frank M. Semple

Well, the Range Resource issue that they mentioned on their call was obviously related to their drilling program, but I think it's important to note that we are, we and Range, in that Washington County wet gas area, had been moving very, very quickly. I mean, you have to look at what has been accomplished over the last 3 or 4 years relative to building out this infrastructure, both on Range's part and on MarkWest's part. So we have been ramping up very, very quickly. And there is no doubt that building facilities in the Northeast, specifically in Pennsylvania, in Ohio, is not Oklahoma, it's a real challenge. So we're pretty proud of what Range has been able to accomplish. We're pretty proud of what we've been able to accomplish. But everyday, there's a new challenge in terms of executing around the processes that are required by the state, including permitting. So yes, I mean, the -- it's a good news, is that there's been a lot of success up there by Range, and we are doing a really good job of staying ahead of them. But you're going to have, every day, every week, every quarter, you're going to have situations where permits are not completed as you'd like them to be completed. But I will tell you that the states have done a pretty good job adapting to the process. And the operators up there, I think, are doing a really good job of meeting the needs and expectations of the state relative to the permitting process. So all in all, I think it's a good news story. We are working really, really hard to stay ahead of Range. And as you heard in my formal comments, the ramp-up has been significant over the last year and it will continue to be significant. So we are getting the permits and we are continuing to execute on our facility buildup.

Operator

The next question comes from TJ Schultz.

TJ Schultz - RBC Capital Markets, LLC, Research Division

RBC Capital. Can you just walk through the thought process for the joint funding of the Harrison fractionator between Liberty and the Utica JV and what the proportionate ownership shares are for each?

Frank M. Semple

Yes, TJ. As we have talked about, that structure, ever since we announced the Utica joint venture with EMG, and again, I will -- Randy, I will give a -- just try to be -- make a short answer, and then if I leave out some of the key points going in here. But see, you have to understand, TJ, that the -- this, I'll call it the disproportionate or different ownership percentage for the Harrison fractionator from the Utica JV, is because of the fact that the initial capacity at the Harrison County fractionator will be supported by liquids that are produced from the Marcellus. And that's really a key point because, and I -- we continue to make that point publicly, is that we were going to expand the Houston fractionator anyway just because of the ramp-up in production in the Marcellus from our Liberty assets. And it just made much more sense as we looked at the Utica development plan to build that fractionator over in that expansion, if you will, over in the heart of the Utica. So obviously, we've been working hard over the last year trying to determine really the optimum size and now, the location in the Utica. But the logic is, as you asked, I think is based around the fact that the -- that fractionator, the initial phase of that fractionator, is being supported by Liberty. So that's why the percentages of ownership is different than the 60-40 going to 60-30 for the Liberty -- or excuse me, Utica JV. Does that...

TJ Schultz - RBC Capital Markets, LLC, Research Division

No, I think that's -- I understand. I appreciate it. I guess just moving onto Rex and the Utica. I know you mentioned the potential gathering, processing and frac agreements, proportions of their acreage. Does this just encompass all of their Carroll County acreage?

Frank M. Semple

Well, first of all, the -- just to clarify for the rest of the listeners, you're referring to the relationship that we have discussed with Rex that has been -- that was initially announced as a part of the Keystone acquisition. So essentially, what we had created as a part of that Keystone acquisition was an opportunity for us and Rex and their partner, Sumitomo, to sit down and evaluate opportunities over in the Utica. And so we have been working on the agreements that could support that kind of opportunity. So and I don't -- Randy, you'll have to -- I mean, is the -- what more can we say about the location of those -- of that acreage?

Randy S. Nickerson

TJ, I apologize. Actually, right now, we probably shouldn't say any more about location. You've covered exactly what it was. We built the framework. We're following up, doing just what we said we can do and delighted to work with Rex certainly in Pennsylvania and hopefully in Ohio.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay, I understand. I know they're waiting on their first well there. I'm just trying to understand what the decision process is for you all to maybe expand there. Is it a function of well results from Rex or is it something where you need other acreage commitments?

Randy S. Nickerson

Well, I guess, I'll start out this one. I think the answer to that, the best answer to that, I think if you can look over and think about what happened in the Marcellus, it's a good example. We started out in the Marcellus really with just Range, one customer and one processing complex at Houston. And now, we're sitting there with a wide number of customers and 5 large processing complex. Sometimes, it makes sense for us to expand at the existing complex. Sometimes, it's better for the producer customer, for a wide number of reasons, to expand and build another processing complex, i.e. Harrison and Noble, 2 different complexes. Producer customers all have very different needs. As long as they're all connected by NGLs going -- as long as they're all connected by the efficient NGL gathering and fractionation, we're in great shape and can provide that tremendous flexibility and reliability to the customers. So we're fortunate to be able to have the same sort of situation in the Utica. The site where we're building the first plant, we were talking about that just yesterday. And the site that we are building the cryo plant in Harrison County is a big site. We can put many, many plants at that size -- at that site. We can easily expand it. That's why the Harrison 2 complex, we could have that up and running potentially by as soon as end of '13. We could put in another 200 million-a-day plant. We're getting awfully -- John's group is getting awfully good at putting in 200 million-a-day plants. And that would not be a huge challenge for us to do. The fact that we're putting in refrigeration first up there is $65 million and another 125 cryo right behind we'll pull the refrigeration plant out as soon as it's not needed. Is that before Harrison 2 or after? We'll just have to see how that works. But we certainly have enormous flexibility to meet the producers' demands early, to allow them to flow their gas early in long term, great recovery to cryo plants and then have the frac and the marketing options you got to have up in the Northeast or you just can't provide the producer customers with what they need. So it's a similar case for a lot of our producer customers current and potentially due to who are up there drilling right now and seeing what the well results are.

Frank M. Semple

It's clearly entered in a process. They need to understand what we're building, as Randy said, and we need to understand what they're planning to develop, what they think they need given their drilling program from a Midstream solution standpoint. So stay tuned. And we'll continue obviously the -- we're excited about what's going over in the Utica. And every quarter, we'll give you another update because we've made a heck of a lot of progress in the Utica. We're excited about what we're seeing. And clearly, we're making a big investment to stay ahead of the producer customer requirements, and that's been a huge resource play.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Understood. I guess just lastly on distribution growth. I think for your guidance at the low end, you mentioned coverage of 1.13x, I think, if distributions hold flat from here. Just trying to understand what kind of what is maybe acceptable coverage for you all, maybe short term, with the understanding that you have a lot of growth projects coming online and growing the fee-based business?

Frank M. Semple

Yes, TJ, you've nailed it. I mean, that the -- there are decision every quarter for distribution growth is based on -- well, clearly, the first -- that quarter's performance. But we also, because of all the growth projects that we are completing and developing, well, we also take into account the ability to sustain that coverage. And again, I've talked previously about what we feel because of our commodity price position, commodity positions and the need to effectively hedge our positions going forward, that we need to have a coverage ratio that's somewhere in that 1.1 to 1.3 range. And so, if you kind of think about that, we have to project forward based on the volume growth, based on for those commodity-based contracts, the assumptions around our -- the forward curve for commodity prices and also, the effectiveness of our hedging program to determine whether and how we're going to be able to draw our distribution. But as you mentioned, I mean, a critical part of that equation is the ability to execute our organic growth program that is very clear and a program that we've done a good job of executing on in the past. So that allows us to forecast the future growth, ability to provide future growth in distributions and to be able to sustain that growth. That's really critical. And we really want to be at the kind of the top of the PE industry in terms of the total returns. And we feel like, with our growth opportunities and where we're positioned in these rich gas shale plays, gives us a pretty good opportunity to do just that.

Operator

The next question comes from Louis Shamie.

Louis Shamie

Zimmer Lucas. I just had a kind of a minor question. Frank, I thought I heard you say something about a monetization of hedges during the quarter. Just want to follow up, what exactly was involved there? And do you actually take any of those hedges off? Or you said that there might be an opportunity to swap those for direct hedges?

Frank M. Semple

Yes, Louis. And I -- you were at our Analyst Day Investor Conference up in New York in several months ago. And I made the comment then that we continue to take a long-term view and execute a 3-plus year hedging horizon for our risk management program. And the majority of those hedges continue to be crude oil hedges. And in this case, we had crude oil hedges out in 2014, that because of the backwardated crude curve that have become more backwardated a few weeks ago, we took the opportunity to essentially sell those out-year hedges in 2014, which was -- which covered a portion of our long position. And we've done this previously. But the fact is that by going -- we're one of the MLPs that -- one of the few MLPs that goes out that far. And by going out that far, it -- in particularly with crude oil hedges, it gives us some optionality as far as being able to make changes to the types of hedge transactions to support the future cash flow. So you just had a case where the forward curve had dipped quite a bit, and we took advantage of that and sold some of those hedges. And we plan to rehedge now that crude has actually come back up in out years already, as have NGL prices. And so that gives us the ability to make some decisions to rehedge those positions long before we're worried about 2014. So again, by going out that far, it gives you that flexibility to make some changes. I will say that as we said at our investor conference and analyst conference in New York, that we continue to look really hard at the effectiveness of the crude oil hedges relative to the NGL pricing environment. And so, we're really taking a hard look, as I mentioned in my formal comments, at how much of our hedge program for our long liquids position will be accomplished using crude oil versus direct product hedges. And based on the analysis that we've done, you're going to see a larger percentage of our long liquids positions hedged with direct products over time.

Louis Shamie

Well, that's good to hear. And then the last thing I was interested in is in the Granite Wash. Can you talk a little bit about the trends there, producer developments and how drilling is holding up there and what you expect to see from volumes going forward?

Frank M. Semple

Yes, Louis, I got John Mollenkopf here. And John, why don't you go ahead and answer the question about what you're seeing out there in terms of drilling programs and trends?

John C. Mollenkopf

Sure. We've had -- we've seen a lot of success in the Granite Wash with our customers having drilling success. And I think we mentioned in our formal comments that we'd expanded our processing capacity at the Arapaho plant just about 9 months ago, and we've already basically at capacity with that entire complex due to the drilling that's occurred in the Granite Wash, very rich gas, good economics for that. And we've seen -- we've added a couple of customers of note over the last 6 months that have brought their gas into our system as well. So we continue to see active drilling out there. And we watched that, the capacity of our plant versus how much gas we're anticipating, and we're always thinking about, do we need to expand again? And we based that on what we're hearing from the producers. But right now, the -- there's a huge focus on the Granite Wash drilling of the rich gas portion of the Granite Wash and we benefited from that.

Operator

The next question comes from Michael Blum.

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

Wells Fargo. Actually, Louis just, I think, asked every single one of my questions. But just in terms of what were the proceeds from monetizing the swaps? And was that -- were those proceeds used to enter into new swaps? Or what did you do with those proceeds, I guess?

Frank M. Semple

The proceeds was about $8 million, $8.8 million, I've got Nancy here. So the point here is that the -- we are -- we have not entered into new replacement hedges, swaps or otherwise, for 2014 but we certainly are looking at opportunistically layering on some additional hedges in '14. And as I mentioned, Michael, that's -- we're looking really hard at what percentage of those hedges would be purity product hedges versus crude oil hedges. And we'll obviously talk about those at future earnings calls. But you're going to continue to see, as we move throughout 2012, additional hedging transactions layered in, in '14 and we're also looking, starting to look at '15.

Operator

Your next question comes from Helen Ryoo.

Heejung Ryoo - Barclays Capital, Research Division

Barclays. A couple of quick questions. Following up on the propane export comment, how much of propane is currently being exported? And how much export capacity does the facility support?

Frank M. Semple

Yes, Helen, the comments that I made earlier about the -- during my formal comments on -- and the question that was answered, it was asked by Cathleen, is about as far as we want to really go on that terminaling operation in terms of the specifics of the volumes and who's doing what and who we're selling to. I'll just repeat myself and say that we're really pleased with the ability to have developed that capability. Initially, it will provide some much-needed relief this summer for propane exports from that area. And so we're just going to continue to work hard on -- continue to optimize the logistics associated with the transportation and the terminaling of the propane out of the Marcus Hook facility.

Heejung Ryoo - Barclays Capital, Research Division

Okay, understood. And just going back to your comment about Marcellus buildup, everything announced, I guess you'll be getting to that 2.5 BCF per day of processing capacity by 2014. Could you give us some idea, how much more spending is required to build it up to that level given what you have spent so far? So I know your 2012 number CapEx guidance includes a majority of that, is related to all this buildout. But just assuming no more projects get announced, I just wanted to get some idea, how much more spending is involved in getting all of that to 2.5 BCF?

Frank M. Semple

Yes, Helen. The 2012 capital forecast that we have, which obviously includes the continued work and completion of those projects that I mentioned to get to the 2.5 billion cubic feet a day of processing capacity, if no other projects are announced and due for completion, then 2012 would be very much a peak year. I mean, it's -- there's no bad doubt about it. In order to get all that capacity completed in 2012, 2013, 2014 that we've mentioned in my formal comments, a significant portion of that capital needs to be completed in 2012. So again, nothing is ever static in this industry, and we are evaluating a lot of new projects in the Northeast, particularly in the Marcellus and the Utica. So it's just really important that we keep you updated as we move forward on what 2012 completion of CapEx looks like at our November call. And also at -- on our November call, we will give you a much better picture of what the 2013 CapEx looks like. But yes, 2012 is a big year for CapEx and we've got a lot of busy people working on projects. So if you would -- it'd be okay with you, let's just keep it at that, and we'll give you some really good perspective in November of what -- how 2013 is shaping up.

Heejung Ryoo - Barclays Capital, Research Division

Okay, fair enough. The -- just some housekeeping items. Your Liberty revenue came down about 20% sequentially from first quarter. And I was wondering, is that due to commodity price? Or is there anything else that contributed to the sequential decline in the Liberty segment revenue?

Frank M. Semple

Helen, let me make sure I understand the question. You're talking about the residue gas we're delivering downstream of the Houston facility?

Heejung Ryoo - Barclays Capital, Research Division

Well, I was just looking at your Liberty segment revenue line quarter-over-quarter, I think?

Frank M. Semple

Well, I don't have the revenue in front of me, but that is a...

Heejung Ryoo - Barclays Capital, Research Division

Yes, it's $60 million this quarter versus $75 million first quarter. And I was just wondering if that's commodity-driven or there was something else that contributed to the sequential decline there?

Frank M. Semple

Yes, it's the -- the revenue, while it's come down, it has -- really is not the indicator of what our cash -- what kind of cash was being generated. Prices have certainly come down, but it's the margin that's really driving the performance of the operating income performance that I mentioned in my formal comments for Liberty, which is obviously going up as volumes ramp up.

Heejung Ryoo - Barclays Capital, Research Division

Okay. And then just quick housekeeping. What was your debt and cash balance for the quarter?

Frank M. Semple

I'm sorry, Helen, I'm having just a little bit of a hard time hearing you. Can you...

Heejung Ryoo - Barclays Capital, Research Division

Sorry. What's your debt and cash balance for the quarter? I was going to wait for the queue, but if you have that number handy?

Frank M. Semple

Wait one, Helen.

Nancy K. Buese

Helen, it's in our earnings release on the balance sheet comments. We had $960 million available for borrowing at the end of June 30 and borrowings of $208 million.

Operator

The last question comes from John Edwards from Credit Suisse.

John Edwards - Crédit Suisse AG, Research Division

Just following up on the propane exports. So I guess as far as capacity or volumes, you're not talking about that right now? Or -- I mean, we're -- I was just trying to, rough numbers, calculating what the fractionation capacity that there should be somewhere around 100,000 barrels a day of propane that could be generated by 2014. I was just curious what, just for our own supply-demand balance forecast, what kind of volumes you'd be capable of exporting? I mean, can you comment on that part?

Frank M. Semple

Okay. So the -- that's a real -- that's a -- now I understand the question. Maybe that's what Helen was asking earlier. But the -- this terminaling capability that we've been talking about, separate and apart from Mariner East, and it involves transporting some portion of our propane that is being produced in Houston, blending that with the Sunoco volumes from Sunoco's refineries over in Philadelphia and moving it onto ships for transporting. And that's a very, very much of a, I would call it, a transitional type project that has allowed us this summer to provide some relief for the propane market in the Northeast. It's a -- it's not intended to be a representative, a kind of a long-term project. It is certainly the start of what we think is a very important component of a long-term propane export terminaling capability out of the Northeast. So there, in terms of supply and demand balance for propane in the Northeast, even this winter, it's going to have some impact. And by the November call, I think that we will be able to provide you more specificity around volumes and logistics. But really, the point here, I think, in terms of the long -- is the long-term supply-demand balance. And that point is that there's going to need to be some world-class type propane export terminaling developed out of the East Coast. We think this capability that we have been developing and working on, on a transitional basis is a good representation of how important it is to kind of add to the existing demand in the Northeast out of propane. So long term, there will be more information about what -- how much propane's going to be shipped eventually over to Philadelphia or Mariner East. How that's going to be terminaled? What facilities are going to be required? And as Randy said, Mariner East is the Sunoco project, so they're going to be right in the middle of determining really what that -- what in as the propane export terminaling capability will be required or what kind of opportunities that will be required? What kind of opportunities there will be for propane terminaling exports over the long term? So it's really -- it was important for us to kind of talk about publicly this transitional project because it has had an impact on pricing. But long-term, we're just going to have to continue to update you on how Mariner East develops in whether or not a larger kind of world-class propane export terminal is built and developed out of the Philadelphia market.

John Edwards - Crédit Suisse AG, Research Division

Okay. So if I'm understanding you correctly, I mean it creates some optionality with respect to being able to balance the market in the Northeast over the long term. Is that a fair way of understanding it?

Frank M. Semple

Well, it creates another key opportunity and option, if you will, of how the producer's propane is being marketed and sold out in the Northeast. And Randy wants to add to that so...

Randy S. Nickerson

Yes, the only additional, 100%, I absolutely agree. It's great if you have 2 things. If we have optionality, we can always maximize the value for the producers, which is they can then experience sort of the premium in the Northeast. The other point is it just may, as you said, maintaining the supply demand balance to the extent that we keep the Northeast -- to the extent that the Northeast stays balanced, then it becomes a very premium market for propane. And our job, our goal for the producers is to make sure that certainly on average over the year, that they experience premium pricing up in the Northeast versus discounted pricing. So it gives us great optionality and it's a great tool to making sure that the basin stays in balance. So both of those, I think, are really critical benefits of being able to export directly from the Northeast.

Frank M. Semple

And it is a separate project from Mariner East. That's the point I was -- I wanted to make. This trucking of propane over to Marcus Hook, which is then transported by ship to international markets, is very -- has created value in the Northeast over the last month or so and will continue to help us balance the supply picture for propane into the winter. But it is a separate project, if you will, from what might become a larger propane project -- a propane export project out of Marcus Hook as a result of mariner East.

John Edwards - Crédit Suisse AG, Research Division

Okay, that's very helpful. And then I just was curious. With respect to the, I guess, the near term, with the softer NGL pricing, have you seen any impact to new projects, new project demands? Any timing delays? Or are you still seeing -- are you rolling out, seeing any impact? Because obviously, the forecast out there are that gas production in the Marcellus will double in the next 4 to 5 years is -- have you seen any impact to your outlook just with the softer pricing here that we've seen recently?

Frank M. Semple

Well, the softer commodity price forecast clearly is a central part of the discussions that we are having with our producer customers in all of our areas about their investments in their development plans, which would then obviously impact our development plans. So whether it's natural gas prices or the upside associated with natural gas liquids prices has been very, very important at the ongoing discussion that we have with our producer customers at our projects. But that being said, a, most all of our projects, all of our future projects, the contracts that support those projects are largely fee-based. So it's really more of a producer decision in terms of what the value of the forward commodity curve looks like. And b, because of those forecasts, which are longer term in nature, and I think reflect a lot of the thinking that we mentioned in our formal comments about NGLs, the projects that we've announced and are working on, the development projects that we are working hard on in the Utica, really have not -- we've not seen any major impact on those projects because we happen to be in areas where there are a lot of NGLs in the gas stream and that there was still a very strong component of the producer's economics that are associated with both natural gas and natural gas liquids. So while it's a key point of discussion, it hasn't slowed down any projects.

John Edwards - Crédit Suisse AG, Research Division

Okay, great. And then last question, with the -- you're indicating, you expect to be at 2.5 BCF a day by 2014 and including the Utica, 334,000 barrels a day of fractionation capacity. In terms of the actual volumetric ramp, is it -- how far does that lag behind the capacity? Or do you expect to be close to full by the end of '14 with regard to that capacity?

Frank M. Semple

No, there'll be a ramp, John, as there always is. And that really, that ramp is expected because in order to move 1 MCF into the rest of the market, then you need to have the process and capability in place in these rich gas regions. So I don't have an answer for you there as far as what we think our volumes are going to be out in 2014 that are going to be supported by that 2.5 BCF, but it's -- we're not just in time, but we're pretty close. I mean, it's -- we are building a lot of plants based on the drilling forecasts of the producers. And we think that there will be a very high utilization rate for those plants just like they are right now with our existing facilities.

Operator

Now I'd like to go ahead and turn the call back over to Frank Semple for closing remarks.

Frank M. Semple

Well, thanks, Julie, and great questions. Thanks to everyone for joining us on our call today. We very much appreciate your interest and continued support of MarkWest. And as always, give us a call if you have additional questions. That concludes our second quarter earnings call.

Operator

Thank you so much for participating in today's conference call. You may disconnect your lines at this time. Thank you, and have a great day.

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