Keyera Corp.

John Cobb – VP, IR and Information Technology Jim Bertram – CEO David Smith – President and COO Steven Kroeker – VP and CFO

Rob Hope – TD Securities David Noseworthy – CIBC Robert Catellier – Macquarie Robert Kwan – RBC Capital Markets Steven Paget – FirstEnergy

Thank you, Sally, and good morning. It’s my pleasure to welcome you to Keyera’s 2013 first quarter results conference call.

With me are Jim Bertram, Chief Executive Officer; David Smith, President and Chief Operating Officer; and Steven Kroeker, Vice President and Chief Financial Officer. In a moment, Jim and David will discuss the business and Steven will provide additional information on our financial results.

At the conclusion of the formal remarks, we’ll open the call for questions. Before we begin, however, I would like to remind listeners that some of the comments and answers that we will be providing today speak to future events.

These forward-looking statements are given as of today’s date and reflects events or outcomes that management currently expects to occur based on their belief about the relevant material factors as well as our understanding of the business and the environment in which we operate. Because forward-looking statements address future events and conditions, they necessarily involve risks and uncertainties that could cause actual results to differ materially.

Some of these risks and uncertainties include fluctuations in the supply, demand and pricing of natural gas, NGLs, iso-octane and crude oil; the activities of producers and other industry players; our operating and other costs; the availability and cost of materials, equipment, labor and other services for capital projects; governmental and regulatory actions; and other risks as are more fully set out in our publicly filed disclosure documents available on SEDAR and on our website. We encourage you to review the MD&A which can be found in our 2013 first quarter report and our annual information form, both of which are available on our website and on SEDAR.

With that, I’ll turn it over to Jim Bertram, Chief Executive Officer. Go ahead, Jim.

Thanks, John, and good morning, everyone, and thank you for joining us this morning on the call. In the first quarter of 2013, Keyera delivered EBITDA excluding unrealized gains and losses of $98 million, up 67% from the same period of last year.

Distributable cash flow was $83 million or $1.07 per share with dividends to shareholders of $42 million or $0.54 per share representing a payout ratio of 50%. With these results and the performance we are seeing in all our business segments, we feel like we’re off to a very good start this year.

Steve will provide further details on our financial results later in the call. First quarter was a busy one in Gathering and Processing business.

We saw a high level of producer activity around many of our gas plants which resulted in new gas being delivered to Keyera plants. Gross throughput in the first quarter was 1.2 billion cubic feet per day, 1% higher than same period last year.

Increased throughput at the Rimbey, Brazeau River, Nordegg river, CARBOB and Minnehik Buck Lake gas plants was offset somewhat by lower throughput at the Simonette gas plant where operational challenges caused us to restrict throughput. Over the last year, a number of new raw gas gathering pipelines were built and tied into Keyera facilities to support new gas production.

In two instances, we have purchased the pipelines from the producers when construction was completed. The latest was a 12-inch pipelines that ties into our Minnehik Buck Lake plant delivering liquids rich gas from West of the plant.

Produces delivering gas to the Strachan and Minnehik Buck Lake plants are starting to benefit from the work we completed over last year, upgrading the turbo expanders at each plant to improve liquids extraction capabilities. For the past two quarters, we’ve faced sulphur recovery challenges at the Simonette gas plant related in part, the composition of the raw gas stream.

As a result, throughput at the plant was curtailed throughout the first quarter. In addition, sulphur handling facilities were taken offline in late February for maintenance remained offline in March while we completed some modifications to improve operations.

Since the sulphur handling facilities were brought back online on April 1, we have been very pleased with the plant’s performance. Our operations team is working very hard to maintain the sulphur recovery levels at the plant and to manage the gas composition coming to the plant.

We anticipate that we’ll be able to handle increased volumes as we move out of curtailments later this week and we’ll continue to work on process improvements that we believe will continue to enhance the plant’s operations. Our goal is to have online time that is consistent with Keyera’s performance and other Keyera plans.

We are working on a number of growth projects in our Gathering and Processing segment that are also – and also evaluating several more. Last year, we announced that we would be enhancing the NGL recoveries at the Rimbey gas plant by installing 400 million cubic feet per day turbo expander at the plant, work on design and regulatory submissions is well underway.

The project is underpinned by long-term gas processing arrangement and the long-term ethane sales agreement. We continue to believe that this project will be very attractive to other producers around Rimbey, particularly if development continues in the Duvernay geological zone West of the plant.

In April, we announced two initiatives that would significantly expand and improve our service offering at the Simonette gas plant. We’ll be expanding the capture into the Wapiti region where producers are very active.

To accomplish this we plan to invest $120 million to construct 12 inch 90 kilometers sour gas gathering pipeline and install new equipment to plant to allow us to receive the gas. We also plan to invest $90 million to enhance the plants processing capability due to addition of condensate stabilization as well as adding 100 million cubic feet per day of liquids extraction capacity.

This addition is required to enable us to accommodate the new gas production we anticipate receiving at the plant. We’re targeting the second quarter next year to have the pipeline operational.

While the plant modifications are expected to be complete in the second half of 2014. As a result of the growing production of liquids rich gas in Alberta, last month we began soliciting interest from producers in the construction of a new liquids pipeline system in northwest Alberta called the Western Reach Pipeline system.

This is an initiative we are undertaking with Plains Midstream, Canada. We are currently proposing that the system consists to two pipelines, one carrying C3+ mix, and the other pipeline dedicated to condensate.

Customers on this system would have the ability to direct their NGLs, the choice of fractionation storage pipeline and terminal facilities in the Fort Saskatchewan region. Once we complete the open season process later this month we’ll have a better idea about the producer needs and the commitments all of which will shape the future of the project.

Finally, we are heading into a season where we bring certain facilities offline to compete our scheduled maintenance turnarounds. This year there were major turnaround plan for three facilities.

In June we’ll take Paddle River and Pembina North offline for their turnarounds while the Simonette gas plant turnaround is scheduled for September. With that I’d like to turn it over to David to review our Liquids Business Unit.

David?

Thanks Jim. The Liquids Business Unit also posted strong results in the first quarter, with contributions from both the NGL Infrastructure segment and our Marketing segment.

The focus on liquids rich drilling in Western Canada has resulted in a busy quarter for our NGL Infrastructure segment. In Fort Saskatchewan, we saw continued demand for fractionation and storage services, while at Alberta Diluent Terminal, oil sands activity levels drove demand for diluent off-load services.

In addition, producer interest in securing diluent storage capacity at Fort Saskatchewan remains high. Utilization levels rose somewhat at Alberta EnviroFuels in the first quarter as we move higher volumes of iso-octane by rail.

Discussions with new customers indicate a high level of interest in iso-octane demand although some customers will need to modify their facilities to be able to receive iso-octane by rail. We are busy with a number of growth projects in the Liquids Business Unit.

At Fort Saskatchewan our 12th storage cavern is complete and waiting regulatory approval before being put into service and washing of our 13th cavern is now underway. In connection with this new storage capacity, we are also working on new brine pond which we anticipate having operational later this year.

Engineering design work for our de-ethanizer project at Fort Saskatchewan is well underway. And based on the current schedule our plan is to begin work onsite in the second half of this year.

Construction of the South Cheecham rail and truck terminal is proceeding well. The storage tanks, structural steel and track are essentially complete and we expect to have the facility up and running in the second half of the year.

We continue to talk with producers interested in using the South Cheecham terminal to deliver dilbit and bitumen to market, and as a result we are already evaluating options for a second phase of development at the facility. With the tightness and fractionation capacity that exist in Fort Saskatchewan, we are evaluating an expansion of our Fort Saskatchewan fractionation facility.

Additional work is required on this project before we’ll be able to make an investment decision. The performance of our marketing segment delivered more typical first quarter results in 2013 compared to the first quarter at 2012.

All products contributed to the good results posted this quarter. Overall sales volumes in the first quarter were 116,800 barrels per day, 18% higher than in the same last year.

This volume increase was primarily due to propane sales returning to more normal winter levels this year compared to first quarter of 2012. Propane markets in North America strengthened in the first quarter largely due to colder temperatures and a longer winter this year, which increased demand and firmed up prices.

This extended weather also allowed propane inventories to be drawn down in Western Canada and in Conway, Kansas, which may allow for some summer pricing firmness. Butane demand and butane margins remain steady through the first quarter leading to healthy results with the end of the winter gasoline blending season prices of butane have begun to soften and Keyera has been using its railcars and infrastructure to import butane at attractive prices.

Diluent demand was strong through the first quarter driven by increased bitumen production in Alberta. This created pricing differentials and enabled us to import condensate by rail at ADT to meet some of that market demand.

And finally, our crude oil midstream activities continue to post strong results in the first quarter. With that, I’ll turn it over to Steven to discuss the financial results in more detail.

Thanks David. As Jim and David mentioned, we are pleased with our financial result for the first quarter.

EBITDA was $97.8 million, 67% higher than the $58.5 million reported in the first quarter last year. This increase is primarily due to the performance of our Liquids Business Unit compared to the first quarter last year, particularly in the marketing segment.

Net earnings were $23.4 million or a $0.30 per share compared to $33.9 million or $0.46 per share in the first quarter of 2012. Significantly higher operating margin from our business segments this quarter was offset by higher longer-term incentive plan costs and non-cash foreign currency loss and higher depreciation charges compared to the same period last year.

The strong performance this quarter resulted in distributable cash flow of $83.3 million or a $1.07 per share, compared to $47.2 million or $0.64 per share in the first quarter of 2012. Dividends to shareholders were $42.1 million or $0.54 per share.

This resulted in a payout ratio of 50%. Our Gathering and Processing business posted strong operational results in the first quarter delivering operating margin of $39.9 million.

Included in these results were operational problems at the Simonette gas plant as Jim described earlier in the call. In the Liquids Business Unit, the NGL Infrastructure segment delivered a first quarter operating margin of $29 million compared to $26 million in the same period last year.

The marketing business generated $23.9 million of operating margin in the first quarter significantly higher than the $12.7 million recorded in the first quarter last year when weak propane markets affected the overall performance of the segment. Propane results were better in the first quarter of 2013 due to more normal winter demand and an effective inventory hedging strategy.

Included in marketing operating margins for the first quarter of 2013 was a non-cash unrealized loss on risk management contracts of $19.5 million compared to a non-cash unrealized gain of $16.2 million in the same period last year. Keyera’s general and administrative expenses were $6.5 million in the first quarter of this year compared to $8.6 million in the first quarter of 2012.

This decrease is primarily due to a realized cash loss of $1.8 million last year relating to a foreign currency financial contract. Long-term incentive plan costs were $8.3 million in the first quarter compared to a recovery of $4.2 million in the first quarter of last year.

This higher expense is primarily due to Keyera share price increasing 16% in the first quarter of 2013 compared to an 18% decline in share price in the first quarter of 2012. Finance costs were $11.9 million in the first quarter, slightly above the first quarter of last year.

The value of NGL inventory at the end of the first quarter was $144 million, $39 million lower than at year-end. This reduction reflects sales of propane through the winter period.

Keyera incurred about $600,000 of cash taxes in the first quarter, about the same as in the first quarter of 2012. These taxes primarily related to one of Keyera’s subsidiaries and Keyera continues to believe that current income taxes for 2013 will be in the range of 1% to 3% of annual operating cash flow before tax.

This forecast is based on Keyera’s estimates to future cash flow, and the timing of future growth projects and is subject to change. Keyera’s ratio of debt to EBITDA a primary covenant for Keyera’s long-term debt was 1.85 at the end of the first quarter.

This metric reflects the fact we are permitted to deduct working capital surplus in calculating debt. We watch this leverage ratio closely as we believe is a good gauge of our financial strength.

Finally, we’ve included our first quarter supplementary information on our website concurrent with the release of our 2013 first quarter financial results. This information includes both operating and financial data for each segment of our business.

You can refer to our 2013 first quarter report for details and how to access the supplementary data. That concludes my remarks.

Jim?

Thanks, Steven. I’d like to conclude with a few comments about the opportunities I see ahead for Keyera.

In the current business environment producers are increasingly looking to Midstream businesses to help them relieve infrastructure bottlenecks and get their products to market. Examples of this, in the Gathering and Processing business includes new gathering pipelines we’ve purchased in West Central Alberta, and we’ll be building at Simonette.

We also include processing enhancements who recently completed its fracking in Minnehik Buck Lake and Simonette or projects still in construction at Rimbey and Simonette. Longer term over the next several months, we hope to get an indication of producer interest in the Western Reach Pipeline System.

We’re closely with the producers to make sure we understand their needs and strive to develop alternatives that help them enhance the value for their shareholders. In our Liquids Business Unit, we also have projects underway that provided value-added services for our customers.

Our de-ethanizer project, the new underground storage under development and the rail and truck terminals at South Cheecham all provide critical new infrastructure that industry needs. As we look to the future, we believe these are opportunities provide further – provide further underground storage as well as additional NGL fractionation capacity in the Fort Saskatchewan and we’re in the process of evaluating these alternatives.

Continued bottlenecks in the delivery of crude oil to market producers and consumers are increasingly looking to deliver crude oil from Western Canada via rail. We believe Keyera can play a bigger role in assisting customers with this objective.

Given our logistics experience developed for more than decade at delivering NGLs to customers by rail combined with our well-positioned rail terminals and the pipeline connectivity between our facilities and other industry players. Given the new business opportunities that we have announced this quarter, we now estimate that our gross capital expenditure in 2013 excluding acquisitions could be in the range of $400 million to $450 million.

Before closing, I’d like to reflect from went in the past as we approach our 10th anniversary as a public entity on May 30. 2003 when David and myself and many of the management team that are still active at Keyera took the company public, we understood that the success of our business would depend on our ability to provide stable and growing value for our shareholders.

I think we have accomplished this. We could not have done this without the commitment and passion of our employees, who understand the meaning of customer service and focus on delivering the best midstream solutions possible.

Another reason for our success has been our ability to invest capital efficiently and undertake projects in manner that provide shareholders with growth and cash flow per share. Today, as we consider the multitude of new business opportunities that are ahead of us, I want to assure you that we continue to follow the same disciplined approach to investment decisions that have made us successful in the past and we remained focused on operating our business in a manner that provides our employees with a healthy, safe and environmentally friendly workplace.

John, that concludes my comments. And you can open up the lines for questions.

Thanks, Jim. Please go ahead, Sally.

Good morning gentlemen. Contracts on other solid quarter.

I was hoping you can provide an update on how discussions went for the new NGL year. Were you able to secure sizable fee increases for your frac and storage capacity.

And maybe, generally, can you talk about the supply, supply demand balance for frac capacity in the next few years?

Sure, Robert, I can try and answer that. I guess first of all, we don’t generally talk specifically about the elements of new frac and storage fees, for competitive reasons, but I can tell you that we were – you know, I think quite pleased with the re-contracting of the of NGL supplies as well as the fractionation and storage capacity that typically occurs on annual basis in the first quarter.

There is no question that frac capacity continues to be tight in Western Canada as a result of the increased supply of NGLs and some of the operational challenges that occurred at some facilities last year. So it’s something that we’re monitoring carefully and it’s one of the reasons why we’re looking quite seriously at the possibility of expanding our fractionation facility at Fort Saskatchewan.

Great. Maybe just as a follow up, just regarding the shallow-cut expansion at Simonette, maybe you can talk about, are you seeing producers shying away from the capital required for new deep cut capacity and rather just preferring to use shallow-cut capacity and focus more on the condensates?

I don’t think so, Rob. I think producers are drilling liquid rich gas, you know, because they ultimately want the value of the liquids.

I think it’s Simonette, I think for us, we see Simonette evolving and developing in a few phases. And maybe this is part of the first phase where we can put a lean oil, sorry, a refridge plant in quickly, a lot quicker than the deeper turbo.

And I think it allows people to at least get gas on stream test, test some new evolving place there both for Montney and Duvernay. Certainly, that isn’t the long-term solution in our minds.

So I ‘d say that what we’re doing at Simonette is really Phase 1and I think producers will continue to look for to recover as much value out of the liquids as they can. Clearly, those place feel like there is, they’re condensate driven, but I think people want to capture all the value eventually.

Great. Thank you.

Morning. Just a quick question to follow-up on the NGL mix contracting.

There had been some talk about basically changing the terms of the contract to take some of the risk off of Keyera’s balance sheet and back onto the producers. I was hoping you might be able to provide us any color on what you’re able to achieve in that sense?

Yeah David again, without getting into too much detail for competitive reasons, I think it’s fair to say that with respect to propane specifically, the structure of many of our supply agreements has changed. We realize I think the producers realize that propane prices are softer and propane supply and demand in Western Canada is such that we’re not prepared to take on the commodity price risk with respect to that commodity.

And so we have in fact restructured the pricing arrangements for most of our supply contracts with respect to propane. Of course with each component of the NGL mix, the actual specifics are a little different for butane and condensate.

It’s – the arrangements are all different.

Appreciate that. And then in terms of the potential expansion fractionation expansion that you’re evaluating, can you just talk through some of the factors that you need to firm up before you are able to make that decision to finalize that evaluation?

Sure, well as you know we’re going forward with the de-ethanizer investment, which will allow us to take C2+ stream as well as the C3+ stream. Some of the new liquids that are being brought on stream from the Deep Basin from a variety of facilities are C2+.

And so we wanted to be in a position to be able to accommodate both to have the flexibility to accommodate both C2+ streams as well as C3+ streams as well as C3+ streams. By virtue of having a navy investment in the de-ethanizer, we will have that the C3+ component of the C2+ mix, will represent an increase to our fractionator on the back end if you like.

And so that represents a built-in additional supply for the C3+ fractionator, which currently can handle about 30,000 barrels a day. And so that in combination with the demand that we’re seeing from producers for additional C3+ fractionation capacity is leading us down to – down the road towards determining what the appropriate size in commercial arrangements are for a frac expansion.

So it’s kind of the second phase, if you like, of the expansion of the facility there. But we’re still working with producers to determine what the appropriate timing and volume commitments are to make that commercial project.

Thanks for that. And just one last question.

On your – Jim you spoke about crude on rail and Keyera’s interest to pursue that opportunity in your comments. When you think about your operations and where it makes the most sense to pursuit that opportunity, where is Keyera focused?

What?

Excuse me, David. I think clearly, as David mentioned, at South Cheecham, as we go forward there to get initial project on online in the fall certainly lots of other interest has come forward, I think it’s obvious that producers are a little bit concerned about pushing crude downstream to Edmonton if the – if it’s bottleneck there to get to market.

So I think more interest in trying to put rail bid or drillbit on the rails at a place like South Cheecham, so clearly we are looking at what needs to happen there that become a bigger operation, and we certainly have the land size and partial there to expand it. I think we have – I’ve always said, I thought we had a very strategic location at our and ADT site.

And we’ve got extra land there. So, we’ll look at those.

I think our view is that we want to expand in locations where we see a long-term demand for rail, whether it’s crude today and then may be evolving into propane, butane, condensate diesel down the road. So, we’re looking for kind of core hubs that be around for a long time.

Maybe just a follow up on that, are you picking more unit train development or something more smaller size?

Well, that all depends on what the customers want and what we can physically accommodate at each site. So, it’s probably too early to sort of say, this – one versus the other.

Thank you very much, those were my questions.

Thanks, David.

Thank you. Just a quick follow up on David’s question on the fractionator, David you said that there’s more work to do before you make a final decision there.

I just want to clarify that, that is effectively on the commercial side, and that there’s no technical elements standing in the way of the sanctioning decision. Can you clarify that, please?

I don’t – Robert if your question has to do with any roadblocks that we see technically. I think the answer is, no.

But, we still have some work to do just in terms of engineering, design work in order to finalize the cost estimate and some of the elements like that.

Right. So, you are just tightening up the investment profile as opposed to having any seeing any technical roadblocks that look challenging?

That’s correct.

Yeah.

As you can appreciate determining what the appropriate size is and how it fits with the other elements storage capacity requirements, things like that, those are all elements of the project that we need to make sure that we’ve got fully understood.

Okay. And then maybe Jim you can comment on the outlook for Caribou, on the one hand that JV up there Petronas and Progress is doing well and there is a 54% gain in throughput.

On the other hand, it’s a well-capitalized player out there. So how do you see the Caribou plant evolving as that joint venture continues to develop the area?

I think it’s probably a little early to tell. I know that our team up there has a great relationship with Progress and there has been a lot of active drilling by them and some pretty extensive pipelining into our Caribou plant, which is resulting in some pretty healthy growth in that plant.

But if you look at what ultimately they require to make an LNG project go, it’s a lot of gas and lot more than the Caribou plant obviously. So we’re going to either have to expand or there’ll be other plants in the area and it’s just a little bit early to sort of know where that’s going.

As I said, I think, we feel comfortable that our plants there today are able and willing to accommodate the gas up to over 100 million a day. And – but there are other players in the area and there will be some half a dozen other players as well.

So, it’s just early, I think we like where we’re at. I think we’ve got a good relationship and we’ll just see where it goes from here.

And no matter what happens, still good position to be in?

That’s right.

I just want to dig down into the capital budget increase announced yesterday. On the one hand you have Wapiti which certainly has to have impacted that number, but I’m wondering, how much capital in that increase is associated with projects that aren’t yet publicly identified or sanctioned, in other words, how much of that is, maybe on spec and not in the market?

Rob, I’ll take a crack at that. Really, I think about the growth in our capital forecast and maybe three pieces.

The new projects you mentioned the Wapiti pipeline and the work we’re doing at the Simonette plant, the expansion that Jim referenced earlier, would be one piece. There is still some work going on, on the scheduling of projects that were – have been announced in the past.

Things like the turbo expander in the de-ethanizer where we’re looking at schedule and trying still fine tuning, if you like the spend profile between this year and next year for instance. And then the third piece, maybe is a piece you’re getting to which would be projects that we have under consideration that we aren’t yet – haven’t necessarily announced or certainly haven’t announced that we’re proceeding with would be the third bunch and, so those are the three factors that are resulting in an – in the movement in our capital spend.

What I would say is that projects like the Wapiti pipeline are still relatively early in terms of project planning and schedule development, and it’s difficult right now to derive opinion. The timing of the actual spend that we’ll see between years.

So for all those reasons, we basically looked at the forecast and come up with the range of 400 to 450. They – I think that there’s certainly what, a relatively large piece of that, that – it projects that we’ve talked about from time to time and haven’t yet announced that we’re proceeding with.

Okay. It’s not material, but I know this is a small write-down of a terminal in the U.S.

and I found that curious for a couple of reasons. My understanding of the terminals that you’ve acquired in the U.S.

and it’s been a good experience for Keyera. And now with propane prices up and seemingly the NGL market normalizing, it just compares to be curious timing as to why you take that write-down now?

Yeah, a good question Rob. I think for the most part we’re still quite pleased with the propane terminals.

This – the one that you’re referring to through was in a fairly small market area and the volumes really just didn’t justify us keeping it open and there were some other factors that I won’t get into that caused us to decide that, that was an asset that didn’t make sense for us to continue to operate.

Yeah, so on the whole they’re still well – they’re still doing well, but that one in particular wasn’t maybe carrying the way the others were?

Yeah, exactly.

Yeah. Okay.

Thanks, those are my questions.

Good morning. Dave you touched on a little bit with respect to the butane imports.

I’m just wondering, last year I think there was pretty or a very attractive market for you to some stranded butane and bring that back into Alberta, just wondering are you seeing that type of price differentials with an early sign right now?

I guess the short answer is yes, as you know butane can be somewhat seasonal as a result of the gasoline for changing gasoline blending requirements from winter to summer particularly in the U.S. And so, we typically see butane prices softening somewhat in the U.S.

at this time of year, as the ability to blend butane into gasoline is reduced and that in fact is what we have been seeing as we move into the summer months and into the summer driving season here. So, it’s an opportunity for us to augment the butane supply in Western Canada with some imports at attractive prices.

As I say, it tends to be seasonal, so we would anticipate that that would continue for the next three months, four months, maybe five months, and then that would be it.

Okay. Just I guess turning the condensate side of things Enbridge’s announcement on an expansion or contracts to fill up Southern Lights.

Do you have any thoughts on that as it relates to a couple of parts of your business, one ADT on the import side, but the other just more condo coming in and some of your direct connections could be good for the handling side?

Sure. Well, as you know, as part of our build-out of what we refer to as our Fort Saskatchewan Condensate System, an important part of that was a direct connection to the Southern Lights pipeline.

And so, our approach is to try and make sure that we’re connected to all of the supply sources and as many of the outlets as we can. And I think that strategy has worked very well, so we would anticipate that that will lead to increased volumes on our system through our pipe and in our terminals and our storage.

It’s an interesting longer term question as to what that increase in capacity and the reversal of Cochin pipeline might mean for the eventual sources of condensate into the Western Canada market. Certainly, we see a strong demand at ADT continuing for rail imports.

We access condensate at ADT from markets that are generally not – or sources that are generally not pipeline connected and so we don’t necessarily see increased volumes of Southern Lights as I addressed, but it is something that, that we watch on an ongoing basis and the nice thing about ADT is because of its location and its connections and its capabilities, we think we have the flexibility to use that site for lots of other things if in the long-term the need for condensate offloading wins.

Okay. Just the last question I have got is on financing and with the approval you received to issue preferred shares, I’m just wondering if you’ve got some refined thoughts on how you might decide to use that product now that you have the optionality?

Yeah, it’s a good question Robert. The key for us is that that to just make sure we had the flexibility to access that pool of capital, we do believe that is a different pool of capital in the marketplace.

No imminent plans to issue preferred shares but though we do see the attractions of that, it does have pretty attractive financing costs relative to a blend of debt and equity and as well it helps to minimize the dilution for the common shareholders. So overall our goal is to finance our capital program in a very prudent way though we would have a bit more willingness to have a little bit higher leverage during the construction period as we wait for the EBITDA to come as well.

Okay. And just on that – oh, sorry Steven...

Go ahead.

Are the press treated, I know from a rating agency perspective, I guess kind of the lowest treatment will be about 50/50. Is that treated differently under your credit agreements?

Yeah, from a rating agency point of view, the lowest one you rate is 50% equity, and more we can see it doesn’t roll into the debt-to-EBITDA covenants on our side there, so.

So to be clear, you get a 100% equity treatment under the covenants?

From my understanding is, yes.

Okay. That’s great.

Thank you.

We’ll continue to evaluate that and see how that works through all our note agreements et cetera as well, but for now it looks like it’s okay.

Okay. Great.

Thank you.

Good morning and thank you. At the AGM you said you might look at fractionation expansion at Nevis and what might that look like, would it be a small expansion or an attempt to create a real regional hub?

And could you do the same thing at Rimbey?

Yes. Steven, I think with the tightness in frac capacity in Western Canada, we’ve really gone back to all our existing fracs and said what could we do cheaply, retraining or just to fix any bottlenecks that we might have with that offloading or loading or physically at the facility.

And I think at Nevis and at Rimbey, we think there is an opportunity to make some small modifications that would give us an incremental frac capacity, but it’s – these won’t be big, but I think from a – from an economic perspective, they could be very attractive ways to give a small increments of incremental frac capacity, but I certainly don’t believe that Nevis is going to become fractionation hub or...

Thank you Jim. We’ve seen our stable come up with some pretty strong claims on how much producers can incrementally earn per QJ by moving gas out of the Alliance to its plants near Chicago.

One arguments this Keyera making to get producers to extract their liquids in Western Canada and they seem to be working quite well.

Well, I don’t totally understand their economics. But I think that today we believe that the best market for condensate, butane clearly is here in Western Canada because we bring both condensate, butane back from that market from time-to-time.

Propane there’s times when you can make an argument that propane in Chicago is stronger than Western Canada, but I think that’s also an argument that you can go back and forth on. And in ethane, there’s a lot of ethane rejection going on in the U.S.

today. So, I can’t comment whether it’s happening in Chicago or not.

I think how I look at it, probably we in Western Canada need Alliance to take away some of the gas that we simply don’t have frac capacity for in Western Canada. And so there’s probably some benefits there.

I guess I’d say long-term. I still think this is the place where you want to take your liquids out of the gas stream and the market Edmonton, Fort Saskatchewan is very – it will become more of liquid hub over time for the different commodities.

So, I think we as a provider of those services just have to work hard at getting our deeper cut facilities online and being able to offer people a market price for their commodities at Edmonton and for Saskatchewan, and I think when we can do that in an efficient and cheap manner, we’ll win and but I think short term over the next three four years, there is room for everybody.

Thanks Jim. Those are my questions.

Operator; There are no further questions at this time. Mr.

Cobb, I’ll turn the call back over to you.

Thank you, Sally. This completes our 2013 first quarter results conference call.

If you have any other questions, please call us. Our contact information is in yesterday’s release.

Thank you for listening and have a good day.