Regency Energy Partners LP (NYSE:RGP)
Fifth Annual Investor Day Event
March 28, 2012 10:00 am ET
Michael J. Bradley - Chief Executive Officer of Regency Gp Llc and President of Regency Gp Llc
Greg Bowles -
Jim Holotik - Chief Commercial Officer of Regency GP LLC and Executive Vice President of Regency GP LLC
Shannon A. Ming - Senior Vice President of Finance and Investor Relations - Regency Gp Llc
Chad Lenamon -
Glen Wind -
Thomas E. Long - Chief Financial Officer of Regency Gp Llc and Executive Vice President of Regency Gp Llc
Unknown Executive -
Michael J. Bradley
Here we go. We're good? All right. Good morning, everyone, and thank you for joining us today and taking the time to hear more about the Regency story. I'm very pleased to welcome you to the Fifth Annual Investor Day event. And we are very excited to have the chance to share with you more detail on our business segments but, very importantly, the growth plans and opportunities that we see for 2012 and 2013.
We'll be happy to take your questions today and we'll have a Q&A after each business segment presentation and -- but ask that you hold your questions until then. For those of you accessing the presentation on the Internet webcast, the slides will advance along with the audio portion of today's presentation, and you will be able to download a PDF copy of the investor presentation under Investor Relations section at regencygas.com.
I want to start to take a minute to mention that Slide 2 describes our forward-looking statements and lists some of the risk factors that may affect actual results. Also important to note is that you will find various non-GAAP measures that have been reconciled back to GAAP in the Appendix section of our presentation.
But before I get started on today's agenda, I want to introduce the Regency Senior Management Team and your speakers for today. First, we're pleased to have Greg Bowles, who will be presenting an overview of our Lone Star joint venture. Greg is Executive Vice President of Lone Star and was previously Vice President of Marketing for LDH Energy where he worked since 2000. Greg knows the Lone Star assets better than anyone and we are pleased that he can join us today to discuss our business and opportunities around this very strategic asset.
Next, Jim Holotik will be presenting an overview of accomplishments and opportunities within the Transportation, Gathering and Processing segment. Jim joined Regency in October of 2010 as Executive Vice President and Chief Commercial Officer. Jim has over 30 years’ experience in the energy industry and has been an invaluable part of our commercial team.
Chad Lenamon is President and Chief Operating Officer of CDM Resource Management and he will be taking you through an overview of accomplishments and opportunities within Regency's Contract Compression businesses. Chad has more than 15 years of experience in the industry and in compression in particular and has been an integral part of the CDM day-to-day operations since joining the company as one of its first employees.
Next is Glen Wind, and Glen is President of our Contract Treating segment or the Zephyr Gas Services, which we acquired back in September of 2010. Glen has more than 30 years’ experience as well. We're getting to be an old group here, I guess. I don't know, I -- we all seem to have more than 30, which is good. And he will provide us with an overview of the treating business and the growth opportunities that we are seeing in this business today.
And then our final presenter will be Tom Long, who will be presenting our financial overview and strategy and goals. And Tom joined Regency as Executive Vice President and Chief Financial Officer back in December of 2010 and, again, has more than 30 years’ experience in the energy business and then, particularly, a strong background in finance and accounting and has been a very key part of our management team.
Again, we're all pleased to be here today to provide you with more insight into Regency. This is a very exciting time for us, and we're very pleased to have a lot of good things to talk about in terms of our future not only in 2012 but what we see going into 2013. With the support of our Board, our outstanding employees and general partner Energy Transfer Equity, I believe we are in an excellent position for further growth.
Turning to the next slide, I will begin this morning with an overview of our business, our growth strategy and why we believe Regency is an attractive investment opportunity.
When we go back to the beginning of last year, 2011 was a transformational year for Regency as we became a significant player in the NGL logistics business. We expanded our presence in 2 very key liquids-rich shale plays and announced over $1 billion in organic -- growth projects all associated with the shift to the liquids-rich plays. As a result, we have evolved into a comprehensive midstream service provider with a significant presence now across the entire midstream value chain.
Over the past year, we achieved some major accomplishments, and it starts in May of last year when we closed on the acquisition of a 30% interest in Lone Star, which is a major player in the natural gas liquids industry. Then in June, the joint venture announced the construction of a 570-mile long NGL pipeline called the Lone Star gateway pipeline. Following that, we announced 2 new fractionator projects to be built at Mont Belvieu. These projects for Lone Star will help address the current constraints in the NGL takeaway and fractionation capacity issues particularly in the Eagle Ford Shale and the Permian Basin and continue to see high demand in these growing liquids-rich plays as we go forward into 2012 and 2013.
Also in June of 2011, Regency announced the $450 million Eagle Ford expansion project, which is going to expand our gathering capabilities in this liquids-rich region. When complete, our South Texas system will be capable of moving about 1 Bcf a day. And then in December, we formed a joint venture with affiliates of Chesapeake and Anadarko, which we call the Ranch JV, which will provide new processing capacity in West Texas. Greg and Jim will discuss some of these growth projects in more detail. And we believe these growth projects will significantly expand our footprint in these liquids-rich plays but also lay the foundation for additional growth opportunities as we go forward.
Moving on to our financial highlights. I think one of Regency's primary focus in 2011 was growing our business organically and also growing our distributable cash flow. In addition, from full year 2010 to year-end 2011, our adjusted EBITDA increased 29% and we have doubled our EBITDA since 2009.
Our 2011 distributable cash flow grew by more than 20% over 2010, and for the full year, we reached a coverage ratio of 1x. We were also able to resume distribution growth in 2011, ending the year with a distribution exit rate of $1.84 per common unit. And we are pleased with our financial performance in 2011 and will continue to focus on growing our coverage in distributions as we move forward into 2012 and 2013.
Let's talk about the strategy a minute. And we believe that the following items are going to be key to support our growth, our increased coverage in distributions and to achieve investment grade ratings. In order to first increase the scale of our business and continue to grow our distributable cash flow, we are focused on, number one, further expanding and growing our integrated midstream platform of services. I think the range and quality of our service offerings allow us to provide our customers a list of comprehensive services, which we think gives a competitive advantage. Also, the strategic location of our assets in some of the major shale plays and basins has created tremendous growth opportunities for our businesses not only in 2012 but as we look forward into 2013. We also look to better optimize our assets to maximize their value.
And second, we will continue to look at maintaining a high percentage of fee-based cash flows. As we have grown our business, we have improved the diversity of our cash flows, which are primarily fee-based, and limit our exposure to commodity fluctuations. The third is to maximize organic growth opportunities which have attractive returns. And as stated earlier, the combination of our various business segments and the strategic location of our assets particularly in these liquids-rich plays have created some new growth opportunities for Regency. As a result, as I mentioned, we announced over $1 billion in major organic growth projects to be completed over the next few years, which includes approximately $500 million in our Gathering and Processing segment and approximately $500 million in our NGL logistics segment. Importantly, our focus is to execute on these projects to successfully generate the highest possible returns. We're going to continue to see organic growth opportunities, as I mentioned, which you will hear more about. I think these are exciting times for Regency, and we have a strong focus in all of our business segments for 2012 to position and capture additional growth opportunities as we move forward.
Fourth, we will continue to evaluate strategic acquisitions to further expand our footprint but also enhance our service offerings. In addition, we're going to look at opportunities, in particular, consolidation opportunities, within our existing plays. And lastly, we value the relationship with Energy Transfer Equity, who is our general partner. And ET has been very supportive of our business strategy, and we believe they will continue to facilitate our ability to grow Regency and create unitholder value, going forward.
To kind of summarize, we believe focusing on these objectives will allow us to grow our unitholder value through increasing our distributable cash flow per unit, increasing our coverage and achieving investment grade ratings.
Looking at our platform. With the acquisition of a 30% interest in Lone Star in 2011, Regency has established itself as a comprehensive midstream service provider providing natural gas and natural gas liquids services. And this includes gas gathering, processing, contract services, transportation, along with NGL transportation, fractionation and storage. The combination of our business segments provide a broad range of services for our customers and positions us well for the future growth particularly in the liquids-rich plays, which is driving growth today across all of our business segments.
As we've extended our service offerings, we have also significantly improved the diversity of our cash flows. Since 2007, we've expanded our portfolio to include contract services, which provides 100% fee-based margins, and the addition of Lone Star joint venture, which provided further fee-based margin diversification. The $1 billion in organic projects we also announced are supported by long-term fee-based margins. Our margin is now comprised of a much broader mix and more comprehensive portfolio that contributes to what we believe is steadier cash flow and less susceptible to change in market conditions. For 2012, we are expecting our fee-based business to approximate 80%. I think this next slide better demonstrates how we are currently positioned with our businesses relative to the most prolific and emerging shale plays in the U.S. Increased drilling in the liquids-rich plays is driving volume growth in our Gathering and Processing business and creating new demand for NGL transportation, fractionation and storage. Our strong position in these businesses have laid the foundation for major growth projects, as we've already discussed, with each of these business segments.
In addition, as producers have shifted their drilling programs to these areas, we are seeing new opportunities for our contract services businesses as well, and Chad and Glen will be talking about that. The demand for compression comes earlier in the process as the associated gas is typically lower pressure, and it must be moved in order to produce the oil and liquids. Treating and condensate stabilization opportunities are also developing, and this is driven by higher concentrations of CO2, H2S. And the very rich gas, which is creating opportunities for treating and condensation stabilization. Our assets are also well positioned in emerging plays like the Brown Dense and the Mississippian Lime shales, along with key dry gas shales, as prices recover.
Since our IPO, Regency has invested over $2.8 billion in acquisitions and through 2011 we -- has generated a considerable growth opportunities. For 2012, as I mentioned, we're going to focus on investing on organic growth and capital expenditures are expected to nearly double over 2011 levels. We believe these projects will also lay the foundation, as I mentioned, for future growth opportunities and provide higher returns compared to acquisitions, again supporting our objective to increase coverage and distributable cash flow as they come online.
As I mentioned, a key focus for 2012 will be on investing in organic growth opportunities and to build and acquire energy infrastructure that generates solid results, expand our scale and footprint and business diversity. Regency's $1 billion of organic growth projects are expected to come online by early 2014, as highlighted on this slide.
These expansions are extensions of our existing assets and are all associated with the developing liquids-rich plays in the Permian and in South Texas. As I mentioned, in addition, these projects are supported by long-term fee-based contracts, and we expect they will provide new expansion opportunities, as I said, going forward.
So before I end my opening remarks, in summary, I think #1 is the strategic location of our assets and the diversity of our service offerings has positioned Regency to benefit from increased drilling in the liquid-rich plays. While our assets are positioned to benefit from these liquid-rich plays, I think they're also strongly positioned in dry gas plays, like the Haynesville, when natural gas prices recover. We are also sitting on one of the largest growth platforms we have ever had at Regency, which has positioned us for significant increases in scale and opportunities over the next several years.
As I mentioned, we're very excited about the opportunities we're seeing for all of our business segments right now, which is positioning us, again, for what we believe is significant future growth, again particularly as our fee-based growth projects, currently under construction, start to come online. In addition, our general partner, who is very supportive for our growth objectives, combining this with our extensive experience, as I laid out, with our management team, Regency is well positioned to create unitholder value.
I will now turn the presentation over to Greg Bowles, but first, I'll stop and see if you have any questions for me at this point in time. Otherwise, we'll go into the business segments and have questions following each of those.
Okay, well, let's go ahead and move into the business segments. And we'll have plenty of time for questions. Greg, I turn it over to you.
because I think we've got a lot of exciting things going on at Lone Star, and I can say Greg knows more about these assets than anybody. And we just think there's tremendous opportunities not only in front of us today but as we go forward. Thanks, Greg.
Good morning. Thank you for being here today. I'm -- I'll go over -- give an overview of our Lone Star NGL business and the projects that we have underway. After we do that, I'll answer any questions that you may have.
In May 2011, Regency contributed $578 million in exchange for a 30% interest in Lone Star NGL Joint Venture. Energy Transfer Partners contributed $1.35 billion in -- for 70% interest and is the operator of the joint venture.
Lone Star's assets are comprised of 3 business segments: The NGL Storage segment includes facilities in Mont Belvieu, Texas, and Hattiesburg, Mississippi, both of which are -- provide 100% fee-based cash flows. The Mont Belvieu storage facility is an integrated liquid storage facility at the NGL hub of North America and the world. Hattiesburg storage facility connects to the Dixie pipeline to serve customers in the Southeastern U.S.
The NGL Transportation segment consists of the West Texas pipeline, a long-haul intrastate pipeline that transports mixed NGLs from the Permian Basin and Barnett Shale to Mont Belvieu. The Fractionation and Processing segment provides refinery services through 2 cryogenic off-gas processing plants co-located at third-party refineries. That's connected to a 25,000-barrel per day olefinic mix NGL fractionator near Baton Rouge, Louisiana.
As you can see from this slide, Lone Star EBITDA is currently comprised mostly of the NGL Storage and Fractionation and Processing segments. As Lone Star's interim expansion on the pipeline ramps up, it's actually underflowing right now. In 2012, of the -- ahead of the gateway expansion, we expect the transportation contribution to the Lone Star EBITDA to increase. In addition, the majority of Lone Star's margin is derived from long-term fee-based contracts related to NGL Storage and Transportation, and we do not expect this to change. These contracts are -- historically had -- have had very high renewal rates and we expect that to continue. Our primary commodity exposure comes from our refinery services business and that commodity exposure is tied to NGL, ethylene and propylene pricing.
The addition of an interest in the Lone Star to Regency's portfolio provided a significant NGL logistics platform, which better positions us to offer comprehensive services to producers both at a Lone Star NGL level and also at the Regency level. Since this acquisition, Lone Star has announced 3 major expansion projects: the West Texas Gateway NGL Pipeline and 2 new fractionators that will facilitate growth for each of Regency's business segments. Construction of the 209,000-barrel per day gateway NGL pipeline is underway, and the pipeline will expand to NGL takeaway capacity from West Texas and South Texas to Mont Belvieu. We expect that pipeline to be 75% contracted by the middle of this year.
Lone Star is constructing new 2 new fractionators at Mont Belvieu. The first, which is fully contracted, is expected to be online in the first quarter of 2013, and the second is expected to come online in the first quarter of 2014. Capacity in the second fractionator is currently approximately 65% committed. And based on our current contract negotiations, we're very confident that we will fill that second fractionator. The additional fractionation capacity will ease the bottleneck of NGLs to the downstream markets and help facilitate the NGL pipeline, facilitate the gas processing business of Regency and Energy Transfer, as well.
Lone Star is also seeking to expand beyond its current assets by enlarging its NGL gathering footprint in the Permian area related to the West Texas gateway project that we have underway and is also exploring exports for -- of NGLs from the Mont Belvieu area. In addition, we are pursuing expansions of our Fractionation and Processing business, our refinery services business in Louisiana to help refiners maximize operations, profits and reduce emissions.
The key advantage to this business segment, the refinery services business segment, is that it's not dependent on onshore production because our gas streams come from refineries that run all the time. We are also looking to optimize our storage mix at Mont Belvieu to maximize storage revenues as industry trends change and -- between the NGLs, refined products. We store olefins there, we do. We store a lot of different products and we optimize that continuously. And we'll continue to do that.
With that, I'll answer any questions that you may have on the NGL business.
Yes, sure [indiscernible] fractionators in the pipeline, through which we'll have -- we'll not [indiscernible] down. It's [indiscernible]. But I'm trying to get a sense of what type of EBITDA multiples are there at the current contracted levels. What I'm really trying to get to is, based on what's been contracted, if that's where we start, we have one kind of sense of money we're going to make that's going to fall to the bottom line. But because of the unsold capacity to date, that's basically costless growth for the future because the money is spent. So I'm trying to get a handle on what our upside is above the current contracted levels as far as compressing today's multiple down more or total return.
Yes. All 3 projects are accretive already at current levels. Obviously, the full fractionator is a full return. The pipeline, when fully contracted, which I believe will happen, I would be surprised if we're not fully contracted before we're operational because we're going to be the first to market with new capacity, and that’s the direction it’s going, it appears. The pipeline has a very attractive return, much greater than 15%. The fractionators have returns in the high teens, a little bit lower than the pipeline but not by a whole lot. And the fractionators are 10-year contracts, pipeline contracts are 15-year contracts. Yes?
Embedded in those returns are what kind of ramp-up in the pipeline in terms of capacity utilization?
Yes, it varies. It varies -- the current contracts are flowing full volume in 2013 -- by the end of 2013 on the transportation side, I believe, pretty close to full.
So once you have this in service, people will be fully paying for contracts by the end of the year?
Right. The majority -- a big proportion of that is from the very beginning. One thing to keep in mind is, West Texas, the Permian Basin is already bottlenecked for NGL transportation. And so as you see in the industry, people continue to build the production, people continue to build gas plants, and so we have this backlog of NGLs that are building up. We're alleviating a little bit of it with an interim project that started up right now, but NGLs are backing up in anticipation for this pipeline to come online. So it's not like the pipe is starting from 0 and going up. It has a good portion of its volumes from the very start. Yes?
Can you just explain what the hurdles are in terms of trying to build an export facility in Mont Belvieu?
Sure. Yes, we are unique in that we're one of -- we may be the only player that is not currently exporting NGLs but we have the nuts and bolts necessary to do an export project by virtue of our storage facility, by virtue of the fractionators and by virtue of the -- all of the propane that we already handle at our current storage facilities. The challenge with exports, and this is a challenge for everyone in the MLP space, is that the exports markets have historically been about one year in length as far as people contracting to load ships at the dock. One year, lots of spot business. That right now has gone to -- the market has gone to about 2 years. The challenge for someone like us is that it takes us to -- 18 months to build a project. And so, it’s difficult for an MLP to get the types of contracts necessary to feel good about proceeding with a "several hundred million dollar" project. And so really, the limitation -- the only thing that we are waiting on at this time is to get the right market contracts to feel comfortable doing. And of course, with the arbs [ph] wide open and with -- as volumes increase as these fractionators spin up, the market, I believe, is going to come to us to where we need it to be. I -- we're in active consultation and negotiations with potential partners, potential customers and customers that may be partners with us in the facility itself. So that's -- the challenge is to get the offtake agreements that make you feel comfortable with proceeding.
Could you just sort of ballpark how large a facility? How many barrels would you be looking to export to make this thing worthwhile?
Yes, our project would load propane at 10,000 barrels per hour, which is world class, what we would -- what we feel needs to be done. The -- a dock can give you about -- depending on how you schedule -- how efficient you are at scheduling it, it could give you 7 or 8 slots per month.
And then if I could just move to the Permian Basin. You had also mentioned that you are looking at trying to expand the NGL gathering. Could you sort of elaborate on that comment? And what are you thinking there?
Yes, not at this time, because things are in motion. But the -- you can see, our gathering footprint right now is in a very specific area. We're connected to a large proportion of the existing gas plants. Obviously, as we sign these West Texas -- the new pipeline deals, we're extending our gathering system to a given plant. But there are attractive regions out there that we're not -- our gathering system does not exist and we're looking to expand.
[indiscernible] the export terminal. What would be your source for purity propane?
Well, a good portion of it would come from our own fractionators. The fractionators that we're building right now are designed to produce export-grade propane. In conjunction with the project, we would also be building a de-ethanizer that we would feed HD-5 domestic-grade propane to. Question up front.
Can you just elaborate a little bit on the refinery services, the expansion -- yes, if you could just elaborate a little bit on the refinery services expansion that -- the specifics that you are pursuing there?
Yes, the -- not all refineries in the Mississippi corridor -- Mississippi River Corridor currently process -- optimize their off-gas. They're -- this is primarily cracker and copper off-gas that we process. So we're looking at doing bolt-on expansions, if you will, to our refinery services business with other refineries. This business line is particularly lucrative for the refineries as well as us. And part of the -- a good portion of the value-add is the fact that you're recovering ethylene and propylene from something that otherwise was going to be used as fuel. And so you're taking natural gas -- ethylene and propylene that was before valued at natural gas Btu value and you're putting it right into the polymer-grade ethylene and propylene markets. So it's quite lucrative for the refineries to do these sorts of projects especially in this market environment for refining in general.
All right. If that's it, I'll turn it over to Jim Holotik. Thank you.
Thanks, Greg, and welcome, everyone. Shannon Ming always makes me promise 2 things before I get up here. One is, don't touch the laser pointer, and the other is, don't tell a joke. Well, I'm not going to touch the laser pointer. However, there was this guy, he's got a check-up and went to his doctor, to get the report, and the doctor said, "I got bad news and worse news." And then the guy said, "All right, well, give me the bad news." And the doctor says, "Well, you're going to die in 24 hours." Then he goes, "Oh my God, what's worse than that?" And he said, "I forgot to call you yesterday."
Anyway, that doesn't have anything to do with my presentation. I just thought it was funny. But my goal today is to provide you with an introduction into our existing assets, along with providing the commercial viewpoint from the ground level, giving you an insight as to what we're seeing in our different commercial operating areas and how we plan to use our existing asset platform in congruence with our announced projects to create a continuing growth vehicle.
It's always interesting to note the drivers in the core areas, much like last year, the key drivers are the advancements made in drilling and completion techniques, liquids-rich gas production and NGL take away and handling of liquids infrastructure. We believe our diverse asset footprint, as well as our strategic location of assets, helps set Regency apart from our peers and we expect major liquid-rich shale plays to be primary growth vehicle and provide uplift for the business year of 2012.
But also, we expect to see some uplift from newly emerging formations as they are further developed. Not to mention, it's great to have Greg here, one of the items that has provided us with a catalyst in these growth areas is the acquisition of LDH or now Lone Star. This liquid platform completes Regency's ability to provide producers with a complete array of services by being able to handle NGLs along with their natural gas.
Our Transportation assets consist of our MEP joint venture, which is operated by Kinder Morgan and RIGS joint venture, which is operated by Regency. These assets consist of approximately 950 miles of intra- and interstate pipe. Our gathering and treating processing facilities are geographically positioned to take advantage of predominantly liquid-rich natural gas plays such as the Midcontinent, which is close to the Mississippian Shale; North Louisiana, which has the Bossier, Cotton Valley, Haynesville, Brown Dense; West Texas, with Avalon Shale and Bone Springs shale; and South Texas with the Eagle Ford Shale. And also on the map is our newly acquired Lone Star acquisition.
In total, these assets consist of 6 processing facilities, 6 treating plants over 6,000 miles of gathering pipelines with over 220,000 horsepower of compression. As we drill down into the individual business segments, I will illustrate how the Lone Star acquisition has benefited our existing assets and provides a launch point for new projects.
First our Transportation segment. Our rig system consists of 450 miles of pipe with multiple interconnects to downstream interstate pipelines and Louisiana markets. At our pipeline expansion of 36- and 42-inch pipe, we added 1.2 Bcf of capacity to our legacy system, which was running about 900 million cubic feet a day, bringing the total available capacity to 2.1 Bcf. Approximately 85% of our margins from the expansion are from demand fees and on the legacy portion, approximately 87% of our margin is covered by in-demand fees. The system is integrated with a number of North Louisiana facilities and is well positioned to receive additional Cotton Valley and Brown Dense gas from our Dubach system.
We have seen increase in utilization on the market side from markets such as Union Power, which –- it had hit a peak demand day of 360 million Btu a day on the system, as well as gas movement on and around storage facilities that are connected into RIGS, utilizing approximately 103 million Btu a day of backhauls. The Midcontinent Express is a 500-mile interstate system that originates in Bennington, Oklahoma, and terminates at the Transco interconnect at the Mississippi and Alabama state line. It has capacity of 1.8 Bcf.
MEP accesses numerous basins including the Barnett, Woodford, Bossier and Haynesville shales. MEP is fully subscribed with long-term demand-fee based contracts and has a competitive advantage as its pipeline design allows it to offer competitive fuel rates in variable costs to transport for suppliers from the Midcontinent area to pipelines serving the Eastern markets.
In the third quarter of 2011, Regency increased its ownership interest in MEP Joint Venture by up to 50% by purchasing the remainder of ETE's interest. We're seeing some additional opportunities to provide ancillary services on MEP, such as backhauls and park and loans.
Looking at the performance of our Transportation business in 2011, total throughput on our RIGS asset was down in 2011 primarily due to one customer who has been off-line due to an operational upset. However, based on conversations we've had with this customer or this producer, we anticipate their facilities to come back online around the beginning of the second quarter of 2012 and their volumes to begin ramping back up. Approximately 70% of our total firm Transportation contracts are for 10 years with 6 to 8 years remaining on these agreements.
MEP throughput decreased slightly throughout 2011. However, with the contract mix consisting mostly of long-term demand FTA [ph] agreements and utilizing backhauls with park and loans, EBITDA still increased each quarter. I would reiterate that both of these systems are almost fully subscribed and the majority of the fees come from demand charges, which helps to mitigate the impact of low gas prices and reduced drilling in some of the regions surrounding these assets.
One of the interesting things to me is the transition that everybody always makes from wet to dry gas and it seems like every year, we come up with a term that's being completely overworked. This year, the term most people are using is liquid rich. And surprisingly enough, I will be no different than anyone else in overworking this term during this presentation. However, as you can see, our driving factor, when you look at the volumes that we're currently targeting, you'll see quite naturally, we are gravitating to the regions where the drilling is located. The greatest advantage to Regency is that the liquid-rich volumes require many ancillary treatments before it's ready for marketing in its various components. This is such as dehydration, treating, processing, compression, liquid takeaway and fractionation, all of which are services that we now provide. So keep that in mind and I will give you a closer look of our individual gathering and processing facilities.
The Midcontinent area consists of our largest gathering systems with approximately 3,470 miles of pipe, as well as available processing. We expect drilling activities to increase [ph] in the Midcontinent due to recent announcements from a purchaser of reserves from our dedicated acreage. Also, 2 producers have started to utilize horizontal drilling to increase recoveries per wellbore. We're making a concerted effort to optimize our operations and extend our existing systems into the developing Mississippian Lime shale play, which is a liquids-rich play with associated gas.
This play extends from the south and east of our facilities and producers known to us have established over 900,000 acres of leasehold positions in 16 counties in Kansas and Oklahoma. The Midcontinent is a mature region in which production experiences neither rapid decline nor growth. But the volumes on our system has remained relatively flat and we expect this trend to continue in 2012.
We have the possibility for upside as the Mississippian Shale and Granite Wash plays stretch towards this system. In addition, a significant portion of our margins are fee-based as our FrontStreet assets provide fee-based revenues on a cost of service methodology that is not dependent on flowing volumes.
In North Louisiana, these assets revolve around 3 main facilities: Elm Grove, Dubach and Logansport. Our Elm Grove is a 200 million a day fee-based plant where Regency conditions gas for producers to facilitate interstate Transportation. Our Dubach system consists of gathering with 100 million a day of processing and 100 GPM treating facilities. We currently experience an increase in processable Cotton Valley volumes due to the new drilling and completion techniques utilized by our producers. Also the Dubach system is well-positioned to gather gas from the developing Brown Dense play where an area operator has most recently announced that they believe that there's 30 billion barrels of oil in place. As you can see on our map, the Brown Dense is on the Arkansas and Louisiana line and going up to the north.
At our previous investor day conference, we mentioned that we expected to see an increased horizontal drilling activities in the liquid-rich Cotton Valley formation, which has traditionally been drilled vertically. Recently, we have seen ramp up in our throughput volumes due to producers yielding positive results from these horizontal wells in the dedicated acreage around the Dubach facility. Also last summer, we installed aiming -- treating facilities on the system to enable us for fee to handle higher levels of CO2 gas. This installation has expanded our services to producers and increased our fee-based business.
With positive results from the horizontal drilling in the Cotton Valley and development of the Brown Dense, we are developing plans to expand our processing capacity as volumes dictate. At Logansport, we continue to see well connect activity due to completions of previously drilled wells and continued drilling on committed acreage. To facilitate this volume increase, we have increased compression and dehydration facilities on our system to utilize open capacity. We have converted the majority of our system to a wet system, which allows greater flexibility while providing additional services to our producers. We expect additional fees from new drills, which have higher CO2 and will continue to need treating.
Margins in the North Louisiana region are well-balanced between fee-based and commodity exposure. While volumes were down from 2 years ago when drilling activity was focused on the Haynesville Shale, in 2011, aggregate volumes increased on our systems as North Louisiana continues to be one of the most resilient producing regions and drilling has continued around the Logansport area.
Our West Texas asset base consists of extensive gathering pipelines and cryogenic processing facilities with a full range of pressure services. However, the most attractive is our low-pressure service to liquid-rich production. One advantage of the low-pressure service is allowing operating companies to produce more liquids.
In doing so, we are able to increase fee-based business because of the utilization of additional compression. With the wide oil to gas price ratio, producers continue to drill this liquid-rich region, which increases demand for additional midstream infrastructure. These assets line the heart of the Permian Basin, which includes the Bone Springs and Avalon shale formation. Last year, we added 41 new well connects into the Waha gathering system, both from new well interconnect and wells drilled behind producer-owned gathering system. This new production has allowed us to back out interruptible, leaner keep-whole gas from our processing facility and replace it with higher margin dedicated production. We continue to see important growth from producers who are drilling behind existing receive points as this adds production to the Waha facility at no cost to Regency.
Additionally, we've just recently added an acreage dedication of 65,000 Bone Springs acres to the current Regency Waha dedication. Our announced Ranch JV with Chesapeake and Anadarko will increase Regency's footprint in the Bone Springs area while creating expansion opportunities around our Waha facility. The joint venture will construct and operate a new 100 million a day cryogenic processing facility, along with the 25 million a day refrigeration plant in the Bone Springs and Avalon shale producing area. These plants will serve as state-of-art processing facilities for producers in the area as well as enable the Waha facility to accommodate production growth. Refrigeration plant is expected to be in service by Q2 2012 and the cryogenic plant is expected to be in service by the end of the year.
We will begin to receive Avalon volumes through our JV partners gathering systems as they are connecting their Avalon acreage into the Bone Springs gathering system that flows into this new facility. We see further growth opportunities in developing Avalon shale play which is just north of our existing system and the Wolfberry producing area, which is east of our Waha system. With these new dedications, we'll continue to expand our system, which eventually will necessitate additional processing facility.
The recent discovery of the Bone Springs and Avalon shale formations has transformed West Texas from a mature play with declining production into one of the most active regions in the United States. This new activity has contributed to increasing volumes on our system over the past year and we expect volumes and NGL margins to increase as producers increase their drilling programs in this liquid-rich play, especially since the primary limiting factor for the area, which was liquid take away, has been solved.
The Lone Star expansion has relieved the liquid transport bottleneck and we believe the West Texas Gateway project should eliminate it. Our South Texas assets provide natural gas gathering, treating, processing and condensate stabilization services. Our natural gas treating facilities remove CO2 and H2S from the gas stream. The Tilden treating facility has additional benefit of providing opportunity to treat both rich and lean gas in 2 separate systems. The geographic location of our treating facilities provides us with a unique opportunity to offer sour gas treatment services in the Eagle Ford Shale.
We recently completed an expansion of our Tilden facility, which added an incremental 20 million a day of capacity, allowing us to utilize additional capacity within our acid gas injection well located at the plant. We also operate 2 separate treating facilities in our Edwards Lime joint venture, which primarily handles gas from our producer partners, which have approximately 60,000 acres under lease in the AMI around these facilities.
During 2011, we completed a series of expansion projects along our rich gas gathering system to increase operational efficiencies and provide an incremental 200 million a day of capacity on our South Texas gathering system.
In June, we announced the $450 million Eagle Ford expansion project and construction is currently underway on this project. Approximately 225 million MMbtus flowed on the Eagle Ford expansion in the fourth quarter of 2011. And additional volumes will be phased in as the project is completed.
The expansion of these facilities, and the increase of our geographic footprint in the area, will allow us to create opportunities and attract and access new volumes to our system while offering the full packaged services of gathering, processing, compression, treating and condensate stabilization. Additionally, we are close to filling our current contracted processing capacity and are actively working to expand our processing capacity in late 2012 or 2013. Upon completion of our announced projects in early 2014, the South Texas system will be capable of gathering, compressing and treating up to 1 Bcf of natural gas and over 26,000 barrels of condensate.
We expect our fee-based revenues to increase in South Texas in 2012, mostly due to new volumes associated with the Eagle Ford expansion project. And we see upside in our margins provided by increased NGLs and condensate production. Volumes in South Texas have continued to increase over the last several years and in 2012, we expect the volumes to further increase as drilling activity continues. As you've noted from this presentation, involvement in the liquid-rich production area calls on many facets of the industry. Additionally, the majority of these new plays are in geographic areas that avoids these types of infrastructure necessary to facilitate production.
Here is something that we have developed and we're proud of. It's a model of our CDP, or central delivery point. Our established CDP design and application allows us for modular portability to other geographical regions, making it an attractive option for producers seeking packaged services including separation, condensate and water storage tanks, natural gas treating and compression. In addition to our ability to package services to producers, we were able to utilize all of our business segments, which creates new growth opportunities for Regency.
As you can see by the full array of services this design creates, an ability for Regency to package those services on an as-needed basis. Our CDP system is continued to be utilized in gathering areas, which also helps us control costs. Also, since they're becoming a standard for Regency, it offers field operators the ability to be familiar with the inner workings of the facilities and have portable knowledge.
In 2012, we expect total gathering of processing volumes to increase overall over year end of 2011. The strategic location of our gathering and processing assets is providing Regency with tremendous growth opportunities. Producers have entered into agreements that call for a new infrastructure within a 2 to 3 year period. Regency has positioned itself and its assets to take immediate production while giving producer expansion opportunities over time. As in areas like the Mississippi shale and Brown Dense have developed, there is some potential for us to further expand our existing asset base into these regions and we continue to closely monitor producers' activities in these areas.
But our most significant growth opportunities are coming from the major liquid-rich plays, the Avalon and Bone Springs formation in West Texas, where we are already expanding our processing capacity and pursuing additional expansion opportunities as well, and in the Eagle Ford Shale where there -- our Eagle Ford expansion projects will provide access to new volumes and we will continue to explore opportunities to offer these services to other producers in the area.
So that is the extent of my presentation. If anyone has any questions, I'll be glad to answer them and after the Q&A, we will take a short break, which we will start with contract services.
On Page 20, where you talked about the firm transportation and legacy system, 87% of the contracts are a little over 1 to 4 years. I'm just curious is that equally spread over the 4 years or is there a difference in the waterfall where most of that 87% either rolls over the next 12 months or 3 years out. I'm just curious if you can comment at all without tipping your hand too much, what the current environment looks like compared to the economics that will be rolling off and should we expect what type of possible hit we might see the cash flow because of the rollover?
Two things I would say to that. Number 1 is it's more or less evenly spaced out, but it is, as it approaches the 4-year, I think you're going to see it's more to the end of the 4 years than the 1 year period. Secondly, the renewals, one of the things on the legacy system that we see is we've got a very competitively priced environment there. Also, on the legacy system is where you have established more of the mature and older production that’s been more establish -- it's not predominantly -- it's not that it's going to move to another system. Once we have it tied in, predominantly, it will stay with that, with us. So probably what we'll see on the legacy system in the short-haul would be some normal decline on the area, but we think that we'll be able to replace some of that gas. However, the new contracts that we're getting are of shorter-term.
Just to Noah's point, as you look to replace those volumes, can you just talk about the rate structure or is there much diminution in terms of what folks are willing to pay?
I'm sorry. What was the last part of the question?
Are you seeing a lot of pressure on rates in terms of trying to re-contract that?
I would say probably on your long-haul rates, there is some pressure on the recontracting. In actuality, the legacy rates were at a competitive rate to begin with, because they were -- those contracts were already in place prior to the expansion. And so those rates will probably remain relatively the same.
Could you give us an example of success that you're having in trying to market the integrated CDP package that you discussed and perhaps, if you could also discuss just the thought processes -- so once you establish that base of operations, is that something that you think will remain in place for 5 years, 10 years, can you discuss the mobility of those assets?
Sure. First of all, one of the things that I would point out about the CDP is what we're offering now is full well-stream service to the producers. Prior to that, people would have to -- they'd contact a gatherer who would set the separation, then have -- and set their own tanks, then they'd go and contract if they needed treating, they’d get a contract treater out there, then if they need a compressor -- so you'd have 4 or 5 different groups working on the same well site. In this new liquid-rich plays, one of the biggest things that you have to be able to do is to handle their liquids because with the oil is coming a lot of condensate and a lot of natural gas liquids. So what we're doing is rather than putting these types of facilities on each individual well head, we've created a spider web of gathering that brings them all to one spot. So to answer the first question of longevity sits in one spot, you’d have to duplicate it every other place if you wanted to switch off of this concept, if a producer wanted to go somewhere else. Also, where we're currently using this is like in Eagle Ford and we'll start establishing that. We've got 10-year commitments on those agreements, in gathering agreements. I think even on the Eagle Ford we may have up to 10 years with a 10-year option. So we fully planned for these facilities to be in place for the life of the agreement. The other thing that it allows us to do is everything on there is a Regency-based company. So if I've got a new producer, I can bring in CDM, I can bring in Zephyr, we go in together and where producers having to see 3 or 4 people to get all of this stuff lined up, we can go in as one and say, we can provide this service, we'll provide this service, we'll provide this service. And our field operators know each other. They operate with each other. They cover for each other. And so you have fewer people on the lease premises itself, which is a big issue down in South Texas these days with how many people are actually on the land owners land.
I think that our ancillary -- I think it's a big benefit to our ancillary businesses to be able to go in and [indiscernible] -- so yes, I think by introduction of us with the gathering, say, here's our compression company. So yes, I think, and the door swings both ways. There are certain areas where they've got an in with the producer that we’re able to piggyback on them and go in and make introductions, where the producer’s saying, well, you’re already providing the compressor services, why don't you provide this service for me also. So yes, I firmly believe that.
Jim, I just want to switch to West Texas. You talked about potentially needing to build new processing capacity out there. What kind of time frame do you think we could expect to see the need for expansion and would that be under existing acreage dedications or you have to go out and sign new contracts, get new business in order to support that?
The two driving factors is how quickly the Ranch JV fills up and there's going to be some capacity that will be available at Waha but not very much, so you’ve got the Ranch JV, which has an area around it, then you got Waha, and so we'll back fill into Waha as we're stepping out into this Bone Springs as -- to answer your question, we think that if you wanted to have something in, you have to start ordering or you to be taking it right now, if you want to have something in by 2013. Our goal is to add new facilities out there probably by the third or fourth quarter or probably by the third quarter of next year. That's our goal.
And in what way does having Southern Union Gas Services within the corporate umbrella. How does that change things, do you see working with them?
Well, some of that I can't really comment on. As far as working with them, we're currently treating them just like we would any other company. We're working together to try to see if there's different ways where our systems are integrated or where they cross that there might be something that we could do with them. We are also are doing that with others, so it's not just exclusively with them. But everyone out there has the same -- all processes have the same type of problem of needing capacity and being able to ramp up. That's one of the things that we're able to offer our producers, especially with the Ranch JV. I think that's going to be one of the first new processing facilities in the area and while it won't be initially 100% full of partners gas, that will enable us to bring in third-party gas from other areas, which will -- go back to your original question, which will allow us to ramp up and put new facilities in other areas.
On your interstates, what kind of deemed [ph] capital structure is FERC requiring for your equity, what kind of rates are they allowing on that? And with those assets, is your FERC mandated rate an artificial cap because things are so competitive?
On our current system, on our rates are set -- I think our max rate is $0.30 on our rig system. That is what we're currently having our demand fee and commodity fee structure is based on that. Those agreements are 8-year agreements. However, we will probably -- I think we'll have an additional case that we'll have to go back in and probably, I guess, I think it's 2 years from now that we will go back in. And what that will do, that will -- we will be able to make the case as to these rates are still the rates they need to be charged for the production -- for the transport that we currently have under contract. For new contracted volumes, we're currently going out at these same rates. We'll be willing to negotiate some, depending on what's available to us, but right now, we're staying at our same rates.
Well, if there’s no further questions, we'll take a quick break and then we'll come back here. How long is this break, Shannon, do you know?
Shannon A. Ming
So we'll come back in approximately 20 minutes and we'll start with Contract Compression. Thank you.
[indiscernible] Now, let’s start off by talking about [indiscernible] is a contract [indiscernible] that was founded in 1997 and acquired by Regency in 2008. We are based out of Houston, Texas, and have more than 400 employees [indiscernible]. Instead, we provide our customers with the highest level of service [indiscernible]. Our employees are highly trained and experienced. We have one of the most [indiscernible]. Our assets work in the full array of applications [indiscernible]. Through our superior level of service [indiscernible]. Our business model is one that is driven by [indiscernible]. We believe we have the best workforce in the industry because we invest in our employees. [indiscernible] We can offer our customers a full menu of services including compression, treating, gathering and processing. As you will notice on this slide, our asset base consists of [indiscernible] to 4,735 horsepower. This versatile range [indiscernible] gives us the ability to cover all the various applications in the industry. Almost 80% of our fleet is 1,000 horsepower or above. The larger horsepower assets have higher rates of return. They also have longer term contracts [indiscernible]. This slide also shows you where we have operating assets in [indiscernible]. You will notice we have a strong presence in many of the active shale plays. Thus, we’re strategically located to benefit from the oil and gas expansion in these areas. Due to falling gas prices in 2011, the drill bit moved from the dry gas shales to the liquid-rich shales. This presented both challenges and opportunities. One of the challenges included managing horsepower utilization in dry gas shales. Specifically, this meant ensuring our compressors were optimally sized for our customers' needs with declining volumes.
In some instances, we resized larger horsepower compressors with smaller compressors for our customers' long-term benefit. This demonstrates our primary focus as a resource management company. This proactive approach to customers' needs also allows us the opportunity to maximize our fleet’s utilization. Due to resizing, we have been able to redeploy the larger horsepower assets from the dry shales to liquids-rich shales. Wells on the liquids-rich shales require compression at early stages to deliver the associated gas to sales. They also require compression to lift the liquids to the surface. You can see we capitalized on these opportunities in the Eagle Ford and Permian Basin last year.
In the midst of this transition, we achieved another milestone, the lowest incident rate in our company's history, 8.7 total recordable incident rate. This is due to our excellent training and safety departments and our overall company focus on safety. Internally, we enhanced our sales team with new Vice Presidents of sales and marketing. These VPs have years of experience and extensive contacts in the energy sector. We also integrated the compression, gathering and processing and treating sales teams to capitalize on opportunities for both CDM and Zephyr.
This slide illustrates our horsepower utilization. As of 12/31/2011, we had 777,000 external revenue-generating horsepower and 132,000 idle horsepower. Of this idle horsepower, we have 40,000 currently committed to external customers and about 13,000 committed to Regency's gathering and processing segment. This year we intend to dispose of 30,000 outmoded horsepower. Some of the remaining idle horsepower is better suited for dry gas applications, but we're evaluating ways to adapt this horsepower for use in liquid-rich plays. For example, we recently deployed some of the idle horsepower, along with fuel gas conditioning skids in a liquid-rich play. Our goal is to be 90% utilized by year end. This is because in the Contract Compression business, you should never be fully utilized to make sure you have accessible assets to address customers' immediate needs.
In 2012, we anticipate the trend of drilling in liquid-rich plays to continue. Likewise, we intend to increase our operational footprint in these areas while maintaining our operations and conventional reservoirs in dry gas shales. We will increase all these operations by deploying new and idle horsepower with existing and new customers. We will primarily focus on strengthening our strategic partnerships with customers active in the Eagle Ford, Permian and Appalachian regions. The expected growth for these regions is 25% in the Eagle Ford, 120% in the Permian, and 60% in Appalachian.
In conclusion, 2012 presents many of the same challenges and opportunities as 2011, but the drilling will be more focused in the infrastructure better developed in the liquid-rich shales. CDM is ready for what the year will bring. And with that, I will open up for questions.
770,000 [ph] of horsepower that's operating right now, what percent of that is in dry gas areas?
About 200,000 horsepower, roughly of that.
And compared with that fourth quarter run rate, are you seeing the rate of people dropping compression in the dry gas areas accelerating or stabilizing or kind of slowing?
The Marcellus, we're seeing growth opportunities. I believe it's due to the infrastructure catch-up of wells that were drilled last year. Early last year 2010, infrastructure finally get put in place, so we think that the Marcellus dry gas will be a good region for us this year, along with the wet gas. But and the other part of the question, I'm sorry, was what?
The Marcellus -- just asking about the rate of change in people dropping compression in the dry gas areas. And Marcellus is, people are still playing catch-up with well completion. What about in Haynesville, are you seeing the rate of change compared with the fourth quarter accelerating or stabilizing?
All of our assets are in the Haynesville region or that geographic area, primarily compressing Cotton Valley and they're not really -- the Haynesville has not been put on compression yet. People have choked those wells back and we anticipated having compression needs in the Haynesville third quarter, fourth quarter this year. But speaking to customers, they think that, that will happen sometime in 2013. The Fayetteville, we have seen a little bit of a decline in the Fayetteville.
Just a follow-up on Michael's [ph] question. So to achieve 90% utilization in 2012, what is your overall assumption of what's going to happen in the dry basins? It seems like those assets are probably going to have to be utilized if you think you're going to be able to get to 90% utilization.
We will downsize in the dry gas shales. So where the bigger horsepower is today, we might have to set in a smaller horsepower asset there. And our plan is to redeploy that to liquid-rich. I think that the infrastructure in the liquid-rich shales has had its challenges and I think that'll catch up with the drilling programs and the drilling programs will be more focused in 2012 in the liquid-rich shales which will require more compression.
Could you also describe what may be happening on pricing going forward?
We've seen a little bit of relief in the pricing pressure. We are, I would say, comfortable with our pricing structure today. I mean, that's been set forth and we are able to achieve those rates today. So we're comfortable. For our internal rate of returns, we're comfortable where our pricing structure is today. And very confident in being able to achieve those rates.
So just quick 2 follow-ups. So I guess my take away from that is that you think you'll be able to hold margin or grow margin from where they are today?
I would say grow margin. It will definitely not go down.
And then the last question is, is there opportunity for further consolidation within the compression space?
I mean, acquisitions?
Not that I'm aware of. Maybe Mike?
Michael J. Bradley
The way that we look at this business is we've got a pretty substantial infrastructure in place and it's probably much more attractive to grow organically than to go out and acquire and consolidate at this point. Like Chad said, I think we're going to get our utilization rate back to where we think it should be this year. But I would say our growth is going to be organically versus going out and consolidating. I’m not saying it would never happen, but when you can grow organically and achieve good returns, that's what you're going to focus on. That help?
Mike just indicated that when you can grow organically and receive good returns, so I just like to take it from that point and ask you to comment on the trends of returns and the competitive nature of the business now. When I think back several years ago and what you said about the opportunities in the business and how you provided unique services and guarantees and that would allow you to earn superior returns, I just like you to revisit that perhaps. And where you haven't had the growth in horsepower and just talk about the competitive nature of the marketplace and return trends that exist right now and what you’re trying to do to improve returns here in the business.
I think the best way for us to improve our returns is obviously by getting our utilization rate up and that's our primary focus this year and what we intend to do. So I think to answer your question is get utilization rates up.
Talk a little bit about that target of growing the external horsepower 15% to 20% a year. How much of that comes from redeploying assets that you currently have idled versus building new and going forward from here? What kind of capital spending do you think this segment is going to require?
I can tell you we have $70 million budgeted for the segment this year. We currently are in the process of using $40 million of that. So what we've decided to do is we're going to monitor these dry gas shales, see how much redeployment we have to do and we'll continue to monitor of how much new growth we think we need. So it's just kind of hard to answer that question until we fully understand what's going on with the dry gas shales as far as downsizing and all that type of stuff. We're out -- people are changing their drilling programs in the dry gas shales today, so we're out gathering that information to try to make some of those decisions. So it's hard to answer exactly how much will come from idle and how much will be new. So until we understand those drilling programs a little better. Yes, sir?
I'm just curious as far as the utilization, how Regency compares to the competition. What kind of utilization you're seeing among other compressor providers?
I don't know the specifics of others. So it's hard for me to speak to that, I'd rather not.
Michael J. Bradley
I think one thing that you keep in mind here, like Chad said, of the 132,000 horsepower that's in idle, 53,000 of that has already been tagged to go into service this year. So that's a big chunk, more than 1/3 is already been identified to go to jobs. We've got about 30,000 of that horsepower that we're going to dispose of, sale. It's older horsepower, and so we're going to use that cash to redeploy into some of the new. So I think we've got a good plan to get our utilization rate at a level that we're comfortable with, and minimize the amount of new capital we have to spend while utilizing the existing units and putting them into service. So I think that we feel very good about our plan to get our utilization rates where they need to be. But we still see continuing opportunities to invest capital into these emerging plays. And I think that's the exciting part of this is let's take the Haynesville, for example. CDM is not providing compression in the "pure Haynesville gas plays" because, like you said, those wells haven't declined in pressure at this point. They've been choking back and so this pressure is so high, it doesn't need compression. As they decline down, they will. This focus in north [indiscernible] is on the Cotton Valley and these other plays where we continue to see, as Jim mentioned, more drilling, okay? So that's a positive. I think our main exposure in the dry gas today is primarily in the Fayetteville. And right now, we're forecasting about a 10% reduction in horsepower there. But when you see the kind of growth opportunities in West Texas, South Texas and the Marcellus, we're pretty excited about what we can do with the business. So, I mean, so when you look at that utilization, keep in mind 53,000 of that is already going out the door.
How big do you see the business in 5 years then as far as the overall focus of the company?
Michael J. Bradley
Currently, our Contract Services business is around what 20%?
Michael J. Bradley
24% of our mix. We plan to grow all of our business segments going forward. But again, our growth will be based on what we see as attractive returns to deploy new horsepower. But I think given what we're seeing in these liquid-rich plays that there's potential for some pretty good growth in horsepower over the next 2, 3, 4 years as these plays continue to get drilled. But I’d say, that mix right now is pretty good where it is. But we plan to grow everything. So that 24% or whatever that is, will be a bigger piece as we go forward.
Just a good warm-up for you, that's all. But the question is when you start thinking about how you allocate capital across the segments, do you differentiate return hurdles based on the nature of the business? So in terms of thinking about compression, are you going to use the same hurdle rate that you might use to build the natural gas NGL gathering line for instance?
Michael J. Bradley
No, it might be different at all. It might be different [indiscernible]
Would you like to say what those hurdle rates are?
Michael J. Bradley
We always targeted -- we targeted mid- to high teens. We target mid- to high teens and obviously better than that but that's kind of our target range. I think the Compression Services probably fall down towards the lower side, but you get good contracts, a good fee-based, there's still good accretive projects.
If that's it, I'll turn it over to Glen Wind. Thank you.
Thanks, Chad. Good morning. Thank you. Freeze the prompter for one second, I want to make an unscripted comment. We sold Zephyr Gas Services to Regency 1.5 years ago and I want to just thank Mike Bradley and Tom Long for your unbridled support. You guys have been awesome for me and my employees. I'd like to thank Jim for his creative energy. He's always got a good joke and a good moral supporter. Obviously, I like to thank Shannon, and Lindsay [ph] and Bailey [ph] for all their help and support for these presentations that we have to do. But most important, I'd like to thank my peer, Chad Lenamon. Chad stepped in in a really bucket, big bucket last year. I know some of you people may know. And has done a great job of showing positive energy for his group and vision and leadership. So Chad, I commend you for that. Okay, so we can go and move on.
So with that said, I'm happy to be here to provide you information on Regency's Contract Treating business, Zephyr Gas Services. Zephyr Gas Services provides the natural gas industry with superior solution to treat their natural gas. Our high quality fleet of newly manufactured treating assets offer a range of services and are located in the high-growth markets. In addition to aiming and treating, our satellite services include JT units or Btu management, and NGL product tanks natural gas cooling, glycol dehydration, thermal oxidizers, power generation, condensate stabilization, H2S scavenging and fuel gas conditioning.
Our full time operations and maintenance programs have proven to the industry that we can provide 98% of mechanical availability with our satellite-based 24/7 online monitoring system. We provide a complete suite of services from turnkey construction, for installation demobilization, to providing other common treating equipment.
So what makes Zephyr different? What differentiates us from the other treating companies out there? Utilizing our unique business model, which includes our patent pending, Modular Quik-Connect, and you'll hear me refer to MQC later in my presentation, but it stands for Modular Quik-Connect aiming plant design, we can reduce cost in time for market, while maintaining the 98% run time guarantee. We offer the most comprehensive turnkey installation and demobilization in the industry. Normally legacy stick built plants can take up to 4 to 6 weeks to install.
We can install, start up, commission an MQC 100 plant in 5 days. We could also remove the MQC plant from a location in 2 days compared to the industry standard of approximately 2 weeks. Looking at these options, the total cost to the customer for mobilization, demobilization is reduced by 40% to 60%. We also offer facility operation and maintenance, flexible contract terms, working with our customers to ensure we are meeting their exact needs.
So we'll talk about more is our flexibility and design. Because of our patent pending Modular Quik-Connect aiming plant, its skid-mounted design meaningfully reduces the time and expense that allows our customers to be online quicker to the market. We offer multiple gallon per minute capacity in aiming plants and you'll see us talk about that. We have a 3, we have a 30, we have a 60, we have 100 and we have a 400 gallon unit as part of our normal fleet with 15-gallon plant in current design.
The compact design of these plants allow for multiple plant applications on site, so if you need a 60-gallon treater but you need 200 gallons of treating, you could put a 60 and a 100, get you 160 or you put 2 100s, you can just add and subtract as you need to. That allows our customers to quickly get online faster. In 2011, we began reconfiguring and redesigning a portion of our fleet to handle the higher H2S environments that we're seeing and more of the prevalent plays that shifted from dry gas to the liquid-rich.
Part of our comprehensive services, with our assets located in the same region as the rest of the Regency family of companies, we have the ability to offer more complete midstream service packages for our producers who need everything from Gathering & Processing, Contract Compression, Contract Treating and Transportation. We will work with our customers to find what best fulfills their needs and ensure they are receiving the most comprehensive services that we can provide.
We're always focused on safety. Our goal is to be the safest in the industry. It's been my mantra since day one we started this company. We have a proven safety record with no recordable incidents from the day I started the company in 2006 to last year of 2011, totaling over 208,000 man-hours, with not one recordable injury. The typical job site in which an aiming play is installed is a noncontrolled environment. It can be very unpredictable with the weather conditions, the presence of other trades working on other equipment all around the installation.
What makes us key in the industry is a Zephyr MQC plant is prefabricated in a controlled shop environment. So all the complex piping and the wiring is done ahead of time when the plant is built, instead of in the field when it's installed. This along with our skid-mounted modular quick design drastically reduces the amount of welding and electrical work that has to be done and performed on-site. This benefit is realized every time we install a plant but also every time we demobilize the plant.
To sum things up, we think we have the highest-quality fleet in the industry, with the most attractive and comprehensive [ph] services, options available, and our goal is to provide the most effective and safe solutions to our customers in the industry. Turning to our asset overview. It looks like kind of everybody else's, which is a great footprint for Zephyr. It's –- our assets are located in some of the most active plays in the U.S. including liquid-rich Eagle Ford Shale, Permian Basin and our geographic footprint aligns perfectly with Regency and CDM, our sister company, which helps us provide additional growth opportunities.
One little factoid I'll tell you guys is, a year ago when I was standing on this Podium, we had 0 treating assets and 0 ancillary assets in the Eagle Ford Shale. As of December 31, 2011, we have 460 gallons of treating capacity and 30 ancillary assets generating revenue for Regency. So it's been a big change for Zephyr gas and our business. We expect this trend to continue in 2012 as we're positioned to capture the majority of 2012's growth in the liquids-rich Eagle Ford Shale and also the Bone Spring Avalon Shales.
Some of our accomplishments for 2011. When we started 2011, because the drill bit did move on us, is we decided to kind of create a strategy where we could begin adapting our fleet to the more higher concentrations of H2S and also the CO2s that we would be dealing with. As you can see, our revenue-generating gallons per minute increased slightly in 2011 to 3,465 gallons per minute versus 3,431 at year-end 2010, with most of that growth occurring in Eagle Ford Shale. We consider this to be the next emerging market for treating just as the Haynesville Shale was 3 years ago. We had approximately 10% new tier 1 customers to our customer base. And again, we also upheld our safety standards in 2011, reporting almost over 70,000 total man-hours with no recordable incidents.
Where we going to grow? We're excited about our growth for 2012. We're seeing the Treating business is not just about treating, it's all our other ancillary products that we offer. In development and in manufacturing being produced right now is our -- one of our new products, condensate stabilization as you know, there's a lot more need for condensate stabilization at new shale plays. Our condensate stabilizers are designed to conform to stricter environment regulations. Most of the wells being drilled today in Eagle Ford Shale and in Bone Springs Avalon Shales had very high re-vapor pressures. The normal transportable re-vapor pressure that was accepted by the industry was 12 RBP, now it's 9. So that's a big change in focus on what they can haul and they can't haul. So there's a big need for condensate stabilization in all applications.
These [indiscernible] are being placed in production but the normal service production equipment cannot provide adequate separation, thus provides us more opportunities for our modular stabilizers in this high-growth areas. The cool thing about these plants, just like our Modular Quik-Connect aiming plants, we can stack them up in parallel so we can ramp up for production needs. And when the rates fall, we can ramp down and remove and replace them at a different location. Our condensate stabilizer has also helped fulfill stricter environment compliance. So the emissions is an issue that people are dealing with every day and our condensate stabilizers help eliminate that problem.
Huge problem that we're seeing in the new shale plays is H2S. There's a lot of sour gas wells being drilled in South and West Texas, and only a certain amount of those can be treated with an aiming plant. The lower levels of H2S, most companies are using sulfur-treating media vessels or H2S scavenger vessels. Sulfur treating works, but it's just a different animal and operating it requires frequent clean out of gasket [ph] beds. It's time-consuming and costly. So we at Zephyr have gone to more of the H2S scavenger vessel.
Some of the advantages of the scavenger over sulfur treat are, there's really no maintenance to H2S scavenger, it's just a vessel that has an injection of chemical that's injected into the vessel. Once the chemical neutralizes H2S, the reaction takes place and everything goes on sweet. These units pay for themselves many times over before they need to be taken out of service. But the way they're designed.
Another new product for Zephyr this year is fuel gas conditioning. As Chad mentioned earlier in his presentation, all these new shale gas wells, the associated gas that they're trying to use for fuel is ultrarich and these lean burn agents cannot run on this ultrarich fuel. So you have to condition the fuel. So between our compressor companies, operators, midstream companies, we've created a package that'll help treat this gas, with addition of a very fuel-efficient fuel gas conditioning skid, we're able to market these packages through our CDM partners and through other companies that may have their own compression. So that being said, the liquids-rich areas, not the dry ones but the liquids-rich areas, are where we expect the most growth in 2012.
In the Barnett Shale, we're seeing a resurrection of opportunities in the northern wet region, where we are seeing much higher levels of CO2 and associated fuel gas to be treated. In the Marcellus, used gas [ph] not quite as strong for the treating side business yet, but there are opportunities for dehydration and fuel gas conditioning, but mostly natural gas dehydration. We're extremely excited about the Bone Springs and Avalon formation. CO2 is between 5% and 10%, so it's extremely corrosive. We can help fill that gap with our Modular Quik-Connect aiming plants. Our Modular Quik-Connect condensate stabilizers and our Btu management skids, we can put those in place while our customers are constructing these larger plants that they have to put in place, aiming or cyro whatever it may be. H2S is also present in some of these areas. So providing the need for more treating for scavengers or aiming plants or maybe even both.
The Eagle Ford Shale obviously is where we're focused in razor-sharp. CO2 is in the 1.5% to 3.5% range, depending on location in the play. Currently due to lower natural gas prices though. The dry gas wells are not being drilled as much as in the wetter region. So most of the wells though in the liquids-rich region have 30 to PPM or parts per million of H2S. Those wells have to be treated or sweetened with liquid scavenger or sulfur treat to remove H2S. We've actually heard and experienced some of the wells reaching as high levels as 20,000 parts per million or 2%, which is extremely corrosive and dangerous. Our gen 3 plants, our gen 3 aiming plants, will allow us to treat gas with H2S levels up to 2% and CO2 levels that are above the pipeline spec.
With that, if you have any questions, I'll be happy to answer them about the Treating business. I know you all want to hear Tom speak, so I'm okay with it. Lewis [ph]?
So it seems like your business model is changing a little bit and providing more of these ancillary services. If you looked at the business a year ago, just a matter of growing your GPM and maybe growing the margin per GPM. How should we monitor the business going forward? What are the right metrics to look at and what kind of capital deployment do you see in returns on capital?
Okay. Metrics for measurement and CapEx deployment for this year? Okay, so for metrics for measurement is real simple for us, is the drill bit moved from the dry gas shale region of the Haynesville to all the wet gas regions, the Eagle Ford and Avalon, Bone Springs. All those wells that are being drilled down south, people are chasing the liquid molecule. Liquid molecule is corrosive, it's got H2S in it. It's going to have to have some type of treating or sweetening to be done, be it aiming plant or be it H2S scavenger or both. So there's a huge potential market for that. I will say this, when I say we have a generation 3 aiming plant, what that means is, our generation 1 and generation 2 aiming plants will treat any natural gas well with H2S, it just may not last as long. So instead of having a shelf life of 15 to 20 or 30 years, we may have a shelf life of 10 because of the corrosive environments they're exposed to okay. So our gen 3 plant takes that and addresses that, by upgrading some of the alloys and some other processes of manufacturing, so we get a longer life shelf life. So we can actually do any job now that's up to 20,000 parts, which is most applications you'll see in any of these new shale plays. So that's our metric we're looking for, is how many wells are going to be drilled in the Eagle Ford Shale and the Bone Springs Avalon. Wow. That's a big moth. Somebody did that on purpose. So we're going to watch that and that's what we're chasing now. So it is a new focus for us, Lewis [ph]. And you know, 3 years ago, I couldn't even spell Haynesville Shale. And it was probably the biggest driver for Zephyr Gas growth over a 3-, 4-year period because people had to have treating and had to have it quick. And that's what we do, is we treat gas quick. We don't spend 4 to 6 weeks hooking up plants and messing around. We get in and 5 days later, we can treat your gas, if that's important to you. And I think it's going to be very important to the Eagle Ford Shale producers and the Avalon Bone Springs guys that are drilling these wells that are making 300 to 500 barrels a day of oil. Because they got to do something with the gas and the only way to do it is flare it, which we can't do anymore by the way, because the emissions are off the chart, so you got to treat it. So that's our metric. As far as CapEx, we're not going to spend $1.2 billion this year. Our CapEx is not near as large as anybody else. We have a $15 million CapEx in our budget. We have some hangover and carryover from last year where we sold some stuff and some other assets that we did not deploy in '11. So probably in the $25 million to $30 million range would be a more true number that you'll see in our CapEx for this year. And granted, when we do our budgets, we didn't know we're going to be introducing 3 new products this year. So we have to adjust some of those spends in different product mix. We may not build as many aiming plants, we may build more fuel gas conditioners, we may build more condensate stabilization skids because that's where the market's telling us to go. So we just watch that very closely. Does that answer your question? Okay. Any other questions, Rebecca [ph]?
On your 25% to 35% revenue growth, can we assume that the gross margins are going to be equivalent to what they are now? So the gross margin growth is equivalent?
Yes, you can. One thing I will say about that is Zephyr has always been about value and I'm not going to say about pricing, but we've always commanded value for our pricing because that's why we can uphold our margins, is we don't try to go out and get every job. We go out and try to get the highest quality job that fits our value chain as much as our client's value chain. So if they don't appreciate safety and they don't appreciate being online faster, if they don't appreciate 98% mechanical availability, then it's probably not the job for us because we will be to a typical producer operator, they may deem us as being more expensive, but if you amortize our Contract Treating rate plus our incremental installation and you amortize it over term, we're the best value in town. So if we get to the decision-maker, it's not a hard decision. Okay? Any other questions? Jim, you got one? No? Okay. With that, I'd like to introduce Tom Long, our CFO for Regency. He's going to go over 2011 accomplishments and the 2012 objectives.
Thomas E. Long
Thank you, Glen. And once again, I want to express appreciation for all of you joining us today. It's always good to get together and get a chance to tell the Regency story. So I think as you kind of heard today, we've clearly got some ambitious growth plans, and we felt like it fits well with Regency. We've got the right platform to do that. So I'm going to walk through some of the balance sheet and some of the financial numbers before we then open it up to Q&A.
Kind of looking back at a little historical and then, of course, where we are today, our top focus is to always continue to maintain the maximum financial flexibility to support the growth that we've talked about here today. So over the past 6 years, just kind of looking at some of the history here, you can see that Regency's book capitalization has grown from $1 billion to $5.6 billion while at the same time improving a lot of our credit metrics. Long-term debt to capitalization ratio has dropped from 66% in 2006 to 30% in 2011. Long-term debt to adjusted EBITDA ratio has decreased from as high as 6.9x in 2006 to 4x in 2011. And, of course, we've achieved this while investing $4 billion on acquisitions and growth capital.
Kind of looking at the debt maturity profile, as a result of the financing activity that we went out with in 2011, as well as the one that we recently closed on last week, our balance sheet is in great shape. Once again, maximizing our financial flexibility to keep the most we can under that credit facility to support the growth. During 2011, we did raise nearly $950 million of new capital, and this included about $450 million of equity and about $500 million of debt. And then, of course, like I just mentioned, we did raise another $300 million last week to continue to support our growth projects.
Looking at the divorce -- diverse portfolio, Regency has obviously made a concerted effort to broaden our asset base. So in addition to just growing the -- in addition to just growing the pie, we're likewise growing the mix, the business mix.
As you can see, the transformation of our business from 2006 to present has resulted in a much more diverse portfolio. The primary change in 2011, in addition to the pie here was, of course, the Lone Star. And as you look at 2012, you can see as you get a full year of Lone Star, it's going to contribute about 11% of our segment margin.
Looking at Slide 51, once again, maintaining a stable cash flow, as you can see the growth of Regency through these pie charts. We have also focused on growing the fee-based portion. In 2010, we were at 76%, 2011, we were at 83%, and you can see with 2012 estimated that we will still be over 80%. One other important note here is that of these capital projects that we've talked about today, the majority of them are clearly fee-based, so as we move through 2012 and some of those earnings coming on, they're fee-based but even the Lone Star assets with the pipe and the fracs, those are all fee-based, that'll be starting up in the first quarter of 2013. So as you look out even to the prior year, you can see how Regency has a very nice earnings mix here.
Now moving on to the portion that's not fee-based, our hedging program, we do continue to maintain a comprehensive hedging program, and as a result, 11% of our adjusted segment margin is expected to still fluctuate with commodity, but we have hedged 8% of that. Since our year-end earnings call, we've also executed some additional hedges that are worth highlighting here. On the NGL side, we brought the hedging levels up to 66% for 2012, and up to 8% for 2013. And as you know, with these NGL hedges, it gets very punitive to go out of a whole lot further, so you won't see us going out past the '13. And then additional condensate hedges that also bring our hedge levels up to 50% for 2013 and 24% for 2014. And, of course, we use crude oil to hedge these -- to hedge the condensate.
For all these products, I think you'll notice that we've lowered the hedging percentages a bit on the ethane, and we still, on the olefins, have not moved forward with putting on any hedges for the olefins. Those are the products that come out of the refinery services business that you heard Greg talk about earlier today from that standpoint. But once again, trying to put those hedges on and going out very far becomes way too punitive so they make up a total of about 4% of our total margins, so of the 19%, about 4% relate to that piece, so as you can see, it's not a big driver.
Just making a -- probably a quick note. This next slide is really just about the hedges that we have executed by product. The main thing that we really want to highlight on this slide is that the -- is to go ahead and give you the prices we've hedged at, but to also note that the NGLs are hedged at a higher price in 2012 than what we had in 2011. And those hedges in the NGLs range from about 11% to 18% higher than what we had last year. If you look at the natural gas in the ethane, we've actually hedged those prices a little lower than what we had in 2011, and the percentage on those are about 6% to 8% lower that we're able to put hedges on for ’12 versus '11.
And then, of course, the last component of it is the crude. For 2012, we have put those hedges on at about 11% higher than the 2011 level.
What all this equates to in the form of sensitivities, for a $10 per barrel movement in crude oil and if you assume the same relationship that we have today with natural gas liquids, it equates to about a $4.4 million impact, and that's positively correlated. If it goes up, earnings go up. Or DCF goes up, it goes down, it goes down by that amount.
A natural gas move, a $1 per M move in gas, equates to about a $3.2 million change in earnings, once again, positively correlated. And then on the olefins that I mentioned earlier, the ethylene and propylene, a $0.05 per pound move there equates to about a $1.9 million move in Regency's earnings. If you were to look at the prices today of the olefins, ethylenes in the high 60s or so, propylenes in kind of the low 70s.
Just talking a little bit more about the capital expenditures. I know we've kind of hit on it with each one of the areas today. Last year, not counting the acquisition of Lone Star, we had $354 million worth of CapEx, we plan to double that this year. And the break out of those numbers, Gathering and Processing, Jim's area here, will be spending about $280 million. The Services business, like Glen mentioned, $15 million in the trading, $70 million in the compression and then $350 million to $400 million will be invested in Lone Star, and those are the projects that Greg talked about. They're the natural gas liquids lines, running from West Texas down to Mont Belvieu, as well as the 2 fractionators, what make up the capital dollars from that standpoint. From a maintenance capital standpoint, we still anticipate that to be about $28 million for the year from that -- from our best projections on that at this time.
And I don’t want to just skip over the pipes. They -- we're not anticipating really any capital dollars spent on either the RIGS pipeline or the MEP pipelines. We have no dollars earmarked for those right now, far as expansions go. The one thing I want to note before I move past this slide, too, is because a lot of these projects are growth projects, we will always target a 1.1x coverage ratio on our distributions. But as we go through this year of organic growth, I think you can expect us to stay below that. Keeping in mind that we'll be funding these projects and they'll be starting up in the first quarter of 2013, a big chunk of them.
But it is worth noting on the Gathering and Processing side, all the South Texas projects, et cetera, those will be coming on. A matter fact, they're already coming on. We're already seeing the volumes come on those lines, so the earnings are coming as those dollars are being spent throughout 2012.
In summary, just kind of looking at a lot of what we've talked about here today, as I've kind of mentioned here, our focus is going to be to continue to maximize our financial flexibility to support the future growth and to achieve the investment grade ratings that are our primary objectives here. We've demonstrated this commitment and by measuring our success against -- several objectives here: One, of course, is to maintain this balance sheet, what we'll do is continue to target the 4x leverage ratio that you saw up on one of the first slides here, so as we continue to grow equity, debt, et cetera, we're going to always target about 4x from that leverage ratio.
We're going to continue to focus, of course, on the stable cash flow, I've already mentioned that a lot of the capital dollars we're spending right now are all fee-based type projects and they all have good long-term contracts on them also. So it's not just a fee-based but they've got a good length to the contracts.
And, of course, third is just maximizing the return on the invested capital and we've talked about that a little bit today also, but mid- to high-teens in good organic projects that we're working on right now so. And of course, lastly, we're just always focused on growing the DCF, growing the coverage and when I say DCF, I mean DCF per unit. It's important that we continue to focus on good accretive projects so we can continue to grow the distributions.
And with that, I'll go ahead, and open it up for questions.
I apologize upfront for this is going to be somewhat a long-winded question. But on Page 48, the side-by-side charts of long-term debt to capitalization of EBITDA, where the [indiscernible] overall debt capitalization, 12 months or [indiscernible]. It would seem to me that
[indiscernible] to that 50/50 debt-to-equity on an overall basis, would be to gain additional EBITDA out of the installed asset base right now, so that you would be under your target so that you could do growth projects with more debt-to-equity. Drive yourself back -- closer to the 50/50 but back to -- but not over the 4x. I'm just curious what type of additional EBITDA you guys think you can squeeze out of the current asset base that will allow you to play those metrics. And it might be as simple as if you look at the footnote on Page 56 there's a footnote that says that long-term debt to EBITDA is 3.61x at the end of 2011 which should just mean that the right-hand graph is a little off. So I'm just curious if you can put a little color around that.
Thomas E. Long
Oh, you bet. And let me say, on that 3.61, that is per -- that is a calculation per the credit facility. And the credit facility allows you to -- if you will, as you spend some of these capital dollars, you're given credit for EBITDA. So this is pure book when you see the 4, so that's the difference, I appreciate. I'd ask the same question whenever I first saw the difference between the 2. So but I'm going to go back to the first part of your question what we can squeeze more out of it. I think where Regency is today and probably the message that you seen a lot throughout all these presentations right now is our capital dollars were talking about right now are organic growth projects and when you take the returns, the guidance that we're kind of giving you on the returns, you can tell from that pretty quick that it doesn't take a 50-50 split of debt-to-equity because those are much lower multiples that you're getting off those capital dollars as you spend them. So when you say, what can you do to squeeze out of your existing base, you're right, you saw the graph with all the acquisitions on there and where we were and then you see the organic growth projects. So what we see when we look out with these numbers, and knowing the returns you're going to get off these organic projects meaning squeezing more out of those acquisitions and now being able to leverage off of them, we will get to the point that you're referring to right now. Does that answer your question? Okay.
Are we supposed to wait for a mic?
Thomas E. Long
Yes. There's a mic coming up right behind you right now.
If you took your average assets or net assets last year and then took your EBITDA, you're making about an 8.5% return on assets.
Thomas E. Long
And is that -- is management comfortable with that? Because that, given all these high-returning projects and everybody is looking at mid-teen un-levered returns, this -- I want to get your view of what you think that number is going to look like going forward because this seems anemic.
Thomas E. Long
All right. Point taken on the assets. As far as the returns in the calculation. I think when you see these organic growth projects, once again, as you run them out, and you see these higher teens, so in other words, the new assets that are going to be added into the base are going to be higher, higher-returning off the base that we incurred. I think you're going to see that number, and we likewise watch that number. You'll see that number start working its way up into the higher returns. You follow what I'm saying? Okay.
A question. I just want to make sure I understand your sensitivity table on Page 54. Just what is the -- what's the base case, if you will, assumption for the commodity prices for oil and for natural gas and then you're moving from that point?
Thomas E. Long
The way we look at this, and I think as the way you've kind of asked that is maybe what's in our budget. We've not disclosed what's necessarily in our budget. But here is what -- here's what it -- these metrics work with. They work with taking where we are today. So you take our, for example, our first quarter earnings and if you have a view that as you're modeling and you think gas is going to go down by another $1 or go up by another $1, or whatever move in one direction or the other, this will give you the sensitivities of where -- of what type of impact you would expect from the levels we are right now. Same on crude oil. Now the reason why we're giving -- we don't give an NGL sensitivity, we give the sensitivity to crude assuming that the relationship stays the same, NGL to crude, which, when you look at that, it's probably about a 50% relationship, if you take an NGL barrel to a crude oil barrel. But what you would -- so what you would do is if, once again, your view on where you think crude oil might go, the $4.4 million on an annual basis for '12, would go in that same direction as what you think crude oil is today. That's –- in other words, I don't have a base dollar amount that I can give you about each one of on the products. Okay?
[indiscernible] you establish the budget [indiscernible] beginning of January [indiscernible] future returns, or how did you think about that?
Thomas E. Long
Yes. If you had the microphone, the question -- the question here was when was the budget pulled together so that we can kind of have an idea of the price we use? The budget was pulled together in about the October timeframe. But I will say that we'd, at that time, we'll then look out at a forward curve that we put into our -- that we put into our budget, so we will take a view internally as to what we think it's going to be at that time. But if you kind of look at about an October, that's when we completed the budget.
You talk about investment-grade ratings being an objective for the firm. What's your target, what do you think the timing is to get up? I think it's -- you're be a 3, so it's multiple notches. What are the agencies looking for? Can you just talk about what it's going to take for you to get there and timing?
Thomas E. Long
Wow, that’s the -- that timing part of it was -- we continue to have very, very constructive dialogues with the agencies. I think they're very happy with the way Regency is growing in a disciplined fashion. As always, they would probably like to see the leverage ratio, a little bit lower. More in the -- maybe 3.5 range or something like that. But keep in mind that when we calculate the leverage ratio, it's not necessarily always exactly the same way as they calculate it. And it’s sure not the same way as our credit facility calculates it. So we think that going with the 4x, we think our earnings mix, staying in that 80% or above and continuing to grow in a disciplined fashion, that we'll -- we will get there. As far as timing, we really don't get any feedback and you're right, there is multiple notches here. But when you're in this type of a growth profile based upon our size, they're wanting to see some time pass also to see how you continue to fund your growth capital and that you stay within those ranges. I think as we continue to work with them through the year, we're sure hopeful we can make some progress there, but that's about as close as I am probably going to be able to dial you in on the timelines.
And then second question, the 9 3/8% notes outstanding, anything you could do there to reduce that amount outstanding to help raise distributable coverage?
Thomas E. Long
Oh, you bet. As a matter of fact, even with the last equity offering, I think you'll probably note in there, we highlighted very clear that we can utilize some of those funds to exercise the 35% claw on those 9 3/8%. The other thing I'd like to highlight though is that the -- those notes do have a -- or that debt does have a January 1 next year call provision at 104.67, half of the 9 3/8%. And so we will continue to be aggressive on that to your point to help the DCF per unit.
Tom, 2 questions. One is, just in terms of asset sale proceeds and expectations this year, I think noted some horsepower being disposed of in the compression segment, anything beyond that we should expect? And second thing, just in terms of how you’re thinking about distribution growth for 2012, given the comments around coverage, you bumped the distribution a bit in '11. Are you comfortable bumping up again potentially in '12 given the visibility on growth in '13?
Thomas E. Long
Let me start with the first one. We really don't have any other, at this point, asset sales. As you're right, we talk about the compression side of it, so we have nothing more to -- that's on the plate right now from that standpoint. As far as the second part of that question is, we don't give any guidance from that front. That's up to -- we'll make recommendations to the board as far as distribution bumps go and they will go from there. I do want, though, highlight that, once again, on that coverage ratio comment, you're right that I made, being kind of less than 1.1 and going through a period of organic growth, those decisions will be made as we go through the year with each quarter. Don’t really have a whole lot more guidance that I can give you than that right now, but I just wanted to make sure I at least highlight it from a coverage ratio standpoint, where we might be.
You budgeted about $750 million of growth CapEx for 2012. Given your footprint, what do you think is a sustainable annual growth CapEx budget going forward?
Thomas E. Long
Oh, gosh. Based upon our footprint, and what we have and -- Mike may actually want to chime in on this one himself a little bit here but -- Mike you want to weigh in on guidance, if any, you'd like to give on the...
Michael J. Bradley
Thomas E. Long
No, this is not guidance but just based upon our footprint, here you want to come up here to this microphone?
Michael J. Bradley
I think, that, obviously, I have a few things to say in my closing remarks about Regency, but I think a couple of things to look at here is when you look at where we sit today versus a year ago, and we've added a significant new asset with Lone Star. And as Greg mentioned, we continue to see opportunities developing around that asset going forward, in addition to what we've already announced. So I think when you look at our business as a whole, I think our platform is getting bigger and the organic projects that we're seeing develop continue to be there, and so I would hope to see us have a much higher rate of organic growth going into 2013 as well. So I'm not going to give you guidance on that, but I think if you see the platform we have today and the types of projects that are out there, I think, we could still see and hope to see a pretty robust spend in 2013. That doesn’t include acquisitions, obviously.
Thomas E. Long
Other questions? One over here.
Tom or Mike. Following up on Gabe's [ph] question and recognizing that the board ultimately makes the decision on the distribution. How important do you think it is for the board to maintain that consecutive quarterly distribution increase that you sort of started to establish in 2011?
Thomas E. Long
You want me to take that one?
Thomas E. Long
There's multiple factors that go into the decision as we kind of go through the year. And it's going to be looking at the business, what type of earnings, how they're growing, and all that's really going to go in into the factor from that standpoint. And then looking at of course where the coverage ratio is, making sure you stay within that. So that's actually a question that once again can lead to guidance. If I said that it was one way or the other, super important or not important, et cetera. But I do think that we will always evaluate the DCF and the cash flow based upon a quarter-by-quarter basis so.
I think to your question about how important is it to maintain that quarterly, that's not our driver. We're not trying to get into position where we can announce the distribution rate every single quarter. We'd like to be able to do that and as we grow, but I think we're going to -- as I said, we're focusing on improving our coverage, as well as increasing our distributions. And so, we'll do it when it makes sense and we can provide good value for unitholders, but we're not -- we don't have this goal of quarter after quarter after quarter of [indiscernible] distributions, that's not what driving us.
Thomas E. Long
What else? Lewis [ph], back here.
Perhaps this isn't a fair question for you. This might be more applicable to us as investors but if I look at where Regency is trading versus some of your peers, the stock looks extremely undervalued, you've got one of the lowest -- one of the highest yields in the group today and if I look out at it, would, expecting for '14, that GAAP stay there as you're growing the distribution. Do you have any ideas of how you can, I guess, get the market to appreciate the value of the existing assets and then growth that you’ve locked in and create some value for shareholders?
Thomas E. Long
Hey, you bet. I think one thing we can do is just continue to communicate the great story that Regency has. It truly is a very good story as you look out for the company. I think, even as you probably look at the various analyst reports that report on Regency, they're all -- most all of those are very strong, likewise. So I think it's just to continue to do that, as far as staying out in front of the investment community and getting the story out. As far as just specific items that you need to work on et cetera, at least I'm not hearing a lot back on that. You hear some other occasional comment here or there about maybe what's coming next around anything to do with the Southern Union deal that just closed, et cetera. But once again, we don't have anything to talk about from that standpoint, so we don't have really anything to address there so. I don't know what else to add to the answer there but we're going to keep working it and we believe in the story completely and we're going to continue to deliver.
Thomas E. Long
Well, if there's no other questions. Mike, you want to come up for some closing remarks?
Michael J. Bradley
Yes, yes. Thanks, Tom. Yes, number one, we really appreciate everybody being here today. I think I'd like to close by making a few comments. Let’s go back to a year ago at this time at our last investor day. I think, the thing that we emphasized was in comments that I made and the management team made was one, of course, we had just announced the Lone Star acquisition. And so we talked about our integrated platform to services, midstream provider and the value we thought that would create going forward.
The second thing we talked about was we shifted our focus as a management team to the commercial -- more commercial versus acquisition. Regency have made a lot of acquisitions, we stated our focus was on organic growth and get more value out of the assets that we already owned because we saw a lot of potential.
And so when I look at today, I'm very pleased with what our management team has accomplished. Number one, we talk about organic growth, over $1 billion in organic growth announced this year, largest ever organic growth platform that Regency has ever had. Second thing is, the drill bit shifted to the liquids-rich plays. And we are benefiting by that in every single business segment we own. So we are well-positioned in the various plays. And we are very pleased about that.
So I think when you think about to your comment about value, what's -- I mean, we couldn't be more happy with that we see going forward for Regency today in terms of growth but high-return growth, which we think will lead to better accretion and distribution and coverage going forward. And I think so, in our opinion, we believe we have delivered an awful lot in 2011 based on what we laid out and we're even better positioned today than we were a year ago at this time. And I think, we emphasized the integrated platform and midstream services because we think it is a great position to be in because of the way things shift in this business. And if they shift back to dry gas, we're still well-positioned in that. And so we like our position, we're very pleased with it.
The other thing was we wanted to get our service businesses and our GNP businesses working together. And I think we have done a tremendous job of integrating our sales efforts as a combination and to cross-sell across our different business lines, which we think is creating more opportunities for all of our GNP and Contract Services business segments. So I'm very pleased about what's going on there. We made the shift in this year to focus on third-party business on our contract services, we talked about that, because that's really where I think we drive the highest margins and the highest growth. But that doesn't mean we don't work together to create that. We're seeing some good examples and success stories on that as we speak today and as you have heard from Jim and Glen and Chad.
So I think, when I think about the key points to leave here today, in terms of -- yes, I believe Regency is way undervalued. We're trading at what, 7.5%, 7.6% yield? 7.75 today? I don't know. Okay. Whatever it is, it’s too -- but when you think about what we've laid out and what we've got going forward, we think our stock is tremendously undervalued. Because this is the best position we've been and we don't see it stopping. So we're very, very pleased. And I think those are key messages to get away. So we're a multi-dimension midstream player, across liquids, across dry, across different services and we like that mix because, number one, I think it provides a more balanced portfolio in this business and we benefit from both and that's the kind of position we want to be in going forward because someday the shift will go back to dry gas. Or be more dry gas produced and we're sitting right there in some of the key shale plays for that today, Eagle Ford, Haynesville, and with our service businesses in the Barnett and those things. So we're really pleased with how we have balanced this business going forward.
So that to me is, when I talk to people, why -- what's the issue with Regency? It's not an issue. We see tremendous growth opportunities and we're very excited and think that, number one, we've already announced over $1 billion and we're not done. So we think we've got a great platform.
I think also, very pleased with the management team. I think this management team has come together extremely well. And Chad, as leader of CDM, has done some tremendous things in that business this year, and we're very pleased about that. So we're really happy. We got a good management team, a good commercial team. So we think we are as good or better-positioned than anybody.
I think the final comment is, we appreciate our relationship with Energy Transfer Equity. It's a very supportive general partner, they’ve very much been behind supporting our strategy and we believe they will help facilitate future growth as we go forward. So I think we're in an excellent position, we're very excited about our business and appreciate everybody being here, and we'll open up to -- and any final questions before we break for lunch, we'll be happy to address those. But I'm very excited about what I see for Regency, and I think if you go back from what we said a year ago to today, we've more than delivered on what we said we were going to do.
Any questions or final thoughts before we break for lunch? All right. Thank you very much and lunch will be served, and get a chance to visit more then and very importantly, have a safe trip home. Thanks.