Targa Resources Corp (TRGP) 2013 Q3 法說會逐字稿

Before we get started, I would like to mention that Targa Resources Corp., TRC, or the Company, and Targa Resources Partners LP, Targa Resources Partners, TRP, or the partnership have published their joint earnings release which is available on our website at www.targaresources.com. We also posted an updated investor presentation on our website which we will be using today, so please access the presentation via webcast or through our website so you can follow along. Speaking on the call today will be Joe Bob Perkins, Chief Executive Officer; and Matt Meloy, Chief Financial Officer. Other management team members are available for Q&A. Matt will cover the first part of today's presentation, which includes a review of our third quarter 2013 results as well as our financial and operational guidance for 2014. Following Matt's discussion of third quarter 2013 results and 2014 guidance, we will begin our 2013 investor and analyst presentation, which will include an update from Matt and Joe Bob on the Partnership's business operations and a Q&A session with the following Targa executives and officers available to participate -- with Mike Heim, our President and COO; Hunter Battle, VP of Logistics and Marketing Assets; Scott Pryor, VP, Liquids Marketing and Trade; Vincent DiCosimo, VP, Petroleum and Logistics; Danny Middlebrooks, VP, Gas Supply and Development, [Badlands], and SAOU; Clark White, VP, Permian and North Texas; Rene Joyce, Executive Chairman; Jeff McParland, President, Finance and Administration; and Jim Whalen.

Pursuant to disclosures on slide 2 of the posted investor presentation, I would like to remind you that any statements made during this call that might that include the Company's or the Partnership's expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor Provision of the Securities Acts of 1933 and 1934. Please note that actual results could differ materially from those projected in any forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings, including the Partnership's annual report on Form 10K for the year ended December 31, 2012 and quarterly reports on Form 10-Q. With that, I will turn it over to Matt Meloy.

Thanks Jen. Welcome and thanks everyone for joining us today, including those who are with us in Houston and those participating by way of the webcast. As Jen mentioned, I will start off with a review of and commentary on the third quarter 2013 and will then move into financial and operational guidance for 2014. For those of you on the webcast, I will be starting with slide 5.

Starting on slide 5, the top graph. This is a record quarter for Targa as our third quarter adjusted EBITDA of $156 million is the highest reported quarter ever and was 34% higher than the same time period last year. The increase was driven by higher volumes in natural gas and condensate prices in our Gathering and Processing division and higher fractionation volumes and fees and increased exports in our Logistics and Marketing division. Our overall results show the benefits of diversity and increasing fee-based margin contributions. Fee-based margins exceeded 50% for the third straight quarter.

Moving to the bottom graph, the operating margin was $200 million for the quarter, which is 24% higher than Q3 2012. The Logistics and Marketing division produced quarterly operating margin of $103 million, up 36% compared to the third quarter last year, primarily driven by higher fractionation volumes, fractionation revenue at CBF, along with increased LPG export and storage activity at our integrated Galena Park and Mont Belvieu facilities. We are pleased to announce that the first phase of our LPG export expansion at Galena Park and Mont Belvieu was completed earlier than expected and we began testing and commissioning in September. The expansion increases in our export capacity to over 2 million barrels from 1 million to 1.5 million barrels a month to 3.5 million to 4 million barrels a month. In connection with start up and commissioning of the export expansions, we loaded low ethane propane on one mid-sized vessel and two VLGCs in September. The Gathering and Processing division produced quarterly operating margin of $92 million, up 28% compared to the third quarter 2012 as a combination of volume increases and higher natural gas and condensate prices more than offset the impact of a fire at the Saunders gas processing plant and the Versado System and a slight decline in NGL prices in the third quarter of 2013 versus third quarter of 2012.

Moving to page 6, starting with the top graph, we saw increased activity across our Field Gathering and Processing division and third quarter over third quarter 2012 had volume increases in both our Field and Coastal segments. Plant natural gas inlet volumes in our Field Gathering and Processing segment increased by 17% in the third quarter of 2013 versus same period last year, Led by a 30% increase at SAOU, a 26% increase in North Texas, and the addition of the volumes from Badlands, which was acquired at year end 2012. This is the third quarter that we are reporting volumes from our Badlands System and crude oil gathered increased by 37% to 52,400 barrels a day in the third quarter versus 38,300 barrels a day in the second quarter. You will note on this chart that NGL production, shown by the triangle symbols, also increased for both points. And the graph also makes a point that not all inlet volumes are created equal, with our Field segment having much more NGL production than our Coastal segments, even with significantly less inlet volumes.

Upon the bottom graph, same page, the increase in volume, coupled with higher natural gas and condensate prices, resulted in a 28% increase in Gathering and Processing operating margin. These increases were partially offset by slightly lower NGL prices, higher operating expenses due to additional compression and maintenance costs associated with system expansion and the addition of Badlands as well as the fire at the Saunders plant. On September 5, we experienced a fire at our Saunders gas processing facility in Lea County, Mexico. Saunders is a smaller gas processing plant in the Versado System. Repairs have been underway since the fire and the plant is expected to be operational by year end. The net impact of the fire for Q3 was approximately $3 million net reduction in margin for the Field Gathering and Processing segment, approximately 50% in lost processing margin and about 50% in cost of our insurance deductible.

Moving now to page 7, starting with the top graph, you can see fractionation volume increased by 8% in the third quarter of 2013 versus the same time period last year. CBF Train 4 was operational during the quarter and we were able to work through some of the inventory buildup that occurred during the second quarter as a result of maintenance and inspection turnarounds of CBF Trains 1, 2, and 3. As previously mentioned, in September, we began testing and commissioning our LPG export expansion at Galena Park. The increased capacity of the facility contributed to export volumes, averaging 1.7 million barrels a month from the third quarter, a 77% increase versus second quarter 2012 average volumes of about 1 million barrels a month. Treating volumes were substantially lower in the third quarter of 2013 due to facility impacts associated with the start-up of our LPG export expansion.

Now on the bottom graph of page 7, the increased activity across the Logistics and Marketing division resulted in a 36% increase in operating margin in the third quarter 2013 versus Q3 2012, with logistics up 40% and marketing and distribution up 30%. The increase in margin was largely driven by factors already discussed, including higher fractionation revenue and increased export activity. The increase margin from fractionation activity was partially offset by factors associated with the start up and commissioning of Train 4 at CBF.

Moving to page 8, the top graph, you will see distributable cash flow for the quarter was approximately $111 million, a 44% increase over the third quarter 2012 and resulted in distribution coverage of over 1 time based on our third quarter declared distribution of $0.7325 cents or $2.93 on an annual basis. On the bottom graph, as you can see in the chart, distribution coverage for both Q3 2013 and Q3 2012 was approximately 1 time. As you will recall, this coverage profile is consistent with our 2013 guidance for distribution coverage being lower in the first half of the year and about 1 times for the full year. Even with the Q3 declared distribution 11% higher than Q3 2012, we expect continued coverage improvement in Q4 driven by the ramp up of contributions from the first Phase of the LPG expansion and continued contributions from projects such as CBF Train 4.

Moving to page 9, the top graph, you'll see capital expenditures were about $267 million in the third quarter of 2013 compared to $145 million for the same period last year. The 84% increase was driven by all of our high-quality growth projects, including the commissioning of CBF Train 4, the initial phase of our LPG export expansion and ongoing construction of the High Plains and Longhorn processing plant and the second phase of our export expansion. On the bottom graph, you'll see net maintenance capital expenditures were $16 million in the third quarter of 2013 compared to $14 million in the third quarter of 2012. The increase in maintenance CapEx is consistent with increased activity, higher volumes, and higher capacity utilizations across our businesses. For the full year 2013, net maintenance capital expenditures are expected to be approximately $80 million.

Moving to page 10, on the top graph, shifting to a few brief remarks about TRC's third quarter. A TRC third quarter 2013 distributable cash flow of $36 million was 62% higher than the same time period last year and resulted in dividend coverage of 1.5 times. The higher-than-expected coverage is a result of an overpayment of taxes in 2012 that is being applied in 2013 cash taxes. On the bottom graph, you'll note that TRC third quarter dividend of $0.57, or $2.28 annualized represents a 35% increase compared to the third quarter 2012.

That concludes our review of the third quarter 2013 reported results. We will now give an update on our 2013 financial and operational guidance and review of our guidance for 2014. 2013 has been an exciting time at Targa as we have seen some of our high-growth projects come online, on budget, and on or ahead of schedule. And we have been working hard on a number of other projects that will contribute in 2014 and beyond.

So moving down to page 12, starting with the top graph you'll see adjusted EBITDA for the last 12 months through the third quarter was a record $545 million. In the fourth quarter 2012, we provided a 2013 adjusted EBITDA guidance range of $595 million to $655 million. At this point in the year, we believe the adjusted EBITDA will likely be in the lower end of that range even with a number of factors that have impacted performance this year, including slower than originally estimated ramp of Badland volumes, lower volumes of Y-Grade to fractionate due to ethane rejection at some of our customers' processing plants, third-party incidents impacting volumes at VESCO, the fire at the Saunders processing facility in the Versado System, permitting delays which move the expected completion of the Longhorn plant to 2014. Despite these impactful factors, we still anticipate meeting the EBITDA guidance provided a year ago which underscores the strong performance across all our businesses.

Now on the bottom graph, thus far in 2013, we have spent $667 million on growth capital expenditures. For 2013, we anticipate spending a total of approximately $900 million. Our previous guidance for 2013 was total growth CapEx of $990 million, but we expect actual spending will be slightly lower. We are pleased to confirm that both CBF Train 4 and Phase 1 of the LPG exports came in on or under budget and early. Our overall CapEx was also impacted by the permitting delays around the Longhorn plant which moved some expected 2013 spending into 2014. Similarly, some of the expected Badlands CapEx for 2013 shifted to 2014. For 2014, we have currently announced plans for $590 million of growth capital spending, which may be conservative if we are successful with some of the projects we currently have under development that are not included in our guidance. As previously mentioned, we now expect to spend approximately $80 million in maintenance, capital expenditures net to our interest in 2013 and approximately $90 million in 2014.

Moving to page 13, we are maintaining 2013 guidance on distribution growth at 10% to 12% at TRP and expect to continue our track record of top-tier growth into 2014. We're announcing distribution growth guidance of 7% to 9% at TRP for 2014. As mentioned earlier, TRP distribution coverage for the third quarter was 1 times. For full-year 2013 and 2014, we expect coverage to be approximately 1 times as well. As our scale and diversity and fee-based business continue to increase, we believe that a long-term coverage target of 1.1 times to 1.2 times is appropriate. Now on the bottom graph, same page, we are maintaining 2013 guidance on dividend growth in excess of 30% at TRC and expect to continue to grow our track record of top-tier growth into 2014. Our dividend growth guidance for 2014 at TRC is in excess of 25% over 2013.

Moving now to page 14, top graph. This -- the graph on this page effectively illustrates how Targa has had stable to increasing EBITDA through periods of high volatility in crude, natural gas and NGL pricing. As I mentioned on the prior page, the prices we use for the 2014 guidance are $95 a barrel of crude oil, $3.75 in MMBTU Henry Hub Natural Gas, and $0.90 a gallon weighted average NGL price. And we also included overall NGL price sensitivities for 2014. Every $0.05 a gallon increase or decrease in weighted average NGL prices equals about a 2% change in 2014 estimated adjusted EBITDA.

On page 15 now, our fee-based margin contributions were a record $113 million in Q3 2013 and fees have provided greater than 50% of our operating margin in every quarter in 2013. We expect our fee-based margin to continue to increase and estimate that 60% to 65% of operating margins will be fee-based during 2014. Joe Bob is going to discuss our major capital projects later in the presentation, but I did want to emphasize a point that 72% of our announced projects that will be completed in 2013 and 2014 are predominantly fee-based.

Moving to page 16, top graph, as of September 30, you see we had total liquidity of $824 million. In the third quarter, we received gross proceeds of approximately $118 million from common equity issuances under our at-the-market equity program, which allows us to periodically sell equity at prevailing market prices. Year to date, we have now raised approximately $383 million of growth proceeds under this program. We are very pleased with the success of the program through three quarters this year and believe that subject to market conditions, we could potentially use the ATM program to meet our equity needs for the remainder of this year and for 2014. Total funded debt on September 30 was approximately $2.8 billion and our third-quarter compliant debt-to-EBITDA ratio was approximately 4 times. We expect this ratio to continue to improve through 2014 and expect to be comfortably within the 3 to 4 times range by the end of 2014 while continuing our 50% debt, 50% equity target funding on growth capital expenditures.

On to page 17, the table on 17 provides a summary of our guidance for 2014. We have already covered a number of these items this morning and we will discuss the others such as CapEx and operating stats later in the presentation. That concludes my review of the third quarter 2013 and overview of 2014 guidance. We will now move into our 2013 Investor and Analyst presentation and I will begin by giving an overview of Targa and will then discuss some of the current industry trends and impact on TRP before turning it over to Joe Bob, who will provide additional highlights related to the Partnership's footprint, operations, and opportunities.

Okay. On to page 19, I want to give a brief overview of the Targa corporate structure. As you can see, there are two publicly traded companies under the Targa umbrella -- Targa Resources Corp., which has a NYSE ticker, TRGP, also referred to as TRC, and Targa Resources Partners LP, NYSE ticker NGLS, or referred to as TRP. TRC does not own any operating assets and its only source of revenue is from its general limited partner interest, including incentive distribution rights in TRP. TRC owns an 11.9% limited partner interest, a 2% general partner interest in TRP and the IDRs.

As illustrated, all of Targa's operating assets are owned by TRP, shown in the gray box segments and bullet point business units and are split into two divisions, Gathering and Processing, and Logistics and Marketing. Currently, TRP's operating margins is split equally between the two divisions. All of Targa's publicly traded debt is issued by TRP and TRP senior notes are currently rated Ba3 by Moody's and BB by S&P. For our public debt ratings, we continue to deliver on all fronts relative to expectations we had laid out for the rating agencies, completion and commercialization of CBF Train 4, and the first phase of our export expansion project are important for the agencies. And we look forward to giving them an update when we visit with them prior to the end of the year.

Moving to page 20, there are two ways to invest in Targa. TRP is a master limited partnership that completed its initial public offering in February 2007. TRP pays quarterly cash distributions and issues K-1 to investors. TRP is the owner and operator of all the operating assets. It's currently trading at about a 6% yield and has a current enterprise value of approximately $8.4 billion. TRC went public in December 2010 and is a C-Corp. TRC pays quarterly cash dividends and issues 1099s to investors. TRC is currently trading at a 3% yield and has an enterprise value of approximately $3.4 billion. As you can see from the graph at the bottom of the page, TRP and TRC have both generated very attractive returns for investors which we'll discuss in more detail on the next page.

So moving to page 21, you can see the steady sequential quarter over quarter growth in TRP's annualized distributions for LP units on the graph at the top right of the page. Given TRP's position as an MLP with top-tier growth, it's not surprising that TRP has outperformed the Alerian Index by more than 50% since the beginning of 2010. The graph at the bottom left demonstrates TRC's strong performance since the IPO and TRC has outperformed the [ANC], S&P 500, and Utilities index year after year. We are proud of the strong returns that TRP and TRC have generated for investors and believe that there is ample opportunity for continued distribution and dividend growth going forward.

Let's now turn to discuss some current industry dynamics and the impact on Targa. Page 23. If we start and take a brief look at rig count, there is some key shift that have taken place, reflecting significant changes in the broader energy industry. In the mid-2000s, producers began to have some success using techniques such as horizontal drilling and multi-stage fracking to unlock some of the tight shale rock that have never been successfully produced before. One indicator of the shifting focus is in the increase in horizontal drilling versus vertical drilling.

Horizontal drilling now accounts for over 60% of US rig activity. Natural gas producing regions were initially the focus for producers using horizontal drilling techniques. Producers then started to apply similar techniques in oil and liquids-rich shale plays with continued success. Producers have continued to shift more and more resources to oil and liquids-rich basins and currently about 80% of drilling activity is focused on oil production. This is a trend that we expect to continue going forward.

Moving to page 24, the potential result of continued producer activity in oil and liquids-rich basins is illustrated on page 24 as crude production in the US is expected to increase over the foreseeable future. The EIAs base case projection estimates crude production of 7.5 million barrels by the end of 2020, with a high case projection of 10 million barrels. Current domestic production has already exceeded the EIAs base case expectations. The majority of the increase over the next decade is expected from tight oil resource plays like those in the Permian and Williston basins where TRP has well-positioned, expanding footprints. One impact of increased crude and liquids-focused activity in domestic shale plays drives more NGL supply from field production. Using forecast from a variety of sources, we estimate that between 2012 and 2017, there could be about a 50% increase in US NGL supply. Increasing upstream crude, NGL and associated natural gas will drive demand for additional midstream and downstream infrastructure, Targa has benefited, and we believe we'll continue to benefit as more highly efficient processing plants, fractionation services, and increased export activity are needed across the country.

Now on page 25, you can see TRP's geographic diversity in our Gathering and Processing division is intentional. Our Permian and Bakken systems are located in two of the lowest cost-producing crude basins which, as a result, are two of the basins with the most active rigs running. The Permian has more than 460 rigs currently running and is the most active Basin in the US. The Williston Basin is the third most active Basin in the US, with 183 rigs currently running. Our North Texas system is located in the liquids-rich window of the Barnett Shale and our coastal Gathering and Processing assets are well-situated for the longer-term potential ramp-up in Gulf of Mexico activity. We have intentionally targeted oil and liquid-rich basins for our Gathering & Processing activity, producing activity around our Field G&P systems has driven expansions that will increase our gross processing capacity by approximately 50% from the year-end 2012 to year-end 2014.

On page 26, TRP has the second largest fractionation position in the hub of the NGL market activity in Mont Belvieu, Texas. NGLs from around the country flow to Mont Belvieu and various pipeline conversions and expansions are trying to get additional volume connected to the country's NGL hub. In addition to our fractionation footprint, TRP has one of only two operating commercial LPG export facilities connected to Mont Belvieu. TRP's overall footprint in and around Mount Belvieu includes fractionation, storage, connectivity to supply pipelines, and a petrochemical complex and an export terminal. We expect to have continued opportunities for growth in this part of the downstream business as additional volumes flow to the Gulf Coast and drive demand for downstream services.

Page 27. The slide title on 27 reads Well-Positioned for 2014 and Beyond and we firmly believe that TRP is well-situated to take advantage of the renaissance of the US energy industry in the US. We have assets across active basins, coupled with the leading downstream position at and around Mont Belvieu that cannot be easily replicated, which means continued opportunities for growth and value creation. 2013 has been a big year for TRP and we've already seen the additional benefits of some of our organic CapEx projects going into service. And we're announcing guidance with continued strong distribution growth as more projects go into service in 2014 and beyond. TRC, our general partner continues to benefit from TRP's rapid growth and we expect dividend growth in excess of 25% for 2014. We're excited about what's going on in our industry and with that -- and what that means for Targa. I will now turn it over to Joe Bob.

Good morning, everyone. Kind of a mic check. We made a last-minute audible that neither Matt nor I could get down to this one and so we're working on the lapel mic. Is everything okay? And they tell me that it's working for the people on the phone as well. That's good.

Well, I'm happy to be talking with you today. If you peeked ahead, you know I've got almost as much material to cover as Matt has already covered and I'm going to try to stay with the highlights but I could stay here on page 27. That really is the one-page story. So if you fall asleep during the middle of my presentation, turn back to 27 and those are the headlines.

I get to start with a pretty good slide. Value creation for TRP since the 2007 IPO. We're proud of what we've accomplished. If you look at the top left-hand chart, capital spending from 2007 to today, there are really two eras. First 2007 through 2010 when we were doing drop downs, then selected investments at the same time on growth capital.

Then 2011 through 2014, we shifted. We shifted as the industry shifted to keep up with the demand. But we shifted to a lot of organic investments and selected acquisitions that are driving growth now and in the future. Our strategy in 2007 through 2011, really back to when we founded the Company, has been the same. It's a strategy of acquiring selected strategic assets in good locations at the right price. Taking those assets, better utilizing them, better commercializing them, and then constantly looking for new opportunities that play to our strengths.

That's the strategy we started with; this is the strategy we're doing today and that's the strategy we're going to do tomorrow. It has worked pretty well. Chart on top right shows the value creation since IPO. IPO did about $1 billion valuation and has grown to, as Matt said, $8.4 billion worth of enterprise value. That's a significant increase in value above the capital that we put into it. The chart shows that there's $2.2 billion worth of value creation above that IPO value, above the capital that was invested in the business. But that doesn't include $1.1 billion worth of cash distributed to TRP investors along the way. So the total value creation is the $3.3 billion since the IPO of TRP and we're proud of that track record.

Page 30 has a lot of words on it. 2014 -- 2013, as we said at this time last year, was going to be a transformative year and it really has been. As I said, our business strategy has been consistent. We're investing in Gathering and Processing; we're investing in the downstream. We're effectively executing across a very diverse business mix and we're identifying and developing new opportunities all the time. I'm proud of the execution in 2013, where we put $900 million of growth CapEx to work this year. We made plants additions, CBF Train 4 has been brought on, the LPG export facility has been expanded successfully, and the Badlands acquisition has been integrated and growing. So great execution for 2013.

Looking forward, by the end of this year, right now, frankly, we are very well-positioned. Fee-based margin, as Matt said, is 50% something and going up to 60% something. Those next few [dock] points talk about execution across the diverse business and then we look at a strong financial position and strong guidance for 2014 where 2014's EBITDA will be 25% plus our 2013 EBITDA. It's a transformative year but there's a lot in front of us.

If we look back to the IPO in 2007, I'm seeing many people in the room remember that. 2007 looked a lot different. The pie charts illustrated we were a Gathering and Processing Company only, with one asset in North Texas and essentially no non-fee-based -- essentially all non-fee-based revenue. North Texas was our MLP.

Fast-forward to today. Looking sort of three quarters through 2013, net business mix is half Gathering & Processing and half Downstream. Gathering & Processing across multiple basins, frankly, some of the best basins. A Downstream business across fractionation and exports and projects that are driving fee-based revenues. A much different look, 60% fee-based pretty soon. It says 54% looking back over our shoulder. That is a diverse, robust business. A whole lot better than just the North Texas assets when we went public.

Next page, page 32 shows our major announced capital projects. We've been using a chart like this for several years. And what we do after things become announced, approved, we put them on the chart. We rack them up and we show people what we are doing with it. We've got approximately $1.9 billion worth of projects coming on in 2013 and 2014.

If you sort of look at the columns, you can see that in 2013, we spent about $900 million by the end of the year. And giving you guidance for 2014 based only on these approved projects, we are at about $600 million. If you look across the entire page, line items and columns, you can see diverse spending across all of these projects, creating and adding to our diverse business mix. About half of the dollars are being spent on the Gathering & Processing side, about half the dollars in total are being spent on the Downstream side and, as Matt said, over 70% of those dollars on this page are being spent for projects that contribute to fee-based revenues.

Now every time we cover this chart, people sort of know these projects well and the first question is, what's next? Well, page 33 is a simplified version of what's next. Some of this is public because you can see it in permits or you can see it in projects or our customers and I are talking about it. That short project list, I just kind of want to talk through so you get a feel for it. In the Badlands and I'll talk about the Badlands in a minute, we've got additional gas processing opportunities in front of us. We've got one plant working. We just commissioned another plant that's had a little bit of start-up issues but we're looking at the third plant, that will probably happen in 2014.

The Badlands expansion program, we talked about how many dollars on the first page we'd be spending next year on identified projects. But we'll be spending dollars beyond those identified projects in the Badlands. Permian expansion program, likewise. We're going to be putting in place pipe that my Board hasn't approved yet; maybe plants that my Board hasn't approved yet because there's so much going on there and we'll talk about that in a little bit.

CBF Train 5 expansion. I don't know how many earnings calls I've been asked when is that permit going to pop out? I'm going to say again, recognizing that our federal government has disappointed me in the past, that I expect that permit will be out by the end of the year. We've been in conversations and that is our expectation.

CBF Train 6 is on the drawing board here, too. We've got room for it. Mike's acquired property quietly for years to make sure that we have. I'll show you how crowded it is but there's space for 5 and 6, and there is underground storage space sufficient for 5 and 6. Another projects are always on the drawing board and we don't talk about them until we approve them. And sometimes they're small enough that you don't even hear about them that drives our EBITDA in the future.

This list of projects will move from this chart to the chart previous as they get approved. That's what we always do. And the list of projects that's not on this chart looks a whole lot like this list of projects. We expect there to be additional investment opportunities as we go forward. I thought I was through with projects but I had to show you some pictures, right?

The top picture is our Mont Belvieu CBF fractionation facility. Looks pretty crowded. If you look real close on the chart, you can see activity in cranes. We've been busy out there for quite some time. And believe it or not, there is some green space and there is sufficient planning for CBF Train 5 after we get a permit and after we come up with the commercial deals that we want to drive that. And even room for a CBF Train 6, if there is demand for it. It is crowded.

I like the picture on the bottom, too. This is a picture of the first phase of the LPG export facility actually in action. That is not a Photoshopped ship. We were putting a Photoshopped ship in there before. That's a real VLGC on the front ground. Now our business before was medium-sized and small ships. You all remember us talking about that. 1 million to 1.5 million barrels of exports with the medium-sized and small ships. They're in the background there. See the medium-sized and small ships, the next two ships above that VLGC?

That gives you a little bit of scale of what the difference is on our new project versus our old projects. All are important. We'll continue to do the other business just as we do a lot of business with VLGCs. There was a conference just recently where I got to show the first ship and it was coming in. It was high in the water and one of the analyst looking at that ship said, that ship is hungry for LPGs, because it was riding high in the water. I thought that was a pretty good comment.

I need to pause a minute. Our environmental safety and health is a lot more important to us and our employees probably than it is for you as an investor but for you as an investor, it' important. You don't want a company that's doing the wrong thing. We do the right things. We spend a lot more time talking with our employees about this stuff than we do with our investors, but our performance is pretty darn strong. For example, if you compare us to our GPA peers, and that's a good group, against our GPA peers, we're far better than average. We get awards and honors all the time. And we're always looking for ways to be more safe, better on the environmental front, and we always will.

I want to take a deeper dive into a few Gathering & Processing highlights. Starting with the Permian Basin. If we could only choose one Basin to be in, we'd choose the Permian Basin. Permian Basin is the second largest oilfield in the world according to the footnoted reference there. It truly is an amazing place to be doing business. Targa's assets across that Basin are part of the active production, taking advantage of active drilling in the Spraberry, Wolfcamp, Wolfberry, Cline, Canyon Sands, Bone Spring, Avalon Shale. Very, very active.

If you look at the bottom left-hand corner, Permian Basin permitting activity, shown since 2006, which you could go further back, is up and to the right. And I expect it to continue to be up and to the right. Permian Basin drilling activity in the chart on the top right shows very high activity, 400 to 500 rigs over time, it's not flattening out. Look at the blue line. The blue line is horizontal rigs increasing steadily over that period of time, which is a multiplier effect because horizontal rigs have a higher rig effectiveness than those rigs we were looking at on the left-hand side of the chart. So permitting activity and drilling activity and advances in technology are driving the bottom right-hand chart. Production going up and to the right, crude oil, NGLs, natural gas from this oil-driven Basin.

Page 38 is forecast. There is a lot of detail in these forecasts and I won't take you through it. You can look at it later, by producer or by hydrocarbon. All of the forecasts for the Permian Basin show continued activity and growing production. Many of them -- I might even say most of them are showing that Permian Basin, growing to 5 million barrels of oil equivalent by the mid-2020s and the charts at the bottom of this, for example, shows decades of growth.

Let's talk about Targa's presence in the Permian Basin on page 39. You can see three major systems across the Permian Basin. They extend from the east side of the Permian Basin to the west side of the Permian Basin and down into the southwest of the Basin. We're active across all of those active plays shown in different colors. We're not dependent on a single producer, not dependent on a single play, not dependent on a single area, and all three of those areas, SAOU, entailed [Wolfberry] side, are expected to have inlet volumes meaningfully higher in 2014 than 2013. Life is good for us in the Permian Basin. The recent expansions that you all are well aware of, 60 million cubic feet a day, in total, they're essentially full.

We're building the 200 million cubic foot a day plant, the High Plains plant, shown in the center of the chart. And we expect more investment opportunities over time. Broadening our footprint, extending pipe to where the drilling is being done from our system, better utilizing the capacity that we have or the capacity we're adding, and then perhaps expanding or adding plants over time, really just getting our share of that activity in the Permian Basin. Those of you who follow a lot of E&P companies know about. I want to talk about each of those three areas quickly so you've got a better feel for what's going on there.

Page 40 starts with SAOU, so-called San Angelo Operating Unit; we never say that full term. SAOU is located on the east side of the Permian Basin. The activity around SAOU is robust. These little red triangles represent a snapshot in the middle of October of how many rigs were running, drilling rigs, not workover rigs. SAOU is an extensive system. Multiple plants and we're adding a big one over on the western side now. And like I said, 2014 volumes will be meaningfully higher than 2013.

Switching to Sand Hills on the next page. Sand Hills is located sort of the southwestern part of the Permian Basin. It covers a large area, as you can see. The same red triangles represent producer drilling rig activity and it's all across the system. My guess would be those over on the east side -- my guess, I know. Those on the east side are drilling for Wolfberry; those on the west side are drilling for Bone Springs. There's some conventional drilling in the center. The volumes year to date for Sand Hills are up from last year and the volumes in 2014 will be meaningfully better than 2013.

The third area is Versado, last but not least. I'll get to that in a minute. For context, by the way, Matt mentioned the fire. That's the Saunders facility on the top, if you see it. It's the smallest of the three plants. Not a meaningful impact and it will be back up in December. If you don't believe me, you can ask Clark White, who's in the room with us. Really an extraordinary job putting it back together and I'm very proud of the employee effort on that.

Back to the activity levels -- you know, this is recent activity. Those of you who followed this for a while, I remember three to five years, ago we would talk about Versado, not say very much about it and when asked about the volumes, say there will be a little less than last year. We said that for several years. Two years ago, we were able to say, flat, the volumes at Versado were hanging in there. They were flat. Last year, we said flat to increasing. Take a look. I'm really proud to say meaningfully higher for Versado for 2014. And we've got available capacity; it's probably our cheapest expansion in the Company, right? It doesn't cost much. Clark White feels good about it, too, as do all of the employees of what we call, Versado

North Texas growth overview. Shifting to North Texas. North Texas located around Dallas-Fort Worth. Someone said the view out of the hotel here looked better than Dallas when I first walked up. Active area. Indications of that activity are shown in the top left chart. selected North Texas well permits. Here I can get a close proxy of our combo Barnett area by looking at Montague, Cook, Clay and Wise counties. Now the dry part of the Barnett is not active but Montague, Cook, Clay, and Wise counties as proxy for that [wet] part show permitting activity back to 2005 growing and up to the right.

Now we know that activity is less than it would be if there weren't so many opportunities in the Permian Basin and people have sort of divert into their resources. But the good news is there's still producers very focused on this and we are benefiting from them. This shows a snapshot of that activity where we are in the middle of October again. Most of the activity in the top right-hand corner, that's the [wet] part of the Barnett Shale. Volume increases here are being driven by the [wet] part of the Barnett Shale and by the Marble Falls. Marble Falls is the same source rock as the Barnett Shale but it's actually a dewatering oil play and has been contributing to our growth. As other shift resources, there's still some companies focused here.

Shifting from North Texas to North Dakota, where our Badlands System is located. Our system is located in McKenzie, Dunn, and Mountrail County. Zooming in on McKenzie, Dunn, and Mountrail Counties, we can look at selected permits in the bottom left-hand corner of page 45. That permitting activity is up and to the right since over the last three years. There's no slacking off in those three counties in terms of activity as indicated by the leading indicator of permitting activity. It is a little harder to see rig activity in North Dakota by county, but if you look across the basin rig activity, it's hanging in there in the sort of 150 to 200 rigs. But that's not the whole story.

As producers largely are moving to manufacturing mode and pad drilling and pad completions, a flat number of rigs is actually an increasing number of effective rigs, if I can use that term. The result of the permitting and the drilling and advances in completion techniques and more formations becoming productive is Bakken/Three Forks oil production going strongly up and to the right in the bottom left-hand corner of the graph. And there are lots of forecast out there. I won't go into the details of this forecast either and I know I can't read the type in those boxes. But if you look at forecasts, most forecasts show oil production doubling in this area over the next 10 years.

2013 has really been a game changer, I think, an inflection point. If I were drawing the box with a little arrows and we sort of stole this one. What I would say is 2013 is manufacturers shifting from delineation and research projects to manufacturing mode. And that shift is just now occurring. It's about still increasing technology, improving the IPs and the tight curves by sub-regions, we are cracking the code. It is about improved expectations. You could hear that from the producers in the area. There are going to be more completions per drilling units, the IPs are higher for each completion than they expected and the reserves are higher than were expected a couple of years ago. So that's the game changer we're talking about in summary.

So now zeroing a bit in on our Badlands facilities. I first want to deal with something that's under the disclosure. Matt mentioned contingent, the so-called contingent consideration associated with Badlands. In quarter three, we estimated this liability that we had to put on our books to zero. Now that's completely consistent with what we thought it was going to be when we acquired the property. Part of the deal was if you got to a certain level, we would have to pay an additional amount to the seller. That was a very low probability. Now with the passage of a little time, and satisfying accounting rules, we can put that to where it was. And by the way, it doesn't impact the adjusted EBITDA that we've been telling you about. So, so much for that.

I'm going to go over pages 47 and 48 together, talking primarily off the map. There are a lot of words on those two pages. What I'll say is consistent with that text and you can read it later, I guess. We acquired target Badlands 9 months ago and spent the last 3 quarters work -- 10 months ago, spent the last three quarters working hard to execute our strategy, working hard to execute that strategy with some difficulties. This is a brand new acquisition. We've experienced the challenges of a brand new acquisition. Operating in a basin that's new to us, we did have a difficult winter and spring weather and we told you all about that.

There are issues with the quality of producer operations up there, too, and they're struggling to work with their own new infrastructure. Producers have had difficulty putting oil and gas lines. That doesn't do a lot for processing plants because of problems with their quality of gasketing our gas lines. But we are working through it, working through it with them in improving those operations. We've experienced some slow and difficult right-of-ways there, too, as well. And if you talk to other producers and midstream companies, you'll know that's most difficult on the reservation.

We are dealing with a boomtown up there, boomtown level of activity and the difficulty of getting people, and working with regulators and governments and the tribe, who is also dealing with that same rapid growth. Probably didn't slow us down a whole lot below -- beyond our expectations, but it has been a lot of hard work. However, we feel as good or better about this property than when we acquired it, for the reasons I sort of alluded to. The map shows the general footprint; I'm going to take you through it.

Why don't we start with a Little Missouri processing plant. Located in the middle of McKenzie, Dunn and Mountrail counties is a very good place to be. That plant location had a 20 million cubic foot a day operating -- actually, it wasn't operating when we visited it, plant when we acquired it. That plant had some design defects that we had to correct to make it work better. That plant that was in progress with some construction delays. We had that one finished. And after considerable efforts, we've got both plants running much closer to the way we would run a plant somewhere else.

From left to right, I also should mention Little Missouri processing plant, we acquired 40 acres right across the road from it for the third plant, an indication of the potential to help on the gas side as well. We're still evaluating that plant, as I mentioned earlier. What's the right size? What's the right timing? Probably have something in 2014. On the left side of the map, our Alexander Terminal is a crude terminal with 30,000 barrels of tank capacity, an improving interconnection capability to enrich North Dakota Pipeline, an important spot for many of our customers. Further east, the Johnsons Corner Terminal now has 40,000 barrels of tank capacity; it's interconnecting to three pipelines, Tesoro, Four Bears, and BakkenLink, and providing truck and other rail capability. We've now got three lines going to five lines, truck lines, for truck to rail for our customers.

At and around the Johnsons Corner Terminal and the Alexander Terminal, we've been adding flexibility and interconnections for our customers to get to those places, even as their desire of what place they want to get to changes on a monthly basis. And that's just what it looks like in North Dakota right now. We're somewhat indifferent to where they move it and our movement by pipe is a whole lot better than movement across the base -- that portion of the basin by truck.

Since closing the acquisition about 10 months ago, we've also been expanding the pipeline footprint. You can see that pipeline footprint. It's on a scale that really is a precise -- it has to be more indicative and that's good, too, because some of those gas lines are still getting right-of-way from and I wouldn't want them to know exactly where it is. The solid red lines are completed oil lines. The solid blue lines are completed gas lines and the dashes represent projects and processes. Those projects and processes may be adding right-of-way, they may be under construction, they may even be done and we haven't updated the map here but that progress in terms of pipeline miles is important.

We acquired the system with 300 miles of pipeline. First of the year, that's about how much oil and gas pipeline were in place after multiple years by the previous owner. By the end of 2014, we will have more than doubled those miles of pipe. More specifically, in 2013, which is almost over, we will have had -- we will have put in place about 200 miles, a little bit more, of pipe on top of the 306. We estimate that based on our known projects in 2014, we'll put in place another 130 miles. So by the end of 2014, across dedicated acreage, with a first mover advantage, we will have 640 or some odd miles of pipe in place, benefiting from producer capital investments.

Our system is a facilitator. The producer spending, the producer drilling will be what drives the growth of oil volumes and gas volumes through our systems. And the drivers of that producer capital investment are pretty obvious. And as I mentioned, they are better than when we acquired. You can look at producer public information about the number of completions per drilling unit, the IP for each completion, the reserves for each completion, all significantly above by micro-region what we were expecting when we first acquired this. So that's why we feel very good about this project that we're having to complete. As an example of increased expectations and I'm not going to get into reserves and I'm not going to get into initial production, but as an example, several producers are saying publicly and telling us that they may have 16 wells per 1280-acre drilling units. That's more than double what we were assuming when we acquired it.

Just as miles of pipe are important to me and I can tell you about miles of pipe and I can tell you about the progress we're making across there while working very hard on the miles per pipe. We're going to be monitoring oil volumes, and our oil volumes have improved. We told you in the second quarter we thought we'd see 20% increase in oil volumes for the third quarter and a 20% increase in the fourth quarter and Matt already told you that we increased oil volumes by 37% for Q3 over Q2. We expect a 20%-plus increase for Q4 over Q3 and 2014 volumes well above that. That's the guidance of what we thought those volumes would increase for 2014. And we usually hit our guidance.

Of course, the Badlands EBITDA -- the Badlands performance is embedded in our overall TRP EBITDA growth guidance and in our overall distributions growth guidance. And because we get the question so often, we reaffirm -- I hate reaffirming. We reaffirm our guidance that this acquisition is accretive during 2014. That completes the Gathering & Processing highlights.

And we will switch to our Downstream highlights, beginning again, a little bit with context. Page 50 shows NGL supply flows, which certainly continued to increase to the Gulf Coast and Mont Belvieu. The reason why? There's a chart at the bottom left-hand corner. That's where the pet chem market is. 80% of North American is down there and that's where the NGLs need to go. Matt touched briefly on the graph at the top left-hand corner. Just touching on a couple of other things about it.

We've got questions. What is that green up sidebar there? Well, first of all, you see everything going kind of up and to the right. That's Field Gathering & Processing and NGLs naturally connected to Mont Belvieu and the Gulf Coast are probably coming in that direction. That green piece up there, that's 400 barrels a day of NGLs, coincidentally, that's probably about -- I didn't do this, [Intergras] did this. I don't probably know exactly how they got there, but 400 barrels a day would equal the first days of Bluegrass plus the Kinder Morgan Northwest or would equal the potential said by Bluegrass. That's NGLs moving somewhere that haven't been moving very well, maybe it is coming to the Gulf Coast. I should also mention that, with respect to Y-Grade moving around differently than it has, Y-Grade potentially coming from the Northeast, to the Gulf coast, ethane rejection occurring at various spots. That area around Mont Belvieu is going to need to get more flexible at handling a range of Y-Grade through its fractionation facilities and you'll probably be hearing a lot about that.

So Mont Belvieu is the demand center. Page 51 says that Targa is very well-positioned around -- in and around Mont Belvieu, in and around Mont Belvieu, meaning all the way to the ship channel. The Page provides a summary of a lot of assets. Interconnected assets between our Mont Belvieu in Cedar Bayou Fractionator that sits on top of the valuable [underground] storage and between Galena Park, which sits on the Eastern channel. It shows details on fractionation and treating assets, underground storage, pipeline connectivity to supplying customers, terminals and box, and very importantly, the interconnected export facility. These all work together and it's very difficult to replicate any one of them, let alone the combination. So when we say it's difficult to replicate our assets, that's what we mean.

Page 52 provides a little more context that I wanted to touch on. In 2012, about 40% of fuel production flow to Mont Belvieu. This chart is trying to show industry NGL supply and Y-Grade pipeline capacity. There's a lot going on. Let me explain what's in there a little bit.

First of all, the blue shaded area represents pipeline capacity. Back in 2012, pipeline capacity, fractionation, NGL supply were all kind of in sync after first fixing pipelines and fixing fractionation. Pipeline capacity continued to go on and you can see pipeline capacity exceeding the other two lines. The blue line represents the third parties' estimates of Y-Grade to Mont Belvieu, which we don't believe includes the announced pipeline projects coming from the Northeast and apparently reflects some significant ethane rejection as we look at the numbers, impacting incoming volumes. We agree there's significant ethane rejection occurring.

The orange line represents a third-party estimate of Mont Belvieu-based fractionation capacity which includes announced projects like Targa's CBF Train 5, which is still in permitting but probably very likely. And you see that yellow line gets a little bit above the blue line in 2014, a little bit more above it in 2015. 2014 looks about like take-or-pay levels on average to me. 2015 looks like utilization may be a little bit below those take or pay levels. Beyond 2015, you continue to have supply increases but starting in 2016 and 2017, we expect demand increases as well, which will bring ethane into that mix, further increasing the supply picture. So some temporary perhaps less than utilization and my longer-term forecast would be and need for additional fractionation over time.

Let's move to page 53. Also for context, shifting to world's LPG exports supply and demand, get this sort of question often, so I sort of want to quickly touch on the basics here. First of all, what regions are exporting LPGs? You can see some of the major ones there, certainly, the Middle East being an important player. You see the US share of exports, 2011 through this year growing 6%, 8%, 14%. Even with that increasing market share over time, the US share of worldwide waterborne LPG is expected to be less than 20% by 2020. So it's not beginning to get too large on a world scale.

And by the way, where does it sit on a cost curve? It sits by comparison -- first, we should look at whose other large propane exporters are. US, larger than any single country in the Middle East, but you have multiple other Middle East countries and then you've got Norway, Algeria, Kuwait, Venezuela, Nigeria. Relative to a cost curve, the US is lower-cost than many of those to the right.

Now where are those exports going? The chart at the bottom left shows you some of the regions -- Latin America, Northwest Europe, the Far East. US LPG exports primarily have been going to Mexico, South America, and Europe. You look at the waterborne reports. Increasingly, particularly with the Panama Canal completion, you'll see some of those exports going to the Far East as well.

So moving to our specific capacity, Targa's export capabilities in Galena Park. We're in the middle of a $480 million expansion project. We have gotten a nice chunk of it already done. If you look back to -- the second quarter, before September, what we were doing was HD5 and butane at about 1 million to 1.5 million barrels a month. As of September, we can do low ethane propane, again HD5 in butane, at a rate of a combined 3.5 million barrels to 4 million barrels per month. The work that is still going on, already started for the second phase of the export project will add at least 2 million barrels, bringing total capacity to 5.5 million barrels a month to 6 million barrels a month. I'd also say that from the first of the year to the third quarter when that second phase is supposed to be completed, we'll be bringing additional capacity to bear as we do pieces of the work and that adds capability.

With that, I think I've covered our Upstream highlights, our Downstream highlights. We have a satellite picture of all of our operations and hopefully a summary of some of the points that we made today. With that, I'd like to turn it over to questions. Operator, would you queue those up, please?

(Operator Instructions)

James Jampel from HITE.

If you could just comment on the revised 7% to 9% distribution growth for next year and how that dovetails into the eventual 1.1 time coverage target? When should we be -- expect to see coverage actually move significantly north of 1?

There were two parts to the question. The first part was, how we would comment on the 7% to 9% distribution growth guidance. We believe that, that is a reasonable range. Our guidance, we usually hit 2% wide. I expect to be within the 7% to 9%. How does that dovetail into our coverage? We expect it to be improving coverage across 2014, and we're ultimately headed towards that target of 1.1 to 1.2. The back end of 2014, for example, we will have better coverage than the front end.

Would 2015 be run at 1.1 coverage in total in your anticipation?

Well, when we look at the coverage, the 1.1 to 1.2 long-term target coverage is not necessarily any one year. If you look at 2014, there is about $900 million worth of projects coming online in 2014, so we're spending the capital will be out the door, but we won't have full credit for all the EBITDA. So we'll still have continued growth and continued CapEx in our plans out multiple years. We don't have as much visibility and don't get into 2015 and 2016 guidance, but as we look through three years, four years, five years and our forecast, we look at when the capital is spent and out the door, when the EBITDA is up and running, that 1.1 to 1.2 times out multiple years.

Stephen Maresca, Morgan Stanley. Stephen? It looks like he has disconnected.

(Operator Instructions)

Hello?

Stephen, are you there?

Can you hear me? I don't know why it said I disconnected. Sorry about that. Badlands, the additional gas processing plant. Can you talk a little bit about what ballpark type of CapEx that could be for 2014 if that were to happen? I don't know if you mentioned that.

What I mentioned is that we haven't yet decided the size that's necessary and that will impact the call.

Okay. On the -- just on the M&A front, you haven't done anything major since Badlands in 2012. Is that just a sign of where we are in the M&A cycle in terms of the expansiveness of the assets? Do see that dynamic changing, or you just feel that organically you've got enough on your plate right now?

We're still looking, but we do have a lot on our plate, and we don't need an acquisition today any more than we did when we did our last acquisition. We don't expect us to be doing a major acquisition in the near future. The market is always a funny market. Sometimes people are paying too much for assets. Sometimes people hang around the net and get a better deal.

Okay. On the export side, obviously volumes up a lot. You are seeing some of the differentials between US and international pricing come down a bit. I mean, how do you think that changes your ability for another expansion project going forward or the types of returns that you've been able to receive there? How deep is this market for the next couple of years, do you believe?

I think I'll answer the short one instead of taking a microphone back to the people who have been working on that, but I know from them that interest, negotiations is still very robust, across a range of types of players. So there's a lot of demand being expressed for our export capabilities. And we have contracted fully for the first phase, and we have got a nice return second phase already underway, and that will be adding to our capabilities across 2014. Once that's in place, we do have attractive return expansion, debottlenecking, capacity of additions on the margin, we are not announcing any of that. I think the market is deep enough for the best players.

Okay. That's all for me. Thanks a lot.

I need to look out and see where Scott is sitting. Did I miss something? Okay. He said it was fine. He will correct me later. Go ahead. What have you got?

(Inaudible - microphone inaccessible)

My crystal ball is not that good. I actually would not expect many of those major projects to contribute any EBITDA in 2014, with the exception of the Badlands gas plant, which we mentioned. There are projects that we're spending money on that aren't on the list of the $590 million to $600 million that will contribute to EBITDA in 2014.

I would say that we are at the $590 million of projected approved projects and that we will add to that across the year. Is that a -- okay. I didn't repeat the question. I'm so sorry. The question was about the backlog and what percentage of the backlog might be spent in 2014 and what percentage of the backlog might be contributing to EBITDA in 2014? So now you have the context for my answer. I apologize for those on the phone.

And a quick follow-up on the backlog, you mentioned the condensate splitter as the potential add-on to your export footprint. Now that we're starting to see some of the crude pricing on the Gulf Coast back off, global prices may be signaling that there's a bit of a bottleneck around the Gulf Coast. Does -- has that accelerated the amount of demand for that condensate splitting for other projects?

And just the final one for me would be, do you think we see [ethane] exports as part of this LPG export boom and if we do, does Targa participate in those ethane export projects?

Okay. Taking the pieces of that. First, there was additional interest or not on the condensate splitter projects that we're working on. And that's separate and apart from LPGs. But I'll look out in the room and I'll just ask Vince DiCosimo to give me an up, down, or even on interest. He said there's more interest on condensate splitters that we're talking about, and that's about as much as I would want to say about it.

And you said is ethane exports going to be a part of the LPG export boom? I think ethane exports are possible, and there's certainly one already there from the East Coast. Facilities like ours could be a part of that. Those projects will have to have backing and the commitment of whatever counterparties who are that want ethane exports to spend a lot more dollars on the other side of the water that need to be spent on this side of the water, so we'll see if that will happen. Did I miss anything in the question? Okay, great.

Could you comment on what type of activity you're seeing in the Gulf of Mexico and what that could mean for Targa in future years?

Some of the people in this room who know me know that I really like to talk about the Gulf of Mexico, but I didn't pay him to say that, and I'm not trying to hide the Gulf of Mexico. We've just got such a great set of assets across the Gulf of Mexico. The best catchers in that, I believe, for nearshore Louisiana and offshore Louisiana. And we keep figuring out how to get more liquids and make more money with West inlet volumes and I think we benefit from the consolidation that's going on.

I'm hopeful of renewed activity and renewed production, particularly oil and rich liquids-oriented, which is what it will be, but I don't see that in 2014. The research projects and the E&P work that you can read publicly also, and I know from my petroleum engineering friends of my age and class, that can lead to something and that would be very attractive for our -- for that small portion of our business.

To give you an idea, we didn't bring someone to the Coastal segment to answer Q&A, so there's no one in the back of the room shaking their head at me or nodding their head at me. Mike did.

(Inaudible -- microphone inaccessible.)

Mike reminds me of Morris B. which is dedicated to Dennis, as he was coming on. Shell has been committed to it and there hasn't really been any slip in their schedule. That is certainly meaningful for the Coastal segment. And we see lots of other projects. We're working with those customers. I'm just not trying to oversell the 2014, 2015, 2016 potential for that. But I think you'll see it help -- continue to help that segment, which is very good at making money.

Can you talk a little bit, just, from your perch, how you see the long-term demand story playing out for liquids, and you highlighted what's going on up in the Bakken and what's going on in the Permian and now you mentioned you have a potential longer-term potential growth for the catcher's mitt in the Gulf region. And all I see is supply, supply, supply, supply. We know that there's crackers coming on board. But are we getting to the point where we're going to be in a perpetual oversupply situation? How do you see the demand catching up to the supply? And are we going to run out of runway?

That is a rich question and we've probably spent six slides talking about it but I'll give you my summary view and then we can talk about it more later. The supply side of the equation in this country is driven by the drill pit, 80% dominated by drilling for oil right now. On a global scale, that supply increases in the United States are not changing the macro supply and demand. So we're going to, in my opinion, exist in a world of pricing to balance the supply/demand for world oil that continues to cause the drill pit to be as active in this country as it has been in this country. And you have just got to tip your hat to the innovativeness of UF E&P to continue to find and improve the productivity of horizontal oil wells. So I believe that continues.

On the other side of the equation, the gas well inventory at pretty low prices becomes economic, and my interpretation of what we saw in 2013 was even some spike in Haynesville drilling, dry gas drilling that occurred when gas prices got a little bit up. So I suspect that gas, natural gas supply/demand will stay in balance, I don't know exactly where. And that, that balance is being assisted by conversion to gas, even gas exports and price will be the valve that turns on how many dryer gas wells get drilled relative to their economics.

And then you've got some stuff in between and that comes with -- and that's the NGLs that come from natural gas wells and that come from the gas from oil wells. Those NGLs come with -- we have tried to show the forecast of what's happening. And in the macro sense, exports balance out also on the global scale where we've got long-life, low-cost or relatively low-cost NGLs on the world scale.

First, ethane that becomes ethylene. It takes a few years to get that built but it's globally advantaged, except for a few Middle East countries and if you're building a new pet chem to keep up with global demand, you might as rather build it here than in the Middle East. That's taking care of exports of ethane and maybe you -- I get the question all the time, maybe you export ethane not as ethylene. That could occur. Then all of the other LPG so as not to continue -- get exported as well, from gasoline to butane to propane as a price clearing mechanism, and that's working.

And when it doesn't work, prices will go down. And then it will adjust. I am not trying to predict prices. I'm just trying to service those multiple needs. Our Company is pretty well-positioned to do okay through this -- sometimes oversupplied, sometimes exported and then one catches up, as far as I can see. So is that a reasonable short answer? I'm happy for any of my team because to give a better one because I often forget things.

So long-term, you see it in balance?

In balance but always being a little bit long and then a little bit short and then having something compensate. There's only brief moments when it is in balance, but not in export balance.

But there's no future -- you're not afraid of any future tipping point of a permanent imbalance between supply and demand?

I think there is a tipping point on ethane right now. We're tipping up to a lot of rejection, which is compensating and handling it until the pet chems get built. And the same sort of thing may happen in another LPG. And someone was talking about the condensate and oil. There was a little tipping points that caused something to happen, but I think it works. And it works because we're low-cost relative to most of the rest of the world supply, and that's important.

Okay. If I may just turn a little bit somewhat in the same regard, on a lot of the charts that you threw up here, there were a lot of red triangles about the active rigs around the different systems. I'm just curious a little bit. How much of those -- how does it all play out -- are those rigs where they're operating for the operators? Have they already dedicated the acreage or the volume so you know what's coming to you and what's not coming to you? Or are those operations so jump balls where you can go out and fight for those volumes, but you show all those rigs, clearly some are right overlapping the pipes and some are two or three inches away from where the current systems are, but on the map, so I'm just kind of -- how that plays in?

You are right. We show all of those to give you a macro view of the activity. And if we actually went to them, the people running each of those areas, not on that scale of map, can circle the ones that are already dedicated and the ones that they competed for and maybe lost or competed for and won. If you kind of draw a circle around our system, the more you're in the center of our system, the more you can be pretty sure of it that we didn't even have to compete for it.

So further out from our system, the more it might have been a competitor; it might have been in the middle of their adjoining system and we have some system overlaps. So I'm not trying -- please, no one interpret that we're saying we did every one of those little triangles. But in our area, we can compete pretty darn well because, when we say yes to a customer, we take all our gas. And we do not have rolling brownouts, and we have a pretty darn good reputation. And if you hear anything about our reputation, we may be hard negotiators, but we get the job done.

(Inaudible - microphone inaccessible) with that --

You're on. When you talked to that, that's going outside.

With that, we are as the producers come in, in this SAOU system as an example. If you look back four years ago, they weren't drilling any wills. They were all vertical wells. We were connecting 300 or 350 wells. There's going to be less wells connected, but they are definitely getting a huge step up in the number of horizontal rigs that we're seeing that have higher IPs. I think that I think that those dedications are fairly long-term in their large areas. There are chunks that came in at 10,000 and 20,000 and 30,000 acres.

For the people who didn't hear when Mike picked up the phone, repeating a piece of it for the people on the phone, across our systems. It should not sound like we've got a lot of jump balls going on. Within our system, system footprint, we've got lots and lots of dedication. That's how we do business. That's how the business is done. Those dedications have been increased over the last several years.

Joe Bob, a couple of quick questions as it relates to everything that you just laid out around liquids export. I'm curious over the next 18 or 24 months, how you see the development of the Patriot Terminal and Channel View? Obviously Channel View more suited to doing, if you will, find a channel export and obviously, there's a big opportunity there. Maybe ultimately, that's where the splitter goes, and it becomes light nat gas or oil export facility.

Patriot a little bit different. It can do those capabilities as well as more propane and butane. So across the opportunities that, if you could just rank it in terms of returns? How do those two terminals look in two years?

You sort of asked a question and then probably gave a pretty good answer to it, and those are nice add-ons to our petroleum logistics. The Patriot Dock has the potential down the road after other expenses of assisting on LPG exports. Our terminalling work will be around whatever is contracted as the most profitable. It may be exports, it may be just be in movements. But I really don't want to say more than that relative to negotiations that are going on for those terminals. When those projects are up and running or you see increases coming from them, we'll talk about it. (inaudible)

Let me add one thing about Patriot in particular. If you take a helicopter and you fly out into the Gulf of Mexico today and you look at the Mount of Galveston today and you see all the ships that are queued up there. Oral imports, refined products imports and exports, the demurrage on those ships are huge. The average wait is somewhere between 9 and 10 days out there for those ships to get into the port. That creates huge demands for utilization of large ship docks. And we've got Patriot, and we're working in our second phase of the LPG export.

We're building Dock Four. It is under construction. We've done engineering to build another dock so that we can, on the other side of our existing large ship dock. So there's lots of demand out there. We're talking to a large number of companies that see the opportunities with all the pipelines that are plumbed through that area of Mont Belvieu to do all types of exchanges and exports.

A couple years ago -- I may have my time a little bit, a couple of years ago, but you guys assembled a team of people that were to be working on terminal acquisitions during M&A and terminal space. There was a fairly consistent flurry of activity through 2011 into 2012 in terms of terminal acquisitions. It's been very quiet since. What happened to that team and what's your strategy method?

Vince DiCosimo from that team is about three people behind you. And what has happened since then is those were three quick acquisitions. We've been spending the capital on those acquisitions that we told you we would be spending. So from the initial acquisition price, I think we basically doubled our capital employed through projects to expand and add tanks, and even add acreage around them. There was another project out there that's public because we have permits options around it and that is at Stockton.

And then there the team is certainly working on other things, and they would say, and here's another little foot -- little thumbprint that we are turning into a multi-fingerprint. And we're still interested in doing that. What some people have asked us about, do we look at great big acquisitions like HEF acquisition. We didn't look at that one very long but we would have been interested in pieces or parts.

Vince, did you have anything you wanted to add to that? Okay. Still active. Still making those more profitable.

Patriot is part of that group.

Yes. So there was one other little acquisition there. And you just asked us about that.

I have a question on the regions you're working on now. You've had a pretty torrid pace of growth in the gathering side. I'm curious as to, is there a point where you see the demand -- the activity ebbing or slowing?

On the activity side?

On your fields where you're gathering the gas. I'm just saying, when the buildout -- is there a point when the buildout is closer to the end than the beginning?

I need to take that by parts. Certainly, the Permian Basin, as far as my radar scope goes, I don't see the activity ebbing there and around our assets being very well-positioned across that Permian Basin. North Texas, I think I said and if I didn't, I should have, that activity in North Texas has decreased. The growth of it has decreased somewhat.

We're still growing volumes, and that's because resources have shipped to the Permian Basin. Pure oil versus very wet gas. As an example, the Marble Falls is an oil play for smaller guys who have a position there and don't have a position in the Permian Basin, that's very attractive economics.

Because of the Bakken and I don't see a need for gathering slowing down there at all. We are slower. For example, we talked about the later potential of our Coastal segment. There are just very few wells going on in Southwest Louisiana or on the offshore for immediate connection compared to other periods of time, and that could improve versus getting slower. So that's my kind of broad, what does it look like?

One more question here. We don't have any more on the phone coming up, do we? I am actually going to say goodbye to the operator. Thank you, operator.

Anybody online who was sort of waiting for question and didn't get it in, feel free to give us a call. Matt or Jennifer, or any of the rest of the team and we'll try to help you later. Okay? We're going to still hang around. Hang on a second. Are we cut off?

Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program. You may all disconnect. Everyone have a great day.