Crestwood Midstream Partners LP Management Discusses Q2 2012 Results - Earnings Call Transcript

| About: Crestwood Midstream (CMLP)

Crestwood Midstream Partners LP (NYSE:CMLP)

Q2 2012 Earnings Call

August 06, 2012 11:30 am ET


Mark G. Stockard - Vice President of Investor Relations - Crestwood Gas Services GP LLC, Treasurer of Crestwood Gas Services GP LLC and Assistant Secretary of Crestwood Gas Services GP LLC

William G. Manias - Chief Financial Officer of Crestwood Gas Services GP LLC and Senior Vice President of Crestwood Gas Services GP LLC

Robert G. Phillips - Chairman of Crestwood Gas Services GP LLC, Chief Executive Officer of Crestwood Gas Services GP LLC and President of Crestwood Gas Services GP LLC

Joel D. Moxley - Chief Operating Officer of Crestwood Gas Services Gp Llc - General Partner and Senior Vice President of Operations and Commercial of Crestwood Gas Services Gp Llc - General Partner


Mark L. Reichman - Simmons & Company International, Research Division

TJ Schultz - RBC Capital Markets, LLC, Research Division


Good day, everyone, and welcome to the Crestwood Midstream Second Quarter 2012 Earnings Conference Call. As a note, today's call is being recorded. And now, at this time, it is my pleasure to turn the conference over to Mr. Mark Stockard. Please go ahead, sir.

Mark G. Stockard

Thank you. Good morning, everyone, and welcome to our call. Bob Phillips, Crestwood's Chairman, President and Chief Executive Officer, and Bill Manias, Senior Vice President and Chief Financial Officer, will review the quarter, then we'll open the call up for your questions.

During this call, we'll make certain forward-looking statements as defined in the Securities and Exchange Act of 1934 based on the beliefs of the company, as well as assumptions made by and information currently available to management. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call.

In addition, during the call, we'll be discussing certain financial measures, such as Crestwood's EBITDA, adjusted EBITDA and distributable cash flow and adjusted net income, which are non-GAAP measures. A reconciliation of these non-GAAP measures to the most directly comparable GAAP measures is included in the press release that we issued earlier this morning and posted on the Investor Relations section of our website at

With that, I'll turn the call over to Bill to review the financial and operating performance of the second quarter.

William G. Manias

Thanks, Mark. Crestwood reported second quarter 2012 net income of $6 million and adjusted EBITDA of $28.5 million. These amounts compare to net income of $10.2 million and adjusted EBITDA of $29.8 million in the second quarter of last year. Adjusted distributable cash flow totaled $20.6 million, and we declared a $0.50 per unit distribution in the second quarter. And that's a 9% increase over the same period last year. As you know, we've revised our second half guidance slightly lower to 8% year-over-year distribution growth, which implies a $0.01 increase in the third quarter of this year. For the 6 months -- first 6 months of 2012, adjusted EBITDA totaled $56.9 million. That's up 13% over the first 6 months of last year.

Second quarter gathering volumes from Crestwood's 100%-owned systems averaged 561 million a day. That's flat versus the prior year and down about 8% from the first quarter. Second quarter 2012 gathering volumes from Crestwood Marcellus, our joint venture with Crestwood Holdings, averaged 257 million a day. Our total gathering volumes from the systems we operated in the second quarter 2012 were 818 million a day, which includes 100% of the related -- volumes related to Crestwood Marcellus. In the third quarter, our total gathering volumes are currently right around 875 million a day.

Processing volumes in 2Q 2012 were 144 million a day, down 10% from the prior year but only 2% down from the first quarter, and currently, we're processing -- processing volumes are around 175 million a day, reflecting the additional volumes on the Cowtown system and the Granite Wash systems.

Almost 90% of the second quarter gathering volume decrease occurred on our 2 dry gas systems in the Barnett, with a slight reduction in the Fayetteville Shale. Although we actually connected more wells during the second quarter than we did in Q1 2012 and Q2 2011, many of the new well connections came late in the quarter, caused by producer delays in completing the wells. So this caused lower overall volumes during the quarter due to natural decline, lower volumes from existing wells, which were shut in to frac the new wells on the same pads, and wells, which were voluntarily shut in by producers due to high operating costs. And these are typically older, low volume gas wells that have high water production costs.

The new wells we connected late in the second quarter on the Alliance system in the Barnett and early in the third quarter on the Twin Groves system in the Fayetteville Shale should drive higher volumes on those dry gas systems in the third quarter.

Major contributors to adjusted EBITDA in the second quarter included $26.2 million from the Barnett, $4 million from the Fayetteville segment, $1.9 million contributed from our 35% ownership in Crestwood Marcellus Midstream and $1.2 million contributed from the Haynesville assets.

Equity earnings from Crestwood Marcellus Midstream totaled $0.4 million for the second quarter and Crestwood received a $1.7 million distribution from Crestwood Marcellus during the quarter as well.

For the second quarter 2012, gathering volumes on the Barnett totaled about 401 million a day, and that's compared to 450 million a day in 2011. Our gathering volumes in the Fayetteville segment totaled 78 million a day, a decline of about 4% compared to last year's volumes of about 81 million a day. Granite Wash volumes were around 15 million a day in the quarter, which is flat to the first quarter. And as Bob will explain, Granite Wash volumes are currently around 20 million, so we're pretty optimistic with the outlook of the Granite Wash for the second half of the year.

Our Barnett Shale processing volumes in the second quarter totaled 129 million a day compared to 144 million a day last year and 133 million a day in the first quarter. The Devon volumes will substantially increase this number in the third quarter, depending on when we close the acquisition.

Our operating expenses in the Barnett totaled about $5.3 million for the second quarter. That's a 4% decline from last year. And operating expenses in the Fayetteville segment totaled $2.2 million for the second quarter. That's down 7% from 2001, and it's primarily due to the acquisition of field compression assets that we leased in 2001.

Our product sales and purchases at Indian Creek plant in the Granite Wash were down quarter-to-quarter, primarily due to lower NGL prices across the industry.

On the G&A side, our G&A expense for the second quarter was $6.9 million compared to $6.1 million in the second quarter of last year. In the second quarter of 2012, we had about $1.7 million of nonrecurring costs, primarily related to acquisition due diligence expenses. And in addition, in 2011, in the second quarter, we had about $1.1 million of nonrecurring costs related to the Frontier acquisition. So if you adjust for these nonrecurring costs, essentially, G&A is flat quarter-to-quarter.

At June 30, 2012, we have $361 million outstanding on our $500 million revolving credit facility. Last week, we completed a 4 million common unit offering in the underwriters' exercise of the full 600,000 unit over-allotment option, which gave us total proceeds of around $115 million. We used these proceeds to repay borrowings under the facility, with a current balance of about $241 million. So pro forma for the offering, our debt-to-EBITDA is around 3.7x. Now we plan to borrow about $85.5 million on our revolver, which is net of a $4.5 million deposit we've already paid to Devon to fund the $90 million purchase price for the Devon acquisition.

Finally, year-to-date through June 2012, capital spending was around $21.5 million for both growth and maintenance capital, and we also invested $131 million to purchase the Marcellus JV.

And with that, I'll turn it over to Bob.

Robert G. Phillips

Boy, that's a lot of data, Bill, that you threw at them. Let me just stop for a second, highlight a couple of things that I want you to -- investors to really focus on. One is, the volumetric throughput on the systems that we own and operate is at an all-time high right now, about 875 million a day. Those of you that have invested with us since the beginning, since the KGS days, recognize how significant that volumetric growth is, and it is entirely due to the number of acquisitions, which we've completed over the past 2 years. You remember, we started in the Barnett, we had 2 dry gas and 1 rich gas system, and we're now in 6 different basins. And we're active in a number of different developmental shale plays, and we built a great platform for this company. And our volumes through our pipeline systems are at an all-time high at 875 million a day.

Substantially, above where we averaged in the second quarter, a lot of that has to do with new wells that were connected at the very end of the second quarter, which obviously didn't have a throughput impact on our second quarter results of operations but will drive third quarter and fourth quarter volumes higher. Additionally, we had new wells come on in July after the end of the second quarter. Particularly in the Granite Wash area, we're excited about that, and I'll focus on that in a second.

And then third, of course, we just announced the acquisition with Devon. Hope to close that in the next couple of weeks, and that will add substantially to our third and fourth quarter as well.

So the big drivers for third and fourth quarter performance in the second half of the year are the increased volumes in these dry gas systems that we talked about at the end of the second quarter, the new rich gas volumes that have come on since the end of the second quarter and the Devon volumes that will start accruing to our benefit after we close the transaction in a couple of weeks. So that ought to drive third and fourth quarter performance.

The second thing that Bill mentioned was that we continue to maintain our operating costs. Costs pretty much across-the-board are down, and they're down substantially in some areas despite increasing volumes. And, as you know, in the gathering business, operating costs are oftentimes linear, they increase as volumes increase. So when you look at our per unit operating costs, we continue to do what we can to control the financial results of our operations, and that is to maintain well operating costs and low G&A as we continue to build out this corporate platform for creating value for our investors.

So I wanted to highlight those 2 things. I guess, the third most important thing is, we did complete an equity offering last week. It's obviously played havoc with the stock price. We thought it was important to go ahead and access the market to make sure that we maintain our conservative balance sheet, relative to the $90 million acquisition that we're going to close in the next couple of weeks but also to maintain our liquidity for future opportunities that may come up. We know this has been a tough market, but there are factors that affect the equity and the debt markets broadly that are far outside of our control. We have no interest in putting ourselves behind the eightball, so we saw a reasonable market to enter. We executed a good strategy. The stock was, we thought, placed well. The underwriters exercised the greenshoe. Demand was there for the stock. And fortunately, it's had a very short-term negative impact on our stock price right now. We hope to get through that in the next week or so and hope that our investors appreciate why we made the business decision to go ahead and access the market instead of being at risk to raise the additional equity capital that we might need to balance our balance sheet throughout the remainder of the year.

So those are highlights out of Bill's run-through on the details. Let me take it up a notch and frame the highlights of the quarter from my perspective, talk about some of the challenges that we face that clearly investors are focused on right now and then close with a short note on our going-forward strategy. We did accomplish a lot in the second quarter, and I'm surprised that we're getting beat up so bad in the market right now. Again, I think I need to stress to you what I think the achievements were that will impact long-term value creation here at Crestwood.

First and most important is we took over operations of our Marcellus Midstream business. Again, that was financed as a joint venture because we didn't want to overly stress the CMLP balance sheet with that $375 million acquisition and probably an additional $200 million worth of growth projects over the next 5 years. We made, again, a business decision to put that in the form of a joint venture. We were fortunate that First Reserve in our holding company, which owns our general partner interest, was there for us to help us structure and finance that project so that we could have ownership and operatorship of these great Marcellus Appalachian assets but not have to bear the full financial brunt of that right now. We said when we announced the transaction that, that joint venture would likely be dropped down into Crestwood over the next couple of years, as the growth continues and as the volume performance improves and the cash flow contribution forms. We've just completed our first full quarter of operations, and I can tell you that we're excited about what's going on in the Marcellus. And that'll be a key driver throughout the rest of the year and next year, and it probably will result in accelerating the drop-down in the CMLP.

The second big item for us in the quarter was what's going on in the Granite Wash. We just connected our first new really big Granite Wash well in the area of our Indian Creek plant and processing facility. We've got an exciting new First Reserve-affiliated producer that's got a development program going there. A majority of the acreage is under contract to us, and we're working with them to expand the acreage to cover the rest of his development plan. We're excited about what the Granite Wash is going to bring the remainder of the year and next year.

Third, no doubt, the Devon bolt-on acquisition expands our rich gas exposure in the southwestern part of the Barnett region, continues to increase our rich gas portfolio and it reduces our dependency upon the dry gas fields there in the Barnett that are operated by Quicksilver.

And third, I already talked about it, successfully executing the $115 million equity offering. Again, I'm a little bit troubled by the impact on the stock price, but we made a conservative business decision to go ahead and go to the equity markets because we didn't want to risk not being able to finance that acquisition and maintain liquidity going forward.

All of these themes are consistently showing our laser-focus on expanding Crestwood's rich gas business. And, as I said, these are the assets that will drive the growth of our company over the next few quarters.

In the Marcellus, specifically, we took over operations in the second quarter from Antero. We've connected a number of new high volume wells. And by the way, the wells that we're connecting are performing far better than our acquisition forecast, so we're really pleased with that. We've now staffed our regional offices in Charleston and in Clarksburg, West Virginia, and we're preparing for a strong second half of 2012. We have a couple of fairly important pipeline projects and compression projects underway. The drilling economics are still good for Antero up there. They're running 7 rigs on our area of dedication, which, as a reminder, is 127,000 acres with the right to -- right of first offer to acquire over 200,000 acres of rich gas acreage located just to the west of our AOD. As I said, we're building our first new pipeline there. We're in the engineering phase on some compression projects. Producer plans right now look to add another 40 -- approximately 40 new wells in the second half of this year versus the 20 that's already been connected in the first half of this year. So we're expecting to see a lot of volume growth and a lot of cash flow growth. The joint venture contributions to Crestwood were minimal in this first quarter as we took over operations, but they will continue to grow each quarter as we add new wells and expand the systems. So right now, we view Marcellus as very solid and right in line with our acquisition forecast. We're also starting to work with third-party producers in the area to identify new drilling programs that are within reach of our existing pipelines.

To the Granite Wash. We're finally, after a year now, seeing the rich gas development activity that we expected when we bought these assets from Frontier back in 2011. As you will remember, back then, Chesapeake was the largest acreage holder and the largest producer on the system, and we thought based on discussions with Chesapeake, that they would be very active on dedicated acreage. But clearly, they've slowed in the area due to obvious reasons.

In the interim, we took over our commercial team, put an overflow deal together with Penn Virginia and we took some leaner overflow gas over the last year to try to fill our plant up. And that's resulted in lower volumes and lower NGLs produced, but it did keep the plant going for a while.

Recently, LeNorman Operating Company, out of Oklahoma City, our first reserve portfolio E&P company, has acquired much of the acreage that's very close to our plant and has started an aggressive development program. They've completed the first great Granite Wash wells, producing over 4 million a day of 6 GPM gas and also producing significant oil. They have a rig about to complete the second well, which we hope to bring online in the next couple of weeks. Current plans call for 13 additional wells on this acreage in the next 18 months. And given the math of the first well and the expectations for the second well, that could fill our plant up with these volumes just from the LeNorman dedication.

LeNorman has also contracted for another 35,000 acres nearby this acreage, and they expect to start testing for Granite Wash in 2013. So that's another strong possibility to add volumes and/or expand the system and expand our processing plant up there. We're excited about what's happening in the Granite Wash. It's been about a year now since we bought that business from Frontier. As you know, it was a throw-in to the Fayetteville deal, and we're starting to see some real value creation there.

The Devon acquisition was a long time coming, but it's a great deal for both Crestwood and Devon. We identified this bolt-on back in 2010 when we bought the original Quicksilver Cowtown assets. We had excess plant capacity then, and we offered to buy Devon system and their plant and integrate their volumes into our plants. They weren't ready to monetize those assets then, but our discussions did register interest with them. And earlier this year, Devon started an internal process to sell that gathering system and plant and enter into a new 20-year gathering and processing contract with a new buyer. So we had an advantage because we have been processing some of their West Johnson County gas, do an offload agreement and we had built a good operating relationship with Devon based upon our performance and our recoveries down there on the Cowtown system. And that served us well in this very competitive auction process that we went through for this Devon asset.

The acquisition allows us to consolidate all of Devon's West Johnson County gas onto our Cowtown system, where we have excess capacity in our Cowtown and Corvette plants. It provides Devon with lower wellhead pressures, which, as we know, in our long experience when we reduce pressures at the wellhead, we create uplift volumes for the producers, so they should see volume improvement just by virtue of our pipeline system operating at a significantly lower pressure than their own pipeline system. We expect to use their gas to optimize our existing process capacity, which will lower our operating cost per unit and create synergies for us. And then our plants, as you may know, we've said in the press release, have higher recoveries than the Devon plant, so Devon's going to benefit from higher NGL recoveries as well due to our deeper cut cryo plants there at Cowtown and Corvette. We expect to complete this system integration process in the couple of months after we close this transaction, which should be in the next couple of weeks.

The 20-year contract that we're signing with Devon is, of course, fixed fee, as is more than 95% of our business. That number actually will be moving up now to probably 97%, 98% pro forma to the Devon gas. It adds 95 million a day of rich gas production, which is right now producing about 4,000 barrels a day of NGLs on their system, and we're going to get paid fees for gathering, processing and compression. We're adding that 95 million a day to about 140 million a day currently on our system and the 4,000 barrels a day of NGLs at the residue to about 16,000 barrels a day of NGLs at the current residue for those plants. So a pretty significant increase in our Barnett Shale rich gas activities.

The acquisition is going to be about 5% accretive to Crestwood in 2013, and that includes accounting for the conversion of the Class C units at the, I think, April 1 of next year, they will get paid the first quarter distribution, but that -- the Devon transactions accretive also taking into account the conversion of those units.

And finally, after we integrate the systems and offload all of the Devon gas into our Cowtown and Corvette plants, we're going to have an additional 100 million a day cryo plant that we can pick up and redeploy into 1 of the other rich gas regions, where we're working on greenfield deals such as the Avalon in the Permian Basin, the Utica right next to the Marcellus and the Niobrara up in Wyoming. We're actively working on organic development projects in all those areas, and we can utilize that 100 million a day cryo that we're buying from Devon, as well as the 60 million a day cryo that we bought last year in the Frontier transaction.

So a lot of positive long-term movement for our rich gas play, and we hope that resonates with investors. We're working hard in that area. We'll continue to look for bolt-ons and greenfield projects in the rich gas areas.

In the dry gas area, frankly, we weren't quite so lucky in the second quarter, but we hope this is the bottom of the barrel for us in terms of issues with our dry gas systems. As we've said, Quicksilver was slow to complete new wells on the Alliance system in the second quarter. Chesapeake continued to curtail volumes on our Lake Arlington system in the second quarter, and producers implemented a restricted choke program on the Haynesville system that frankly resulted in lower volumes there than we expected when we bought that business back in November of last year. To the Alliance system, as we said, we brought on some very strong new wells. And at the end of the second quarter, we added 12 wells to the Alliance system, and those 12 wells are currently making over 50 million a day. So the good news is, we continue to see great wells in Alliance when Quicksilver does drill and complete them.

In the Fayetteville, the volume decline was fairly marginal, only 2.4 million a day year-over-year, and that was also due to delayed timing of 6 new wells that came on very, very late in the second quarter. Those 6 new wells are currently producing between 12 million and 14 million a day.

So we continue to get good wells in the Alliance and the Fayetteville. The producers have just slowed down their development plans. I'll speak to the Fayetteville in a second.

Year-to-date, we've connected 15 wells to the Fayetteville systems, and we expect a similar number of new wells to be connected in the back half of the year based upon current producer activity and things that we're doing there to make ready for those.

So while we're on the Fayetteville, let me speak to the news that came out last week with respect to BHP's recent announcement of a $2.8 billion impairment charge to the carrying value of their Fayetteville investment, based entirely on, as they said in their press release, low gas prices. We don't know any more than you do about this write-down, but let me provide some context to BHP's development program to our investment in the Fayetteville.

Our second quarter volumes, as I said, were only down 3% compared to the second quarter of last year. So we've remained a relatively flat volume focus up there. In other words, the producers have drilled enough to maintain flat volumes. They're not declining. They're simply just not growing as fast as we expected them to. So a little history there.

Remember, when we bought this business from Frontier, April 1 of last year, Chesapeake was the operator. And we bought the business based upon an expectation that Chesapeake would continue their drill-the-hole development strategy for the first couple of years, meaning '12 and '13, and then move to a more aggressive development plan and ultimately, to in-fill drilling when prices improve.

As you may remember, BHP acquired Chesapeake's operations for $4.75 billion immediately after we closed our transactions. And frankly, we had no idea BHP was going to acquire that asset when we acquired it from Frontier. So we really bought the Frontier business, the Fayetteville assets, expecting about a 2-year "drill the hole type" development strategy, in other words, flat to slightly increasing volumes. When BHP announced the acquisition, they also announced plans to accelerate the drilling program. We thought that made a whole lot of sense. We felt like BHP needed to assume an accelerated drilling program, along with higher gas prices, to justify the price that they paid for the assets. So we built that accelerated program that they announced publicly into our 2012 plans.

With the write-down, again, not knowing the details of the write-down but having observed a slowdown, not a stoppage but a slowdown, in their development plans, we think the recent announcement means that BP is likely going to assume a development pace that's probably far closer to our original Chesapeake assumptions. Again, those were the assumptions that we modeled our acquisition on.

Having said that, even if our volumes are flat to up slightly over the next year or so, until gas prices improve in late '13 and '14, the systems are still anchored by very long-term contracts, with some of the highest credit counterparties in the lower 48 shale game, that being BHP, BP and Exxon. And they are drilling at a sufficient rate to maintain flat to slightly increasing volumes through our assets.

So frankly, I think we're better off with the exposure to improving gas prices and with a very strong counterparty like BHP. Ultimately, we believe they will come back to their accelerated drilling program to justify the investment that they made.

So that's our take on the BHP announcement. Let me just speak finally to our going-forward strategy. As you all know, the acquisition market is getting much more crowded, and as a result, multiples continue to climb. We're going to be very selective going forward as we look at new opportunities. We'll continue to look for bolt-on acquisitions like Devon. What we won't continue to do is to diversify our portfolio with the acquisition of additional wellhead gathering processing, treating in other shale plays simply for diversification sake. What we will be looking at are assets up and down the value chain or something transformational to diversify our portfolio, unless, of course, it's a bolt-on like Devon, which allows operating synergies, as well as the accretion that we're acquiring.

In its place, we're prepared to ramp up and focus on developing new greenfield opportunities in the rich gas plays, like the Avalon, Permian, the Utica and the Niobrara. And, as I said before, we own a 60 -- brand-new 60 million a day gas plant, and we'll own a 5-year-old, 100 million a day gas plant when we close the Devon deal. And we hope to leverage off of those into some of these new rich gas plays. It gives us a huge timing advantage as we're negotiating with these producer operators for the infrastructure needed to develop these. And this reminds me of the way we operated at GulfTerra and Enterprise, where we had an active acquisition program, coupled with a very aggressive and first-class business development team.

So we're in the process of putting that business development team together. We're going to leverage the plants, leverage our producer relationships, leverage our First Reserve relationships and use the Crestwood brand name that we've created over the last couple of years to hopefully become a major player in developing some of these rich gas infrastructure plays. So stay tuned for some exciting announcements in the months ahead with that.

And Mark, with that background, I think we're ready to open the call up for questions.

Mark G. Stockard

Great. Thank you, sir. Go ahead and give instructions and open up the line for questions. Thank you.

Question-and-Answer Session


[Operator Instructions] We'll go first to Mark Reichman of Simmons.

Mark L. Reichman - Simmons & Company International, Research Division

It looks like you did manage your costs very well. I was just curious on the gathered and processing volumes. What might you expect in the latter part of the year, the second half, excluding the impact of the Devon acquisition?

Robert G. Phillips

Mark, again, we revised second half guidance last week before the equity offering, but we didn't lay out volumes as we typically don't do. Let me -- without giving you specific volume guidance by segment or by system, let me just give you some color. The color is that in the Barnett dry gas, which has been kind of the focus or the criticism with our portfolio, we added significant volumes in the second half, in the latter part of the second quarter. Those volumes are currently driving kind of higher volumes back to where we were at the beginning of the year in the Alliance area. We're kind of running in the 200 million a day range in the Lake Arlington area because the Chesapeake offload is down due to their curtailments. We're running less than 100 million a day, but those numbers are consistent with where we were at the end of last year and the beginning of this year. And we kind of expect to stay there on Alliance and Lake Arlington for the balance of the year. We don't have any insight into Quicksilver's drilling program for 2013 yet. At this point in time, we think it's far too early for that. But dry gas ought to stay relatively flat for the balance of this year. Rich gas in Cowtown, as we said, as Bill said earlier, is up pretty significantly from our second quarter average, and we expect to add the 95 million a day, possibly even over 100 million, 105 million a day potentially on the Devon system by the time that we get that fully integrated and rolled over. So a pretty significant increase in rich gas volumes there. In the Fayetteville, again, same issue. We added wells at the very end of the second quarter. Our volumes in Fayetteville right now are up around 95 million a day. They haven't been there at any time this year. They averaged 78 million a day during the quarter. So you can see the impact already from the 6 new wells that we added on the 1 pad at the end of the second quarter. Based on BHP discussions and activity they have in the field right now and instructions they've given us for where we need additional laterals and additional treating capacity and potentially additional compression around our Prairie Creek system, we expect them to add another 12 to 14, maybe 15 wells in the second half of the year. These wells are typically -- come on in kind of the 2 million a day range. So our expectation for Fayetteville second half year is frankly up from where we are now. So hope that will work. In the Marcellus -- yes, go ahead, Mark.

Mark L. Reichman - Simmons & Company International, Research Division

On the Marcellus, it seems like that, that joint venture has performed in line with expectations, if not a little better. How are you thinking about -- you mentioned the possible drop-down of an additional interest. I mean, what will kind of drive that? Or how do you think about that and kind of the timing there?

Robert G. Phillips

Great question. I'm glad you brought it up because it is something we're thinking about in the long range plan. Original acquisition forecast had us not dropping that until sometime in '14 on the first drop, probably accelerate that to earlier in '13. We'll make the call on that when the actual performance gets to a point where it's exceeding the acquisition forecast. And at that point in time, I think that would be a good point to drop. Remember that we do have minimum volume guarantees. I think the average for the second quarter was 270 -- 257, not 275, Bill, 257. The minimum volume guarantee for the year is 300. We hope to be at or above that. We'll be well above that by the end of the year. We'll exit the year well above the 300 and be real close to the 300 minimum average for 2012, or at least for the 9 months 2012 because we won't have a full year on that. So the good news is, the wells there are far better than we thought. They're probably 20%, 25% better than we thought they were on the acquisition forecast. We're running maybe a few wells behind, but Antero looks to pick up pretty significantly in the second half of the year, thus, the expectation for an additional 20 wells. And then we get a new development plan from them every month, and our 2013 view -- their 2013 view is the volumes will be higher than our acquisition forecast by about 5% to 8%. So, again, if all these things come together as we hope, we've only owned the business for a month, but it's going to make a pretty meaningful contribution to CMLP for the second half of the year. And if we accelerate the drop-down, then that will be a significant growth driver for 2013 for us.


[Operator Instructions] We'll go next to TJ Schultz of RBC Capital.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Just on the equity recently, obviously, more equity that was needed for the Devon deal here. Are there other specific bolt-on targets you have near-term or was this more a function of just thinking to put in kind of a more conservative balance sheet?

Robert G. Phillips

TJ, great question. I wish I had the data at my hand. Let me describe it this way. We have historically managed this business from a capital standpoint to a 50% equity, 50% debt threshold. At the same time, I like to keep around $150 million liquidity because those are kind of the deals that we see in our wheelhouse that we can execute quickly on. So both of those were in our thinking when we decided to go ahead and hit the market. Frankly, I've observed the broader equity markets over the summer. And just like everybody else, we never know from week-to-week whether Europe's going to be a problem or there's going to be broader issues that shut down the equity markets for anybody much less for MLPs. We know that the long-term equity story in the MLP market is good, that infrastructure capital is continuing to flow into our industry and people want to invest in these projects. So the main thing is, we wanted to keep a good 50-50 balance. The equity offering does pretty dramatically improve our leverage ratio on a pro-forma basis. I think Bill touched on that, but I'll highlight it again. Pro forma gets us down to 3.7x. That's a good thing. I hope that investors pick up on that. So we've got dry powder. Yes, we are working on some additional bolt-ons. More importantly, we're working on some additional development projects that we hope will be kind of the next strategic leg down for Crestwood, and I just want to make sure that I've got plenty of liquidity to do those things and have the flexibility to step out there and do them if the opportunity presents itself later in the year.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay. And then, I guess, just so I understand with the Devon plan and kind of the movements with some of the processing. So the volumes will be placed on your existing plants, and the Devon plant will be idled. I mean, is this or will this or can this older plant be utilized elsewhere?

Robert G. Phillips

Absolutely. And we made that point in the press release, and I said it again in my opening observations and I want to say it one more time. There were 3 drivers in this deal for us. One was, it's an accretive acquisition. It's very accretive this year and next. And so we needed that accretion to cover the conversion of our Class C units. This is the deal that does that. So everybody that's been worried about converting those Class Cs shouldn't worry anymore. This is the deal that covers the Class Cs, and -- so we're excited about that. We bought it at a full but fair price, and it's going to have a big impact contribution in 2013. That was the first driver. The second driver was, this allows us to optimize significant excess capacity we have in the Barnett Shale on those plants we bought from Quicksilver. When we bought the business in 2010, we had 325 million a day of processing capacity in those 3 plants, 2 Cowtown plants and 1 Corvette plant. We've only been running about 140 million to 170 million a day through those plants, depending upon offloads. Today, we're running about 170 million through those plants because we've got some of the Devon offload gas coming to us. That still leaves us with 150 million a day of excess capacity. So, as you know, you can always operate your own plant cheaper than you can operate somebody else's plant. So we're going to interconnect the 2 gathering systems, which lay right next to each other, very small 3- to 4-mile pipeline that will connect the 2, that will give us an even larger offload point than the existing connect that we have today. And then we're going to basically shut down the Devon plant and flow all the gas over into our plant, lowering our operating expense, spreading our fixed cost across now what's going to be about 250 million to 260-or-so million a day through our 325 million a day plant complex. That's all good. That results in lower operating cost for us. The plants run better at the higher volumes, and we give the lower wellhead pressures and the higher NGL recoveries to Devon. So that was all part of the deal. The third and final benefit is, we can now take that 100 million a day plant, which is probably a new plant in the open market with cost, what, Joel, $16 million, $17 million?

Joel D. Moxley

$15-plus million.

Robert G. Phillips

$15-plus million, plus compression, that we're getting in the deal, and now we got a 6- to 9-month time advantage on anybody else because that's the queue right now for new 100 million a day processing plants, maybe 9 to 12 months on the -- Joel is saying more like 9 to 12 months in the queue on that. So that gives us a very clear advantage. We can bring a brand-new 60 million a day plant that's sitting in a warehouse at Exterran and a relatively new 100 million a day cryo plant, which we can pick up, along with compression, and move into one of these new areas. And we think that gives our new BD team, which we're assembling and about ready to announce a significant advantage in some of these plays that we're working on. So yes, that was a very important part of that. And, of course, if nothing else, we'll just sell the plant to somebody, take the cash and we got a much lower purchase price. It's still a very accretive deal for us.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay, great. I guess, just lastly, in the Granite Wash. Sorry if I missed this, but just some detail maybe on the cost you owe for some of the gathering expansions that you kind of indicated there at Indian Creek?

Robert G. Phillips

De minimis. Under the contract that we have with the producer they gather to us to our existing points on the system. So right now, we're looping an 8-inch line and adding a little bit of compression, but it's relatively small in terms of capital. What we are excited about is filling this plant up and being able to expand the plant for the additional acreage and potential of the long-term development there or the other 37,000 acres that's closer to us. So yes, relatively little capital but a pretty significant potential increase in volumes through that plant over the next 12 to 18 months.


And at this time, there appears to be no further questions. I'd like to turn the conference back over to the speakers for any additional or closing remarks.

Mark G. Stockard

No, we appreciate everyone's participation this morning. And thanks again.


And again, that does conclude today's conference call. We'd like to thank you for your participation.

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