Good day, ladies and gentlemen and welcome to the Targa Resources’ Third Quarter 2014 Earnings Webcast and Presentation. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. (Operator instructions) I would now like to turn the call over to Chris McEwan.

Thank you, operator. I'd like to welcome everyone to our third quarter 2014 investor call for both Targa Resources Corp. and Targa Resources Partners LP. 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 or the Partnership, have published their joint earnings release, which is available on our website www.targaresources.com. We will also be posting an updated investor presentation to the website later today. 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 the Q&A. Joe Bob and Matt are going to be comparing the third quarter 2014 results to prior period results as well as providing additional color on our results, business performance and other matters of interest. I would like to remind you that any statements made during this call that might 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 10-K for the year ended December 31, 2013 and quarterly reports on Form 10-Q. With that, I will turn it over to Joe Bob.

Thanks, Chris. Welcome and thanks to everyone for joining. Following our customary format, I'll start off with a high level review of our third quarter 2014 performance highlights. Then Matt will review the Partnership's consolidated financial results, segment results and other financial matters for the Partnership. He'll also cover key financial matters related to Targa Resources Corp. following Matt's comments, I'll provide some concluding remarks, then we'll take your questions. Obviously, we've had some important announcements since last quarter, including TRP's execution of a definitive agreement to acquire Atlas Energy L.P., and TRP's execution of a definitive agreement to acquire Atlas Pipeline Partners, L.P., also our successful completion of an $800 million 4.125% senior notes offering. Although Matt will discuss the senior notes offering in more detail, I want to say that the enormous demand that we saw for the new issue and year-to-date record yield for a callable high yield note is reflective of the confidence that the debt markets have in the Targa story. And also, I want to point to our press release announcing Board approval for two additional processing plants, one in the Delaware Basin and one in the Williston Basin. Because this is our first public opportunity to really discuss the new processing plants, I want to provide some additional color on the new plants during my concluding remarks. Now the primary focus of this call is third quarter performance, but I will provide a brief update on the Atlas transaction here in the introduction. We completed and submitted our initial HSR filings on October 24th and I am very happy to report that this morning we received verbal notice that we have received early termination, so very good job for those people who worked on that filing. We expect to file our proxy at…

Thanks, Joe Bob. I'd like to add my welcome and thank you for joining our call today. As mentioned, adjusted EBITDA for the quarter was $247 million compared to $156 million for the same period last year. The increase was primarily the result of higher LPG export activity and fractionation activity in our Logistics and Marketing division, a higher contribution from Badlands and record natural gas inlet volumes and gross NGL production in our Field Gathering and Processing segment. Overall, operating margin increased 48% for the third quarter compared to the same time period last year. And I will review the drivers of this performance in the segment reviews. Net maintenance capital expenditures were $20 million in the third quarter of 2014 compared to 16 million in the third quarter of 2013. Based on the year-to-date spending, we’re updating our 2014 net maintenance CapEx to be about 80 million for the full year. Turning to the segment level, I’ll summarize the third quarter's performance on a year-over-year basis and we will start with our Gathering and Processing segment. Field Gathering and Processing operating margin increased by 39% compared to last year driven by higher natural gas inlet volumes, higher crude oil gathering volumes and higher gross NGL production. Third quarter 2014 natural gas plant inlet volumes for the Field G&P segment were 953 million cubic feet per day, an 18% increase compared to the same period in 2013. The overall increase in natural gas inlet volumes was due to increases in all the field business units, 149% at Badlands, 26% at SAOU, 16% in North Texas, 9% at Sand Hills and 8% at Versado. We benefited from full quarter contributions from our plants completed in the second quarter, the High Plains plant in the Permian and the Longhorn plant in…

Thank you, Matt. Certainly a very good quarter. We are now more than 80% through the year and we have demonstrated strong reported performance through three quarters. We expect this performance record to continue through the fourth quarter and beyond. We continue to benefit as our attractive organic growth projects come online and contribute to EBITDA. At the beginning of the third quarter we completed Phase 2 of our international export expansion. And as Matt said, we also had full quarter contributions from our Longhorn and High Plains G&P projects. We were able to export 6.3 million barrels per month during the third quarter. I am very proud of our ability to increase our export service capabilities beginning first with butanes and HD5, then with the construction and ramp up of Phase 1 which started up only a little over a year ago and then incorporating each phase of the second expansion throughout 2014. Our ability to export propane and butane has exceeded our expectations year-to-date and is a testament to Targa’s employees doing a great job in many areas, including engineering, project management, operations, trading and marketing, logistics management and customer service. We continue to see a lot of demand for our propane and butane export services and we’re continuing to add contracts and contract link. We are also pursuing export opportunities for ethane. The market is continuing to develop as evidenced by a variety of announcements including companies building ships to service the expected market need. We have a viable ethane export project and continue to have high interest and discussions with a variety of customers. Our strong quarterly performance in our Field G&P segment is indicative of continued high levels of producer activity around our areas of operation supported by the capacity additions of our High Plains…

(Operator Instructions) The first question comes from Brad Olsen from TBH.

I had a question really kind of on the competitive dynamic along that you’ve been Ship Channel obviously we’ve seen one of your larger competitors buy out one of the larger lessors of acreage along the Ship Channel. And I was really just curious if you believe that consolidation is going to have any impact on Targa’s plans to potentially participate in ethane or condensate exports around the Ship Channel going forward?

I didn’t find that a particularly surprising deal and I don’t think that those in the industry did either, good deal for them but I don’t see it impacting the competitiveness of the Houston Ship Channel for propane, ethane, LPG, butane exports.

And so I guess there have been rumblings out of the producer community that it felt as though it’s putting a lot of export capacity in the hands of one party. But your thought is that it doesn’t effectively change the competitive dynamic and that there is kind of sufficient competition to keep a robust competitive atmosphere in that area?

I think the two competitors performing that export service are pretty darn competitive.

I realize that you guys did give quite a bit of color around both the Badlands expansion and the Delaware Basin plant. I just wanted to see if I could dig a little bit deeper and maybe just kind of get a qualitative understanding of the agreements or the producer requests that led to the announcement of those plants. Was it producers in those respective areas contacting you about a shortage of processing capacity, were they plants that you’ve been working on for a certain period of time? And I guess really I understand that you guys are very low in the kind of North American cost curve in terms of where rigs are going to continue to operate. But just trying to understand better, are these plants going to be servicing volumes that are going to be generated by kind of a flat rig count or are these plants anticipating an increase in rig count in their respective acreage dedications, if you could provide a little bit of color around that.

Sure, let me separate them for a little bit more color for you. Starting with the Permian, we’ve been working on a project like that project for some time as almost everybody knows Sand Hills was full. And we look towards helping Sand Hills we first created the Midland pipeline and are processing gas for the Sand Hills system over at SAOU at our High Plains plant, that allows us to continue the contract but ultimately that’s a short-term solution because of the growth at SAOU. The plant on the Western side of the Sand Hills system allows us to better access it hydraulically puts us in a superior position for serving the far Western high development area. I think one time we said publicly there is no doubt we’re going to put a plan out there, it’s just a question of whether the 200 million a day or 300 million a day plant economies of scale to get between the 200 and 300 are not much and that shows our strong belief of the continued long-term development potential in the area. It will be serving both dedicated acreage for existing customers and contracts that we’re currently working on, but we feel very good about the potential for that plant. You go to North Dakota and that new facility also a little bit upsize due to economies of scale is just trying to keep up with our existing customers and existing dedications and their oil wells being much better than original it’s been reasonably anticipated and more gas from those oil wells than even recently anticipated. When you think of that is really serving just our existing customers. So little bit different, do not require increases in rig counts, think of it as benefiting from existing levels of rig counts and benefiting even more so if rig counts increase in the area.

And you mentioned that the returns are attractive and I assume that’s kind of in line with your historical 5 to 7 times guidance on the G&P investments you make?

I understand, yes I did say attractive and I said even more so in North Dakota without pointing to the 5 to 7 times which is kind of a narrow band I would say it falls on the more attractive side of historical.

The next question comes from Schneur Gershuni from UBS.

See a couple of quick questions here. In your concluding remarks you sort of talked about potential for shifting economics to be potentially a beneficial outcome for you, kind of given how the producers could change their footprints with respect to the declining environment. I was wondering if you sort of step back and think about your pro forma footprint. Kind of what percentage of your geographic footprint benefits versus the areas, just wondering if you could just sort of can expand on that a little bit?

We are in the two best oil basins in the United States. And maybe not in the perfect sweet spot in North Dakota but we’re in one of the sweet spots in North Dakota. In the Permian Basin we currently have three attractive footprints within the Permian Basin that benefit from some of the most active and I guess you’d have to therefore assume most economic for producer’s portions of the Permian Basin. That certainly is, Brad calls it the cost curve. Yes, relative to the producers cost curve that’s a good place to be. And North Texas system has continued to have more focus; these are I guess producers without a Permian footprint more focused development but volumes have been increasing there. When we first brought up the new plant we actually were able to turn down one of the trains at the Chico facility to test it out. We now have both trains at the Chico facility running as well as the new plant and we’re at kind of high percentage utilization. So volumes are increasing in North Texas, it’s not as attractive on the cost curve as those areas of the Permian Basin, but it’s still increasing volumes. For field GMP North Dakota, Permian Basin and North Texas it’s hard to point to where you would rather be. So I think you benefit from those positions.

So it’s fair to conclude that basically a majority of your pro forma with Atlas assets are basically kind of where the producers will ultimately end up and are less likely. So is that fair to conclude from those comments?

I wasn’t addressing the Atlas assets and I point you back to what we said about leading basin positions and leading positions within those basins pro forma for Targa in our comments at the time. And I don’t feel any differently about it today.

As a follow up question you mentioned the ethane export potential. Does the recent change in global oil prices in Naphtha and how we think about ethylene margins so forth? Does that change the conversation or does the fact that ethane just continues to collapse, kind of continue to support an ongoing dialog. I was wondering if you can sort of give us a little clue into the mindset of who the potential shippers would be?

It doesn’t appear to have changed the dialog.

And then one final just clarification, these sensitivities you gave earlier in the call with respect to commodity pricing that was for standalone Targa that does not include in pro forma Atlas. Correct?

Correct.

The next question comes from Darren Horowitz from Raymond James.

Joe Bob, just a quick question on refined product export. Obviously the Patriot Terminal has got good proximity and some flexibility for that just based on the producing fields. And we’ve heard some announcements recently from competitors. I am just curious has the level of interest with regard to the discussions that you guys are having increased significantly? Whether or not it’s gas oil or naphtha or even more aggressively refined products? I would imagine that could be a big opportunity for you and a nice piece of vertical integration to bolt onto this system.

Interest in dealing with exportable condensate.

Sure, or further refined products.

Yes condensate through splitters and other refined products is pretty high. Lots of people are trying to impact the rules and influence the rules over time. We have some well positioned facilities on the East Coast, the West Coast and the South Coast that maybe working on those projects in the future.

And then follow up question, just with regards to your comments around propane and butane exports across your existing docks. Is there any consideration at this point for additional products possibly propylene, isobutylene? Do you think there is an arb between normal and isobutene and we could see some of that? I am just curious to how you see the evolution of those assets over the next 12 to 18 months with all the commodity price volatility that we’re seeing?

Our Galena Park facility is pretty well committed for butane, propane and potentially ethane. We do small amounts of cargos, ethylene for example from there as well. I don’t see a major ramp up on the other products in the near-term. However, we’ve got other facilities that can’t be entertaining such possibilities.

We’ll move on to the next from John Edwards from Credit Suisse.

Just appreciate some of the color you’re providing on the impact of commodity prices. I’m just curious diving a little deeper there, how say you’re seeing that perhaps impacting your opportunity set or if you’re seeing say a shift in that opportunity set at all? And if you can maybe comment a little bit regarding that sensitivity perhaps.

We aren’t yet seeing a shift in our opportunity set, I think all customers are being thoughtful and cautious but interest is still high in those development projects that you have visibility on.

So you’re not seeing any decreases, sounds like you’re not really seeing any increases either. Is that fair to say?

I think that’s fair to say, the interest remains about the same, people are being thoughtful and cautious and this is a recent short-term move that’s being digested by those customers. Comments I made about producing customers or probably similar to the way downstream customers are thinking about it.

And then on the new plants you’re announcing, are those 100% fee based?

The new North Dakota plant is 100% fee based; the new Permian West Texas plant will have a mix of field POP and fee based. Our existing customers will be POP; new customers will probably be a mix of POP and fee based.

Can you talk about kind of what the percentage mix is there?

No.

The next question comes from Jerren Holder from Goldman Sachs.

Just wanted to start off with I guess LPG exports and obviously throughout this year you guys have benefit a lot from the short-term or spot contracts. What are some of your expectations I guess going forward just given the lower commodity prices, more volatile environment, your recent expansion online which are back by long-term contracts? And then maybe some of the competitor expansions that are scheduled to come online as early as the first quarter of next year and throughout 2015?

Two or three quarters performance has been very strong and pretty far end of the fourth quarter and know that the fourth quarter will be a well performing export performance as well. I expect that performance to continue into 2015. The tendency for analyst to look at the visible arb and quite volumes to that arb is not showing a strong correlation during times when the arbitrage has gotten more narrow, we’ve added contracted cargoes, and we’ve added shorter term contracted to cargoes in the third quarter, and I can say that for the fourth quarter and the first quarter as well. Despite what seems to be a smaller arb as published or discussed due recognize that you don’t have all the moving pieces on what’s an economic transaction. There is term transportation for example; it may be at a lower price than spot transportation. Needs of term market probably means that they need to go ahead and get supply. And then you have an advantage position of our facilities on the U.S. Gulf Coast relative to Latin America and the Caribbean and the transportation cost term transportation costs or spot transportation costs were significantly lower to those markets. I expect that those dynamics don’t look a whole lot different in ‘14 than they do in ‘15, demand and interest remain high.

And then again maybe switching to the Bakken, obviously there is concern the lower oil prices and I recognize that McKenzie County is one of the core areas of the Bakken. But I guess can you maybe touch on just what the current natural gas flaring opportunity is there that would probably support some of the projects that you’ve laid out?

My existing customers would probably say that they wish that the plant that’s coming on by the end of this year was owned faster. The plant we’re done to try to have on by the end of next year is highly needed. We’re trying to do everything we can to work on the flaring, fact is the oil wells are better and there is more gas from those oil wells than people originally anticipated. So I think of it as an opportunity and a task to get our arms around the flaring issue.

The next question comes from Danilo Juvane from BMO Capital.

As a follow-up to the LPG export question, is there a way that we can think about sort of the weighted average down track length that you have on those facilities inclusive of the expansion that just came online?

We made some announcements in the second quarter and all we’ve said since then is, more term and more contracts.

Is there a sort of percentage of total capacity that we can sort of…

These contracts are multi-year contracts; some of them go up to five years or so and even beyond. It's a mix, but these are multi-year contracts.

And I am showing no further questions. I would now like to turn the call back over to Joe Bob.

Thank you operator. Thank you to everybody for your interest. Please feel free to contact any of us, if you have further questions and have a good day.

Ladies and gentlemen that does conclude the conference for today. Again thank you for your participation. You may all disconnect. Have a good day.