Plains All American Pipeline LP (PAA) 2014 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to PAA and PAGP second-quarter results conference call.

(Operator Instructions)

As a reminder, today's teleconference is being recorded. At this time, I will turn the conference call over to your host, Director of Investor Relations, Mr. Ryan Smith. Please go ahead, sir.

Thanks, Tony. Good morning and welcome to Plains All American Pipeline second-quarter 2014 results conference call. The slide presentation for today's call is available under the events and presentations tab of the Investor Relations section of our website at www.plainsallamerican.com. In addition to reviewing recent results, we will provide forward-looking comments on PAA's outlook for the future.

In order to avail ourselves of Safe Harbor precepts and encourage companies to provide this type of information, we direct you to the risks and warnings included in our latest filings with the Securities and Exchange Commission. Today's presentation will also include references to non-GAAP financial measures, such as adjusted EBITDA.

A reconciliation of these non-GAAP financial measures to the most comparable GAAP financial measure can be found under the guidance and non-GAAP reconciliations tab of the investor relations sections of our website. There you will also find a table of selected items that impact the comparability of PAA's financial information between periods. Today's presentation will also include selected financial information of Plain's GP Holdings, or PAGP.

As the control entity of PAA, PAGP consolidates the results of PAA and PAA's general partner into its financial statements. Accordingly, we do not intend to cover PAGP's GAAP results. Instead we have included a schedule in the appendix to be a slide presentation for today's call that reconciles PAGP's distributions received from PAA's general partner, with the distributions paid to PAGP shareholders, as well as a condensed, consolidated balance sheet.

Today's call will be chaired by Greg Armstrong, Chairman & CEO, also participating in the call are Harry Pefanis, President & COO, and Al Swanson, Executive Vice President & CFO. In addition to these gentlemen and myself, we have several other members of our management team present and available for the question-and-answer session. With that I'll turn the call over to Greg.

Thanks, Ryan. Good morning to everyone. Yesterday afternoon PAA reported its second-quarter 2014 results. Second quarter adjusted EBITDA totaled $512 million. These results were $57 million or 13% above the midpoint of our guidance for the second quarter of 2014, and also slightly above the increased performance expectations we provided on June 4, just prior to our analyst day presentation.

Harry will provide a detailed comparison to guidance for each of our segments later in the call, however, I would generally characterize our second quarter results as solid, particularly in our transportation and supply and logistics segments. Slide 3 contains comparisons to last year's second quarter results for adjusted EBITDA, implied DCF and distribution coverage, and adjusted net income per diluted unit.

The quarter-over-quarter increase in adjusted EBITDA is composed of a 15% increase in PAA's fee based segments primarily as a result of continued expansion capital investments and a 6% decrease in the supply and logistics segment. As expected, our quarter-over-quarter our supply and logistics results decreased primarily due to less favorable NGL market conditions compared to the second quarter of 2013, partially offset by improved crude oil market conditions in certain areas.

As reflected on slide 4, this quarter's results mark the 50th consecutive quarter that PAA has delivered results in line with or above guidance. Additionally, for the second quarter of 2014, PAA declared a distribution of $0.645 per common unit, or $2.58 per unit on an annualized basis, payable next week. This distribution represents a 9.8% increase over PAA's distribution paid in August 2013, and a 2.4% increase over PAA's distribution paid in May 2014.

Distribution coverage for the quarter was 107%. PAA has increased its distribution in 39 out of the past 41 quarters, and consecutively in each of the last 20 quarters. PAA's compound annual distribution growth rate averaged 8.4% over the last 10.5 years, and 9.5% for the last three years.

Additionally, PAGP's quarterly distribution of $0.1834 per share represents a 7.5% increase over the distribution paid in May 2014, and a 23.1% increase over the initial quarterly distribution included in PAGP's October 2013 IPO prospectus. PAA continues to execute well and we are on track to meet or exceed our 2014 goals while positioning PAA favorably for 2015 and beyond.

During the remainder of today's call we will discuss specifics of PAA's segment performance relative to guidance, our expansion capital program, our financial position and the major drivers and assumptions supporting PAA's financial and operating guidance. At the end of the call I will provide a recap, as well as a few comments regarding our outlook for the future. With that, I'll turn the call over to Harry.

Thank you, Greg. During my portion of the call, I'll review our second-quarter operating results compared to the midpoint of our guidance, discuss the operational assumptions used to generate our third quarter guidance and provide an update on our 2014 capital program. As shown on slide 5, adjusted segment profit for the transportation segment was $229 million, which was approximately $24 million above the midpoint of our guidance.

Our volumes of 3.9 million barrels per day were largely in line with the midpoint of our guidance. Our adjusted segment profit per barrel was $0.64 or $0.07 above the midpoint of our guidance. The higher than forecasted segment profit was primarily driven by higher than anticipated pipeline loss allowance barrels and component gains on our NGL pipelines, plus less than forecasted seasonal flooding downtime on certain of our Canadian pipelines, and lower operating expenses primarily due to the timing of some of our integrity management projects.

Adjusted segment profits for the facilities segment was $138 million, which was in line with the midpoint of our guidance. Volumes of 120 millions barrels of oil equivalent per month were 2 million barrels below the midpoint of our guidance. However, adjusted segment profit was $0.38 or $0.01 above the midpoint of our guidance.

Our rail volumes were lower than expected, primarily due to lower third party volumes moving towards St. James Terminal and longer transit times on rail movements due to rail congestion. In addition, NGL fractionation volumes were a little lower than forecasted, primarily due to upstream pipeline constraints related to supply into our Sarnia facility. Adjusted segment profits for the supply and logistics segment was $144 million, or approximately $30 million higher than the midpoint of our guidance.

Volumes of approximately 1.1 million barrels per day were in line with the midpoint of our guidance. Adjusted segment profit per barrel was $1.48 or $0.31 above the midpoint of our guidance. Overperformance was primarily due to crude oil differentials in Canada and the US that were more favorable than forecasted, however, this was partially offset by weaker margins in our NGL sales activities.

Let me now move to slide 6 and review the operational assumptions used to generate our third-quarter 2014 guidance furnished yesterday. For our transportation segment, we expect volumes to average approximately 4.1 million barrels per day. And that's about 200,000 barrels a day higher than the volumes in the second quarter.

The volume increase is spread out across all the major resource plays. Volumes are forecasted to be up approximately 40,000 barrels per day in the Permian, and that includes our Basin and Mesa volumes. Up about 20,000 a day in both the Eagle Ford and the Midcontinent, and up about 10,000 in the Bakkan and our Salt Lake City area pipelines and our pipelines from the San Joaquin valley to the LA Basin.

In addition, Capline is forecast to be approximately 30,000 barrels a day higher as we are through refinery turnarounds, and our Pascagoula pipeline is expected to add 30,000 barrels per day, reflecting a full quarter of operations. We expect adjusted segment profit per barrel of $0.60, which is lower in the second quarter, and while FERC tariffs will increase by 3.9% on July 1, the revenue increase will be more than offset by lower forecasted PLA volumes and higher integrity management expenses.

For our facilities segment, we expect an average capacity of 122 million barrels below equivalent, adjusted segment profit for barrels is expected to be $0.37, which is consistent with the second quarter segment profit. The slight increase in volumes as compared to the second quarter is primarily due to increased rail movement, particularly to our St. James facility. I'll also add that in general, we have tempered our outlook for rail related activities a bit relative to our forecast at the beginning of 2014, primarily due to increase in transit times.

The slight decrease in segment profit per barrel is primarily due to the expiration of a short term storage arrangement with a pipeline pending completion of their facilities and that was at a higher fee than our typical long term storage contracts. For our supply and logistics segment, we expect volumes to average approximately 1.1 million barrels per day, which is consistent with volumes in the second quarter. Adjusted segment profit per barrel is expected to be $1.14.

The decrease in the second quarter is primarily due to less favorable market conditions associated with Canadian crude oil grades. Let me now move on to our capital program. As shown on slide 7 we have increased our 2014 expansion capital by approximately $100 million to a revised target of $1.95 billion. This increase is not attributable to any single project, it's spread across a number of smaller opportunities and includes some seed capital on a couple of projects that are not yet advanced enough to discuss.

I'll note that the increase is not due to cost overruns. The expected in-service timing of our larger projects in our capital program is included on slide 8, and I'll provide a status update on a few of these investments. In June we announced a project to build two 80-mile pipelines to move production in the Peace River area in Canada to a connection to our Rainbow pipeline system at Nipisi. The pipelines include a 24-inch, 240,000 barrel per day blend line and a 12-inch, 65,000-barrel per day diluent line.

This is a $535 million project that is underpinned with an anchor shipper commitment and is currently in the permitting, right-of-way design phase. Assuming all goes well with permitting and right-of-way acquisition, we would expect the pipeline to be in service in 2017. In the Permian Basin, we think the combination of our Sunrise pipeline, which extends from Midland to Colorado City, and our new line from Monahans to McCarney, coupled with the start-up of BridgeTex and the expansion of Longhorn, should begin to de-bottleneck the Permian Basin in late 2014.

In addition, our Cactus pipeline should be in service in April 2015, which will provide an additional 200,000 barrels a day of take away capacity at that point in time. And I'll note, subject to demand and the quality of the crude movements we have the capability to add additional pump stations and expand the capacity of the Cactus line by approximately 40% to a total of 280,000 barrels per day.

In the Eagle Ford, the expansion of our joint venture pipeline from Gardendale to Three River should be completed by April 2015. In addition we're developing a terminal at Corpus Christi, which will have a dock capable of loading ocean-going vessels at a rate of 20,000 barrels per hour, and will compliment our existing barge loading facility. In California, our Bakersfield rail facility is nearing completion. We expect the facility to be in service in October of 2014. Finally, maintenance capital expenditures for the second quarter were $48 million. We expect maintenance capital expenditures for 2014 to range between $185 million and $205 million.

With that I will turn the call over to Al.

Thanks, Harry. During my portion of the call I will review our financing activities, capitalization and liquidity as well as our guidance for the third quarter and full-year of 2014. We were active during the quarter from an equity financing perspective through our continuous equity offering program.

As illustrated on slide 9, PAA sold approximately 5.3 million units in the second quarter, raising net proceeds of $302 million. Our current continuous offering program is a $750 million program initiated in May 2013 and will soon be completed. Accordingly, we intend to initiate a new program in the third quarter of 2014. As illustrated on slide 10, PAA ended the second quarter with strong capitalization, credit metrics that are favorable to our targets and $2.2 billion of committed liquidity.

At June 30, 2014, PAA had long term debt to capitalization ratio of 48%, and a long term debt to forward adjusted EBITDA ratio of 3.4 times. Slide 11 summarizes information regarding our short term debt, hedged inventory and linefill at quarter end. Moving on to PAA's guidance as summarized on slide 12, we are forecasting midpoint adjusted EBITDA of $480 million and $2.175 billion for the third quarter and full-year of 2014 respectively.

Our forecast for the midpoint adjusted EBITDA for the full-year 2014 represents an increase of $25 million. Consistent with past practice, our guidance for the third quarter only takes into account favorable market conditions to the extent that we are highly confident that our current activities will capitalize on those conditions with an assumed return to near baseline-type conditions for our supply and logistics segment for the balance of the year.

Accordingly, we continue to expect negative quarter-over-quarter and year-over-year supply and logistics segment profit comparisons in 2014 as compared to the same period in 2013 given that market conditions during 2013 were extremely favorable for our assets and business model. The $1.6 billion of investments that we made in our transportation and facilities segment in 2013, combined with our $1.95 billion 2014 capital program, will continue to provide meaningful growth in our fee-based activities into 2015 and beyond.

Furthermore, the cumulative affect of these capital investments provides us with good visibility for continued multi-year distribution growth given the time lag associated with achieving full run rate cash flows. For more detailed information on our 2014 guidance, please refer to the form 8-K furnished yesterday.

As represented on slide 13, based on the midpoint of our 2014 guidance for DCF and distributions to be paid throughout the year, our distribution coverage is forecast to be 111%, and in line with our targeted coverage of 105% to 110%. This will enable PAA to retain $152 million of excess DCF or equity capital. With that I'll turn the call back over to Greg.

Thanks, Al. The first half of 2014 has been a very active and productive period for PAA, and we are pleased with our positioning for the remainder of the year and beyond. As discussed in detail during our analyst day presentation in June, PAA's significant asset presence in substantially all the major crude oil resource plays in North America, positions PAA to meaningfully benefit from continued increases in crude oil production.

PAA's proven business model, multi-billion dollar organic project portfolio and solid capital structure, provide strong visibility for continued, attractive multi-year distribution growth, without relying on potential acquisitions. That said, we believe all these characteristics position PAA to capitalize on attractive acquisitions, especially if the industry or the capital markets weaken.

We thank you for participating in today's call and for your investment in PAA and PAGP. We are excited about our prospects for the future and look forward to updating you on our activities at our next call in November. Tony, at this point in time we're ready to open the call up for questions.

Thank you very much.

(Operator Instructions) [Steve Cherkowski, Goldman Sachs.

Hi, good morning. You've been in the news recently noting the potential need for separate infrastructure to transport condensate out of the Permian. I'd just be interested to hear your further views on that?

What we're seeing is a lot more of the Delaware Basin crude is a lot lighter than the Midland Basin crude. It is ratcheting up the gravity. And we think there could be a point in time where you see two separate streams, the condensate stream and the historical WTI type of stream. And really what we've geared Cactus up for is to be able to handle a lot of the condensate stream coming down to the Corpus Christi area.

Okay. And are there any design or other restrictions that is would limit your ability to, or how much you could batch condensate on Cactus or your other Eagle Ford pipelines?

Well, there'll be a couple different batches on the Cactus Pipeline system. We expect there's probably going to be a typical WTI type of stream, a sour stream and a condensate stream, but there is nothing that would really restrict the amount of condensate that could move down Cactus.

I might just mention, effectively I think when we're looking at potential delay dedicated condensate streams, when you have an area that needs improved infrastructure to handle volume growth, if you can add smart pipeline design to it, you can handle a combination of both increased volume and increased varieties or segregated varieties, so it's really just trying to optimize the overall growth that's probably going to happen in the area in general.

Understood. Thanks. And I'd be curious, just based on your own gathering volumes, how much of the Delaware Basin production is condensate or qualifies as condensate?

Let me tell you, right now there is a big question as what is defined as condensate right now. In general it's pretty light. What is it, John, probably 250?

Yes. (Multiple Speakers) When we ramp up, 200 to 250 when you ramp up. When we look at what we think volumes are going to look like in 2017 or 2018, we think the condensate stream could be 200,000 barrels a day plus or minus.

And that's just for the Delaware Basin.

Yes. Mostly Delaware Basin.

And a quick final question, could we just get a quick update on Bakersfield?

Should be in service by late October. (Multiple Speakers)

Okay. Thanks.

Jeremy Tonet, JPMorgan Chase & Co.

Good morning.

Good morning, Jeremy.

There is a lot of talk about project backlog in the MLP space these days it seems like. I see Plains as a very robust spending program for 2014. I am wondering, given your expansive platform, if you believe that your footprint will continue to deliver a level of organic growth spend in future years similar to the current year, any thoughts on that would be helpful?

You know, Jeremy, I guess -- and I'm going to go backwards in time so I can set the stage for my comments. We are pretty cautious about trying to overforecast what we think capital is going to be and then try to run underneath it because I think there's a tendency among human nature to want to fill the basket up once you define the size of the basket.

What we've taken the approach in the past has been, the size of our basket will be whatever is necessary to meet the needs and the attractive investment opportunity. Going back in time I think we started off a couple years ago with a target of $1 billion and we moved it up to $1.2 billion and by the time we got through it that year we were at $1.4 billion. Last year we did a similar trend and now we're up to almost $2 billion.

We provide a directional guidance on our capital program that said it'd be between $1 billion and $2 billion for the next couple of years, and then we expect to it tail off based upon what we could see at the time we were making that forecast. There's no question that the resource plays and shale plays, whatever you want to characterize them as, are robust and they're continuing to have innovations in technology and efficiencies that look like it's extending that run.

So, we haven't -- we'll provide and typically do, in our November call our preliminary guidance for not only EBIDTA but our capital program, but it's hard -- it would be hard to make an argument right now that it shouldn't be at least as robust as we have been seeing and right now we are at $1.850 billion to $2.050 billion in terms of expectations for 2014, and I promise you that' we're not slowing down any in terms of engineers and commercial guidance in terms of dealing with opportunities.

That makes sense and we do appreciate your conservative approach there.

Yes. And as Harry points out, our portfolio, we've actually put a lot of projects into service and we're still running with about a $7 billion portfolio, so that really tells you it's continuing to regenerate on its own and that's usually on account of a front-end loaded basis.

Some of the projects we're looking at right now as Harry mentioned in his comments, are becoming a little longer dated because as we finish optimizing our existing infrastructure and we're having to build incrementally new pipes, but the lead time on those pipes is still in most cases in the 18 to 24 months range. A few projects, especially up in Canada are going to be a little longer lead time just because you have to hit the seasonal windows to build.

You can't -- you don't really have a 365-day work window there. You have to catch the winters just right, so those will usually add an extra year to what would typically probably be an 18- to 24-month project in the US.

That's helpful. Thank you.

And switching gears, I was wondering if you could provide any updated thoughts on Nacka storage market. During the quarter it seems like there was some weakness in contract renewals. Just wondering if you see inflection storage rates and if so, how you trade off on a late versus duration of contracts when you are thinking about these renewals?

I would say, I don't think there has really been any major difference in the market, the contract renewals were things we saw coming. In fact, we talked about it when we were -- we talked about bringing P&G in because we felt very positive about the long term fundamentals, but we were a little bit concerned about the transition period. Nothing's really changed that outlook.

I think on the last call somebody asked the question when we thought the market would start firming up and we said two weeks prior to the call. That still feels like it's the case. In other words, we're seeing probably higher volume metric demand for storage and people are trying to look longer term. It's always a balance.

The question you asked about how long would you sign a contract for a rate that you think is probably going to be suboptimal in a couple years? And it somewhat depends on the client. If we're looking at fundamentally solid, long term dispatch-oriented type clients, we are probably more inclined to bring them in a little earlier but they tend to pay a higher price than the market arbitrageurs that right now there really isn't an arb in the market. So they're not really trying to bang on anything other than just finding the cheapest storage they can for as long as they can negotiate with.

And so, the quality of the customers in the mix is pretty important to that. We don't really put our playbook out there, but we are not having any problems having the right discussions. We think we have some of the best facilities in the business. And after last winter's challenges that hit everybody, we think ours stood out as being some of the best performing and we think that'll continue to be the case.

That is helpful. Thank you very much.

Faisal Kahn with Citigroup. Go ahead.

Just a few questions on condensate here. How much total condensate stabilization capacity do you guys have across your whole system? I think you've talked about how you have about 80,000 a day in the Eagle Ford and that's going to 120. But how much do you have across the whole system. And then how much of this capacity or volume do you think is eligible to be exported?

Have you approached the DOC or the BIS about moving those volumes, it sounds like -- you were talking about the Corpus Christi docks. I'm just trying to figure out how this is going to evolve for you?

The only real stabilization facility that we have is at Gardendale and the Eagleford. We have a couple small ones in eastern -- in the Alabama area, but not anything as substantial as far as more field stabilization facility. So the 80,000 barrels per day is what we have today. As you can imagine we have several thoughts on where potential stabilization facilities could be added in the future, but, like I said, Gardendale is probably the primary spot.

We're trying to get some clarity too on exactly what level of processing is necessary for the condensate to be excluded from the export ban. We hope to have some more clarity on that by the next call, and we are certainly positioning ourselves to be able to move condensate on our system and across our assets and into the export market if the stabilization at Gardendale is sufficient to qualify for the -- so that the condensate wouldn't be subject to the export band.

I think it's also fair, the quality of the asset that we do have is pretty high. I'd be surprised to hear -- we're not really aware of anybody else that has one of the size, scale and capability that ours already is. And so we're simply adding to that. Extremely large distillation towers and everything you can imagine that should meet the standards that we believe have been set out there. It's a little bit hazy exactly what the standards are. We could meet that, so we're -- the other element of it, I think Faisal is segregation.

Once you created a product that qualifies for export, you have to be able to trace that barrel to make sure it doesn't get contaminated or blended with something that might not meet that.

Right.

And our system really is unparalleled out there. Because we have the gathering system, we have the stabilization distillation towers and the pipeline system all the way to the dock, we can pretty much trace the pedigree of that barrel all the way through.

It sounds to me and correct me if I'm wrong, you are going from 80,000 boe a day to 120,000 boe a day in the Eagle Ford, is that right?

At stabilization capacity, yes. The 120's plus or minus or a year from now, but yes.

What's the cost of -- when you look at the facility of this magnitude that you have, what's the total installed cost of a facility like what you have up and running right now of 80,000 boe a day?

Favorable. If I could leave it at that? I think we've heard numbers from others that are having to start from scratch on that. I think their costs are a lot higher than ours, but we haven't really disclosed that separately. And the way things are developing, I am not so sure it is our best interest to put those numbers out there. We want to get paid for the best value not -- based on the return on the investment.

It sounds like you are fairly confident that you can identify -- and you have the systems in place, you can identify the barrels and therefore given what you've seen with the remarks and the DOC so far, there's no reason to think your volumes wouldn't be eligible to be exported, but you still have to go through the process to figure that out. Is that a fair statement?

Yes. The only thing that might get in our way is political arbitrariness.

That's always hard to predict. On the sunrise project, I think you mentioned in your prepared marks, when you expect that to start up and the line fills to sort of start taking place on that? How does that exactly work?

We're expecting the line to be in service by January 1, 2015.

Okay.

The line will be actually in service before that but there's a lot of facilities work tie-in, et cetera, to be able to get the line totally in service.

Okay. Got it. Appreciate the time.

Thank you.

Cory Garcia with Raymond James.

Thanks, morning fellas. Turning back to the Corpus market and obviously with the Cactus start up next year in conjunction with the surge of Eagle Ford production, how are you thinking about the possible congestion down not only just in the field level, but obviously down along the Gulf Coast, and how we should envision the Cactus ramp, if there's going to be any impact there? And then, obviously, the opportunity set for you down in Corpus?

Well we think Corpus will be less congested than Houston, which is probably the best way to say it. Cactus will add 200,000 barrels a day capacity. It's probably not going to come on at that level. It's be somewhere between 100,000 to 200,000 barrels a day. That's supported the expansion of our joint venture Pipeline systems and the expansion of our dock facilities down there. So, it'll be a little congested in Corpus when we get the dock facility in full service. We should be able to handle all the volumes that come down Cactus and our Eagle Ford pipeline system.

Is that the expansion from 300 to 470? Is that the correct numbers?

Yes.

And what sort of piece of that $140 million in investment target that you have is in fact the dockage versus actual field level Eagle Ford projects? (Multiple Speakers)

It's not in that number.

Okay. Thank you for the color.

Thank you.

Michael Blum with Wells Fargo. Please go ahead.

Hi, everybody. A couple of bigger picture questions. One, in the Bakkan, looking at rail versus pipe, you're seeing some movement there. There's been, obviously, a Pipeline project announced. Can you give some updated thoughts on how you think that market may or may not be changing in terms of the ultimate mix between rail and pipe, and does that change anything in the way you approach things there?

I would probably tell you it's fairly dynamic. For example, Pony Express which is going to be able to haul off from the Rockies area 200,000 to 225,000 should be coming on stream here shortly. So that's going to change the day-to-day dynamics. I think there's a lot of anticipation of some of these projects, as there should be, about what volumes are going to look like in the future, but in many cases the willingness of producers or others to make commitments is somewhat affected by -- you know, you sell more umbrellas when it's raining than when you don't.

So how differentials and congestion is present will dictate that. But I don't think there's anything that's actually been announced that's really changed our view on the long term dynamics of Bakken. To some extent, to the extent you may have more take away capacity, we may have imagined you've actually seen more production capacity to off-balance that thing, so it's pretty much the same as we've viewed it before.

The way we view it, there's going to be plus or minus 700,000 barrels demand on the East Coast for light sweet crude, there's going to be some demand on the West Coast for it. These pipelines that go to the Gulf Coast aren't going to satisfy those markets. So you're still going to see rail to the East and West Coast. They're probably going to displace rail that's moving crude down into the Gulf Coast right now.

The Pony Express is probably going to impact volumes that you rail them to some of the MidContinent areas. That's where we think you'll see the decline in rail movement as these pipeline projects are developed.

Great. That's helpful. Then, the other question I wanted to ask broadly was on rates at Cushing and just how you see -- do you see anything changing there in terms of the pressure we've seen on rates, and I realized you are well positioned there but if you could just remind us if you have any exposure there in terms of contracts rolling over and where you think rates are going for your storage?

I don't think we have anything rolling over through 2015. We have a little bit in 2016. To be honest with you, the way we've structured our arrangements, really they're operating to the operating requirements. So we never were the guys out in the market trying to figure out what the contangle was and how much you can extract from guys that were trading the inner months spreads. It's always been operational and always been priced on a operational basis.

We said definitely, we never pressed for the highest rates that would be associated with bringing in the financial arbitageurs, where you're really talking about splitting the inner month spreads. They were extracting the most rent they could to still allow enough money to put capital up to put the barrels in the tanks and extract it. We were more focused in on the longer term relationships. We certainly gave up some near term opportunities to raise our revenue but we really sustained our long term ability to have repeat customers.

If you harken back to some of the calls that we've had over the last two to three years, we still think there's three rings of tank functionality in Cushing and the best place to be is right in the middle of the bull's eye where you have the absolute most versatility and as Harry said, it's optionality and functionality and operational capabilities, and nothing has changed that. And so I don't -- we're not really sweating any of the contract renewals because we think people need our tankage and our manifold systems to be able to function.

Thank you.

Brad Olsen, TPH Investments.

Good morning, everyone.

Good morning, Brad.

My question's really more big picture. I realize that some of the arbitrary and unexpected decisions that we've gotten out of the government probably create a little more uncertainty than certainty, but when you look around the energy space today and you see a government focused on at least ostensibly increasing exports, you see maybe a slightly more streamlined LNG approval process, and now you see maybe a lower cost way to export condensate.

Is it too early to say that we're seeing at least a subtle shift toward a more export friendly administration?

I wouldn't get too carried away with it, but I would tell you that we've been very encouraged like on the export issue. We're not at the crisis mode yet on the light sweet product. We're getting close, but they've been able to address this early and embraced it and so I probably -- we're encouraged when we saw that and for the reasons you just mentioned, Brad, probably equally as encouraged in the fact that they've realized we are actually a positive catalyst to stimulating the economy and raising employment, et cetera as opposed to the evil empire, and so in that respect, absolutely.

Do I think that there are things that we're always do the right thing as early as we should do it? Why, that'd be a hard one to press to go all the way there, but again, very encouraged that it's more of a cooperative spirit and attitude than probably what we might have expected at this same stage.

Got it. One of the things I guess that surprised me, and it's not just your call, but we've heard it elsewhere too, is this idea that the department of commerce ruling on condensate is somehow a competitive advantage. Is the department of commerce not obligated on some levels to share the technology that is helping people export condensate with the broader industry so as to remove confusion about what can be done?

I mean, I'm sure you have the technical ability to figure out what needs to be done on the stabilization side, but is it right to think of this as something that only a couple of companies really have the ability to participate in, or is this more something that is going to have relatively low barriers to entry over the next year or so?

I don't think that there's really any secrecy around technology or anything else. We all have access to it. I think it's a definitional issue to some extent. And then ultimately I think the segregation issue of being able not only to say that you did something to the product to make it non-crude and therefore available to be exported, but to be able to trace that molecule throughout the system. That so far seems to be very important.

And if you go back in history of time when we used to have old oil, new oil, et cetera, and everything else back when we had strict price regulations, it was critical back then and I think it's going to be equally critical today. Gosh forbid that you have an 80,000 barrel batch of what truly qualifies for export and it gets put in a pipeline and dumped into a tank with 40,000 barrels of something that doesn't meet the same definition, that's a problem.

Generally it's always a problem in hindsight. In other words, it's only when something happens to raise prices at the pump and they're looking for a scalp on the wall that they come back and say, "Aha, you didn't meet the definition that we wouldn't fairly define for you." So I think that segregation part of it is going to be an important of it. I don't think it's a technology issue.

And when you think about segregation it's going to be, where do you locate these stabilization facilities? Because if you have that production facility and as Greg mentioned it goes into a pipeline that also takes unprocessed condensate, then you're not going to be able to trace that barrel all the way to an export facility.

Got it. And so that segregation process creates more opportunities than not for somebody who has got assets in the right place and the ability to stabilize and move it to the dock?

Yes, I think it does, but also, you have to deal with the context that the pipelines are common carrier pipelines. If you have a stabilized batch, there will be -- anyone that comes in with stabilized products always will be able to go to a stabilized batch, but I want to clarify that these are common carrier pipelines.

Got it. One final one and it hits on some of the storage question that Jeremy brought up earlier. We're sitting here heading into what could be the lowest winter storage fill in a decade. Spreads are still relatively subdued in terms of natural gas Contango and we're on the verge of moving a lot of gas to Mexico starting late this year and moving into the later part of this decade, as well as ramping up LNG exports in the next couple of years.

Do you believe that the markets is really so sanguine about this that they just believe that the Utica and the Marcellus are going to overwhelm all possible gas demand or is the market looking maybe a little too complacently at a storage market that has a real shot at getting ugly by this winter?

I'd probably say the latter. Brad I think -- everybody's focused in on the aggregate storage levels and saying if we get to 3.5 TCF we're okay. I think the important think to look at is that especially in the producing area based on current trends, if we get to the 3.5, we're probably still only going to be about 75% to 80% of where we were last year in the producing area, which is where most of the high deliverability is.

I can tell you as an industry we got very, very close last year to not having enough deliverability. There was gas in the ground but there wasn't enough capability to get it out in the short time periods that were necessary to meet the demands. If we have a winter this year like we had last year, I would say it's not going to be pretty at all and everybody's going to be upset.

I think the inner month spreads that you're talking about certainly are not reflecting that attitude and so I would say they are complacent. I do think you're starting to see regional issues, so you've seen big differentials between gas prices at the well head, the Marcellus and the Northeast versus in the Gulf Coast. And that's reflective of the fact we're still just not filling storage up fast enough in the Gulf Coast.

If you parse it even more in the Gulf Coast area and you assume for a minute that most salt storage facilities because they have injectability and people like to be able to draw it rapidly, will be at or near full. The implication is for the reservoir storage in that area, in the same area, we may only be at 60% to 70% of where we were the year before, just because the math works in such that to be at an 80% in the aggregate in the produced of where we were in 2013 and you are 100% full in salt, you are going to be by definition sub 70% in many of those particular reservoir facilities and that's historic.

In other words, that's not been seen in quite a while. So, I think there's some complacency out there about our ability to meet deliverability. I don't think we'll ever run out of gas we just may not be able to get the gas out of the ground fast enough to keep people from freezing.

That is very interesting. Thank you.

Becca Followill, US Capital Advisors.

Good morning. Back to the Bakken rail question, can you talk a little more with the recent changes in regulations about your view on how that might further change transit times?

It's not going to shorten it until you get some rail infrastructure, some better rail infrastructure. Most of the rails are looking at improving their infrastructure and trying to de-bottleneck some of the congestion areas, so that's going to have to happen before you see any real improvement in transit times.

Do you have a feel for timing?

Not really.

Not really. (Laughter) I think there's a lot of motion. It's just right now I don't know if it's translating into measurable action right now. I think everybody's saying we will do X, Y and Z, which is more than they've been doing in the past, but you can't translate that into what used to be a two week to three week turn around time on rail cars. In some cases we are seeing that extend quite a ways.

And by the way, the unpredictability of it is a fair bit of the problem, especially for anybody's who's bought on one basis and sold on another basis and realizing that the backwardation in the market right now could cause the delivery of that oil off pattern to suffer quite a bit of degradation in value.

Becca, I will say that they are working on improving the rail infrastructure in North Dakota and some of the congestion locations like Chicago and et cetera. That is one of the advantages we think that we have with our Yorktown facility, is it by passes a lot of congestion going into the Philadelphia area. But still, even in Yorktown we are seeing a little longer transit times than we would like.

Thank you. Next question to be more direct on condensate, have you applied for a private letter ruling from the department of commerce?

No comment. (Laughter)

That's what I thought but I had to ask. Thank you.

(Operator Instructions)

Sunil Sibal, Global Hunter.

Good morning and congratulations on a good quarter.

Thanks Sunil. Most of my questions have been asked and answered. I just have one with regard to NGL footprint, especially in Canada. Lately I have seen a few announcements with regard to NGL export opportunities. I was wondering if you have any discussions in regard to that, and how do you see that opportunity developing for you?

If I understood your question correctly, is the export opportunities, especially in Canada and the answer is we are looking at that and there are some efforts under way. Nothing that has been made public that could be really talked about, but I think we're definitely seeing a market trend up there that is favorable for our asset base and our business model up there. And ultimately the resource play in certain of those areas are just now taking off.

It will probably add to that imbalance and we think exports should be a part of that. It is not an easy process to put in place, but we're working hard on incremental opportunities. Hopefully that covers that question.

Yes, it does. And then one last one. In terms of any updated parts on M&A in the sector?

M&A in the sector?

Yes.

Could you repeat the question real quick?

I was just curious, I know that on analyst day that you are mostly focused on organic growth opportunities, I was just curious if you had any updated parts on any opportunities in the sector per se, in terms of what you are seeing?

It still feels about the same as it did on analyst day. I hate to characterize it a little bit like Groundhog Day but it does feel that and the market's still pretty ebullient. We're still looking at a number of things. I could probably tell you that the number of things that are available have slowed down just a pitch but we're still looking at things. Prices are still hot and we're still focusing on things that are strategic to us. There have been a couple things that have available and are on the market right now. So we're still active but it feels about the same.

We're swinging a lot but there are people that have bigger bats. (Laughter)

Thank you. That is it for me.

Thank you.

At this time there are no additional questions in queue. Please continue.

If there's no additional questions, again, we want to thank you for dialing in and for all of those that invest in us for the trust that you place in us that it represents. We look forward to updating you on our activity in our November call. Thank you.

Thank you very much, ladies and gentlemen. That does conclude our conference call today.