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Executives

Frank Semple - Chairman of the Board 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

Nancy Buese - Chief Financial Officer of MarkWest Energy GP LLC, Chief Accounting Officer of MarkWest Energy GP LLC and Senior Vice President of MarkWest Energy GP LLC

Dan Campbell - Investor Relations Officer of MarkWest Energy GP LLC and Treasurer of MarkWest Energy GP LLC

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

Randy Nickerson - Chief Commercial Officer of MarkWest Energy GP L.L.C and Senior Vice President of MarkWest Energy GP L L C

Analysts

Sean Wells - RBC Capital Markets, LLC

Vince Maddi

Heejong Ryoo

Louis Shamie - Zimmer Lucas

John Edwards - Morgan Keegan & Company, Inc.

Michael Blum - Wells Fargo Securities, LLC

MarkWest Energy Partners LP (MWE) Q1 2011 Earnings Call May 10, 2011 4:00 PM ET

Operator

Welcome to the MarkWest Energy Partners First Quarter 2011 Earnings Conference Call. [Operator Instructions] This call is being recorded. I will now turn the call over to Dan Campbell. Thank you, sir, you may begin.

Dan Campbell

Thank you, Sarah, and welcome to everyone who's joined us today on the call. Our comments today will include forward-looking statements, which involve risks and uncertainties that are not guarantees of future performance. Actual results could vary significantly from those expressed or implied in such statements. And 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 that we file with the SEC. And we encourage you to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading Risk Factors.

And with that, I'll turn the call over to Frank Semple, our Chairman, President and CEO.

Frank Semple

Good afternoon, and thank you, everyone, for joining us on the call today. We started the year with a strong quarter, including record distributable cash flow, increased distributions and a closing of a very strategic acquisition of EQT's processing asset in Kentucky. During the call today, I'll give an overview of our financial performance, provide a commercial and operational update and then conclude with a review of our balance sheet and our updated guidance. We'll then respond to your questions.

Beginning with our financial performance, distributable cash flow during the first quarter was a record $76 million, adjusted EBITDA was $96 million and segment operating income was $148 million. In April, we announced a first quarter distribution of $0.67 per common unit, which reflects our long-term objective of delivering sustainable, top-quartile total returns for our unitholders. With a strong balance sheet and distribution coverage ratio, we are very well-positioned to continue executing our growth strategy in 2011 and beyond.

Moving to the operational update. Our focus for the last several years has been to continue expanding our presence in liquids-rich resource plays that provides superior economics for our producer customers and solid results for MarkWest. As a result of our success in executing this strategy, we continue to see growing gas and liquid volumes in many of our systems. Our strong performance in the first quarter demonstrates the continued success of our strategy. As I'll mention later, the strong forward commodity market has also provided an opportunity to lock in high margins and increase our future hedge positions.

In our Western Oklahoma operating area, which includes both our Foss Lake and Granite Wash systems, gathering volumes during the first quarter of 2011 averaged 207 MMcf/d, an increase of approximately 6% compared to the fourth quarter of 2010. Most notably, our Granite Wash volumes increased to more than 130 MMcf/d in the first quarter. The liquids-rich volumes in the Granite Wash continue to expand rapidly and as a result, we have increased the size of our Arapaho processing expansion to 75 MMcf/d from the 60 MMcf/d we announced earlier this year.

When that expansion comes online in the third quarter of this year, our total processing capacity will be 235 MMcf/d. The Granite Wash continues to be one of the most profitable and active plays in the U.S. and MarkWest is ideally positioned to further expand our presence in the Granite Wash and surrounding areas.

In Southeast Oklahoma, our overall gathering volumes were approximately 500 MMcf/d in the first quarter, which was essentially flat compared to the fourth quarter. On our last earnings call, I mentioned that our volumes in Southeast Oklahoma may decline somewhat over the course of the year due to soft gas prices. But we are pleased that volumes continued to show strength in the first quarter. The strong volumes are primarily due to drilling activity by the Newfield, BP, XTO, PetroQuest and others, which are experiencing great results in the Woodford.

Several of our producer customers, particularly Newfield, are focused on the liquids-rich area of this play. As a result, the volumes that we process in the Woodford have nearly doubled in the past year to more than 100 MMcf/d. While overall gas volumes may decrease slightly in 2011, we believe the new liquids-rich focus and the consistent drilling activity will continue to deliver solid performance in Southeast Oklahoma.

At current activity levels, there are well over 30 years of drilling locations to fully develop the Woodford Shale. In our Carthage system in East Texas, gathering volumes during the first quarter averaged 425 MMcf/d, a slight increase compared to the fourth quarter. As a result of strong processing margins, our producer customers are once again exploiting the liquids-rich Cotton Valley formation. The producers also continue to drill both rich and lean Haynesville wells behind our Carthage system. While our forecast of relatively flat volumes in East Texas in 2011 has not changed, we are very encouraged with the strong drilling activity in the first quarter.

Our Javelina Plant in Corpus Christi provides important diversity and stability to our cash flows and continues to perform well, both operationally and financially. Javelina delivers critical processing, fractionation and marketing services to refineries at Corpus Christi and we have seen a significant increase in the demand from Gulf Coast petrochemical companies for the ethane, ethylene, hydrogen and other products we produce at Javelina.

Now let's move to our operations in the Northeast. In our Southern Appalachia operating area, which includes the Siloam fractionation and marketing complex and 5 processing facilities in Kentucky and West Virginia, gas processing volumes increased significantly in the first quarter. This increase was primarily a result of our acquisition of EQT's Langley processing complex.

NGL sales volumes also increased in the first quarter by approximately 11% compared to the fourth quarter, primarily due to strong seasonal demand for NGLs. We continue to fractionate record volumes at Siloam driven by the significant volume growth of butane and heavier NGLs from our Marcellus operations and continued strong volumes from Langley.

Our Siloam complex will continue to fractionate the heavier NGLs from our Marcellus operations until our Houston, Pennsylvania fractionator comes online in the third quarter of this year. The Langley acquisition was a very strategic transaction that further strengthens our franchise position in Kentucky and West Virginia. This infrastructure is critical in the support of EQT and other producers' ongoing development of multiple shale formations in this region.

From an operational perspective, the integration has gone very smoothly, primarily because we were already familiar with the Langley facility as a result of our long-term relationship with EQT and the proximity of our Boldman plant to Langley. We were delighted to welcome 14 employees from EQT and they're already making a great contribution to MarkWest.

As we look forward, one of the key benefits of the acquisition is the associated growth capital that will further strengthen our competitive position. The first project is to complete the Ranger NGL pipeline, which will eliminate the trucking of Langley NGLs to our Siloam fractionator. We're ahead of our schedule and expect to complete the pipeline construction late this year. Another key project is the installation of 60 MMcf/d of additional cryogenic processing capacity at the Langley complex that will provide EQT with increased processing capacity and greater NGL recoveries. It's also exciting to note that several of the growth opportunity that we identified at the time of the acquisition may allow us to significantly increase the size of the planned processing expansion.

Overall, the acquisition is ahead of plan relative to our transaction economics and we're very pleased with the strategic addition of our operations in West Virginia and Kentucky.

In our Liberty segment, 2011 is also off to a great start. Compared to the first quarter of last year, processed volumes nearly tripled, gathered volumes doubled and NGL production increased 2.5x. Many industry experts consider the Marcellus to be the second largest gas field in the world and this significant shale play is a game changer for natural gas supply in the U.S. We're very fortunate to work with the leading Marcellus producers, as well as with The Energy & Minerals Group, our MarkWest Liberty partner.

As we discussed on the fourth quarter call, we have numerous expansion projects underway to our Liberty gathering and processing systems. I'm very pleased to report that in late April, we commenced operation of our Houston III cryogenic processing plant, which had the capacity of 200 MMcf/d. I'm very proud of our entire team who continues to work incredibly hard to meet our customers' objectives. And by the end of this quarter, when the Majorsville II plant comes online, our team will have installed 620 MMcf/d of Marcellus processing capacity in less than 36 months.

Looking forward, by mid-2012, MarkWest Liberty's processing capacity will grow to nearly 1 Bcf/d, essentially all of which is supported by long-term contracts. This is pretty spectacular growth when you consider that in mid-2008, we did not have any asset in the Marcellus. We're also pleased to report that for our producer customers, we are now ahead of the wet production curve and we believe that processing limitations are no longer a factor.

Our forecasted capacity in mid-2012 includes the completion of two additional cryogenic processing complexes in northern West Virginia. The first is Mobley, a 120 MMcf/d complex that will primarily serve liquids-rich gas transported in EQT's Equitrans gas pipeline. The second is a 200 MMcf/d processing complex that will serve producer customers and is supported by recently executed long-term agreements, the terms of which are confidential. This is an exciting new addition to our Marcellus growth plans and we look forward to sharing more details with you in the future.

We're in the process of expanding our NGL gathering system to connect these two plants to our Houston fractionator.

With the start up of Houston III plant, we have completed the front end of the 60,000-barrel per day C3-plus fractionator and we have the capacity to produce 35,000 barrels per day of purity propane and 25,000 barrels per day of a butane and natural gasoline mix. Near the end of the third quarter, we will complete the remaining portion of the Liberty fractionator and we'll be able to produce purity iso-butane, normal butane and natural gasoline at our Houston facility. This will allow us to eliminate trucking cost to Siloam and to fully capture the premium market for the purity products in the Northeast.

We are also evaluating the installation of a normal butane isomerization unit to maximize the production of the high-value iso-butane in the Northeast markets. Our Houston complex is ideally located with great access to premium local truck market, as well as being connected directly to TEPCO pipeline on which we have nearly 1.3 million barrels of NGL storage.

In addition, in the fourth quarter, we will complete the first phase of a 50,000-barrel per day rail-loading facility. This addition to our Houston complex, coupled with our local truck access, significantly enhances our ability to take advantage of the premium Northeast NGL market.

We're also making great progress on the 7-mile extension of our Majorsville NGL pipeline to receive Chesapeake's and Statoil's mixed NGLs from the Caiman Energy Fort Beeler processing plant. This pipeline will transport NGLs to the Houston complex for fractionation, allowing Chesapeake and Statoil to benefit from our integrated NGL fractionation and marketing system.

The final piece of the NGL value chain is ethane. Since the beginning of our Liberty development, we have included in our design the ability to recover ethane at our processing plants and to transport the ethane in our NGL gathering system. With the installation of ethane fractionation facilities at our Houston complex, we will provide a central production point to deliver ethane into any of the potential ethane pipeline projects. So regardless of which ethane pipeline project is completed, we will play a key role in the ethane solution for the Marcellus.

Within 2 months, we will have the processing capacity to recover more than 40,000 barrels per day of ethane and by mid-2012, that capacity will increase to 70,000 barrels per day. While the producers will only need us to recover roughly 1/3 of this volume to meet interstate gas pipelines specs, our processing infrastructure provides significant capacity to support multiple ethane takeaway projects.

Now let me spend a minute and provide an update on the Mariner Projects. As a reminder, our joint effort with Sunoco Logistics has expanded to include two independent Mariner Projects. Mariner East will transport 50,000 barrels per day of Marcellus ethane to premium Gulf Coast markets via pipeline and marine vessels beginning in mid-2013. Mariner East has a significant advantage relative to the other announced ethane projects, including lowest cost -- the lowest capital cost and the unique ability to deliver ethane to multiple markets, including the premium Gulf Coast market, rapidly evolving international markets and potential future ethane crackers in the Northeast.

The second project is Mariner West, which would be able to transport up to 65,000 barrels per day of Marcellus ethane to Sarnia markets in the second half of 2012. To support Mariner West, we will construct a 45-mile pipeline in the Houston complex to an interconnection with an existing Sunoco pipeline at Vanport, Pennsylvania. The ethane will then be transported from Vanport to markets in Sarnia, utilizing existing Sunoco pipelines, which will be modified for ethane service.

To conclude the discussion regarding ethane, I want to emphasize that MarkWest has been the leader in developing midstream infrastructure to support our producers in the liquids-rich area of the Marcellus where ethane provides an economic uplift opportunity. With the growing demand for ethane as a feedstock for U.S. petrochemical companies, the Marcellus will play key role in meeting the increasing demand, and we are committed to helping the producers maximize the value of their ethane.

Before moving on to our financials, I want to reiterate our long-term vision for the Appalachian region. We believe the liquids-rich shale production in Appalachia will extend from the Huron/Berea shale in southeastern Kentucky to the Marcellus shale in northern West Virginia and Southwest Pennsylvania. MarkWest is uniquely positioned to capitalize on this growth given our existing NGL capabilities with multiple processing facilities and extensive NGL pipeline network, strategic downstream market access and two large fractionation marketing and storage complexes.

Our vision is to ultimately connect our two existing systems, serving Appalachia with fully integrated scalable midstream solutions that will allow our producer customers to fully develop the multiple resource plays in this basin.

Now turning to the balance sheet. We also had a very productive and active first quarter. Given the significant growth of our business, we continue to focus on the right timing and size of capital market activities to fund our capital expenditures, while consistently improving our credit metrics and maintaining a strong liquidity position.

During the first quarter, we completed several capital market transactions including an equity offering and two senior note offerings. The proceeds were used to fund the EQT acquisition, as well as the refinancing of our 2016 and 2018 senior notes. These transactions were well executed and very well received by the market. The refinancing of our 2016 and 2018 notes resulted in a reduction in annual interest expense of approximately $6 million and significantly extended the maturity of our debt.

Overall, our weighted average cost of capital has come down by more than 200 basis points in the past year and we have funded our capital requirements well in advance of our needs. Today, we have available liquidity of more than $550 million and the next maturity of our senior notes is not until 2018.

We ended the quarter with total debt of $1.5 billion comprised primarily of long-term debt. Our debt-to-total capital is 49%, our leverage ratio is 3.8x and our interest coverage ratio remains a healthy 3.6x.

One of our long-term objectives is to continue increasing our fee-based operating margin. With our contracts in the rapidly growing Marcellus operations, we forecast our fee-based operating margins will increase to approximately 50% by the end of 2012. We continue to execute our rolling 36-month hedging program to manage the risk associated with commodity price exposure and to lock in future cash flows. We've also aggressively executed on future hedge transactions to lock in current high prices and processing margins.

The futures market for direct product hedges was strong in the first quarter and we recently entered into several direct product hedges for 2013 and 2014 at historically high margins. For 2011 and 2012, we are fully hedged, which because of operational considerations, is between 65% and 70% of our NGL production. For 2013 and 2014, we are hedged at approximately 45% and 15%, respectively.

A disciplined hedge program is a critical part of our strategy and we will continue to execute a range of hedge transactions to lock in solid margins and to secure a large percentage of the commodity sensitive portion of our future distributable cash flow.

Before concluding, I want to briefly discuss our updated guidance for 2011. We have increased our forecasted 2011 DCF from a range of $260 million to $310 million to a new range of $280 million to $320 million. This increase is primarily due to updated forecast for each of our operating areas, including growth projects currently under construction, as well as a higher commodity price strip. The midpoint of the updated DCF guidance range results in 25% year-over-year DCF growth and provides a coverage ratio of 1.5x for the full year at our current distribution and units outstanding.

This coverage provides us with plenty of room for continued distribution growth. On a DCF per unit basis, the midpoint of our 2011 DCF guidance results in 15% growth of DCF per unit year-over-year. As always, we included in our earnings release a sensitivity table that shows the impact on 2011 DCF of various crude and natural gas prices as well as NGL correlations.

We also updated our 2011 growth capital forecast to a range of $650 million to $700 million, which includes the $230 million Langley acquisition. The increase in our capital forecast reflects recently executed agreements. Our growth capital program continues to fund high-quality largely fee-based projects in our key operating areas.

In summary, 2011 is shaping up to be another record year. With our diverse set of assets and growing resource plays, we are very well-positioned to continue developing high-quality midstream solutions for our producer customers. These growth opportunities, coupled with the strength of our balance sheet, continue to provide sustainable distribution growth and will allow us to achieve our objective of providing long-term top-quartile total returns for our unitholders.

So with that, Sarah, let's open it up to questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question is from John Edwards.

John Edwards - Morgan Keegan & Company, Inc.

It's Morgan Keegan. I guess kind of macro looking on some macro issues, I guess, what in terms of the total production outlook in the Marcellus and then I guess production outlook in the areas where you're focused, how do you view that? And then also, in terms of investable opportunities, I'm trying to get an idea of how many years you think you'll be investing at the current pace, sort of this $400 million to $600 million, I guess. And then what's the likelihood, do you think, of being able to grow that given what looks like a pretty huge opportunity set in front of you?

Frank Semple

Okay. John, just to get three different pieces to that question. And just starting at the high level. The question about production, primarily, I think in the Marcellus and then kind of expanding out to the rest of the areas of operation. And then how does that drive CapEx and how we're going to support that. First of all, I think it's important to note that as we put together our forecast, and we do this, we basically put together each year, we update our 5-year forecast, it's based on fairly close coordination with our producer customers in terms of their drilling programs and the economics of their drilling program and the production forecast that result. And I think I would -- the way I would try to answer that question is to say that if you look at it -- if you look at that forecast, our stated -- the comment that I made in several of our last quarterly calls has been that we believe that those drilling programs, that overall production forecast for all of our areas would result in roughly a $300 million of CapEx for administering facilities. Again that's net of the Liberty PNG contributions for total CapEx for the next several years. And I feel pretty strongly as we look at those forecast, in the areas that we operate, these growing resource plays and economics of particularly the wet area of those resource plays that we can support over the next 3 to 5 years that kind of capital. And again that's net of EMG and that's also net of acquisitions, like the recent EQT acquisition. Now having said that, if you kind of then go a little bit more micro and think about the next couple of years, the good news about our forecast and our discussions about future growth opportunities is that for the next several years, we already have projects and agreements in place that really support that kind of CapEx over the next several years just with our current project schedules. So it's easy for you do the math. And it's very easy to support those kind of CapEx productions. The majority of that CapEx, that I've been discussing, definitely will be in the Northeast, in the growing resource plays in the Northeast of the Marcellus, the Huron, Berea, the Utica, and we're very pleased to be in those areas. But again, the majority of that CapEx will, no doubt, be in that area. But the other areas, the Granite Wash, the Woodford, the Haynesville, Cotton Valley in East Texas, all will contribute to that growth.

John Edwards - Morgan Keegan & Company, Inc.

Okay, so if I hear you right, you're basically saying given the agreements you already have in place, you can already support $300 million in annual CapEx pretty much for the next 3 to 5 years. And so potentially with new agreements, there'll be potential upside in terms of investment opportunities, am I understanding correctly?

Frank Semple

Just one slight correction to that summary. What I said is that we feel pretty comfortable based on the agreements that we have in place, the relationship we have with our producer customers that for the next 3 or 5 years, we can sustain that kind of capital programs in the growing resource plays. The next couple of years, it's much more supportive because we already have contracts and agreements in place to support the pipelines, the plants, the fractionation, the NGL infrastructure to support that kind of capital. So again, we've tried to be very transparent for the investors and the analysts on what that CapEx looks like, the rough economics that result from those investments and what the resulting EBITDA and DCF and DCF per unit will be. So it should be easy to do the math.

John Edwards - Morgan Keegan & Company, Inc.

Okay. And then in terms of potential upside from that, I guess, how would you assess potential upside beyond the sort of this $300 million, what sounds like a rough -- potentially a $300 million floor for the next 3 to 5 years?

Frank Semple

Well, we're working incredibly hard to develop new projects, both within our existing operating areas as well as in new areas of development. So we, again, we have a pretty good track record, John, of supplementing kind of that base capital with new projects. And we continue to be very active in the acquisition market and very active in developing new greenfield opportunities in growing resource plays, particularly, wet areas of those resource plays. Our strategy as you know is to be able to work with our producer customers, provide really good customer services and to be able to help them develop their production in those areas with midstream services. So obviously, we continue to talk to them about where they see the next game changer and be a part of that. So I think that I would assess our opportunities for increasing those projects above and beyond our core project opportunities is good.

Operator

[Operator Instructions] Our next question is from Helen Ryoo.

Heejong Ryoo

Yes, this is Barclays Capital. Frank, you touched upon this in your Mariner comment, but it seems like regardless of which ethane solution becomes the firm project, your economics would not be that different because you would be making incremental fee on the ethane front, is that correct characterization?

Frank Semple

Helen, that's exactly correct and the point we continue to make -- I mean, the deal to prepare and ultimately support the ethane solution has required a lot of preparation in the, not only, the ability to recover the ethane through our existing processing plants, which I mentioned in our formal comments is something that we've been doing from day one, but it also takes a lot of preparations from an NGL infrastructure and marketing perspective. So that's where the value really is created for us. And if you just kind of think about what's occurring in the Marcellus, we are building plants that have that capability to extract the ethane, transport the ethane, ultimately extract the ethane at our Houston facility. So the ethane will be -- that will be the origination of any ethane pipeline project and obviously, we have been very consistent in our comments that our goal for the producers relative to ethane is provide them with options, provide them the ability to create as much value as they can for the ethane that they are producing. And so that's been our goal. And as you said, whether it's Mariner East or Mariner West or both Mariner East and Mariner West and even a different project, the economics and value that we're creating really comes from the -- all of the other ethane facilities that we are providing for the producer customers.

Heejong Ryoo

All right. And then just a follow up to that, I guess, does your current CapEx include about was it a 60,000 barrels per day deethanizer, is that currently in your CapEx? And if that's the case, I mean, if you have both Mariner Projects take off, you will be shipping out much more than that, so do you need to increase the deethanizer capacity?

Frank Semple

That's correct. That is exactly right. And it's probably important -- I'll turn this over to Randy to make a couple of comments, but that calculation that you're making is probably something we should be more clear about because we are, I would say, as we ramp up our production capabilities, that includes the recovery of ethane, then that ramp up essentially has to match the takeaway capacity for the ethane pipelines. Randy, do you want to mention something?

Randy Nickerson

Yes. Building on exactly what you said, and maybe just a clarification, the 2011 capital budget that we have really doesn't require much capital for the ethane projects. All of the deethanizer and the changes of the plant we've talked about, that really would probably occur in the 2012 time frame. We're in the middle of the design part of that, but obviously the capital, when you're just sort of doing paper design is de minimis compared to when we're out there putting steel in the ground and that will occur 2012, 2013. So 2011 does not include very much at all of capital. '12 and '13 we would expect where it's up.

Frank Semple

That basically, that capital in 2012, 2013 is for that final stage of fractionation. That will provide the purity ethane for these markets that we discussed.

Heejong Ryoo

Right. And you would maybe have to increase the deethanizer capacity by like 125,000 because you have 65,000 to Sarnia, 50,000 to Gulf? Or even if you have those 2 projects from that, you may not need that much? I mean, could you provide some color?

Randy Nickerson

It's -- just to the high level, it's very possible that the tower, just because of the size of the equipment itself, we will not be installing one single tower at that Houston to provide the deethanization. It will probably be two or perhaps even three towers. It will be very easy for us to sort of cost-effectively match the deethanization with the needs of the project. And since many of these projects are 2-, 3-, sort of, year projects, we can very, very easily, in that time frame, install whatever deethanization matches the project. So from that standpoint, deethanization is probably the easiest part of the project just from a timing standpoint.

Heejong Ryoo

Okay, that's very helpful. Just moving on to the CapEx, I guess, gross CapEx, you increased it by about $50 million compared to your previous guidance and I think you mentioned you're increasing the Arapaho plant by $15 million. What were the other projects that got included?

Frank Semple

Really, the other project is the 200 million a day processing complex that I mentioned in my formal comments to support this new project that's under confidentiality.

Heejong Ryoo

Okay. I'm sorry, was that in Marcellus or I think I missed that one?

Frank Semple

Yes, that's a Marcellus Liberty project.

Heejong Ryoo

Got it, okay. And that's part of the $50 million increase?

Frank Semple

Correct.

Heejong Ryoo

Okay. And then, I guess, just lastly on the Gulf Coast segment. I think, Javelina margin was down year-over-year and volume was down, could you just talk about what's going on there and maybe what you expect to see going forward?

Frank Semple

Yes, just basically an operational turnaround that you'll see periodically already 18 months or so that will create a little bit of variability quarter-to-quarter, but that was a turnaround.

Heejong Ryoo

Okay, so you don't expect Javelina to be materially down from previous year?

Frank Semple

No, no. It runs pretty much at max capacity day after day. And the end of quality of the gas that comes into Javelina is pretty constant.

Operator

Our next question is from Michael Blum.

Michael Blum - Wells Fargo Securities, LLC

Wells Fargo. Just a couple of questions for me. Number one, just in terms of any update on timing for the potential Mariner Projects or any other projects? And sort of, I guess, any color you can provide in terms of, to be just frank about it, what's taking you so long for -- what are the sticking points in terms of a solution being announced ultimately?

Frank Semple

Okay. Not surprising that you asked that question, Michael. Yes, Mariner, both Mariner Projects still are on track for the 2012 and 2013 time frame. 2012, kind of second half 2012 for Mariner West, and mid-2013 for Mariner East. And I know there continues to be some frustration from the analysts and the investors about not being able to provide more clarity on the progress and the process, but it's actually probably a good news story. I mean, it's a very complex market out there right now for ethane and with the economics of ethane changing fairly rapidly, even over the last several quarters, that enters into the negotiations between the producers and the petrochemical companies on the right structure and the right price, if you will, for the purchase and sale of that ethane, of that purity ethane. So I think it's understandable that as these negotiations proceed, there's a lot at stake in getting it right. We were pleased with the recent announcements by Range and Dow in the Gulf Coast and NOVA in Sarnia for these replacement MOU announcement because that demonstrates progress. And as I've stated on previous calls, the completion of the agreements between the buyers and sellers of the ethane in these markets is really the critical next step. We have been working with Sunoco and continuing to move forward on the physical side of this equation, the design of the facilities that will need to be in place over these 2 time periods. And because we expect that once the purchase and sale agreements are in place and the transportation agreements are in place, hopefully, sooner rather than later, that we will have to move quickly with Sunoco to complete the projects. So again, just in summary, I'd say, even though it still is a little bit unsatisfying to hear that we're still not to a point where we can announce the projects definitively, there has been progress on the various critical commercial parts of this ethane solution.

Randy Nickerson

Yes, Michael, Randy. Building on just on what Frank said, that I think one of the complicating things in -- and we're in many of those conversations because we're here to support the producers sort of working through a lot of the complex stuff, and so we end up being involved in a lot of that, but I think one of the complicating factors of course is obviously it takes no, one, single producer can push a project. It takes multiple producers and all of those producers sort of are in a different stage of their development, they have different plans, different time frame and that sort adds, I think, a layer of complexity. The other thing, I think, that makes the Marcellus exciting, but also makes it somewhat challenging, is that it's not just one market, right? Each of the producers are, again, looking at Sarnia, they're looking at -- so Canadian markets, looking to Gulf Coast market, they're all looking at international markets and so when you sort of add the mix of multiple producers, all coming up with new projects, with different time frames, all sort of evaluating the costs and real benefits of the different projects, it's been fairly -- it's taken a lot to put it all together, but the fact that they are coming together, it's just -- it's taking longer than any of us probably would have stepped out and expected, say, 6 months ago.

Michael Blum - Wells Fargo Securities, LLC

Okay, that's helpful. My second question, it seems like there's increasing rhetoric around frac-ing technology and the impact on water and the environment, et cetera. I guess, from your perspective, sitting in the Marcellus and talking to all of your producer customers, how real do you see the risk of any sort of meaningful curtailment in development because of regulatory oversight or otherwise?

Frank Semple

Well, this issue, you can't discount the concern that we all have about the -- as you said, the rhetoric. I think the rhetoric has created a huge amount of focus and sensitivity, not only for the industry but also the states that we operate in, at the highest levels. I was at a meeting a couple of weeks ago with the governor with a number of the other industry CEOs and the message was very clear, that the Marcellus could be a game changer for the state of Pennsylvania and for the industry. And it should be. But it's very -- it's incumbent on the operators, the producers, the midstream providers to ensure that they are operating in a safe manner. And to be very conscious about the critical -- how critical communications are about the concerns by the public on all aspects of the production and transportation and processing and fractionation of natural gas. So there's incredible amount focus by us and our producer customers on being responsive to these issues, to operate safely, in an environmentally responsible manner, and also make sure that there's -- basically, there's an open book. There's a huge amount of transparency in terms of how we're operating and I think that, that's really critical going forward. Now coming full circle to the initial part of your question, do we have concern that there will be curtailment? We are not factoring in to our plans any impact on production from the rhetoric, if you will, of frac-ing technology in particular, because we feel like the industry will continue to be very responsive and responsible in terms of how they're operating, but it's something that we just need to keep a real focus on.

Operator

Our next question, from Vince Maddi.

Vince Maddi

It's Vince Maddi, SIR. Just 3 questions. The first is, can you guys give us any guidance on what deferred revenue is likely to look like for the rest of the year, is that a known number or a knowable number?

Nancy Buese

Yes, you're talking about the revenue deferral adjustment benefit?

Vince Maddi

Yes, the $7.9 million or whatever it was in the first...

Nancy Buese

Yes, and that's really relative to some contracts where the GAAP revenue recognition doesn't really match DCF revenue recognition and it's really a timing difference in the recognition of those contracts. And probably a good run rate for you to think about going forward is probably about $2 million a quarter and then that will reverse over time.

Vince Maddi

So quite a bit lower than the first quarter then?

Nancy Buese

Yes.

Vince Maddi

Okay. And then 2 other questions. You had 2/3 of the quarter of the equitable acquisition that I think ran to the Northeast, processing volumes were up pretty significantly in the first quarter, should they be up more in the second quarter as well as you get a full quarter in there or is that -- there's some seasonality in there? How much did that contribute in the first quarter?

Frank Semple

I would just take, yes, basically 2/3 of the quarter.

Vince Maddi

Or whatever the delta was between Q1 and 4Q?

Randy Nickerson

Yes, sort of -- building on that, I think it's important to note that all of those -- all of the liquids that came from the EQT transaction already came into our system. So the fact that we own the facility as opposed to EQT owning the facility, really doesn't change the production numbers. What it obviously changes -- so when you see those in terms of the volume, make sure we're separating those out between volumes of liquid and volumes of gas.

Frank Semple

And I think the issue is, are we talking about the operating income, Vince?

Vince Maddi

No, no. I'm really just trying to figure out just in terms of the volumes, which obviously may have some impact on how operating income is. . .

Frank Semple

John, go ahead.

John Mollenkopf

The Langley facility is processing about 135 MMcf/d and so we closed our acquisition on February 1, I believe. And so we've had that extra 135 MMcf/d and we expect that volume to be there or maybe a little bit higher in the remainder of the year, maybe 140 MMcf/d or so adding to the volumes.

Vince Maddi

So if I added about 1/3 of that 2Q that would give you a run rate for the full quarter of equitable?

John Mollenkopf

Yes, I think that makes sense because we did not have -- we didn't recognize the volumes in January.

Randy Nickerson

Yes, for gas volumes, that's absolutely correct. Gas volumes are additive, NGL volumes have always been there so a little confusing but...

Vince Maddi

There's no real change in the NGL volumes basically?

Randy Nickerson

No change in the NGL volumes.

Vince Maddi

Okay. And this is maybe a little longer-term question but in your discussions of how much ethane, at least you'll have the capacity to produce, your liquids in Liberty are -- I think, ran about 13,700 barrels a day in the first quarter. When do we start to see the ethane volumes? Is it coming all at once when Mariner comes on or are there some projects in between now and then when in fact -- it will go out by truck or rail will be used locally or some other -- what's the timing of that and how do we think about that in terms of...

Randy Nickerson

There's been a lot of discussions, a lot of smaller projects that could take incremental volumes, you blend a little bit, you do a lot of the small things. But the big picture answer is ethane volumes come on, all at once sort of step function to support one of the pipeline projects.

Vince Maddi

So no real impact on NGL production in Liberty until mid-'13?

Randy Nickerson

No, real impact of ethane on NGL volumes. One thing it is, we've talked about that a little bit earlier. Today, we are gathering 180 million or so of gas into Houston and processing another, we'll call it, 120 million day of gas at Majorsville. So if you add those two together, then say, well it's around 300 million. In Frank's comments, he mentioned we've signed agreements that come darn close to filling about 1 Bcf a day of gas. So there's going to be a lot of volume growth of NGLs ignoring ethane and then of course, when ethane comes on, then the volumes grow to match sort of whatever project comes online.

Vince Maddi

Right. So the non-ethane volumes will grow as the processing grows and then when you can actually start to strip ethane, even at a fixed capacity level, your NGL volumes will grow quite substantially because it's a big chunk of the NGL stream, is that how to think about it?

Randy Nickerson

Exactly. It's going to be a step change. So if we have 2 to 2.5 gallons per MMcf of C3-pluses, those are going to grow ratably with gas volumes. We suddenly turn on ethane and we have is sort of maybe as little as 1.5 gallons per GPM up to 3 to 3.5 gallons that could come on very quickly to support an ethane project. So the guess is, obviously, that we're going to see an enormous step change beginning at some time.

Operator

Our next question is from Louis Shamie.

Louis Shamie - Zimmer Lucas

I'm with Zimmer Lucas Capital. Great quarter and great change to the guidance. I guess my question kind of stems from the guidance and if you keep your distributions flat, you said that at the midpoint you'd be covering about 1.5x. Just wondering what the distribution policy is going to look like over the next couple of years being that you do have this very dramatic increase in distributable cash flow per unit, what the pace is going to be for increasing the pay out there?

Frank Semple

Well, Louis, there is no policy, first of all, on the distribution growth. Obviously, as we continue to grow our DCF and finance our business, we will continue to distribute -- increase our distribution to provide as much return, the highest return to our unitholders as possible, while still maintaining reasonable coverage ratio. And you are very good at modeling our business and you obviously have to factor in what our financing requirements will be, and I've made the -- I continue to make the statement about the fact that we're very, very sensitive to delivering a sustainable distribution growth year-over-year that kind of puts us at the top of the industry from a total return standpoint. And we feel like with the projects that we have clearly in front of us, that are going to deliver fairly significant increases in DCF and DCF per unit, that we will be able to accomplish it, be able to maintain kind of top-quartile total-return performance and maintain a reasonable coverage ratio, a conservative coverage ratio and I say conservative coverage ratio, I continue to think that, that may vary quarter-over-quarter but somewhere in that 1.2 to 1.3 range feels about feels about right. So we have a lot of room for growth from a distribution standpoint.

Louis Shamie - Zimmer Lucas

Great. And then when it comes to Liberty, if you look at kind of the fee exposure there versus the commodity-based exposure, how would do you break that out and how is that changing over time?

Frank Semple

Liberty is -- if you think about it, it basically is all fee-based. I mean, we have a bit of a commodity component there but it's insignificant when -- at the level that we're achieving now from an operating income standpoint.

Randy Nickerson

Yes, adding on to that. You're exactly right. I think, let me see, the actual number is somewhat just less than 80% now, but is fee-based and that grows up as we build on that. That ends up looking a lot more like, I think, about 80% fee-based for Liberty, maybe a little bit higher than that. But yes, so an awful -- as Frank said, and awful, awful lot of Liberty ends up being sort of purely fee-based.

Louis Shamie - Zimmer Lucas

Great. And then when you're able to market the ethane, does that increase the fee stream there? Is that the plan?

Randy Nickerson

Absolutely. Yes, yes. Everything related to ethane, every part of the value chain where there would be a fee-based value chain. So from a MarkWest perspective, that would certainly enhance, grow and improve that fee-based nature.

Frank Semple

So for ethane, just to clarify, [indiscernible] Fractionation fees and then to the extent that we transport, there'll be transportation fees.

Operator

We have time for one final question from Sean Wells.

Sean Wells - RBC Capital Markets, LLC

RBC Capital Markets. I guess, I just wanted to piggyback on Louis' question. You guys have been quoting the fact that by 2012 you're targeting 50% of your operating margin being fee-based and so you've been quoting that for like I said, a couple of quarters. But since that time, you've been adding on some more processing projects. So why isn't that number improved to like 60% or 65%?

Frank Semple

Well, you're correct. That 50% has been a target or kind of a point that we've made over the last year or so and that was based and continues to be based on our forecast of obviously the fee-based and the commodity-based gross margin. And what's happening is that the commodity-based gross margin continues to be a bigger number and so you had that all being offset by the fee-based growth primarily from Liberty and so it's just kind of the math around those two components, the fee-based contribution to the fee-based operating margin as it continued to grow, and it actually ramps up fairly rapidly through the end of this year and into 2012. But with the current commodity price strip, that bogey of 50% gets harder and harder as the commodity gross margin grows. So hopefully that's helps, but that's what happened. You've got two pieces that are moving in different directions.

Sean Wells - RBC Capital Markets, LLC

Right. Okay, that make sense. And I just have one last question and it has to do with the Arkoma Connector Pipeline. Volumes fell out -- dropped sequentially and year-over-year and I was just wondering what was going on there?

Frank Semple

Yes, we had -- I'll let Randy jump in, we had a phenomena last year that involved one of the other pipeline transportation company in Oklahoma that essentially brought more volumes to our system because of issues that they had. So you saw kind of an increase in 2010 that went away, essentially, when they resolved their operating issues. So is that. . .

Randy Nickerson

Yes, that's exactly right. I think the current levels are about the run rate we expect going forward, you hit it exactly.

Frank Semple

So what you're seeing right now is, in terms of volumes, is basically what you'd expect. This is basically a fee-based interstate pipeline system that runs -- should run fairly consistently day after day, month after month, quarter after quarter.

Sean Wells - RBC Capital Markets, LLC

And what's the capacity of the pipeline again?

Randy Nickerson

Capacity of pipeline is just in the neighborhood of 600,000 decatherms a day. I think it's just slightly over 600,000 decatherms a day off the top of my head.

Operator

Now I'd like to turn the call back over to Frank Semple for closing remarks. Sir?

Frank Semple

Well, thanks, Sarah, and thanks for everybody for joining us on the conference call today. We really appreciate your interest and continued support. And as always, if you've got any follow-up questions, feel free to give any of us a call. Certainly, Dan Campbell is the point person for those questions. So again, thanks a lot and that concludes our call for today.

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