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Executives

Dan Campbell - Vice President of Finance - Markwest Energy Gp Llc and Treasurer of Markwest Energy Gp, L.L.C

Frank M. 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

Analysts

John Edwards

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

TJ Schultz - RBC Capital Markets, LLC, Research Division

Unknown Analyst

John K. Tysseland - Citigroup Inc, Research Division

MarkWest Energy Partners LP (MWE) Q4 2011 Earnings Call February 29, 2012 4:00 PM ET

Operator

Welcome to the MarkWest Energy Partners Fourth Quarter 2011 Earnings Conference Call. [Operator Instructions] This call is being recorded. If you have any objections, please disconnect at this time. I would now like to turn the call over to Dan Campbell. Thank you, sir. You may begin.

Dan Campbell

Thank you, Melissa, and we welcome everyone that has joined us on the call today.

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

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

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

Frank M. Semple

Good afternoon, and thanks to everyone for joining us on the call today. As indicated in our earnings release, we finished the year with another record quarter, and we continue to experience strong growth and financial performance from our diverse set of high-quality midstream assets.

Throughout 2011, we saw significant ramp-up in cash flow and distribution growth, which is the direct result of more than $2 billion of strategic investments. These investments were made during the past few years to provide critical infrastructure required by our producer customers to develop their liquids-rich acreage. We also continue to strengthen our balance sheet and liquidity and are in a great position to aggressively develop additional growth opportunities in some of the best resource plays in the U.S.

During the call today, I'll discuss our financial performance and provide a commercial and operational update, including more details on our recently announced Marcellus expansions and our Utica development plans. Finally, I'll review our balance sheet and discuss our 2012 guidance, and then we'll respond to your questions.

Beginning first with a high-level overview of our financial performance, we achieved record distributable cash flow of $88 million during the fourth quarter, an increase of nearly 30% compared to the fourth quarter of 2010. Adjusted EBITDA was a record $128 million and segment operating income was $171 million. In January, we announced a fourth quarter distribution of $0.76 per common unit, an increase of 17% compared to the fourth quarter of 2010, while maintaining a strong distribution coverage ratio of 1.2x for the quarter. It's worth pointing out that the strong coverage ratio included coverage for the issuance of more than 16 million units in the fourth quarter to fund our growth capital projects and the acquisition of the 49% of the Liberty joint venture.

For the full year 2011, which does not include the 49% of the Liberty joint venture that we acquired at year end, DCF was $333 million, an increase of nearly 40% compared to 2010. And adjusted EBITDA for the year was $451 million, a year-over-year increase of 36%. DCF per unit grew 23% in 2011 compared to 2010, and we maintained a coverage ratio of 1.38x for the full year. This is obviously great financial performance and as you will hear, we are not slowing down in 2012.

Now moving to the operational update. Let me begin with our Southwest business unit, which includes our operations in Texas and Oklahoma and contributed nearly 60% for a total segment operating income in the fourth quarter and the full year. Our consolidated basis, our gathering volumes in the Southwest segment increased approximately 2% year-over-year, driven primarily by a 24% increase in rich gas volumes in the Granite Wash, which was offset by slight decreases in Southeast Oklahoma.

During 2011, we commenced operation of a 75 million cubic feet per day expansion at our Arapaho processing complex to support the growth in liquids-rich volumes from the Granite Wash. Our total processing capacity in Western Oklahoma is now 235 million cubic feet per day. And we're currently operating near capacity. The Granite Wash continues to be a very economic play and we continue to evaluate additional opportunities for gathering and processing expansions in Western Oklahoma and the panhandle of Texas.

In Southeast Oklahoma, our gathered volumes remained strong at more than 500 million cubic feet per day, and our processed volumes year-to-date are greater than 100 million cubic feet per day. The volume of gas that we process in Southeast Oklahoma increased by nearly 30% compared to 2010, which continues to provide a healthy uplift in operating margin.

There are tremendous reserves yet to be drilled in the unconventional plays in which we operate in Oklahoma, and we continue to be ideally positioned to further expand our presence in the Southwest. While certain producers have indicated that they are reducing their drilling programs, we have been a very successful in executing agreements with new producer customers and connecting new wells for existing consumers. Overall, we believe our volumes in Oklahoma will increase modestly in 2012.

In East Texas, we continue to see growth opportunities around the Cotton Valley and Haynesville. Last quarter, I mentioned that we were evaluating incremental capacity in East Texas, and I'm pleased to report that we recently signed new long-term agreements with several producer customers, including Chevron, Petroquest and Samson [ph]. They are continuing to aggressively develop the rich gas areas of the Haynesville and the horizontal Cotton Valley. As a result, we're expanding our processing capacity by 120 million cubic feet per day with the addition of the Carthage East [ph] plant, bringing the total processing capacity to 400 million cubic feet per day. Carthage East [ph], which is expected to come online in early 2013, will also increase our gathering and residue gas out leak capacities.

Our East Texas assets continue to be among the most profitable in the company, and with the continued development of the rich Haynesville Shale, we look forward to many more years of superior performance. Our Javelina plant in Corpus Christi, which accounts for nearly 10% of our segment operating income, continues to be a solid performer both operationally and financially. Processed volumes and fractionated barrels were relatively flat in 2011 compared to 2010, while segment operating income increased by more than 10%, primarily as a result of strong purity product prices. Javelina continues to be a key part of our operations and provides important diversity and stability to our cash flows.

Let's move now to our Appalachian operations, where we have 2 business segments: our Liberty business unit, which is our Marcellus operations; and the Northeast segment, who serves the Huron and the Southern Appalachian Basin. We're the largest processor and fractionator in the Northeast United States and we continue to significantly strengthen our leadership position in this critical growth area. Today, on a combined basis, our Northeast and Liberty segments have processing capacity in excess of 1 billion cubic feet per day and fractionation capacity of nearly 85,000 barrels per day, essentially all of which are supported by long-term, high-quality contracts. Equally important is our pipeline network that delivers NGLs to our 2 large fractionation complexes in Kentucky and Pennsylvania. These assets allow us to leverage our significant marketing expertise in the Northeast through our extensive storage, rail, truck, barge and pipeline infrastructure.

In the Northeast segment, our processed volumes increased significantly year-over-year, primarily as result of the Langley acquisition. We also recently completed the Ranger NGL pipeline, which allows us to transport to our Siloam fractionator all of the NGLs that are produced at the Langley complex. In addition, we're currently in the process of increasing the processing capacity at Langley, which will come online later this year. EQT is a significant customer in the Northeast segment and they recently indicated that they are temporarily suspending their drilling program in the Huron as a result of low gas prices. And it isn't surprising that producers are modifying their drilling programs given today's gas price environment, including in liquids-rich areas like the Huron.

Consequently, we expect to see volumes decline modestly in the Northeast segment in 2012, which is included in our updated guidance. Having said that, there are huge natural gas reserves supporting our Kentucky assets. The Huron is still very prospective. And while some producers curtailed drilling in the short-term, we remain focused on staying ahead of our producer customers' long-term midstream requirements, which will allow us to continue investing in strategic, high return projects.

In the Liberty segment, we continued to see significant volume growth in 2011, with gathered volumes increasing by more than 70%, processed volumes increasing by 50%, and fractionated volumes increasing by nearly 3x. Today, we operate an extensive and continuously expanding gathering system, 625 million cubic feet per day of cryogenic processing capacity and a 60,000 barrel per day fractionator.

As many of you know, in December we acquired the 49% of the Liberty joint venture previously owned by The Energy & Minerals Group. We chose to partner with EMG in the Marcellus in early 2009 to provide financial flexibility. And while EMG has been a great partner for 3 years, our goal has been to achieve 100% ownership of Liberty. We're very pleased to have completed the acquisition of the EMG Liberty assets in one of the best shale plays in the U.S. This is an asset that we already operate and where we have clear visibility into future growth opportunities and financial performance.

In our Liberty segment, we are currently executing on a number of large projects critical to the full development of the liquids-rich Marcellus acreage in Western Pennsylvania and Northern West Virginia. Our current projects include the construction of 6 additional processing plants in West Virginia, with combined processing capacity of more than 1.1 billion cubic feet per day. This includes our previously announced plants in Mobley and the Sherwood I plant, as well as the recent announcement to increase capacity at the Majorsville complex by 400 million cubic feet per day and the planned construction of a second 200 million cubic feet per day plant at the Sherwood complex that was recently announced by Antero Resources. These processing plants are supported by long-term contracts with producer customers including Range Resources, Antero, CONSOL, EQT, Magnum Hunter and Noble.

Our significant projects under construction include 3 de-ethanization facilities at Majorsville and Houston, with combined ethane capacity to produce 115,000 barrels per day; approximately 400 miles of gas gathering, NGL and purity ethane pipelines in West Virginia and Pennsylvania; and a 200-car rail facility at our Houston complex. When these projects are all completed in 2012 and 2013, our processing capacity in the Marcellus will increase to more than 1.7 billion cubic feet per day, and our total fractionation capacity will increase to approximately 175,000 barrels per day.

Capturing premium NGL markets in the Northeast is critical for our producers as they develop their rich gas acreage in the Marcellus. MarkWest Liberty is in a very favorable position because of our large-scale NGL infrastructure, which is essential to capturing premium price opportunities for our producer customers.

Now let's move to the Utica. As we recently announced, we're partnering with EMG to develop midstream infrastructure to support the future drilling programs for our producer customers in the liquids-rich region of the Utica shale in Eastern Ohio. This approach is very similar to what we did in the Marcellus, where our success was a direct result of developing a large, integrated full-service midstream solution for the producers. Our initial development plans are focused on the Harrison County assets that will include a 200 million cubic feet per day processing complex and 100,000 barrel per day fractionation complex. The rapid growth of our Marcellus processing volumes requires an expansion of our Marcellus fractionation capability.

The Harrison County facility will fractionate NGLs from both the Marcellus and the Utica, which will allow us to cost-effectively expand our Marcellus fractionation capacity under long-term contracts and create world-class midstream facilities in the heart of the Utica, the majority of which will be base loaded by Marcellus production. Houston and Harrison will be the 2 largest fractionation complexes in the Northeast. And by connecting the 2 through a large NGL gathering pipeline, we will have tremendous operating flexibility, reliability, as well as market access. The Harrison fractionator will be owned jointly by MarkWest Liberty and the Utica joint venture with EMG. And the capital required to build the complex will be shared accordingly.

In addition to the Harrison County assets, we are developing a second processing complex that is currently slated for Western Monroe County. We continue to make good progress on the completion of gathering, processing and fractionation agreements. It's important to note that the first $500 million of capital expenditures for the Utica JV will be funded by EMG, after which MarkWest will fund 100% of the capital requirements until we achieve 70% ownership. However, MarkWest will receive 60% of the distributions for the first 5 years or until our ownership exceeds 60%. Although we're very much in the early stages of the Utica development, we are very excited about the play, which we believe will drive significant long-term high-quality investment opportunities.

Let me make a few comments about our ethane pipeline projects before wrapping up our Appalachian discussion. With our existing NGL infrastructure and the completion of our ethane and fractionation facilities, our Houston, Pennsylvania and the Harrison County complexes will be key supply sources for Northeast ethane pipeline projects. These includes our Mariner West and Mariner East projects, which are being developed in partnership with Sunoco Logistics; and the Enterprise ATEX Express pipeline to the Gulf Coast, which is expected to be in service in the first quarter of 2014. We believe that these projects adequately address the issue of ethane takeaway capacity for the Northeast markets.

To summarize our Marcellus, Utica and Huron midstream capacity and future development plans, by 2014 we will have total processing capacity in Appalachia of more than 2.5 billion cubic feet per day and fractionation capacity of approximately 300,000 barrels per day, including the capacity to produce 155,000 barrels per day of purity ethane at our Houston, Majorsville and Harrison complexes. We have a long history of constructing and operating the integrated pipeline, processing and NGL fractionation facilities required to support the dramatic increase in shale gas development by our producer customers, and our Northeast midstream infrastructure will create enormous reliability and flexibility for Appalachian producers. Appalachia is where MarkWest started almost 25 years ago and it's exciting to be a part of the long-term development of multiple shale plays in the Northeast, which is creating tremendous economic benefits and thousands of jobs in Pennsylvania, West Virginia, Ohio and Kentucky.

Before moving to the financial overview, I want to comment on the recent Energy Point midstream survey results. A key part of our strategy is to provide exceptional customer service in all of our operating areas. And since the survey began in 2006, we have been ranked either first or second, and we were again ranked #1 in the industry in 2011. Energy Point compiles the rankings from all the major producer customers in 8 major categories, as well as service-specific and region-specific rankings. Of the 8 major categories, we were ranked first in 5 of the categories, including total customer satisfaction, pricing and contract terms, project development, service and professionalism, and personnel. We also ranked first in the service category of NGL transportation and storage, and first in the Marcellus and East Texas regions. We're obviously very proud of these rankings, as it validates the hard work of our employees, who consistently deliver best of class midstream services for our producer customers.

Turning to the financials. The balance sheet was a key area of focus for us last year. We were very active in the capital markets in 2011 with net proceeds of $2.3 billion from multiple senior notes and equity offerings to support our significant growth capital program and the acquisition of the 49% of the Liberty joint venture. During 2011, we also amended the terms of our credit facility to lower our borrowing costs, while increasing the size of our revolver to $900 million. As a result, we achieved upgrades to BB from both Moody's and S&P, which was a key driver in reducing our long-term weighted average cost of debt. Today, we have available liquidity of approximately $1 billion to fund our capital program. As of year-end, our debt-to-total capital was 55%, our leverage ratio was 3.3x, and our interest coverage ratio was a healthy 5.1x.

Given our distribution objectives and the variability of the forward markets, we continue to consistently hedge our future commodity positions. For 2012, we are hedged at approximately 65%. And for 2013 and '14, we are hedged at approximately 50% and 20%, respectively. Our hedge transactions have been executed utilizing a combination of crude oil swaps and collars and direct product swaps. Our crude oil swaps for the next 3 years range from approximately $85 to $100 per barrel and our crude oil collars have an average floor of $85 and average ceiling of $105 over the next 3 years. This hedging philosophy continues to be a key priority for MarkWest given our long-term distribution objectives.

Before concluding, I want to discuss our revised guidance for 2012. We estimate that DCF in 2012 will be in the range of $440 million to $500 million. While this is a change of approximately 8% from our December guidance, I want to reiterate that the midpoint of our 2012 guidance results in year-over-year growth in DCF of more than 40% and nearly 20% growth in DCF per unit at our current units outstanding. The coverage ratio in 2012 at our current distribution and units outstanding would be approximately 1.6x for the full year at the midpoint of guidance, which obviously gives us plenty of room to continue growing our distributions and delivering strong total returns for our unitholders. Even at the low end of the DCF range, the coverage ratio would be nearly 1.5x at our current units outstanding in distribution.

The majority of the change in our guidance is due to the current low ethane and propane prices at both Conway and Belvieu. As most of you know, there are several major ethane crackers that are currently undergoing maintenance outages, and there will be additional cracker outages in April. These outages were mostly planned and many of the turnarounds will include capacity expansions so that when they come back online, ethane cracking capacity in the U.S. will increase by more than 40,000 barrels per day in 2012. As these crackers are brought back online, the market should come back in balance and most experts expect ethane prices to increase in the second half of 2012.

In addition, based on recent announcements, ethane cracking capacity could grow by more than 250,000 barrels per day over the next 5 years with a combination of increased capacity at existing crackers and the strong potential construction of up to 3 new world-class crackers in the Gulf Coast. Long-term, given the economics of cracking ethane over other feedstocks, coupled with global demand, ethane fundamentals of the U.S. look very sound.

Our revised guidance assumes that NGL prices will remain low through the middle of this year and recover in the back half of the year. We included in our press release the usual sensitivity table that shows projected 2012 DCF based on a range of crude and natural gas prices. It's also important to note that the contribution to our 2012 DCF from the Liberty acquisition remains unchanged, since the large majority of our business in the Marcellus is fee-based and our Marcellus producer customers are continuing with their drilling programs. Our 2012 capital forecast remains unchanged in the range of $900 million to $1.3 billion to fund high-quality projects, the vast majority of which are fully contracted and announced. This range is net of the capital requirements for the Utica JV that will be funded by EMG.

In summary, 2011 was a record year, and our guidance for 2012 would provide strong year-over-year growth in both DCF and DCF per unit. With our diverse set of assets in growing resource plays, we're very well-positioned to continue developing efficient and effective midstream solutions for our producer customers. These growth opportunities, coupled with the strength of our balance sheet, continue to support our objective to provide superior and sustainable total returns for our unitholders.

So with that, we'll open it up to your questions. I'll turn it back to you, Melissa.

Question-and-Answer Session

Operator

[Operator Instructions] It does look like our first question comes from John Edwards, Morgan Keegan.

John Edwards

Just, I guess you were talking about having -- reaching 2.5 bcf per day and 300,000 barrels per day of fractionation capacity and 155,000 of that purity ethane in 2014. Just is that going to be you think at the beginning of 2014, by the end of the year? What's the specific timing, do you think, on that?

Frank M. Semple

Yes, that's definitely towards the middle -- from the middle to the last half of 2014.

John Edwards

Okay. And then in terms -- I mean, you're spending 1.1 -- or the midpoint's roughly $1.1 billion this year. Do you have a handle yet on what kind of capital expectations you have for 2013 and '14?

Frank M. Semple

Well, we do internally, John. We're not going to provide that guidance on this call. But as we move into the year, on the next few earnings calls, we'll start to give you -- as we did last year, we'll start to give you a flavor for what the 2013, 2014 capital programs look like. That's just been an approach I think that's worked for most people. There's a lot of things that are moving around, particularly in the Utica, out in 2013 and '14. And it's best that we start providing that kind of loose guidance as we move into this year, later on this year.

John Edwards

Okay. I guess and then another way of asking, I take it that -- I mean, this is really an incredible achievement in such a short period of time. But it sounds like even with getting there, you're -- I don't get the sense that you're done yet. I'm just -- what's the trajectory, I guess, past what's on the deck right now?

Frank M. Semple

Well, just for everybody on the call, I think it's important to remind everybody that we had a big increase in our capital program in 2012, primarily as result of that 100% ownership of the Marcellus. And the big drivers for our capital programs going forward will be from these major shale plays. And you're right. I mean, we have accomplished a lot in a short period of time, but we're well-positioned to continue that growth, particularly up in the Northeast, where we had that full set of natural gas gathering, processing and fractionation services and the integrated NGL logistics and marketing capabilities. So yes, we expect to continue to have a very strong capital program for the next several years.

John Edwards

Okay, and then what's -- how are you thinking or how will the -- I mean, eventually, Shell is going to announce -- they've been talking about announcing a world-class petrochemical facility somewhere in the Northeast. How does that impact your plans and your outlook?

Frank M. Semple

Well, first of all, as I mentioned on my formal comments, it's kind of neat to see all of the ethane transportation solutions that are being developed out of the Marcellus and the Utica. I mean, this time 2 years ago, I mean, we were kind of the lone rangers out there trying to help encourage and develop -- encourage the market and develop projects that would allow our producer customers to get their ethane to market. And now with our projects -- our joint projects with Sunoco to Canada and to the East Coast, that could be -- where ethane could be delivered to the Gulf Coast and international markets, and with the Enterprise pipeline, we have -- I think we've solved at least for the near-term the ethane issue. And in conjunction with that, obviously, reaching the Belvieu market with the growing ethane projects, the crackers that have been announced and we feel are going to be moving forward, the Belvieu market's the right place to be with this Marcellus and Utica ethane. Now having said all that, Shell -- the Shell plans for developing a 60,000 barrel a day cracker in the Northeast continue to move forward. You know as much as I do about what that final decision will be, but it's pretty clear that they're focused on that integrated solution for their natural gas resources in the Northeast and their petrochemical capabilities. So I think it's a real serious project and would just add to the development of the petrochemical complexes that would be advantaged by the low cost of ethane coming from these shale plays, as well as propane for that matter. So yes, I think it's pretty exciting what's happening and Shell is just one additional point of reference relative to the continued development of the -- in the competitive position of the U.S. petrochemical markets.

John Edwards

Okay, great. And then last question. So what are your thoughts on the -- going forward on the relative supply/demand balance on natural gas liquids?

Frank M. Semple

Well, there is an imbalance right now, and that's what's causing the softness in the NGL pricing relative to crude. We see that as being fairly short-term. It's kind of interesting, John. If you look back, 2011 was a extremely strong year from an NGL pricing perspective. It was the strongest, both for C2 and for C3-plus NGLs over the last 5 years. And yet, if you look at the first quarter of 2011, prices were also depressed. They were soft. They did recover midyear. And the recovery was driven -- recovery in 2011 was driven primarily by the increased demand for ethane, again, the economics of ethane cracking, and also there's a significant amount of propane that is used for the cracker feedstocks. So my point is that there was -- it started out low and it increased rapidly throughout the year. We sort of see that same phenomena this year, although the lack of a winter has also contributed to the softness in the propane pricing relative to crude. But all that being said, if you look at what's happening in the Gulf Coast relative to the turnarounds that I mentioned earlier, the cracker shutdowns and turnarounds, the amount of cracker facilities that's offline right now, there's about 150,000 barrels of -- excuse me, about 90,000 barrels of current cracker capacity that's offline. And there'll be about another 150,000 barrels of additional cracker capacity that would go offline through the second quarter of 2012. Now obviously, those are going to be coming back up again. And so they're down right now. When they recover, when they come back on the market, then it's going to obviously increase the demand for ethane. And as I alluded to in my comments earlier, part of the turnaround projects involve additional capacity or upgrades to the capacity of those crackers to the tune of about 40,000 barrels a day. So again, the fact they're on turnaround right now is causing the softness. But when they come back, it will increase the demand for ethane. We also have the issue around the -- there's about -- oh, I think there's 150,000 barrels a day or so -- or excuse me, 100,000 -- 100 million cubic feet a day of processing capacity that's also down. And so that will be going down in the first quarter of 2012. And so that will help firm up the pricing for C2 plus -- C2 and C3-plus and obviously help kind of balance out the supply/demand picture, particularly in the Gulf Coast. So that, all that being said, that's the reason why we see NGL prices starting to recover in the second half of the year, similar to what we saw in 2011.

John Edwards

Okay. And then longer-term, are you thinking it stays relatively, because -- do you think it stays relatively balanced and then maybe going back into shortage, say, 2015, '16? Or what's your thoughts there?

Frank M. Semple

Yes, the analysis that we've seen and our internal analysis would indicate that -- most of our analysis are really done from the supply side because of all of the processing that we're developing and also looking specifically at the Northeast, Marcellus and Utica processing development, but also on the demand side. There's a lot of pretty good studies out there in terms of ethane expansions, cracker expansions that would consume ethane because of the economics. And again, we're going to -- we expect to see some short-term kind of disconnects in terms of supply/demand, but it'll firm up over the -- through the remainder of 2012. And then further out, you're seeing a lot of new projects, a lot of new crackers that have been announced and planned for the Gulf Coast and also the Shell facility that we mentioned earlier that are -- that have been announced, and we feel we'll be moving forward. I mean, the numbers are pretty compelling. It's kind of neat to see that by the end of 2012, we'll actually have over 1 billion barrels per day of ethane cracking capability. And that's going to expand out to -- in 2016 up to 1.3 billion barrels per day of ethane cracking capability. And so you're seeing fairly significant growth year-over-year over the next 5 years. And obviously, this is a huge market. The U.S. petrochemical industry is certainly taking a hard look and creating a huge advantage with the low price of ethane to be able to continue to not only build out the U.S. infrastructure, but also to be competitive internationally with the products. So yes, we see long term, as do most of the experts, that the supply/demand for ethane will stay in balance over the -- will generally stay in balance over the long term. And it's driven -- again, it's just driven by the economics of cracking ethane over current base feedstocks.

Operator

The next question we have comes from Michael Blum from Wells Fargo.

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

Just a couple of questions. One, can you give any update on the latest progress with Mariner East?

Frank M. Semple

Sure. Mariner East continues to work on the producer contracts that would support that project. And really nothing has changed relative to the focus and the objectives that we have with Mariner East. You'll be the first to know when we secure those agreements. But there continues to be a lot of interest. I mean, in -- that interest not only is driven by just the general demand for ethane, primarily in the Gulf Coast, that I talked about earlier from John's question, but also the interest is being developed -- also being developed because of the closure of the East Coast refineries and also the potential for developing ethane transportation infrastructure in that Philadelphia area of Marcus Hook specifically to be able to transport ethane internationally in addition to the Gulf Coast. It was important for us to get Mariner West online first. It was the project that was -- that could best meet the near-term requirements for the producers. And we've worked very hard with the producers on the Enterprise ATEX project to be able to accommodate the ethane market in Belvieu. And Mariner East is a third project that I believe will move forward, just based on that additional market capability that would come from being able to place the ethane on transports and move it very flexibly to the international markets. We're also looking at the potential for moving other products in that line besides ethane. So yes, it's -- we made a lot of progress with regard to educating ourselves and the producers and frankly, some of the consumers on what the timing and capabilities of that project will be. And we hope to be able to announce something sometime this year.

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

Okay, great, that's very helpful. And then the other question I had was just in trying to understand the guidance. So can you -- so it sounds like some decrease in your outlook in the Northeast segment were primarily driven by a change in your commodity deck. Can you -- now looking at the table at the back, I'm just having trouble trying to triangulate, what is the commodity deck in rough numbers that you guys are looking at when you come up with the range of DCF that you provided?

Frank M. Semple

Sure. The -- first of all, I'll answer the first part of your question. The change in guidance is -- the lion's share of the impact on the change of guidance is coming from the change in assumptions relative to purity products. And there is again some impact from the reduction in volumes due to drilling programs, but the large majority comes from the change in assumptions on NGL pricing. And our assumptions for NGL pricing is based on -- for the first half of the year, it's based on essentially 1 standard deviation off of a 3-year mean for the first half. And then it reverts back to the historical average. Again, this is off a 3-year regression of NGL prices relative to crude oil. So if you think about that 1 standard deviation off of the historical mean, and then you go back to the -- you go to our sensitivity table, then it will make some more sense because the middle of that table, let's say, using $2.50 natural gas prices and $100 crude, it's $485 million of DCF. But in order to adjust for the assumptions on NGL prices, you need to assume half the year will be at the 1 standard deviation below the historical mean. So that's what gets us down to the low end of our range, if in fact we have that kind of pricing for the remainder of the year. So to repeat myself, the NGL prices for the first half of the year are assumed to be at the 1 standard deviation off the historical mean based on 3-year regression, and then it starts to recover through the last half of the year. And we can help you with those assumptions and how we've kind of baked them into our model if you give us a call.

Operator

Next question we have comes from TJ Schultz, RBC Capital.

TJ Schultz - RBC Capital Markets, LLC, Research Division

I guess just on CapEx for 2012. You've mentioned recently the Sherwood II plant and then Carthage East [ph]. Maybe just trying to get -- or if you could provide a high-level breakout on the percent allocation of this -- of kind of your CapEx by segment in the Southwest, Northwest or Liberty?

Frank M. Semple

Okay. I realize, TJ, that we have a -- still have a fairly wide range for CapEx for 2012. But that said, the Carthage East [ph] project, which is under construction; and the Sherwood plant, Sherwood II plant, which is under construction, are included in that guidance. Sherwood II will be in the Liberty segment. And Carthage East [ph] will be in the East Texas segment, Southeast -- Southwest business unit. And just in terms of timing, the Carthage East [ph] plant will be completed in 2012, so basically 100% of those expenditures would be completed -- would be in the 2012 budget. And Sherwood II will be completed in mid 2013, so it will be -- the lion's share of that will be in the 2013 capital plan.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay, just bigger picture, I mean, if we take the midpoint of CapEx, what percentage is to Northeast and Liberty and percentage to Southwest?

Frank M. Semple

Hold on one second. Yes, the -- actually we have that capital broken out in our presentation. And it's about 80% or so of that whether you're talking about the full range or the midpoint of that 2012 capital will be up in the Northeast.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay, I'll look at the presentation. I guess, just on the Utica, any cost parameters around what you've already announced? Just trying to get a feel for when you expect to begin contributing to CapEx on the Utica JV.

Frank M. Semple

Sure. Yes, the -- EMG will fund the first $500 million. 2012, we're aggressively pushing forward with the projects that I' mentioned in my formal comments. And in those projects, would drive somewhere in the $150 million to $200 million of capital in 2012. And, as I mentioned earlier in John's -- my response to John on the -- kind of the capital for 2013, we'll update you later on in terms of what '13 looks like. But you can kind of assume that we will start contributing to that, to our Utica development plans after the $500 million sometime late 2013, early 2014. But again, we'll keep -- we'll continue to update you and everyone on our capital plans for 2013, particularly as it relates to the Utica joint venture, because we know that, that's -- when we start contributing is a critical issue for your models. So stay tuned.

Operator

The next question we have comes from Jacob Strumwasser [ph] from Motoroc Capital [ph].

Unknown Analyst

I just wanted to understand, it looked like EBITDA was a little bit less than what it normally would have been had revenue come in at this level. So is there anything operationally that lowered that margin?

Frank M. Semple

Yes, not that I know of, Jacob. I'm looking around the room. We'll have to get back to you on that.

Unknown Analyst

Okay, we can follow-up offline. I mean, the Street -- it may just have been Street models, but we'll speak offline. I'll give you a call afterwards.

Frank M. Semple

Okay, that's fine.

Operator

Next question we have comes from John Tysseland from Citigroup.

John K. Tysseland - Citigroup Inc, Research Division

Just one question for me. Can you provide us a rough calculation for how much of a headwind -- propane's dislocation from crude price is impacting your 2012 guidance? Is that impact greater in 2012 due to your crude hedges? Or is that -- or is the impact just really a lower assumption for NGL pricing?

Frank M. Semple

Yes, it's mainly a function, John, by -- because of -- the main issue is the pricing for propane relative to our original plan. And so the ineffectiveness, if you will, for the crude hedges is a smaller percentage and I don't have that percentage in front of me. But the majority of the impact on our guidance really came from lower NGL prices, period. Now, you have to remember that we have both from a hedge prospective -- from a crude oil proxy hedge perspective, we have both swaps and collars. And inside the collars, as you know, we don't -- that doesn't really impact your mark-to-market or your hedge settlement exposure, so that helps a little bit on that issue around -- or your point about what hedge effectiveness might look like relative to the various NGL purity products. But yes, most of it is just due to lower absolute NGL prices compared to what we originally assumed.

John K. Tysseland - Citigroup Inc, Research Division

Yes, I guess the hedging loss in the fourth quarter was a little bit greater than what we had expected. And I think what was driving that is that I believe you closed out a few crude oil hedges in the fourth quarter and realized some losses there. Should we expect that to happen again in the first quarter? Or is that pretty much all taken care of in the fourth?

Frank M. Semple

Are you talking about the cash impact?

John K. Tysseland - Citigroup Inc, Research Division

Yes.

Frank M. Semple

Okay. No, you'll continue to see that throughout the year, as we -- as I mentioned earlier, if you look at -- and you can see this in our K. You can see all of the pricing for all of the future crude oil hedges as they roll off quarter-to-quarter, so you can get a sense of where we are in that $85 to $105 on the collars, as well as the average swaps that I mentioned in my script. So yes, to the extent that crude oil stays high, then we're going to see settlements that are a negative impact on the actual sales of NGL products.

John K. Tysseland - Citigroup Inc, Research Division

So is it fair to assume that following fourth quarter, you did make -- is it right to assume that you made a few adjustments to your hedge book that -- where those crude oil hedges were not keeping pace or, I guess, propane prices weren't keeping pace with your crude oil hedges, that you shifted a little bit and now you're a little bit better hedged directly for what the current NGL environment is?

Frank M. Semple

Yes. Well, it wasn't all in the fourth quarter, but we made decisions in 2011, not to shift, but as we extended our hedge positions in 2012, we decided that instead of hedging with crude, we would hedge with direct product, NGL products. And so that's just an ongoing process we take. You might ask the question, "Well, are we continuing to add direct NGL product hedges in 2012 or even out in '13 and '14?" And we are looking at that. We look at that every week in terms of the economics for both converting and adding additional NGL -- converting crude oil hedges to NGL hedges and also adding direct NGL product hedges. And we make those decisions on a weekly basis. But right now, that market is not very good. In other words, for us to go out and add hedges -- first of all, we're just about fully hedged in 2012 given all of our operational requirements, so there's not a whole lot of opportunity to add direct product hedges. But even if there were, the prices are so poor that right now, we're just -- we feel much more comfortable with the recovery of the correlations of NGL pricing relative to crude versus going out and locking in a big negative position for additional NGL hedges, direct product hedges, so...

John K. Tysseland - Citigroup Inc, Research Division

Yes, I guess the concern would be fully hedged versus possibly over-hedged if it's crude and NGL pricing falls, is my concern, I guess, I'm driving at, and just making sure that, that's not a concern in '12.

Frank M. Semple

No, that's not a concern at all in '12, because that's my point, is that we do not over-hedge. We're very conservative in terms -- we don't hedge ethane, number one. And we also are very conservative at forecasting the actual NGL volumes production, if you will, that would be used to support these crude oil hedges. So we will not put ourselves in that position.

Operator

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

Frank M. Semple

Well, thanks, Melissa, and thanks to everyone for joining us on the call today. We, as always, appreciate your interest and continued support. And please give us a call if you have any additional questions. That concludes our fourth quarter earnings call.

Operator

Thank you for participating in today's conference. All parties may disconnect.

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