Targa Resources Corp (TRGP) 2014 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Targa Resources Corporation third-quarter 2014 earnings webcast and presentation.

(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 Corporation Corp. and Targa Resources Corporation Partners LP.

Before we get started, I would like to mention that Targa Resources Corporation Corp., TRC or the Company, and Targa Resources Corporation Partners LP, Targa Resources Corporation 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, its segment results, and other financial matters for the Partnership. He'll also cover key financial matters related to Targa Resources Corporation 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 TRC's execution of a definitive agreement to acquire Atlas Energy LP and TRP's execution of a definitive agreement to acquire Atlas Pipeline Partners LP; also, our successful completion of an $800-million 4 1/8% 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 low 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 24, and I am very happy to report that this morning we received verbal notice that we have received early termination. It's a very good job for those people who worked on that filing. We expect to file our proxy at TRC soon, perhaps within a couple of weeks from now, and we continue to expect the transaction to close in the first quarter of 2015. As we said on the day of the announcement, we are very enthusiastic about this strategic transaction, and continue to believe that is a great deal that benefits all equity holders.

We understand and appreciate your interest and natural questions on the topic, but for additional information on the transaction, we need to point you back to our transaction announcement presentation and to a replay of that conference call. Both of those are available on our website. And we can point you forward to the public document soon to be filed with the SEC that will contain additional information, including financial outlook information. Now, that wraps up all that we plan to say about the Atlas transaction.

So, let's turn now to third-quarter performance highlights. It was a very good quarter. Our reported third-quarter adjusted EBITDA of $247 million was 58% higher compared to $156 million for the third quarter of last year. The logistics and marketing division operating margin was 75% higher, and the field G&P segment operating margin was 39% higher than the third quarter of 2013. The logistics and marketing division produced quarterly operating margin of $180 million, primarily driven by higher LPG export activity and higher fractionation activity.

The last piece of the phase 2 expansion was the addition of another de-ethanizer at Mont Belvieu, which we completed in early September. Our other phase 2 capabilities, including pipeline, dock, and additional refrigeration, were added earlier in 2014. The added capabilities from our project helped drive record LPG export volumes, which were 273% higher than the third quarter of 2013. As you probably recall, phase 1 of our international export project began loading a few test ships with low-ethane propane for the first time in September of 2013.

The margin increase in field gathering and processing was primarily driven by: significant contribution increases from Badlands compared to the third quarter of 2013; experiencing large increases in both crude gathered, and natural gas gathered and processed; and the margin increase was also driven by higher natural gas inlet volumes across all of our other field systems. Our distributable cash flow for the quarter of $193 million resulted in distribution coverage of approximately 1.5 times, based on our third-quarter declared distribution of $0.7975, or $3.19 on an annual basis. The Partnership's third-quarter distribution represents a 9% increase compared to the third quarter of 2013. If we look at the TRC level, the third-quarter dividend of $0.7325, or $2.93 annualized, represents a 29% increase compared to the third quarter of 2013.

Now, that wraps up my initial comments, and I'll hand it over to Matt.

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 2014 compared to $16 million in the third quarter of 2013. Based on the year-to-date spending, we are 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'll start with our gathering and processing segments. 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 at 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 North Texas.

Crude oil gathered increased to 99,000 barrels per day in the third quarter, an 89% increase versus the same time period last year, highlighting our continued progress in North Dakota. For the field gathering and processing segment, natural gas prices increased 14%, while condensate prices decreased 17% and NGL prices decreased 4% in the third-quarter 2014 compared to 2013.

Turning now to the coastal gathering and processing segment: Operating margin decreased 9% in the third quarter compared to the same time period last year, primarily driven by lower throughput volumes at LOU and the Coastal Straddles. For this segment, natural gas prices increased by 12%, and NGL prices were flat compared to the third quarter of 2013.

Next, I will provide an overview of the two downstream segments, starting with the logistics asset segment. Third-quarter operating margin increased 68% compared to the third quarter of 2013, driven by higher LPG export and fractionation activity. For the quarter, we loaded an average of 6.3 million barrels per month of LPG exports, benefiting from previous completion of aspects of our phase 2 export expansion, plus completion of the final piece of the expansion completed in early September, and from continued high international demand for propane and butane.

Fractionation volumes increased 16% versus the same time period last year, driven by a full quarter for CBF train 4, which was still ramping up during the third quarter of 2013. In the marketing and distribution segment, operating margin for the segment increased 90% over the third-quarter 2013, due primarily to higher LPG export activity.

With that, let's now move to capital structure, liquidity, and other matters. As of September 30, we had $575 million of outstanding borrowings under the Partnership's $1.2-billion senior secured revolving credit facility due 2017. With outstanding letters of credit of $42 million, revolver availability was $583 million at quarter end. Total liquidity, including approximately $72 million of cash on hand, was about $655 million. At quarter end, we had borrowings of $238 million under our $300-million accounts receivable securitization facility.

Through September, we received approximately $257 million of net proceeds from the at-the-market equity issuances, which we continue to be very pleased with the success of this program. Although we may take advantage of other equity offering sources, we expect to continue to use this program to meet our equity needs. Total funded debt on September 30 was approximately $3 billion, or about 55% of total capitalization, and our third-quarter compliance debt-to-EBITDA ratio was 2.7 times.

On October 23, we priced $800 million of senior unsecured notes due in November 2019 at par to yield 4 1/8%. We used the net proceeds to reduce borrowings under our senior secured credit facility, and reduce borrowings under our accounts receivable securitization facility. After giving effect to the offering, our pro forma liquidity as of September 30 was approximately $1.5 billion.

Since the closing of the notes offering, we have issued a redemption notice for the $250 million of outstanding principal amount of our 7 7/8% notes; the total cost of the redemption is approximately $260 million. As Joe Bob mentioned, we are very proud of the issuance, as our notes are the lowest yielding callable bond issued in the high-yield market this year, and among the lowest in the history of the non-investment-grade market.

For the third quarter of 2014, our operating margin was approximately 72% fee based. Based on current hedges in place, including some entered into since the end of Q3, we estimate that we have now hedged approximately 50% to 60% of our current natural gas equity volumes for 2015, and approximately 20% to 30% for 2016. If we have significant ethane rejection for those years, we will be towards the bottom of those ranges. For condensate, we have hedged approximately 45% to 55% of the current equity volumes for 2015, and approximately 25% to 35% for 2016.

With this hedge position and our large, fee-based operating margin contribution, Targa is well positioned for near-term commodity price weakness, and we estimate the following sensitivities for Targa's 2015 EBITDA relative to current prices. A $5 drop in crude price would decrease EBITDA by approximately $3 million for full year of 2015. A $0.05 drop in the weighted average NGL price would result in approximate $12-million reduction in EBITDA for 2015. And a $0.25 drop in natural gas price would result in an approximate $5-million decrease in EBITDA for 2015.

So, now, moving on to capital spending: We continue to estimate approximately $780 million of growth capital expenditures in 2014.

So, now, turning over to Targa Resources Corp., I'll make a few brief remarks about the results of TRC. Targa Resources Corp. stand-alone distributable cash flow for the third-quarter 2014 was $31 million, and TRC declared approximately $31 million in dividends for the quarter. TRC declared a cash dividend of $0.7325 per common share, or $2.93 per common share on an annualized basis, representing an approximately 29% increase over the annualized rate paid with respect to the third quarter of 2013. As of September 30, TRC had $92 million in borrowings outstanding under its $150-million senior secured credit facility, and $6 million in cash, resulting in total liquidity of approximately $64 million.

That concludes my review. And I'll now turn the call back over to Joe Bob.

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 and Longhorn plants. Although there has been considerable discussion about the decrease in crude prices over the last month or two, and we are certainly watching prices, and investor research and media reports about the impacts, just as all of you are, we are also reminded that Targa is very well positioned to handle lower prices with resilience, given our strong financial position and given locations in the best oil basins and premier liquids-rich gas gathering basins in the country. That is also the case, pro forma, for the Atlas transaction.

We are also in consistent dialogue with our producer customers on their expectations for forward rig activity, expected future wells drilled, and resulting volumes, which we use with some natural conservatism to develop our own forecast for activity and volume growth. What we hear from them: Producers are, of course, being cautious and thoughtful relative to current price levels and the recent fall. Some have said that they couldn't slow down immediately due to rig, sand supply, and other commitments.

Others have said that they expect to maintain current levels of activity, but may not increase those activity levels as much as recently planned. Some have said that they are moving rigs from one basin to another due to better economics. That is usually to our advantage, sitting in the best basins, and some of the best parts of the best basins.

So far, we haven't really seen any slowing down. We anticipate that with lower-than-anticipated prices, producer cash flow relative to their leverage may impact activity for some producers in some areas. And, of course, we have all read articles about, and seen previous evidence of, how producers will use any slowdown to extract mitigating cost reductions from their service providers. While we will obviously continue to monitor the situation, we are not currently expecting dramatic impacts to our 2015 volume outlook, either on the field G&P side or on the downstream side. And, as I said, Targa, and Targa pro forma the Atlas transaction, is well positioned to manage lower prices, given our strong financial position and given our locations in the best basins in the country.

As I mentioned at the beginning of the call, one of the exciting announcements that we made since last quarter are our additional expansion plans in the Delaware basin and the Williston Basin, two of the most economic basins for drilling in the world. These expansions were approved based on our view that activity will continue in these areas of operations near term and longer term, even in a commodity price environment similar to what we are experiencing today.

We approved construction of a new, 300-million-cubic-feet-per-day cryogenic processing plant, a header pipeline originating at the new plant into the heart of the southern portion of the Delaware basin, and related gathering compression infrastructure. That new plant will be located in Winkler County, Texas, west of our existing Sand Hills gas processing plant, to provide additional midstream services to producers on the western side of the Permian Basin. The size is indicative of our view of the potential for additional captured volumes in the area, and we have engineered it such that we benefit from plant economies of scale while still having relatively efficient lower volume start-up capability.

The addition of the plant will increase our stand-alone Permian Basin capacity to a total gross capacity of nearly 1.1 billion cubic feet per day. It expands the capacity for the Sand Hills system, and, to some extent, increases future capacity for the interconnected SAOU system, which is currently processing Sand Hills volumes coming across our Midland County pipeline.

The new processing plant in the Delaware basin is expected to be operational at the end of the first-quarter 2016. We're thinking about calling it the Joyce Johnson plant; we got to get permission first.

In the Williston Basin, we expect our 40-million-cubic-feet-per-day Little Missouri Train 3 expansion to be completed by the end of 2014, and in service early January, subject to the completion of ONEOK's 8-inch NGL pipeline, which may be delayed until the first part of 2015, though we know they're working very hard on it. We also approved the purchase of a 200-million-cubic-feet-per-day cryogenic processing plant that will also be located in McKenzie County, and will increase our total effective processing capacity to approximately 300 million cubic feet per day.

Producers continue to improve their performance in the Williston Basin, and in our part of the Williston Basin, with better oil wells and even more gas being produced than we expected only one or two years ago. We're continuing to work together to reduce the amount of natural gas being flared in North Dakota. The additional Badlands plant is expected to be operational as early as the end of 2015 or perhaps early 2016. Understanding that many of you are focused on the incremental CapEx of the two new plants and their related infrastructure investments, I would say that, although preliminary, the total incremental CapEx over time for the two is somewhere around $600 million, and the expected returns are attractive, especially in the Badlands.

Regarding some of our other major announced growth projects, train 5 remains on track to be completed in mid-2016, and we have filed the air permit for the condensate splitter project at our Channelview terminal. As for a completion timing on that project, we expect end of 2016, perhaps beginning of 2017, depending on the permitting timing.

Customer interest and demand for additional midstream infrastructure remains strong. We continue to make progress on the $2 billion of projects that we have shown currently under development. So, we've certainly had a busy third quarter, and our forward-looking plates appear as full as our plates of the recent past.

Before we open up the line to questions, I get to take this opportunity to thank our employees for another great quarter performance. We are continuing to safely and effectively execute on our daily operations and commercial activities, despite very high activity levels. And I'm proud of the continued excellent service that our customers are receiving.

With that, let's open up the line to questions, please, operator.

(Operator Instructions)

Brad Olsen from TPH.

Good morning, everyone. I had a question, really kind of on the competitive dynamic along the Houston ship channel. Obviously, we've seen one of your larger competitors buy out one of the larger lessors of acreage along the ship channel. I was really just curious if you believe that, 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.

Got it. 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's sufficient competition to keep everyone -- to keep a robust competitive atmosphere in that area?

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

Got it. That's helpful. 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 request 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 had been working on for a certain period of time?

And I guess, really, I understand that you guys are very low in the 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, that project for some time as most everybody knows Sandhills was full. Look towards helping Sandhills, we first created the Midland pipeline in our processing gas for the Sandhills system over at SAOU at our High Plains plant. That allows us to continue to contract, but ultimately that's a short-term solution because of the growth at SAOU. The plant on the western side of the system -- the Sandhills system, allows us to better access and hydraulically puts us in a superior position for serving the far western high-development area.

I think one time we said publicly we were wondering, but there was no doubt we were going to put a plant out there, it was just a question of whether it would be a 200-million-a-day or 300-million-a-day plant. The 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 upsized 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 originally -- than recently anticipated and more gas from those oil wells than even recently anticipated. You can think of that as really sort of being just our existing customers. So, a little bit different. Do not require increases in rig counts. Think of it as benefiting from existing levels of rig counts and it benefiting even more so if rig counts increase in the area.

That's really helpful. 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.

That's great. Thanks for all of the color, Joe Bob.

You're welcome.

Shneur Gershuni from UBS.

A couple of quick questions here. In your concluding remarks, you sort of talked about the potential for shifting economics to be a potentially beneficial outcome for you, given how the producers could change their footprints with respect to the commodity environment. I was wondering if you sort of sit back and think about your pro forma footprint, what percentage of your geographic footprint benefits versus areas that are at risk? I was wondering if you could just sort of 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 producers, portions of the Permian Basin. That certainly is -- Brad called it the cost curve. Yes, relative to the producer's cost curve, that's a good place to be.

Our 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 in the Permian Basin, but it's still increasing volumes. For field G&P, 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, we are the producers, we'll ultimately end up, and are less likely at risk. Is that fair to conclude from those comments?

I wasn't addressing the Atlas assets. Kind of 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.

Great. As a follow-up question, you mentioned ethane export potential. Does the recent change in global oil prices and [naphtha], and then how we think about ethylene margins and so forth, does that change the conversation at all? Or does the fact that ethane just continues to collapse kind of continue to support an ongoing dialogue? 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 dialogue.

Great. And then, one final just clarification. The sensitivities you gave earlier in the call with respect to commodity pricing, that was for standalone Targa, that did not include a pro forma Atlas, correct?

Correct.

Perfect. Thank you very much, guys. Appreciate the color.

Thank you.

Darren Horowitz from Raymond James.

Good morning, guys. Joe Bob, just a quick question on refined product export. Obviously, the Patriot terminal's got good proximity and some flexibility for that just based on the producing fields, and we've heard some announcements recently from competitors. I'm 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 the system.

Interest in dealing with exportable condensate?

Sure. Or further refined products.

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 may be working on those projects in the future.

Okay. 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's an arb between normal and isobutane, and we could see some of that? I'm 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 cargoes -- 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 be entertaining such possibilities.

Okay. Thank you.

Sachin Shah from Albert Fried.

Good morning.

Good morning.

(Operator Instructions)

John Edwards from Credit Suisse.

Good morning, everybody. I appreciate some of the color you're providing on the impact of commodity prices. I'm just curious, delving 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, if you could 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.

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

I think that's fair to say. 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 are probably similar to the way downstream customers are thinking about it.

Okay. That's helpful. And then, on the new plants you are announcing, are those 100% fee based?

The new North Dakota plant is100% fee based. The new Permian West Texas plant will have a mix of POP and fee based. Our existing customers will be POP. New customers will probably be a mix of POP and fee based.

Okay. Can you (technical difficulty) the percentage mixes there?

No.

(laughter) Okay. All right. Fair enough. That's all I had. Thank you very much.

Jerren Holder from Goldman Sachs.

Good morning. I just wanted to start off with, I guess, LPG exports and, obviously, throughout this year you guys have benefited 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 backed 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?

Okay. Through three quarters, performance has been very strong. We're pretty far into the fourth quarter and know that fourth quarter will be a well-performing export performance as well. I expect that performance to continue into 2015. The tendency for analysts to look at the visible arb and equate volumes to that arb is not showing a strong correlation.

During times when the arbitrage has gotten more narrow, we have added contracted cargoes and we've added shorter-term contracted 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. Do recognize that you don't have all the moving pieces on what's an economic transaction. There's 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.

So -- and then you have an advantage position of our facilities on the US Gulf Coast relative to Latin America and the Caribbean, and their transportation costs. Term transportation costs or spot transportation costs are significantly lower to those markets. I expect that those dynamics don't look a whole lot different in 2014 than they do in 2015. Demand and interest remain high.

Thank you. That's very helpful. Maybe switching to the Bakken. Obviously there's concern with the lower oil prices, and I recognize that McKenzie County is one of the core areas of the Bakken, but I guess can you just 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 on faster. The plant we're going 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. The fact is the oil wells are better and there's 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.

Okay. Thank you.

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 contract link that you have on those facilities, inclusive of the expansions 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.

Some of them go beyond that.

And beyond. It's a mix, but these are multi-year contracts.

Okay. I appreciate that. That's it for me. Thank you.

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.