John Cobb - Vice President, Investor Relations & Information Technology Jim Bertram - Chief Executive Officer David Smith - President and Chief Operating Officer Steven Kroeker - Vice President and Chief Financial Officer

Robert Kwan - RBC Capital Carl Kirst - BMO Capital Dirk Lever - AltaCorp Capital Elaine Williams - FirstEnergy Capital David Noseworthy - CIBC Rob Hope - Macquarie Securities

Thank you, Liza, and good morning. It's my pleasure to welcome you to Keyera's 2014 third 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 about our financial results.

After that, 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 reflect 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 outcomes, they necessarily involve risks and uncertainties that could cause actual results to differ materially.

Some of these risks and uncertainties include fluctuations in supply, demand and pricing of natural gas, NGLs, isooctane 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 essential for our capital projects, governmental and regulatory actions or delays, and other risks as are more fully set out in our publicly filed disclosure documents available on SEDAR and on our Web site. We encourage you to review the MD&A which can be found in our 2014 third quarter report published yesterday which is available on our Web site 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. Thank you for joining us here this morning.

Demand for Keyera services and products resulted in continued strong financial performance in the third quarter. This demand comes from two primary drivers of our business, ongoing development of liquids rich natural gas reserves on the west side of the Alberta and growing demand for diluent-handling services as bitumen production from active oil sands continues to ramp up over the next several years.

Our integrated business lines allowed us to provide a full suite of midstream services meeting the needs of our customers along the value chain. As producers continue to target the numerous resource plays available in Western Canada, we’re seeing increased demand for both gathering and processing and NGL fractionation services.

And we’re continuing to see strong demand for access to the Edmonton/Fort Saskatchewan NGL market hub. Our customers continue to see advantages in our integrated approach, which has contributed to increased throughputs at many of our facilities as well as producer support for expansion projects.

All key financial metrics were higher in the third quarter of 2014. Net earnings $82.4 million or $0.98 per share.

Adjusted EBITDA was a record $151.4 million, 83% higher than the third quarter of last year. The distributable cash flow in the quarter was a record $124.4 million or $1.48 per share, up 131% on a per share basis despite higher cash taxes this year.

Steven will talk more about our financial results later in the call. Drilling activity has been very strong as producers continue to drill at the best plays targeting liquids rich natural gas in the west central region of Alberta and in the Deep Basin.

In west central Alberta, we have several large gas plants -- where we have several large gas plants, producers are focusing on a number of geological formations a few which include the Spirit River, Cardium in Glauconite horizons. The resulting production is driving throughput growth at our facility.

In the Deep Basin area around our Simonette gas plant, the Montney zone continues to be the primary focus for most producers. We’re also seeing some activity focused on the Duvernay horizon both in the [KBOB] area near our Simonette gas plant as well as West Central Alberta adjacent to several of our Keyera plants.

Several of our facilities including Rimbey, Strachan, Minnehik Buck Lake, Pembina North and Brazeau North were operating at or close to their effective capacity in the third quarter. Overall, gross processing throughput in the third quarter was 1.4 billion cubic feet per day, up 10% from the third quarter of last year despite outages at four of our gas plants.

Net throughput, that is our share of the gross processing capacity, was 1.2 billion cubic feet per day, 14% higher in the third quarter of 2013 with the addition of the Cynthia gas plant volumes. The integration of the Cynthia gas plant, which we acquired in the second quarter, is going well.

And given the increased levels of activity in the area, we’re pleased to have additional deep-cut capacity available for our customers. Expense into our pipeline infrastructure over the past few years has allowed us to better serve producers while successfully growing the capture area around several of our facilities.

To keep up with increased demand for gathering and processing, we are working on a number of additional infrastructure solutions to expand and optimize our operations, relieve processing constraints add operational flexibility and provide enhanced service levels for our customers. Construction is expected to begin the in the fourth quarter of the Twin River’s pipeline project, a 45 kilometer, 12-inch pipeline to deliver liquids rich gas to the Brazeau River and West Pembina gas plants.

This pipeline will run from the Brazeau River gas plant to south of our Nordegg River gas plant and connect with existing Keyera and producer owned pipelines. We’re targeting the first quarter of 2015 to complete the first phase of the project.

And if all goes as planned we expect the second phase to be completed in the second quarter of next year. With the shortage of processing capacity in the region this pipeline system together with the changes to some of our existing pipelines will allow us to deliver gas to plants that currently have capacity available.

There was a strong producer interest in the project and we continue to receive additional request for capacity on the Twin River system. At the Rimbey gas plant, installation of the 400 million per day cubic feet turbo expander is progressing.

We completed a planned 10-day outage in September to complete tie-ins of the new equipment. The demethanization and deethanized repowers were lifted into place in October and the flush back is expected to be installed this month.

When complete around the middle of next year, the new turbo expander will increase recoveries of ethane and other NGLs from the new far gas streams. To keep pace with growth in the liquids rich gas production in this area we have plan to debottleneck the fractionation facilities at Rimbey which could add approximately 6,900 barrels per day of fractionation capacity.

We’re also looking at expanding the NGL truck offload capacity by approximately 6,000 barrels per day. With the anticipated growth in production from the Cardium, Ellerslie, Glauconite and Durvernay zones in this area, we continue assess the work that would be required to increase processing capacity at Rimbey including the possibility of operating both the lean oil system and the new turbo expander simultaneously.

At our Simonette plant construction of our Wapiti pipeline system which includes a 12-inch raw gas gathering pipeline and a 6-inch condensate pipeline has been completed. The raw gas pipeline was commission in September while the segregated condensate pipeline is scheduled to be brought online once the condensate stabilizer at Simonette plant is complete.

Based on current construction schedule we expect this to occur by year end. 100 million cubic feet per day expansion of the Simonette gas plant is well underway with completion expected in early 2015.

As part of the expansion project, the plant was taken off line for 10 days in September to complete tie-ins. And while the plant was offline we completed some repair to the sulfur plant.

With that, I’d like to turn it over to David to review our liquids business unit.

Thanks Jim. The liquids business unit also reported strong results in the third quarter with contribution from both the NGL infrastructure and marketing segments.

We are continuing to see growing demand for fractionation, storage, transportation and other liquids logistics services as producers increase production of both liquids rich natural gas and bitumen from the oil sands. In the NGL infrastructure segment, operating margin of $45.8 million was 46% higher than the same quarter in 2013, driven by higher fees for services associated with the processing and handling of natural gas liquids, crude oil and isooctane.

This growing demand for fractionation and storage services highlights both the diversification of our service offering and the value that our integrated operations provide for our customers. To meet this increase in demand, we have a number of infrastructure projects underway at Fort Saskatchewan.

Our new 30,000 barrel per day de-etherizer expected to be operational early in the first quarter of 2015 will allow KFS to receive an ethane rich stream of NGLs known as C2+ mix. Work is also underway for the construction of the second fractionators which will more than double our C3+ mix fractionation capacity to 65,000 barrels per day.

We expect this project to be up and running in the first quarter of 2016 assuming timely receivable of regulatory approvals and no changes to our construction schedule. To increase our underground storage capacity we are completing construction of our fourth brine pond and expect to have it in service this quarter.

Our 13th cavern is nearing completion and is expected to be in service by about mid-year and washing of the 14th cavern is currently underway. The next phase of cavern storage capacity expansion is already in development and we expect to begin drilling the wellbore for our 15th cavern in the next few months.

We celebrated the opening of our rail and truck terminal at Hull, Texas in October. The terminal is being used initial to facilitate deliveries of propane, butane and isobunate in and out of local markets.

Longer term with Hull’s connections to Mont Belvieu and other area infrastructure, it is possible that we could integrate that facility with our NGL business in Western Canada. Site preparation is nearing completion for the Josephburg Rail Terminal located just east of our Fort Saskatchewan complex.

The rail terminal will be used to load propane barrels to provide access to propane markets across North America. We anticipate having the terminal in operation for next year’s heating season.

We’ve spent a number of years creating a large liquid transparent diluent handling system in the Edmonton Fort Saskatchewan hub to provide customers with the flexibility to access a variety of receive and deliver points, storage facilities and rail and truck terminals. We achieved another milestone in August when we began receiving condensate at our Fort Saskatchewan facility from the Kinder Morgan and Cochin condensate pipeline.

Our connection at Fort Saskatchewan is the only received point for diluent deliveries into Alberta from the Cochin system. We work with the Cochin shippers who use our integrated condensate system to facilitate movement of diluents either into storage or on to its final destination and we are continuing to pursue further enhancements to our condensate infrastructure and our service offerings to support producer’s needs and oil sands growth.

In October, we entered into an agreement to provide solvent handling services at the South Cheecham Rail and Truck Terminal. Assuming all conditions of the agreement are met and subject to timely receipt of regulatory approvals, we will undertake enhancements to the rail infrastructure and build additional storage tanks at the terminal, with start-up anticipated in 2017.

On September 25th, we celebrated the grand opening of our Alberta Crude Terminal which is situated adjacent to our Alberta Diluent Terminal in Edmonton. In new size a 50-50 joint venture with Kinder Morgan extracts crude streams from Kinder Morgan’s Edmonton terminal for loading onto rail cars.

The site has 20 loading spots with potential loading capacity of about 40,000 barrels per day. And we are currently in discussions with customers to determine a level of support for a future expansion of the terminal.

Our Marketing segment also had another good quarter delivering an operating margin of $79.9 million, an impressive $46 million higher than the third quarter of last year. A big factor in these results was the performance of our isooctane business with both higher sales volumes and higher margins.

We continue to be pleased with our success in developing new markets for iso-octane across North America. Earlier this year we completed the modifications at the Edmonton terminal to increase our capacity to load isooctane by rail and we are currently adding a truck terminal for loading isooctane at Alberta EnviroFuels to provide better service for local customers.

We are utilizing our storage arrangement at the Kinder Morgan Galena Park facility located adjacent to the Houston Ship Channel in Texas to support isooctane sales in the U.S. Gulf Coast market.

Increasing delivery options has resulted in extended markets for isooctane which allowed our Alberta EnviroFuels facility to operate a close to full capacity again in the third quarter. Growing production of butane across North America has meant the butane prices remained relatively soft in the third quarter.

We continue to use our storage and rail capabilities to purchases store butane volumes in order to effectively manage the [feeds] dock requirements at Alberta EnviroFuels. We expect butane prices will remain week for the rest of this year due to a continued over supply of butane across North America.

Diluent demand has been lower than initially expected this year which has resulted in somewhat weaker relative condensate prices in Alberta compare to a year ago. Despite that we continue to see opportunities to import condensate from the U.S.

when the economics are favorable. Finally our crude oil midstream activities continue to post solid results in the third quarter of 2014.

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 very pleased with how well all segments of our business performed this quarter and with the record results achieved.

Adjusted EBITDA was a record 151.4 million, 83% higher than the 82.6 million recorded in the third quarter last year. Net earnings more than doubled to 82.4 million or $0.98 per share, compared to 40.8 million or $0.52 per share in the third quarter of 2013.

For the third quarter distributable cash flow was a record 124.4 million or $1.48 per share, compared to 50.5 million or $0.64 per share in the same period of 2013. What was particularly encouraging about these results is that they reflect the strength of the underlying business before we include the expected results from our large growth projects over the next year or two.

Dividend declared to shareholders were 54.2 million or $0.645 per share. This resulted in the pay-out ratio for the quarter of 44%.

Our gathering and processing business unit delivered an operating margin of 54 million in the third quarter, these results can be attributed primarily to continuing growth in throughput at many of our facilities and the recovery of cost associated with the turnaround of the Strachan gas plant in the second quarter. The liquids business unit also delivered strong results in the third quarter, operating margin in the NGL Infrastructure segment was 45.8 million, 46% higher than the 31.4 million reported in the same period in 2013.

This increase reflects continued demand for NGL Fractionation and Storage services. Higher pipeline volumes and tariffs and the inclusion of margin from the South Cheecham Rail and Truck Terminal.

The NGL Infrastructure segment also continues to benefit from fees charges to Marketing segment for the production of isooctane at the Alberta EnviroFuels facility. High utilization at the facility contribute to the strong results in our NGL Infrastructure segment.

The marketing business generated an operating margin to 79.9 million in the third quarter, compared to 33.2 million in the third quarter last year. Excluding unrealized gains and losses in both periods third quarter marketing results were approximately 45.8 million higher than the same period last year, largely driven by stronger isooctane volumes in margins.

The isooctane portion of the marketing results was significant reflecting high sales volumes and attractive prices. It is important to remember though that isooctane results tend to be seasonal with results typically stronger in the second quarter and third quarter due to the driving season.

The increase in marketing operating margins also reflects a realized hedging gain in third quarter 2014 compared to a realized hedging loss in the same period last year, primarily relating to the hedging of inventory to protect inventory values. Keyera’s general and administrative expenses were 10.4 million in the third quarter compared to 6.1 million in the third quarter of 2013, this increase is largely due to higher staffing levels and other related costs to support Keyera’s growing business.

Long-term incentive plan cost was 17 million in the third quarter, 9.9 million higher than in the third quarter of 2013. This higher LTIP expense was primarily due to the growth in share price in 2014 compared to 2013.

And was also affected by higher anticipated payout multiplier in light of Keyera’s strong performance. Finance cost was 13 million in third quarter, 0.6 million higher than in the same period in 2013.

And the value of inventory at quarter end was 272.4 million 19.4 million higher than at September 30th, last year. Keyera incurred 8 million of cash taxes in the third quarter compared to only 0.9 million in the third quarter of last year.

Keyera’s 2014 income tax largely relates to 2013 taxable income from the Keyera partnership, a wholly owned subsidiary and Keyera main operating entity. As a result, Keyera currently estimates that its cash taxes in 2014 will be between 35 million and 40 million based on the partnerships 2013 taxable income.

The increase in cash taxes in 2014 compared to 2013 is largely due to the growth in Keyera’s business and lower available deductions. Our capital liquidity continues to be strong with a net debt to EBITDA ratio of 1.8 times at quarter end compared to our [strictest] covenant of four times.

And as a result, Keyera is well positioned to execute its growth plan and to pursue acquisitions as appropriate. Finally we’ve included our third quarter supplementary information on our Web site concurrent with the release of our financial results.

This information includes both operating and financial data for each segment of our business. You can reference our 2014 third quarter report for details on how to access the supplementary data.

That concludes my remarks Jim, back to you.

Thanks Steven. Despite some recent commodity price turbulence, I continues to be optimistic about the opportunities I see ahead for Keyera.

We always look at this business through a long-term wins and certainly we have the facilities and infrastructure to enable us to continue to provide services for decades to come, because of that Keyera’s focus continues to be on ensuring that there is safe and reliable infrastructure in place to enable producers to get the products to market. To meet our customers need, we’re developing and expanding our network of interconnected plants, pipelines and facilities in order to enhance our service offering.

We currently have over $1.6 billion in projects under development and many more opportunities under evacuation. Year-to-date we’ve already invested over 500 million on growth capital investments excluding acquisitions and expecting that’s between 700 million and 800 million for the full year, again excluding acquisitions based on our current construction schedules.

In 2015 we currently anticipate that our growth capital investment will be about the same between $700 million and $800 million. Maintenance capital for 2015 is expected to be approximately $65 million.

We appreciate that the high level of activity throughout the oil and gas sector in Western Canada puts pressure on cost schedules and skilled man power. We also understand that many factors that contribute to successful project execution and are committed to continuing to work with our partners, customers and contractors to deliver quality infrastructure solutions.

We believe that a strong based business and accretive growth opportunities will [out carry] to continue to deliver shared value into the future. Our dedicated leadership team is committed to executing on our business strategy.

I will be transitioning from my current role of Chief Executive Officer to my new role of Executive Chair of the Board as of January 1, 2015. At that time David Smith will become President and Chief Executive Officer.

As Executive Chair, I am not going too far away and will remain closely involved in helping to set Keyera’s strategic direction. David will be taking over the range in running the day to day operations of the company, something he’s already very, very familiar with.

In connection with these changes David will also be joining the Board and Doug Haughey who has been on the Board since 2013 will take on the responsibilities of Independent Lead Director. I have been proud to work alongside Dave for the past 16 years and I have always Dave as an equal partner, very confident in his abilities to lead Keyera as he steps into his new role as CEO.

Our success to date has come from a focused business strategy, a disciplined approach to capital investments and a responsible effective corporate governance model a formula that we’ll continue to follow going forward. John that concludes my comments.

Thanks Jim. Liza please go ahead with the questions.

You talked a lot about some of your pipeline initiatives around optimization, I am just wondering specifically it's still early but you had Cynthia here. Just your thoughts on projects to move the plumbing around in the area to optimize volumes in the region both the shale plants you talked about earlier, but also to stream the rigs of gas to the right plants like Cynthia?

We certainly plan to get Cynthia more connected to our wellbore in the West Pembina region whether we can get as specific as streaming hot gas to specific plants that’s a tough one I think we’re just going to continue to be more focused on trying to optimize and fill up whitespace or capacity at existing plants and that’s been a focus so far.

And I guess, Jim, how important has it been as you've been talking to producers to give them -- I know how you talked about historically. But, I guess, at the current time, how important has it been to producers to have that ability to potentially move into various different plants to avoid both planned and unplanned downtime?

Producers don’t like to have shut in gas and I think when you have the flexibility to move gas around to keep it on for their sake, it’s certainly a benefit. So it’s very important.

The issue with us, I think as plants fill up we start to lose some of that flexibility. So we’re trying to optimize as best we can but I mean the good news for us is that we’re losing some of that flexibility because our plants are filling up.

Okay. Just moving to isooctane, given you're reaching a lot of new markets and you're pretty much running full out at this point, while isooctane prices are likely to continue to move with RBOB to some degree, I'm just wondering.

Have you seen the premium move up, just given you guys are running full out and there seems to be a lot of demand that you've been able to reach?

Robert hi, it’s David Smith here. I think the short answer is yes.

We as you know we price isooctane at a premium negotiated premium to RBOB and as a result of having done the work that we’ve done to improve our distribution options the tankage in Galena Park as well as more volumes moving out of Edmonton by rail we’ve been able to reach customers that we couldn’t reach before. And what we’re finding is that the demand for isooctane continues to be strong and as a result the margins that we’re able to get for that isooctane, assuming that we can meet that demand have been strengthening.

That's great. And if I can just ask one last question, just on your 2015 maintenance CapEx number, can you just give some details of what some of the major planned outages are for that year?

The big one is Rimbey, Minnehik Buck Lake would the two major ones.

That’s great. Thank you.

Good morning everybody and congratulations to both of you as well as to a good quarter. Just maybe a question on the isooctane and recognizing seasonal pattern, but also to the extent that you've been successful at negotiating the premium given the higher demand.

What I'm wondering I guess is as we think about the feedstock hedging, is it also possible to hedge or are you actively hedging future periods of isooctane as well or should we think about the hedging as more just feedstock management?

It’s both Carl I guess is the short answer. We look at -- we use RBOB primarily to forward sell or to hedge the forward sales of isooctane because that’s what most of our sales prices are based on as a base.

And the approach we use there is the hedge using the RBOB swap against WTI. Similarly, a lot of our supply contracts for butane are in relation to WTI so we’re basically using that as a marker as well on the hedging of the feedstock side.

Should we think of -- and again, just trying to think of the commentary with respect to it being seasonal. But in light of the higher demand and I think the very strong utilization that you guys have been using.

As we enter into the fourth and the first quarter of 2015, should we be expecting a sequential drop in contribution, or is the combination of the hedging perhaps prior to RBOB selling while -- falling while butane is that maybe spreads can be maintained? Is there any color on the winter outlook you can provide on that?

Well, first of all, we don’t anticipate that the volumes will effecting by the seasonality, we think that the demand will continue to be there. But I think if you look at and it’s easy to look at the forward curve for RBOB I think what you will see is that prices for RBOB in Q4 and Q1 tend to be a little softer than the prices that you see during the peak driving season of Q2 and Q3.

So that’s really the effect that Steven was referring to. So, I don’t think it will be a huge impact, we don’t expect it will affect the volumes but it will have some effect on the margins.

Understood. Appreciate that.

And then just really two other quick ones, if I could. The first is from the maintenance capital, trying to kind of get a better sense of -- as the additional facility's been added, but it was a little bit higher than what we were expecting.

And I know it's going to be lumpy from year-to-year, I’m kind of trying to get a better framework perhaps of what maybe the best way to think about it, is an average -- what you expect an average annual run rate to be, to perhaps be over the next three years, if I could ask it that way?

Carl, I’ll take a shot of that, I think and maybe we can take your question offline and gave a further discussion about it, but I think the reason is lumpy is because the largest chunk of our maintenance capital by far is still the turnaround cost. And when you are turning around a plant like Rimbey, which is our largest gas plant or facility like AEF which will have its turnaround in 2016, that has the big impact on the total maintenance capital in the year because those costs are capitalized.

There are some additional smaller maintenance capital projects that are tend to be a little steadier year-to-year, but we can probably give you a little bit better sense for kind of what you can expect going forward.

No worries. I can follow up with John.

I appreciate that, guys.

I think it is important to remember though that a large portion means that is recovered through our flow through mechanism there too.

Thanks very much. Congratulations to both Jim and David.

Jim, I'm sure you won't be that far away and congratulations to you all on some great results. I wanted to ask a couple of questions here.

On the processing and gathering side, is it safe to say then that we're back to normal operations, that the facilities that were brought down and hit the results a little bit in the quarter will be back to normal now for Q4?

Yes, I think is safe to say that. I think both Rimbey and Simonette were the two big ones a lot of work there done with anticipation of turnaround next year, Rimbey and the bringing of the turbo and at Simonette also work done for the pile expansion is coming, so it's done.

Okay. Great.

And I'm going to come at the same question that Carl and Robert had basically alluded to. And that's looking at your marketing division.

And it seems to me that we ought to be looking at this differently because, if there's a surprise, it's probably coming from this. I think we all understand the isooctane.

But, there's probably a little bit more to it. So, when we're looking forward, how should we be looking at the profitability and the margins within the marketing group?

Well, that’s maybe a tough one Dirk. As you know we don’t provide guidance, we have five different cash flows streams in essence within the marketing group, we have a propane business which will be stronger in Q4 and Q1 and weaker in Q2 and Q3.

The isooctane business has grown to be probably the largest piece currently and its seasonality is opposite, so there is a bit of natural hedge there the isooctane results are stronger in Q2 and Q3 typically than in Q4 and Q1. But we also have butane, condensate has been somewhat smaller this year just because we haven’t seen the same opportunities to bring condensate in at a positive margin from the U.S.

but I think that’s likely to change over the course of the next few quarters as we see things unfolding. And then we have the crude oil maturing activities as well.

So, I mean the good news is we have diversified portfolio cash flows and they will Ebenflow. I think certainly as we’ve said the strongest contributor this quarter has been the isooctane.

We are optimistic that isooctane will continue to be a good contributor over the course of next little while, subject to the fact that the margins will be a bit seasonal.

Okay. And then on the condensate side, with the U.S.

Gulf Coast guys looking -- able to export some of their condensate, are you seeing any impact from that -- with the price in that market sort of firming up as they're taking product offline? Is that impacting some of your margins there?

Actually, I would say no. There has certainly have been some activity around export of condensate out of the U.S.

but there has been a huge growth in supply of condensate from some of the various significant resource developments in the U.S. and we’re actually seeing -- for the most part we’re seeing very soft prices for condensate in the U.S.

and that’s one of the reasons why I am optimistic that we’ll see more opportunities to bring condensate in from discounted U.S. markets into the into the Edmonton, Fort Saskatchewan.

And then when we're looking at your expansion programs, you had mentioned a while ago that the approvals coming out of Alberta were slow. Has that -- have they now rectified some of their issues?

And are the approvals coming in faster now so that you have greater visibility as to getting projects done or if there's a change in scope that that can be done along with a project that's underway?

I would say that’s probably true, Dirk the work that the Alberta NGL regulator has done to try and streamline their processes and have a one window to approach. I think we’ve started to see that that’s working well.

I mean there is still a process and part of it is making sure that we’re doing our part to manage that process and to plan ahead and to make sure that our applications are complete. Keep in mind though that the Alberta NGL regulator is only one of in many cases only one of several approvals that we need to get before we can proceed with a project like Josephburg for instance.

And so we need to manage all aspects of the regulatory process.

And are you finding that easier now? And then when you look at actual build-out, how are your cost pressures looking?

There's a lot of people in the midstream business sector that are incredibly busy.

Well I think Jim alluded to that a little bit in his comments and we talked about that in our last conference call in August. We’re certainly seeing some increases in capital costs associated with the high degree of activity in the infrastructure sector.

At this point I think we’re being pretty good about planning ahead and managing the commercial arrangements appropriately.

And then a final question then for Steven. On the partnerships, wasn't there a five-year phasing on those?

And so, are we getting close to the lag from the partnerships, that they'll then be coterminous with corporate year end?

Yes we’re getting closer to that, there was a five year phase-in period. But we’re still -- I believe we have one more year left on that benefit that we received.

Thanks very much guys, keep going. This has been great.

On the new contract at South Cheecham, I'm just wondering if this additional agreement brings utilization of diluent and offloading capacity to near 100%, or is there still some remaining first-phase capacity available?

Hi Elaine, it’s David Smith here. The new contract at South Cheecham is for solvent, it’s for segregated offloading and storage of solvent, much like we’re doing currently at the Alberta terminal in Edmonton.

So it doesn’t affect the condensate capacity. And in fact, we still have available capacity for offloading the condensate at South Cheecham.

Great. Thanks for the clarity.

Given the Cochin line reversal and that your Josephburg terminal won't be online until mid-2015, I'm wondering if you can give us some insight into what your outlook for the Western Canadian propane market is for this year's heating season, kind of assuming average weather for North America.

I think North America is well supplied for propane, but I think what we saw last winter is that weather can have a severe effect depending on how severe it is and how long that severity is and where the storage is. I think what we’re observing so far this year is that the downstream customers have somewhat learned their lesson and are filling their storage a little earlier in the season.

So that may have the effect of [sliding] out the demand somewhat. But it will still depend on weather and as you pointed out we and Western Canada do not have the alternative of using Cochin pipeline anymore.

And so for increased exports will have to rely pretty much entirely on rail.

And finally, you've noted in the past that you’re like fixer-uppers, buying a plant and building it into your system. Can you comment on the current state of acquisition opportunities in terms of the availability of these opportunities and the willingness of owners to potentially sell their interest in plants?

We’re still like fixer-upper, but it’s always hard to guess project what’s out there. I’d say that we continue to have lot of discussion about certain facilities that we like and their worth producers.

I think with little bit of shock in the commodity today maybe some are going to be more willing to look at selling assets or joint venturing on assets. So I think we’ve got our antenna up, I think we have a good reputation as an operator of these facilities and I think more and more producers are looking for that integrated approach to not only processing but then managing their liquids into the market place, so I would say we’re -- I’m personally a little more optimistic that there is some opportunities out there.

Thank you very much. And let me add my congratulations on the great quarter and also to your recent new appointments to both you, Jim and David.

So, just with regards to maybe following up a little bit on the isooctane conversation, can you talk about what kind of premium Keyera's able to capture above and beyond say the RBOB or CARBOB butane differential as a result of your rail, truck, and marketing activities?

David I can’t be too specific. The arrangements that we have are a variety of arrangements with different terms on different basis with different customers.

And so it’s hard for me to be specific. And those are all subject to confidentiality restrictions with our customers.

Yes. So, if you gave an average and a customer’s worried above that average, that'd be an issue.

Got it. Okay.

We'll move on then. And maybe then just in terms of the propane opportunity.

Can you talk just a bit about what you're seeing in the Midwest crop drying opportunity and how the absence of Cochin changes that dynamic for you?

I am sorry David could you repeat the question.

Yes. Just talking about crop drying in the Midwest, and now that the Cochin is no longer bringing propane out that way, how does that change the opportunity?

And what are you seeing in terms of rail volumes?

Well I think certainly as I mentioned earlier all of the volume that -- all of the export volume from Western Canada is going to have to go by rail essentially. We’re seeing some demand as we speak from crop drying in the U.S.

but the harvest has been quite late. So, it’s still a little early to be able to say what the impact of crop drying demand might be.

And so at this point, that’s probably as much as I know.

Yes. So, your marketers, no expectation in their minds of what they're anticipating?

I think the expectation is that there will be some demand for that, whether it will be as much as last year not it’s still too early to be able to say.

Okay, fair enough.

And some point to remember to that on the commodity price side of it, we have adopted a new mechanism or sale process for propane where we pass along in the commodity exposure -- commodity price exposure to our supplies of propane to producers. So again just like you saw last year we didn’t really benefit from the increased pricing we did from the strong volumes but not the price itself.

Yes, and I guess what I was thinking is that, if you had more volumes going on the rail versus going on the Cochin pipeline, that you might be picking up an incremental margin because, as opposed to using a third-party transportation system, you're using your own. So, even if volumes might be slightly down year over year, it's more on your rail and therefore, there's more margin to be made.

Is that the wrong way to be thinking about it?

I don’t think that effect would be material David. I think you’re probably correct but it’s not going to be something that is material.

Fair enough.

One of the direct results we had with the Josephburg Terminal, we proceeded with developing the Josephburg Terminal as a way of replacing Cochin pipeline. So obviously that’s a Keyera owned infrastructure and we’ll be able to charge some revenue for that, for helping producers get propane out of Alberta.

Right makes sense. Just in terms of the South Cheecham and if you've already said this, I apologize.

But is there -- what's the CapEx related to the solvent handling services agreements?

No, we haven’t disclosed that just for our proprietary reasons.

Okay. And can you provide any more detail regarding the JACOS and Nexen dealer transportation service agreement?

Obviously, it starts up in 2016. But in terms of volumes relative to your other three contracts with Imperial, Husky, and Synovus, how does this compare?

Well, I think it’s smaller than the first two, David. But we’re not going to sort of get into the business of getting specific on volumes by contract.

I think the point of us talking about that is really just to explain that our numbers -- our condensate system is supported by contracts with a growing number of different customers.

Okay. All right.

And then, Jim, maybe just one last question. Is the Synovus diluent agreement contributing uniquely to your NGL structure results yet?

I am sorry David I didn’t hear the question.

Okay. I was just wondering.

The Synovus diluent agreement -- handling agreement, is that contributing meaningfully to your NGL infrastructure results yet?

Yes, that contract has already started. And it phases in over time.

Again, along with my comment about JACOS it’s just it’s one of the several contracts that we have in place now. It’s just illustrative of the growing demand and growing revenue that we’re receiving on the condensate systems.

Okay. Great.

Thank you very much. Those are my questions.

Good morning, and congratulations on the new roles. I guess, I have to ask an isooctane question as well.

So, just on isooctane, just looking at Q4 and Q1, I understand that RBOB's coming down. But, would it also be correct to assume that your isooctane premium will also compress during these periods as well?

Generally no, Rob. I think as I said earlier we don’t anticipate that the volumes will be affected by the seasonality and we don’t anticipate that the premium for isooctane is going to be affected materially, it's really just the fact that gasoline prices has reflected in the RBOB premium tend to be softer in the winter time.

Okay. Good.

Thanks for the color and then maybe just looking at your 2015 CapEx number. Would you have a rough estimate of the breakdown between gathering and processing a NGL and I guess when these projects could potentially come online?

Again I would describe that $700 million to $800 million range as being a combination of approved projects as well as a portion of some of the projects that we’re currently evaluating that we think are probable and so there is a combination there. But for -- I would probably assume so to half-half between G&P and NGL infrastructure in this upcoming year.

And so, the ones that are not approved yet, should we assume that these are kind of two-year construction projects?

There is actually a combination of smaller projects as well, just as you can appreciate ones you start developing assets, there are follow on kind of opportunities and smaller opportunities. So, what I’d probably say, at least half will be the longer timeframe.

Alright that’s great, thanks for the color.

Thanks Liza. This completes our 2014 third quarter results conference call.

If you have any other questions please call us, our contact information is in yesterday’s release. So thank you for listening and have a good day.