MarkWest Energy Partners, L.P. Management Discusses Q4 2012 Results - Earnings Call Transcript

Feb.28.13 | About: MarkWest Energy (MWE)

MarkWest Energy Partners, L.P. (NYSE:MWE)

Q4 2012 Earnings Call

February 28, 2013 12:00 pm ET

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

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

Randy S. Nickerson - Chief Commercial Officer of Markwest Energy GP LLC and Senior Vice President 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

TJ Schultz - RBC Capital Markets, LLC, Research Division

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

Siqi Tang

Vincent Stephen Maddi - SIR Capital Management, L.P.

Heejung Ryoo - Barclays Capital, Research Division

John Edwards - Crédit Suisse AG, Research Division

Operator

Welcome to the MarkWest Energy Partners Fourth Quarter 2012 Earnings Conference Call. [Operator Instructions] This call is being recorded. If you have any objections, please disconnect at this time. I will now turn the call over to Josh Hallenbeck. Thank you. You may begin.

Joshua Hallenbeck

Thank you, Amy, 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 our 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 our call today. As indicated in our earnings release, 2012 was a record year for distributable cash flow, anchored by significant volume growth throughout our operating segments. We continue to build on our leading position in the Marcellus Shale by investing almost $2 billion on strategic growth projects. In addition, with our partner EMG, we have extended our footprint in the rapidly developing Utica Shale. Our premier position in these 2 growing plays provides MarkWest with enormous potential as our producer customers continue to experience strong results and expand their drilling programs.

During the call today, I'll discuss our financial performance and provide a commercial and operational update. In addition, I'll review our recent capital market transactions, risk management program and our 2013 guidance. As always, I'll leave time at the end for your questions.

So beginning with a high level overview of our financial performance. For the fourth quarter, distributable cash flow rose a record $112 million, an increase of 27% when compared to the fourth quarter of 2011. For the full year 2012, DCF was $416 million, an increase of 25% compared to 2011. For the fourth quarter, adjusted EBITDA was $135 million, and segment operating income was $163 million. For the full year 2012, adjusted EBITDA was a record $528 million. In February, we announced a fourth quarter distribution of $0.82 per common unit while maintaining a distribution coverage ratio of 1.06x. On an annual basis, our distribution increased over 12%, which represents the second consecutive year that we have achieved double-digit distribution growth. As you will hear throughout our discussion, we expect to continue to deliver solid financial results in 2013 despite the ongoing weakness of natural gas liquids prices.

So moving to the operational update. We continue to benefit from the successful drilling programs of our producer customers and have experienced strong year-over-year volume growth as a result. Our total year-over-year processed volumes have increased an impressive 23%. This is a direct result of our capital investments in liquids-rich resource plays with superior producer economics. Beginning in the Southwest, our Texas and Oklahoma assets remain a key driver in our financial performance, contributing 45% of operating income during the fourth quarter. In East Texas, we continue to experience strong volume growth, as our producer customers are successfully drilling new, liquids-rich areas of the Haynesville Shale. Our 120 million cubic feet per day Carthage East expansion, which began operations at the end of last year, is already operating at over 75% of capacity in 3 months. In Southeast Oklahoma, we are moving forward with our joint venture partner, Atlas Pipeline, with the construction of a 120 million cubic feet per day plant expansion that will allow us to process additional rich gas from the Woodford Shale. In Western Oklahoma, we continue to support producers drilling into Granite Wash, one of the most economic plays in the U.S.

Now transitioning to the Northeast operating segment, which serves producers in the Southern Appalachian Basin. The processed volumes remained flat when compared to last quarter and the fourth quarter of 2011. As a result of the startup of our high-recovery cryogenic plant at our Langley facility in October 2012, fractionated volumes rose 11% compared to the third quarter of 2012 and 7% compared to the prior year quarter. The Northeast segment contributed 19% of total operating income during the fourth quarter.

Moving to our Liberty segment. We continue to experience tremendous growth in the Marcellus Shale. Processed volumes during the fourth quarter rose an impressive 45% when compared to the last quarter and 86% when compared to the fourth quarter of 2011. Gathered volumes increased 10% quarter-over-quarter and 66% compared to the prior year quarter due to the connection of Range Resources' highly successful super-rich wells in Washington County, Pennsylvania.

During the fourth quarter, we reached 2 very point important milestones that helped drive the dramatic increase in Liberty processed volumes. The first milestone was the completion of our 200 million cubic feet per day cryogenic processing facility at the Sherwood complex in Doddridge County, West Virginia. In less than 4 months, the plant is already operating at 70% of capacity due to Antero's highly successful and expanding drilling program. We are also well into the construction phase on the next 2 Sherwood plants, which are expected to begin operations during the second and third quarters of this year bringing our total capacity to 600 million cubic feet per day.

The second milestone was the completion of our first cryogenic processing plant at the Mobley complex in Wetzel County, West Virginia. The 200 million cubic feet per day facility came on at 60% capacity, and we continue to experience volume growth. Our second processing facility is currently in the start-up phase, and we expect to be fully operational in the next couple of weeks. In order to support the growing wet gas production of EQT, Magnum Hunter, Stone Energy and other producers, we are completing a third facility by the end of 2013, which will give us 520 million cubic feet per day of total processing capacity at Mobley.

At our Majorsville complex in Marshall County, West Virginia, we are currently constructing our third and fourth processing plants, and both projects are on schedule and on budget. By the end of 2013, we will have 670 million cubic feet per day of processing capacity, and we are already finalizing the design of our fifth processing facility at Majorsville. In order to increase reliability and processing flexibility for Range Resources and other producers, we've also completed a high-pressure gas header system connecting our Majorsville and Houston complexes.

During our first 4 years of operations in the Marcellus, we installed over 1 billion cubic feet per day of processing capacity, and it's exciting to consider that in 2013, we will install 6 new processing facilities and more than double that processing capacity to over 2.2 billion cubic feet per day. All of the processing capacity is located in the prolific rich gas fairway of the Marcellus and is supported by the long-term, largely fee-based contracts.

In addition to rapidly expanding our processing capacity throughout our Liberty segment, we continue to move forward with the development of additional fractionation capacity to handle the associated growth in natural gas liquid volumes. Our Houston complex has 60,000 barrels per day of C3+ fractionation capacity and extensive NGL marketing options by truck, rail and pipeline. By the first quarter of 2014, we expect to complete a liquids pipeline connecting our Majorsville complex to the Hopedale fractionator in Harrison County, Ohio. By extending our Marcellus infrastructure to our planned Utica operations, we will efficiently increase our C3+ fractionation capacity for our Marcellus producers and offer significant additional flexibility, reliability and market access.

During the third and fourth quarters, we will begin operations of 2 large de-ethanizers at our Houston and Majorsville complexes, offering Marcellus producers the ability to recover ethane. In 2014, we will add a third de-ethanizer at Majorsville, increasing our C2 fractionation capacity to 115,000 barrels per day. The purity ethane will have access to all 3 of the planned ethane pipeline projects and will allow our producer customers to maximize their flexibility and the long-term value of their Northeast rich gas production.

Throughout the fourth quarter, we continued to sell a portion of our Marcellus propane into international markets, and since July of last year, we have sold over 1.3 million barrels through Sunoco's Marcus Hook facility for delivery to Europe and South America. The international propane market is an important part of our marketing strategy, and we expect to continue to sell propane to international customers in 2013. The continued export of propane for the Northeast underscores the benefit and importance of the Mariner East ethane and propane export project currently under construction and the expanded marketing and transportation capabilities to serve our producer customers.

Now moving out our Utica segment, where we are rapidly developing a fully integrated midstream system to support Gulfport, Antero, Rex Energy and other producers. The drilling results have been very impressive and our producer customers' plans to continue to expand. To support the rapid development within the area, we are constructing extensive gas gathering compression, processing, fractionation and NGL marketing infrastructure. About a year ago, we announced our Utica development plan, and shortly thereafter, we executed our first producer agreement. We, then, began our initial design and land acquisition efforts. The build-out of these facilities requires a significant amount of time and planning. We've got a lot of experience constructing facilities in the Northeast, and the challenges that we are currently facing in Ohio are similar to what we've overcome in Pennsylvania and West Virginia. Drilling activity in the Utica has ramped quicker than in Marcellus, and obtaining permits and right of way for the hundreds of miles of pipeline and all the compressor stations that we are constructing is a huge undertaking. While the initial build-out of the system takes time, we have acquired the majority of the right of way and are well into the construction phase of the backbone at major laterals. We've completed several critical pipeline segments and will be in a position by late March to bring on a number of additional Gulfport wells. By June of this year, we expect to complete the majority of our backbone system and be in a great position to stay ahead of Gulfport and our other producers' drilling programs. We will continue to aggressively develop gathering infrastructures throughout the remainder of 2013 and 2014 to meet our producers' schedules in the Utica.

In addition to the expansive gas gathering system, we are constructing 2 large-scale processing complexes in the Utica with total capacity of nearly 800 million cubic feet per day. We have completed the initial phase of our Cadiz processing complex in Harrison County, and we are currently processing Gulfport's production through a 60 million cubic feet per day refrigeration facility. By the second quarter of this year, we will begin operation of the 125 million cubic feet per day Cadiz I cryogenic plant, which will both increase our total processing capacity and allow us to recover significantly more NGLs from our producers' gas.

At our Seneca processing complex in Mobile County, we are currently installing the first 2 processing facilities, each with a capacity of 200 million cubic feet per day. The first plant will be operational in the third quarter of this year and will be followed by the second plant at the end of 2013. And by the middle of this year, we expect to complete a high-pressure, rich gas header connecting Cadiz and Seneca with the -- and with the completion of the bidirectional header, we will be able to efficiently move gas between those 2 large gas complexes to provide maximum flexibility for our producer customers and optimize our facilities.

This month, we announced definitive agreements with Rex Energy to provide midstream services for their Warrior South acreage near the Seneca processing complex. We are currently constructing the gathering lines and expect to begin gathering and processing Rex's gas by June 1. Now we're excited to continue our partnership with Rex as they extend from the Marcellus into the Utica.

In order to provide our producer customers in Utica full uplift from their NGL production, we are developing extensive NGL gathering fractionation and marketing capabilities at the Cadiz and Hopedale complexes in Harrison County, Ohio. Together, these facilities will provide 100,000 barrels per day of C2+ fractionation capacity. We expect to begin operations of the Cadiz de-ethanizer and the Hopedale fractionator during the first quarter of next year.

Prior to the completion of this infrastructure, we have the ability to transport natural gas liquids production from the Utica to either our Houston or Siloam fractionation complexes. We believe our core operating area in the liquids-rich Utica spans more than 1.5 million acres. Given our experience operating in the Marcellus and our producers' ongoing success in the emerging Utica, our opportunities for growth are significant. As you can tell, our development in Ohio is an important part of our 2013 growth plans. In order to support the expanding growth opportunities in the Utica and the increasing investment opportunities available to us, we recently completed a transaction with our joint venture partner EMG. The agreement allows EMG to increase their investment to a total of $950 million. We're very excited to continue to strengthen our partnership with EMG and develop a leading midstream presence in the Utica Shale.

Now turning to our financials. The balance sheet remains a key focus for us, and we have been active in the capital markets to support our significant organic growth program. In November of last year, we raised $438 million through a marketed equity offering, and in January, we completed a public offering of $1 billion of 4.5% senior unsecured notes. We were very pleased with the bond offering because it represented the lowest new issue coupon for a non-investment grade MLP since mid-2008. A portion of the proceeds from this offering was used to fund redemptions, which resulted in nearly $10 million in reduced annual interest expense. The remaining proceeds will be used to fund our 2013 capital plan.

In addition, during the fourth quarter, we began utilizing our aftermarket equity program to periodically issue common units. Today, we have liquidity of over $1.7 billion and are well positioned to fund our high-quality growth projects at the Marcellus and Utica Shales. Given our recent capital markets activities and our ability to efficiently issue equity through the ATM program, we have essentially funded our 2013 capital program. As of December 31, our debt to total capital was 44%. Our leverage ratio was 4.3x, and our interest coverage ratio was a healthy 5x.

Given our commodity exposure and the variability of the forward markets, we continue to consistently hedge our future commodity positions. We are hedged at approximately 70% for 2013 and 30% for 2014. We have also continued to ship a larger percentage of our long liquids position to direct product hedges. Nearly 50% of our 2013 hedges and almost 90% of our 2014 hedges have been completed utilizing direct products. And as we previously stated, our goal is to hedge our future commodity exposure on a 3-year time horizon, and we expect to increase our 2014 and '15 hedge positions throughout this year.

In addition to an active hedging program, we continue to make progress on our goal of increasing our fee-based margin. Over the last 3 years, all of our new contracts in the Southwest and rapidly growing Marcellus and Utica business units are supported by long-term, fee-based agreements. At the end of 2012, 53% of our net operating margins is fee based. This was up 15% in where we ended 2011. With the continued growth of our Liberty and Utica segments, we are on target to increase our fee-based margin for the full year 2013 to over 60% and anticipate reaching almost 70% by the end of 2014.

So before concluding, I want to also review our 2013 guidance. DCF remains unchanged and will be in the range of $500 million to $575 million. We have narrowed our 2013 capital forecast to a range of $1.5 billion to $1.8 billion to reflect the incremental financing provided by EMG and our continued success in the Marcellus and the Utica. We expect to start funding our portion of capital for the Utica joint venture during the second half of 2013.

So in summary, 2012 was a great year for MarkWest, and we're not slowing down a bit in 2013. Highlighting this year will be the installation of an additional 1.6 billion cubic feet per day of processing capacity and 76,000 barrels per day of fractionation services in 2 of the best liquids-rich resource plays in the U.S. By offering comprehensive and integrated midstream solutions in the Marcellus and now the Utica Shales, we are uniquely positioned to drive future growth in volumes and cash flow. We remain focused on providing superior customer service and developing unique solutions that drive value for our producer customers. And as always, we are committed to providing superior and sustainable total returns for our unitholders.

With that, Amy, I'll open the call up to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from TJ Schultz with RBC Capital.

TJ Schultz - RBC Capital Markets, LLC, Research Division

I guess just, first, in the Utica, sounds like you'll be in a position to get more Gulfport wells on in the next month. I guess, just as you look at that development, obviously, the comment is that production is ramping faster than what you saw in the Marcellus. Just kind of what point do you expect to kind of be ahead of some of the producer activity?

Frank M. Semple

Yes. TJ, the -- you're right. The wells by Gulfport and Antero and the other producer customers in that core area of the rich gas envelope in the Utica have been pretty spectacular, so that's great news. We've made, as I mentioned in my comments, we've made excellent progress on the gathering pipeline, the high-pressure and low-pressure pipelines that are going to be required to support those drilling programs. And progress has been pretty amazing when you think about the fact that we just announced our Utica development plan this time last year. So as I mentioned in my comments, the -- if you can kind of envision the Utica, the area that we operate, we have a major north-south header, high-pressure header that will be connecting our Seneca complex in the south end of the system to Cadiz and Hopedale in the north end of the system and then another large header backbone system that extends to the west out of Cadiz over into the rich areas to the west of that north-south header. And major parts of that, we already have several major components or pipeline segments online that have -- that are gathering gas from the 2 wells that Gulfport is currently producing into our system, into our processing facilities. And by March of this year, we will have completed another large segment that will hook up kind of the Gulfport wells that are kind of at the midpoint between that now -- on that north-south header. And then by June, we will have that entire north-south artery completed. So as I mentioned on my comments, my formal comments, by middle of this year, we will be pretty much in front of the Gulfport production from a gathering standpoint, and obviously, the processing will be gathered into our -- the rich gas would be gathered into our processing complex at Cadiz. That first Cadiz cryogenic facility will also be completed midyear. So back to your question, I think by -- we'll make a lot of progress over the next several months, but really by June, we should be able to stay ahead of the Gulfport production, which is so critical for them in getting those plants onto Cadiz and then followed by Seneca later in the year, which are connected by that header, absolutely critical for all of our producer customers in the Utica, so really good progress.

TJ Schultz - RBC Capital Markets, LLC, Research Division

And then I guess just moving to your DCF guidance range for 2013 and just reconciling that with the sensitivity table in your press release, so on your guidance range, is that low versus high end of the DCF guidance solely a function of commodity prices? Or if you could comment on potentially other factors, maybe from a timing perspective on some of the projects you have now that would impact kind of the high end or low end of your guidance range this year?

Frank M. Semple

Yes. TJ, the table is provided, and we've been providing the table for a number of years now. But the table is provided, as you know, to provide all of our investors and analysts an opportunity to look and see how DCF varies based on commodity price changes, natural gas and liquids prices. The -- it does -- our overall guidance, however, is based not only on NGL prices or on commodity prices but also other variables in our plan. So a good example would be volumes that are impacted by the dates of completion of these major projects, particularly gathering and processing projects, so -- and also, it's important to point out that, that table is a full year view. So it does give you a pretty good understanding of how DCF can vary based on NGL prices. It gives you a way to provide your -- the support to your analysis based on your view of NGL prices and natural gas prices. But in order to get to our guidance, the other big variable is the timing of major projects, particularly with MarkWest because we've got so many projects that are driving volume increases throughout the year.

Operator

Our next question is from Michael Blum with Wells Fargo.

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

I'm going to -- I want to stay on this topic that TJ just talked about. So should we -- presumably, this table, this guidance table or this sensitivity table that you provide, this is a full year look and is also incorporating the projects as they come into service. Is that right? Or is it not?

Frank M. Semple

That is correct. It incorporates what I would call our base case plan for volumes based on our producer projections and the in-service dates of new projects throughout the year, and it incorporates our base case assumptions for commodity prices. And my point, Michael, to TJ was that number one, -- so having said that, if you think about natural gas liquids prices, if they stay where they are today, then based on that table and assuming $3 -- $3 to $3.50 for natural gas prices that we would be at and perhaps even below our -- at or below our guidance of $500 million. But obviously, we have other factors that drive our plan that change everyday. And so as we look out to 2013, we are taking into consideration some of the upsides that we see in our plan that have driven really by in-service dates and production throughout our system, so -- and really, the bottom line is that it's so early in the year. We have 1 month of operations. It's so early in the year that it just doesn't -- didn't make a lot of sense for us right now to start adjusting our DCF guidance. At the end of the first quarter, as we always do, we will come back and provide our perspective on operational variables based on in-service dates, the then current in-service dates for our projects, the then current forecast for NGL and natural gas prices, and we'll provide an updated table. But again, the reason we're not changing our guidance right now is because mainly because how we're hitting some of those metric variables and also the fact that we're just 1 year into the -- 1 month into the year, and it's really too early to start making adjustments.

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

Another question I had was just in terms of distribution growth for 2013. In the past, you've talked about having a goal of being, I believe, in the top quartile relative to your peers in total return performance. I just wanted to confirm that, that's still the goal for 2013.

Frank M. Semple

Yes, it's still -- it's not only our goal for 2013, Michael. It's our long-term goal. We believe that with our structure, which obviously without incentive distribution rights allows all of our cash flow to be available to our common unitholders and the growth projects that we are developing and are forecasting to continue to develop around our core operating areas that we can continue to perform as we have in the past in the top quartile in the industry from a distribution growth standpoint. Having said that, 2013, there are some NGL headwinds, as we just talked about, and we're very sensitive to the coverage ratio going forward. So that's why we provide the table. That's why we have provided a lot of visibility into our financing activities, so that you can make your own determination in terms of whether or not at low end, at the midpoint, at the high end of DCF range given your own financing assumptions for MarkWest where we will be on coverage based on a 5%, 6%, 7%, 8%, 9% distribution growth. And if you just take the midpoint of our DCF range right now and assuming we don't issue any more equity this year, then we'd be really in pretty good shape to continue to provide that high-single-digit, low-double-digit type distribution growth. However, we're very conservative when it comes to that coverage ratio for the units. So 2013, because of all the growth, because of all the equity that we've raised and really that dilutive impact on all of this organic growth capital, you will see us be pretty -- when we go to our board for distribution recommendations, you'll see us be pretty conservative in terms of distribution increases in order to maintain a solid coverage ratio.

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

Okay, great. Just one more question for me. Can you talk about any ethane rejection that you had going on across your system in the fourth quarter and now and to the extent you can quantify what that meant for you in terms of volumes?

Frank M. Semple

Well, the ethane production issue for us is in our Southwest business unit, and as you know, Michael, -- and that's really driven primarily out of our Western Oklahoma operations, our Southeast Oklahoma processing operations, East Texas and Javelina. And currently, we are -- even though the margin for ethane recovery is pretty thin, we are only rejecting ethane up at our Western Oklahoma facility. And so volumetrically -- and I have John Mollenkopf here. Volumetrically, what is that? 50,000, 60,000? Overall, it would be -- if we were rejection everywhere, what would be our approximate rejection?

John C. Mollenkopf

Yes, Frank...

Frank M. Semple

Or excuse me, everywhere -- if we were recovering everywhere, what would be our ethane production? Just so I'm clear on the question.

John C. Mollenkopf

Yes, it's about 20,000 barrels a day overall for the company. And like Frank mentioned, today, we're in recovery in the plants that get Belvieu pricing. The only place we're not recovering ethane is Western Oklahoma, which gets Conway pricing, and that's about -- it's down about 5,000 barrels a day when we're in rejection for Western Oklahoma. Now I think, Michael, your question was in the fourth quarter, what were we doing. In the month of December, we did reject ethane for -- in the Belvieu area for about a month, and it was really December when that made sense to do that. It was a very close call. But then since January 1, it's -- the prices have -- the frac spread has reverted to the point where it makes a lot of sense to just run the plants in recovery because they do recover more propane when they run in recovery. And so we're -- it's basically a wash on Belvieu prices, and it's still better to reject in Oklahoma.

Operator

Our next question is from Siqi Tang with Valley Asbey [ph] .

Siqi Tang

Just to clarify on the liquidity comments that you guys had. So basically, you have about $1.7 billion of liquidity, and that covers your CapEx spending for the year. So does that mean you would be trying to stay out of the equity market for as long as possible? Is that the right interpretation here?

Frank M. Semple

That's correct, Siqi. Yes, that's. As you and I have discussed in the past, we -- the financing that we did at the end of the year and early this year was designed to -- with that coupled with the implementation of the ATM program was designed to prefinance our capital program for 2013. The EMG transaction helped with that financing, so we'll give you another update at the end of the first quarter, but that was our objective, to stay out of the equity markets.

Siqi Tang

Got it. And then when will you provide a 2014 guidance?

Frank M. Semple

We'll provide 2014 guidance in November of next year after our third quarter and on our third quarter earnings call.

Siqi Tang

Yes, okay. Got that. Okay. I was thinking about Analyst Day in May, but okay, fair enough. And then I was looking at some of the results at Rex. They were talking about that they have some wells that are resting. Seems like they're waiting for the midstream infrastructure to be built and then flow into the -- in Utica processing plants. You have been talk in the past that it takes about 12 to 18 months to ramp up on the processing plants. Does -- if I'm interpreting this correctly, does that mean that the time to ramp up the volumes probably will be a little bit faster than you originally anticipated?

Frank M. Semple

Siqi, I -- and I apologize. Some of your -- I was missing some of your questions. So if you wouldn't mind, could you just repeat that question?

Siqi Tang

Yes, for sure. So I was looking at Rex and some other producers. They're talking about some of the wells that are already drilled but to put this wells at Rex basically waiting for -- seems like to be waiting for the midstream infrastructure to be built. So does that mean the ramp-up on your processing plants will be a little bit faster than you originally anticipated? That's like 12 to 18 months. Or would it be like faster than that?

Frank M. Semple

Okay. So in the Utica, we are -- as I mentioned earlier, we are rapidly deploying our gathering system and processing plants in order to support the producer drilling program. In the case of Rex, we are in a position with the timing of that large set of -- those 2 large laterals that we're completing in the first half of the year will be in a position to support Rex's and Gulfport's production in the Utica. Now that core set of laterals and what we call our backbone, that comes on over time throughout the first and second quarter. But by middle of the year, we'll be in a position with the completion of those laterals and the backbone system to be able to support the ramp-up in Rex's volumes. I mean, that's just the time it takes in order to get these facilities built.

Siqi Tang

Okay. I mean after this is built, it won't -- does it still take another 12 to 18 months to fill it up? Or it's probably faster than that?

Frank M. Semple

That's right. Siqi, let me just -- also, I've got Randy Nickerson here, our Chief Commercial Officer. Do you want to make some more comments on that?

Randy S. Nickerson

Yes. Just to build on exactly what you said, I think one of the points is because we have a backlog of wells when we connect up by March and then into June, middle of the year, that backlog will come in faster. And so does that mean by definition that we fill up the processing side a little bit quicker? And the answer, of course, is certainly, the early facilities that we're building will come on. There'll be a lot of wells coming on very quickly into the Cadiz I processing facilities. The flip side of that though is this is very close on the heels of Cadiz I combined with the refrigeration plant at Cadiz. We're building Seneca I Seneca II and then other facilities. So yes, the early processing facilities will come on and be very full very quick, but we're certainly adding other facilities, processing facilities, which probably fit back in the mold that Frank's talked about in the past. I don't know if that helps or makes it more confusing.

Siqi Tang

Yes, both. Okay, a question regarding -- because Frank was talking about the propane export in the Northeast. I'm curious, what kind of pricing are you getting on the propane Northeast right now because you used to have some issues in last -- in 2012.

Randy S. Nickerson

Yes. When we first started exporting the propane in 2012, it was, of course, following the non-event of last winter, and there were some other storage issues up, not on our system but in other systems in '12 and bringing on the production. So '12 was a very tight time in the Northeast. And so our primary goal in the -- a lot of the exports last year was sort of maintaining some supply and balance -- supply-and-demand balance for the entire Northeast, which, of course, had a huge impact on the gallons that we were selling into the local market. Our export pricing that we were realizing was at the low end of our average pricing. However, as we went into this winter and currently, we're now getting pricing that we think from the international markets was actually is at or above the average pricing locally. So it's worked exactly the way we expected, done exactly what we want. And certainly, there are strong export numbers, and we expect to continue benefiting from that in the near term for sure, in addition to just manning healthy supply-and-demand balance in the Northeast, which is the other real reason for the international exports.

Siqi Tang

Perfect. My last question regarding your financing, basically, you have -- I think that you still have a 8.75% note. Is that refinanced yet? Or -- because you're able to issue some note at like 4.5% lately. I'm curious that's probably -- is it possible to actually lower your interest expense in the -- in 2013 by just refinancing some of the high-interest-rate notes?

Nancy K. Buese

Yes, Siqi. We have one tranche of high-interest-rate notes still outstanding, and those had some slightly different terms in the indenture than the other notes that we did redeem. It is certainly possible to take out those additional high-yielding notes. But at this point in time, as Frank indicated, our financing for the year is really mostly complete.

Operator

Our next question is from Vincent Maddi with Standard Investment Research.

Vincent Stephen Maddi - SIR Capital Management, L.P.

Question, what I'm trying to understand a little bit is the -- if I look at the Liberty segment, volumes are up 80%, 90% depending on whether you're looking at gathering or processing. But operating profit's only up about -- segment operating profit before minority interest, only up about 5%, and I'm trying to understand if that segment is burdened by some inefficiencies as a lot of new plants start up or just help me understand it because my understanding is that it's mostly a fee-based revenue stream.

Frank M. Semple

Well, you have -- Vince, you have the percent of liquids component that we've talked about previously. That is a important part of our contract structure in Liberty that we implemented with Range Resources at the very beginning of that relationship back in 2008. And as you and I have talked in the past, having that percent of liquids component, which essentially provides us with equity liquids from the production of that rich gas, is critical because, again, it has -- it basically puts us in the same position as our producer customers because we're marketing majority of those liquids in the Northeast from a value standpoint. So that's the reason why we did that, that we have a percent of liquids agreement in place with Range Resources. And Range Resources has been very successful in the Marcellus, and the volumes continue to ramp up as you noted. Liquids prices have not ramped up. So when you're comparing period to period, you have to take into consideration the impact of those -- of the fee based going up and the percent of liquids value going down.

Vincent Stephen Maddi - SIR Capital Management, L.P.

So the main -- that's the main reason that the operating income really hasn't kept up with the revenues or volumes?

Frank M. Semple

Yes, that's the main reason. I mean, we do have some start-up costs and O&M's a little bit higher on the startup relative to the -- as we ramp up the volumes. So it's those 2 major components. You'll see it catch up. You'll see the O&M component true up over time as we start -- as the volumes continue to ramp up. But it's mainly a key percent of liquids issue that when you're looking at comparing 2011 to 2012, it's mainly a percent of liquid because we obviously had fabulous prices back in 2011 and early 2012.

Vincent Stephen Maddi - SIR Capital Management, L.P.

Can you give me a rough idea of the -- in the fourth quarter, what the composition of fee versus commodity exposure was in Liberty?

Frank M. Semple

Say it again, Vince.

Vincent Stephen Maddi - SIR Capital Management, L.P.

Can you give me rough breakout? Within that segment, what was the -- in the fourth quarter, what was the mix of revenue that was fee based versus commodity?

Frank M. Semple

You mean from an operating income standpoint?

Vincent Stephen Maddi - SIR Capital Management, L.P.

If you can either operating income or yes, whatever measure you have, really.

Frank M. Semple

Yes, just think about it in terms of a 75%-25% split, 75% being fee based.

Vincent Stephen Maddi - SIR Capital Management, L.P.

75% fee-based in 4Q, and it would have been presumably higher than in 4Q of last year because you had higher commodity prices?

Frank M. Semple

That's right. That's correct. And again, as -- since all of the non-Range agreements are fee based, as 2012 and '13 -- excuse me as 2013 and 2014 ramp up, the majority of that increase is going to be fee-based volumes from the Marcellus and West Virginia, all those new plants we're bringing on in both Pennsylvania and West Virginia.

Vincent Stephen Maddi - SIR Capital Management, L.P.

So from this point forward, there should be a -- maybe a tighter correlation between the growth in operating income and growth in volumes?

Frank M. Semple

Well, absolutely, yes, as the volumes grow. But keep in mind, the reason why we have that percent of liquids component in there, it just makes a lot of sense from a customer standpoint because, again, we're in the same position they are, and it makes us wake up every morning trying to figure out how to make as much money as possible from the liquids production in the Northeast.

Vincent Stephen Maddi - SIR Capital Management, L.P.

Yes, that make sense. I just -- I didn't -- I thought -- I didn't realize the magnitude maybe.

Operator

Our next question is from Helen Ryoo with Barclays.

Heejung Ryoo - Barclays Capital, Research Division

Just a clarification question on your guidance table. When you talk about this NGL-to-crude ratio, I guess, that's based on your barrel mix, not the market price. Is that correct?

Frank M. Semple

That's correct, Helen. We -- the percentages that we're providing, we look at -- as TJ or Michael mentioned earlier, we -- every quarter, we look at what we provide in terms of the percentages of -- the ranges that we provide in terms of crude oil pricing, the NGL-to-crude-oil ratios and the natural gas prices. So you'll see that -- you'll see those percentages and prices vary from quarter-to-quarter, but the actual value of the natural gas liquids that are in each of those boxes are based on a MarkWest average barrel, projected barrel. And we provide in that -- on that sheet, on that page of the earnings release also, what those percentages are, so you can compare those to what has become kind of a standard barrel that most of the analysts are using. And kind of the bottom line is that we have less ethane in our barrel than the standard barrel, so impact of ethane is less for us than it would be for a standard barrel.

Heejung Ryoo - Barclays Capital, Research Division

Right. And then I guess, as you start recovering ethane, your ethane mix will go up probably in '14 and '15. Is that the right way to think about it?

Frank M. Semple

Well, our standard barrel will go up because of the ethane that's produced in the Northeast, but the impact on our DCF is minimal, if you will, because most of that gas that we're processing in the Northeast is going to be fee based, under fee-based agreements. But you are correct. As we start to recover ethane then the -- up in the Northeast, then you'll see our barrel have higher percentage of ethane.

Heejung Ryoo - Barclays Capital, Research Division

And could you disclose what sort of NGL-to-crude ratio you realized in fourth quarter?

Frank M. Semple

About 40% -- a little over 43% or so.

Heejung Ryoo - Barclays Capital, Research Division

Okay, great. And then just switching gears and just big picture, is there any upstream or downstream challenges you're seeing in Marcellus as you're ramping up -- very quickly ramping up your capacity up there? Any producer issues or any issues related to the very richness of the gas? I guess, a competitor of yours in that region talked about this challenge, and I was just wondering what you're seeing there and how big a risk factor this is for your own DCF expectation for the year.

Frank M. Semple

Well, the challenges in the Marcellus, Helen, are what I would call or characterize as being pretty manageable from a DCF standpoint because we have been operating in the Marcellus since 2008. And as you know and you've heard on today's call, the processing facilities, the pipeline systems, the compressor stations, the fractionation facilities that are required to be able to support this, our plan and our guidance, are manageable, very controllable because we are in all of these major -- in all these major locations. We have existing facilities, and we're just adding to those facilities with a processing capacity in 2013. So it's a little different risk than the Utica, as you would expect, because the Utica is still very much in start-up phase. But we feel very comfortable and confident with our volume projections in the Marcellus for those reasons. And also, as I mentioned earlier when we were talking about our DCF table, we believe there will be potentially some upside given the success of the producer customers in the Marcellus and potentially our ability to bring these facilities on a little bit sooner. It's important to note, as I mentioned in my comments, that these plants, as we commission these plants in the Marcellus, they are filling up very, very quickly. Sherwood and Mobley, within a few months, we're operating north of 60% of utilization. So that's all a very -- rich gas. So that's a testament to our producers customers' success and also the fact that there's a huge demand for quality processing solutions in the Northeast.

Operator

Our next question comes from John Edwards with Crédit Suisse.

John Edwards - Crédit Suisse AG, Research Division

Frank, just following up on Vince's question on the structure of the payments in Liberty. The fees for -- the fixed fee or the fee based, is that for capacity? Or is it for volumes, just to be clear? I take it, from your comment, it was volumes but just to clarify.

Frank M. Semple

Yes, it's volume based. Now we do have backstops in our agreements that provide some support. There are some downside protection. But when I talk about the impact on fee-based margin or fee-based operating income, it's based on the volumes that we anticipate and what we've experienced in the Marcellus with the point -- the question earlier.

John Edwards - Crédit Suisse AG, Research Division

Okay, great. And then I'm just curious. In terms of developing things out, I guess in planning this, you have to have a relative balance between the gathering and processing, your fractionation and other infrastructure. I'm just curious in terms of where do you see any shortages of infrastructure versus perhaps surpluses in terms of trying to balance the development, if you could talk a little bit about that.

Frank M. Semple

Sure, John. And I'll just make an initial comment, and I'll hand you off to Randy to add to my comments. But this is obviously -- your question goes kind of to the heart of the opportunity and the challenge in all of our areas of operation, but particularly up in the Marcellus and the Utica where the producers' success has been so substantial and the increase in volumes has been so rapid. We work very, very closely with our producer customers and jointly develop long-term forecasts for their production and -- which allows us to plan our facilities. So that's why you see us building out ahead so aggressively of our producer customers in the Marcellus and the Utica. And having said that, there are -- and these plants come on with large capacity, but they come up -- they come on in steps. And so if you look at ahead of our -- if you look at our plan, then it's -- we're in really good shape from the standpoint of processing facilities. Fractionation facilities are becoming fairly tight, and that's why we are aggressively executing on our fractionation build-out in the Utica Shale, which includes that interconnect over to our Houston fractionation facilities to provide the flexibility to provide incremental capacity in the Utica for our Marcellus liquids, and the bigger we get in the Northeast, up in the Marcellus in the Utica, the more flexibility we can provide to our producer customers. And we've got a lot of scale up there right now. But Randy, I'll turn it over to you. But I do believe that if you look at our bottlenecks over the course of the next several years, fractionation is really critical.

Randy S. Nickerson

Yes, I agree with Frank just building on that one. When we think about it, when we sort of start with gathering, after you build out the initial backbones, what you've now done in Washington County in the Marcellus and they're doing in the Utica. But once you build that out, gathering is almost sort of just-in-time investment, right? As you work with the producers, with Range or with Gulfport and add a compressor station, add a line, and so the projects are generally maybe smaller and it's easier to match capacity with needs. So on the shortest event, gathering is easy to add. It's almost just in time. In the middle would be processing plants. The good news for us, as we add on these "200 million a day" building blocks at the facility, it's easier to sort of -- we talked about that -- to sort of match volumes with capacity. And then Frank -- just exactly what Frank said, probably the bigger step functions, of course, are fractionation. We'll have 2 large fracs. We'll have a number of plants and then enormous amounts of small segments of pipe. So as you go from gathering up the frac, they're bigger step functions. We have to step out ahead of time, keep going as what Frank said. When our Hopedale frac over in the Utica comes on, which will serve both Utica and Marcellus in early '14, will be timed just perfectly for when we need it.

Frank M. Semple

Case in point, an example, John, was when the Liberty fractionator at Houston was being completed, we were running -- before it was completed, we were running short of frac capacity. And we were able -- because of our Siloam fractionation capacity, we were able to overflow into the Siloam facility. And again, the bigger we get up there, the more scale and capability, the more flexibility we have. And so getting that third fractionator in place in early 2014 is really critical. But again, we're looking out 5 years. So you can see that additional fractionation is going to be required. We see additional infrastructure being built probably down at the Gulf Coast. It all plays together. But the value of those assets up in the Northeast and the Marcellus and the Utica are really preserved by the fact that we have high-quality facilities. We can produce the purity products, and we have markets for those purity products. And again, it's just a part of our strategic planning that goes on with our producer customers.

John Edwards - Crédit Suisse AG, Research Division

Okay, that's really helpful. And just following that then, sounds like you're a little bit fractionation short, so that's pretty much, I take it, running at near 100% utilization. And then your gathering and processing, what do you think that's -- utilization, where do you think that's running at right now? And this is up in the Northeast, I mean.

Randy S. Nickerson

Yes. Just to make a quick correction, just to make sure we don't put out something. Today, if we look at the Houston frac, we're at 60,000-odd barrels of capacity, and today, we're running -- with just C3+, we're running 24, 25, 28. So it would be a misnomer to say that we're running at capacity. What would be accurate is to say, by the time we continue to install plants, our producers are ramping up their production. By the time, we get to next -- by we get into early -- into '14 in the first quarter, Houston, the Houston frac will be running close to capacity. If we have to overflow, for a short while, the Siloam, we can. But just to clarify that, as we speak today, we are absolutely not running at capacity in fractionation. We will be just in time for our second major or the third frac when you have Siloam is first or the second to come online. It'll be perfectly based on what we expect today.

John Edwards - Crédit Suisse AG, Research Division

Okay, sorry for that. I -- I was just -- It just sounds like as you're stepping up, you're trying to match your gathering and processing to your fractionation, and obviously, it takes some coordination. I'm just trying to understand, I guess, maybe it's better to add. What's the utilization you're running on your -- I'm just trying to get a better idea of the ramp-up. What's your utilization rate on your gathering processing now? That sounds like frac, it's -- will be full by next year. Where are you at on the gathering and processing side?

Frank M. Semple

Yes, John. The -- I'm kind of guessing that right now, if you look at all of our -- let's just take Marcellus, which is, obviously, where we have the majority of our processing that we're probably somewhere around 50%, 60% of utilization, is ramping up quickly. And as we add these new facilities that we just talked about in 2013 and 2014, they will fill up fairly quickly. So again, the processing in the Marcellus is more manageable now that we have the infrastructure in place. We have these large facilities where you can add. It's not easy, but you have a facility, let's say, at Sherwood where you can add multiple 200 million cubic feet a day cryogenic processing skids to that facility. And the critical path -- or the limiting factor there for the schedule really is your time, your long lead time items. So I know your question is around are we running into bottlenecks or capacity constraints with processing in the Marcellus, and the answer is really not because we're able to continue to add large-scale facilities at all these major processing hubs. Fractionation, as we continue to say, is a bigger challenge, and even though we're [indiscernible] we have very manageable utilization at the existing fractionation facilities, they're filling up rapidly because you have all of these major plants that are producing a lot of liquids, moving into the fractionation facilities. So they -- so by 2014, as Randy said, we really need to have that third fractionator online, and obviously, it's real critical. It's real critical in order to produce the purity products, and we feel confident we'll make it. But that's to us. You asked the question earlier about the biggest challenge. I think it is fractionation in any associated natural gas liquids transportation and marketing facilities that are required to support the marketing activities.

John Edwards - Crédit Suisse AG, Research Division

Okay, great. And then -- okay. And this -- and then this is kind of also expanding on Vince's question on -- so are margins then -- directionally, it sounds like they're going to improve. This is on Liberty. Is that a correct interpretation of the earlier question or your earlier answer to Vince's question?

Frank M. Semple

Vince's question was why is operating income -- why is the operating income between -- from 2011 to 2012 for Liberty, on a percentage basis, less than the volume growth in Liberty for -- between 2011, 2012 and that's for the percent of liquids impact. Again, to put a finer point on it, the increase in volumes in 2011, 2012 -- and these are in your tables -- is about 53%. The operating income increase is about 38%. And yes, you will see that difference decrease over time as our fee-based volumes continue to ramp up. Does that make sense, John?

John Edwards - Crédit Suisse AG, Research Division

Yes, okay. Okay, that ties back to the -- because their volumetric contracts for the most part that, that should even out over time.

Frank M. Semple

Right. The fee-based contracts or gathering, compression, processing, fractionation.

Randy S. Nickerson

And early on, a lot of our revenue came from processing Range's gas. Whereas, we're going now today, if you look at the total picture, maybe 1/3 of the revenue off of that from Range is now, we'll call it, commodity based and almost 2/3 of that, that even for Range is now fee based as we build more gathering. We have fractionation. All of those are fee-based services. So on day one we had an enormous amount of processing in fuel well service -- fuel well agreements. But we've been growing for Range and for everyone else. Everything has been fee based. So yes, the drop in NGLs prices showed up. Now that we're at it, it should all track much, much, much more closely with volumetrically for Range and every other producer.

John Edwards - Crédit Suisse AG, Research Division

Okay, that really helps. And just now just a couple more and I apologize. On the volumes now, you guys are doing so much, it's difficult to keep track now. So the projects that, all with your recent announcements, are those reflected in your latest slide deck on your website in terms of where you expect to be in terms of total processing and capacity and NGL production capacity? Is that now updated? Or -- and if not, if you could clarify for us where you expect to be for 2013, '14 and '15, that would help.

Frank M. Semple

Yes, John. The answer to your question is that the most recent investor presentation does not include all of the latest changes because of the point you're making, that things are moving so rapidly. But we are going to be providing a new investor presentation next week, to next Tuesday. So that will sync up with all of the comments that we've gone over today in the earnings call.

John Edwards - Crédit Suisse AG, Research Division

Okay. If you could then just give us what's the incremental numbers to what you've posted for '13, '14, '15, just to help us with our math on -- and modeling purposes if you could or if you have that handy.

Frank M. Semple

John, I don't have it handy, but if you could give us a call, we'll go over it with you. And again, everyone else on the call, we can -- we're always available for calls to our IR group to give you some preview of that. But again, the next update of our investor presentation will be out early next week.

John Edwards - Crédit Suisse AG, Research Division

Okay, I'll take that offline. Just last question then, what's target -- actually, second to the last. What's your target leverage by the end of this year, your debt to trailing EBITDA? And then if you could give us some preliminary CapEx plans for '14 and '15, and that's it.

Nancy K. Buese

Sure, John. On the leverage issue, certainly, with the additional debt financing we did earlier this year, we've levered up a bit, and our objective will be to continue to take that down over time. We had been in the 3x range over the last year or so and only levered up in order to finance some of this growth, but that will be coming down over time.

John Edwards - Crédit Suisse AG, Research Division

Right. So you're at 4.3 now. Should would we be thinking kind of mid-3s by the end of the year? I'm just trying to get a little more granularity there.

Nancy K. Buese

We really don't provide guidance [ph] .

John Edwards - Crédit Suisse AG, Research Division

Kind of mid-3s by the end of the year?

Frank M. Semple

John, what Nancy said when you were talking was that we don't provide the guidance. We certainly provide the -- all of the information you need to make your term, to make your assessment. A lot of it depends, again, on where you are in the range that we provided for DCF and adjusted EBITDA and obviously, whether or not we assume that we have more equity. But you will see us lever up a bit because of the bond offering in the early part of this year. And then we'll -- you know us better than almost anybody we will work hard -- we're going to work hard to get that leverage back down certainly in the 4s by the end of the -- by the second half of the year.

John Edwards - Crédit Suisse AG, Research Division

All right. Fair enough. And then '14, '15 kind of rough CapEx outlook, anything you can provide there would really help.

Frank M. Semple

Yes, I understand, and I didn't forget that part of your question. We don't -- even if I wanted to, we don't really have the ability to have a good estimate for CapEx in 2014 and '15. What I will say about CapEx is that we will, as we -- because of the rapid expansion of our facilities and the CapEx that you've seen for MarkWest over the last several years, it is -- we get the fact that it's important that you understand a little bit more about what 2014 and 2015 might look like from a CapEx standpoint, and so even though we'll give formal guidance next November for 2014, certainly, on our July call, we will give you little bit of better indication of how 2014 is shaping up for CapEx, not formal guidance but some indications. And I'll say this, that if you -- we certainly have the 5-year plan that I mentioned earlier, but the -- a lot of the -- a big part of the determination of our 2014 CapEx budget is going to be based on the work that we do with our producer customers. So we're just not ready to start talking formally about what CapEx would be required to support their drilling programs. We -- having said that, we would expect though, just like what's happened in the Marcellus, that the Utica will start to turn over a little bit in the '14 and '15 time frame because we're building -- we're very, focused on that south end, the core area of the rich gas envelope of the Utica, and where -- that's where our capital's going to spent. And we expect to have a significant amount of that infrastructure in place over the course of the next 12 to 18 months. So we would expect that the big driver in capital in '14 and 15 will come from the Utica. We expect that to moderate somewhat in the 2014 and '15 time frame. But stay tuned. We'll give you some better information and some visibility into how we're thinking about those out years on the next couple of earnings calls.

Operator

I will now turn the call over to Mr. Frank Semple for closing remarks.

Frank M. Semple

Again, thank you very much for joining us on our call today. We appreciate all of your interest and great questions and support. If you've got any other questions, feel free to give us a call. And Amy, that concludes our conference call for today.

Operator

Thank you for participating in today's conference. You may disconnect at this time.

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