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

David McColl – Morningstar Linda Ezergailis - TD Securities David Noseworthy – CIBC Carl Kirst - BMO Capital Rob Hope - Macquarie Robert Catellier - GMP Securities Matthew Akman - Scotiabank Robert Kwan - RBC Capital Markets Steven Paget - FirstEnergy

Thank you, Steve, and good morning. It's my pleasure to welcome you to Keyera's 2014 second 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 general 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 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 website. We encourage you to review the MD&A which can be found in our 2014 second quarter report, which was published yesterday and is 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. Thank you for joining us this morning on the call.

Keyera reported another strong quarter as demand for our services continues to grow. Liquids rich natural gas drilling and ongoing oil sands development continue to drive expansions of our existing operations and offer new business opportunities.

I am pleased to report that all financial metrics were higher in the second quarter of 2014 compared to the same quarter last year. Net earnings in the second quarter were $62.9 million or $0.78 per share and adjusted EBITDA was $143 million, 44% higher than the second quarter of last year.

Distributable cash flow of $84 million or $1.04 per share was 3% higher than the same period last year despite significant maintenance capital expenditures and higher cash taxes. Dividends declared to shareholders were $51 million or $0.63 per share reflecting our 7.5% dividend increase in May to $0.215 per month.

Our payout rato for the quarter and full year was 61%. Steven will talk more about our financial results later in the call.

Strong demand for processing continues at many of our facilities as producers continue to drill for liquids rich gas. Higher throughput at many of our gas plants and the addition of the Cynthia gas plant volumes offset the effect of turnarounds at four of our gas plants in the second quarter.

Net throughput volumes of 1.1 billion cubic feet per day was 6% higher than the second quarter 2013 volumes. Drilling activity is very strong both in the West Central region of Alberta where we have several large gas plants and in the Deep basin area around our Simonette gas plant.

In West Central Alberta, producers are focusing on a number of geological zones, including Glauconite, Cardium Fuller [ph] and Spirit River horizons and the resulting production is driving throughput growth at our Rimbey, Minnehik Buck Lake, Strachan, West Pembina, Nordegg River and Brazeau River gas plants. In the deep basin area, the Montney zone continues to be the primary focus for producers and this is driving throughput at our Simonette gas plant.

Producers are also targeting the Duvernay Horizon in both the Simonette and Pembina areas adjacent to Keyera facilities. Although it’s still early delays for the Duvernay, the land position, increased activity levels at many of the major producers in these areas suggests that this liquids rich horizon has significant potential.

To keep up with the increased demand for processing, we are working on a number of infrastructure solutions to expand and optimize our operations, relieve processing constraints, add operational flexibility and provide enhanced service levels for our customers. The Cynthia gas plant, which we acquired in the second quarter, is a great example of this and will be a great addition to the Kayera network.

It has deep cut processing capabilities that are complementary with other assets in the region and is located in close proximity to our Bigoray, Pembina North and Brazeau North gas plants, in addition to acquiring an 85% ownership interest in the Cynthia 6-20 gas plant. We also acquired the corresponding working interest in the lands from which gas is produced into the plant, as well as the remaining 4.6% interest in the Bigoray gas plant, bringing our ownership in that plant to 100%.

A dispute with a third party was resolved in Keyera's favor, and it allowed us to complete the acquisition. Total consideration was $113 million.

The plant successfully completed its turnaround in May and in June we became the operator. The integration is going well and we're looking at ways to connect this plant with Kayera’s other facilities in the area.

In West Central Alberta, we reached definitive agreements for phase 2 of the Twin River gathering pipeline, which will extend the pipeline an additional 25 km south. The 12-inch line will not run south from the Brazeau River plant to south of our Nordegg River gas plant, to connect with existing Keyera pipelines as well as existing producer owned pipelines.

We expect to begin production later this year. Our goal is to have phase 1 operational in the first quarter of 2015 and phase 2 flowing gas in the second quarter of next year.

The Wilson Creek pipeline and Carlos offload pipeline project were both completed and brought online in the second quarter. The additional volumes from these projects helped the Rimbey gas plant reach its highest throughput level in over two decades.

After receiving all regulatory approvals in April, construction of a turbo expander project at Rimbey gas plant is now underway and we expect to have the project up and running in the second half of next year. To stay ahead of the growth in liquids rich gas production in the area we plan to expand the fractionation and NGL truck offload capacity at Rimbey.

These expansions are expected to add approximately 6900 barrels per day of fractionation capacity and over 6000 barrels per day of additional NGL mix offload capacity at the NGL truck offload terminal. With the production growth anticipated from the Cardium, Ellerslie, Glauconite and Duvernay zones in this area, we continue to assess the work required to increase processing capacity by operating both the lean oil system and the new turbo expander simultaneously.

Drilling activity continues to be robust in the deep basin around the Simonette plant. As mentioned earlier, we’ve been successful in fully contracting the capacity on the Wapiti pipeline system as well as increasing commitments for gathering and processing services at the plant.

Since resuming work on the Wapiti pipeline in July, we’ve made considerable progress and assuming no further delays we expect to put the pipeline into operation in the third quarter. We are continuing to make minor modifications to the Simonette gas plant in order to process the growing volumes of liquids rich gas being delivered there.

In September, we will take the plant offline in order to complete the tie-ins for the 100 million cubic feet per day gas plant expansion scheduled for later this year. Construction of the 10,000 barrel per day condensate stabilizer at the plant has commenced and fabrication of the equipment is completed.

The stabilizer is currently on schedule to be operational by the end of the year. The Strachan, West Pembina, Caribou and Cynthia gas plants successfully completed scheduled maintenance turnarounds in the second quarter.

In the third quarter we have two plant outages at the Rimbey and Simonette gas plants started to undertake the process improvements mentioned earlier as well as complete tie-ins for the new projects underway at each facility. With that, I would like to turn over to David to review our liquids business unit.

David?

Thanks, Jim. The liquids business unit also reported strong results in the second quarter.

The NGL infrastructure segment once again posted record operating margin 68% higher than the same period in 2013. The NGL infrastructure segment continues to benefit from growing demand for fractionation, storage, transportation and other liquids logistics services as producers increased production of both liquids rich natural gas and bitumen from the oil sands.

Higher volumes and fees for services associated with NGLs, crude and isooctane drove the year-over-year increase in operating margin. The growing demand for services in this area of our business highlights both the diversification of our service offering and the value that our integrated operation provides for our customers.

We continue to pursue enhancements to our service offering to address the infrastructure required by oil sands producers. In May we announced that we will be participating as a 30% non-operating owner in the Enbridge Norlite Pipeline.

Besides adding to Keyera's long-term take-or-pay and fee-for-service cash flows, Norlite will also be a great complement to our other diluent handling services in the area. We will use our Fort Saskatchewan condensate system to deliver the volumes into the Norlite pipeline, providing the Norlite shippers with access to multiple sources of diluent supply.

Enbridge will construct and operate the Norlite pipelines and they anticipate having it in service in 2017. Norlite is now planned to be a 24-inch pipeline and Enbridge estimates the total costs to be approximately $1.4 billion.

We recently began receiving condensate at our Fort Saskatchewan facility from the Kinder Morgan Cochin pipeline which has been converted to north-bound condensate service. Our connection is the only receipt point for diluent delivers into Alberta from the Cochin system, further enhancing the operational flexibility of our condensate infrastructure in the Fort Saskatchewan area.

Demand for diluent storage also continues to steadily increase and we continue to expand our underground storage capacity on site to meet this demand. Our 13th and 14th caverns are currently under development and we're already planning for the next phase of cavern development which has the potential to add approximately 4 million barrels of storage capacity.

As part of this next phase we expect to begin drilling our 15th cavern later this year. We’ve spent a number of years creating a condensate system that provides producers with the flexibility to access a variety of receipt points, storage facilities and rail and truck terminals and the demand for these services suggests that our customers are seeing the value in using our system.

We made significant progress on our de-ethanizer project at Fort Saskatchewan in the second quarter. All of the major components have been placed on site and we're working to complete the installation.

We now anticipate that the gross total cost will be approximately $200 million and the project will be operational in the first quarter of 2015. Also at Fort Saskatchewan, detailed engineering work is well underway on our C3-plus fractionation expansion.

We expect this project to be on stream in the second quarter of 2016 assuming timely receipt of regulatory approvals and no changes to our construction schedule. To address the growing need for propane transportation capacity within Alberta, we are developing a rail terminal at Josephburg, located near our Fort Saskatchewan fractionation and storage facility.

The rail terminal will initially be constructed to load propane barrels to provide access to propane markets across North America. We currently anticipate having the terminal in operation next year.

At Hull Texas, we expect to complete the work to reactivate our rail and truck terminal in the next several weeks. Initially we anticipate using the facility to facilitate deliveries of propane, butane and NGL mix in and out of local markets.

Longer-term with connections to Mount Belvieu and other area infrastructure we expect the facility will integrate well with our NGL business in Western Canada. We're pleased with the growing operation at our South Cheecham rail and truck terminals south of Fort McMurray, as well as the interest we're seeing in additional services at the facility.

We continue to pursue expansion opportunities for storage and transportation of diluent, solvent, bitumen and other products at the site. Construction of our Alberta crude terminal at Edmonton is progressing well.

We recently completed construction of a 12-inch condensate pipeline to connect our Alberta diluent terminal to our Fort Saskatchewan pipeline system. Completion of this work allows us to begin delivering crude oil from Kinder Morgan’s terminal to our site and we’ve begun loading crude onto rail cars on a limited basis this quarter.

All 20 spots are expected to be fully operational in the fourth quarter. We are currently in discussions with customers to determine our level of support for a future expansion.

In our marketing segment, we had another good quarter delivering operating margin that was 13% higher than the second quarter of 2013. Higher sales volumes and higher margins in our isooctane business contributed significantly to these results.

Overall second quarter sales volumes were 83,000 barrels per day, the same as in the second quarter of last year, as higher isooctane volumes were offset by lower volumes from the other products in the quarter. The combination of new customers, strong margins and solid risk management practices resulted in our isooctane business contributing strongly to our results in the second quarter.

Increasing demand allowed our Alberta EnviroFuels facility to operate at close to capacity in the second quarter. We continue to develop new market for isooctane and we are utilizing our storage arrangement at the Kinder Morgan Galena Park facility to support isooctane sales in the US Gulf Coast.

In the second quarter we completed modifications at the Edmonton terminal to increase our isooctane rail loading capacity and we are currently adding a truck loading terminal at Alberta EnviroFuels to provide better service for local customers. Butane demand and butane margins remained solid in the second quarter, again contributing to strong marketing results.

We continue to use our storage and rail capabilities to import butane volumes in order to effectively manage our feedstock requirements at Alberta EnviroFuels. We expect butane prices will remain weak for the rest of this year due to a surplus of propane across North America.

Condensate supply and demand remained balanced in the second quarter of 2014. Diluent demand has been lower than initially expected this year but as bitumen production begins to ramp up we will continue to look for opportunities to import condensate when the economics are favourable.

Finally our crude oil and midstream activities continued to post solid results in the second quarter of 2014. With that, I will turn it over to Steven to discuss the financial results in more detail.

Thanks, David. We're pleased with how well all segments of the business performed this quarter.

Adjusted EBITDA was $143 million, 44% higher than the $99.4 million recorded in the same period last year. The growth we experienced in all three of our business segments led to record operating margin for the quarter.

Of note, a large portion of this growth in adjusted EBITDA came from our exiting asset base and day-to-day operations rather than the newly commissioned projects, once again pointing to the solid foundation underlying Keyera’s business. In the same vein, net earnings were $62.9 million or $0.78 per share compared to $48.2 million or $0.62 per share in the second quarter of 2013.

In the second quarter, distributable cash flow was $84 million or $1.04 per share compared to $79.3 million or $1.01 per share in the same period of 2013. This result was achieved despite the inclusion of approximately 35 million of maintenance capital related to the four scheduled maintenance turnarounds completed in the quarter.

Dividends declared to shareholders were 51 million or $0.63 per share. This resulted in the payout ratio for the quarter of 61%.

Keyera increased its dividend by 7.5% from $0.20 per share per month to $0.215 per share per month or $2.58 per share annually, beginning with this dividend paid on June 16, 2014. This is Keyera’s 12th increase since going public in 2003.

Overall more than two-thirds of Keyera’s second quarter operating margin was from fee-for-service businesses with the remainder coming from the marketing segment. Our gathering and processing business posted record results in the second quarter, delivering operating margin of 64 million.

Strong second quarter results can be attributed primarily to continued growth in throughput at many of our facilities. This operating margin also reflects two months of operating margins in the newly acquired Cynthia gas plant, including recovery of Keyera’s share of turnaround costs.

The Cynthia turnaround costs are also recorded as an expense in the other income segment where Keyera’s margin from producing assets, including Cynthia, are recorded. The liquids business unit also delivered record results in the second quarter.

Second quarter operating margin in the NGL infrastructure segment was 49 million, 68% higher than the 29.1 million recorded in the same period in 2013. This increase reflects continued demand for 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 charged to the marketing segment with respect to the Alberta EnviroFuels iso-octane production facilities. The marketing business generated 52.8 million of operating margin in the second quarter compared to 46.8 million in the second quarter last year.

Excluding unrealized gains and losses from both periods, second quarter marketing results in 2014 were approximately 10 million higher than the same period last year, largely driven by stronger isooctane volumes and margins. The isooctane portion of the marketing results is significant reflecting high facility utilization and attractive commodity prices.

It is important to remember though that isooctane results tend to be seasonal with results typically stronger in the second and third quarters. Keyera’s general and administrative expenses were 9.2 million in the second quarter compared to 5.4 million in the second quarter of 2013.

This is largely due to higher staffing levels and other related costs to support Keyera’s growing busiess. Long-term incentive plan costs were 12 million in the second quarter, 5.1 million higher than in the second quarter 2013.

The higher LTIP expense this year was primarily due to the growth in share price in 2014 compared to 2013. Finance costs were $13.7 million in the second quarter, $0.7 million higher than in the same period in 2013.

And the value of inventory at quarter end was $193.8 million, $24.3 million lower than at June 30 last year. Keyera incurred $6.8 million of cash taxes in the second quarter compared to only $0.6 million in the second quarter 2013.

Keyera’s 2014 income tax largely relates to 2013 taxable income from the partnership within Keyera’s structure. As a result, Keyera estimates that its cash taxes in 2014 will be between $35 million and $40 million.

The increase in cash taxes in 2014 compared to 2013 is largely due to the growth in Keyera’s business and less available deductions. Certain capital expenditures are not able to be claimed as a deduction for income tax until the assets are available for use.

Hence taxable income can vary significantly from year to year. In the second quarter, we issued over 4.3 million new common shares via a public offering at a price of 73.75 per share with total gross proceeds of approximately $318 million.

We also closed the final portion of the private debt placement announced in the third quarter of 2013 receiving proceeds of $75 million in April. Our capital liquidity continues to be strong with a net debt to EBITDA ratio of just under 1.8 times at quarter end compared to restrictive covenant of 4 times.

As a result, Keyera is well-positioned to execute its growth plan and to pursue acquisitions if appropriate. Finally we’ve included our second quarter supplementary information on our website concurrent with the release of our second quarter 2014 financial results.

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

That concludes my remarks, Jim.

Thanks, Steven. I continue to be optimistic about the opportunities I see ahead for Keyera.

We continue to develop and expand our network of interconnected plants, pipelines and facilities in order to enhance our service offering for our customers and allow them to access our entire value chain. As the leader in delivering midstream solutions, our focus is on ensuring that there is safe and reliable infrastructure in place to meet the needs of our customers.

In addition to over 1.6 billion in projects under development, we have several opportunities under evaluation. We now expect to spend between $700 million and $800 million this year on projects already sanctioned and underway and we see no signs of growth opportunities slowing down.

This is a challenging time to be undertaking this level of capital investment. There continues to be a high level of activity throughout the oil and gas sector in Western Canada which places pressure on costs, schedules and availability of skilled workforce.

We understand the many factors that have contributed to successful project execution and are committed to continue to work with our partners, customers and contractors to deliver quality infrastructure solutions. Despite these challenges we continue to believe that Keyera’s combination of strong base business and accretive growth opportunities should allow Keyera to continue to provide stable and growing cash flow to our shareholders in the future.

John, that concludes my comments.

Thanks, Jim. Steve, please go ahead with the questions.

Good morning, everyone. Thanks for taking my question.

I'm taking a look at the project list, and I notice there's been a little bit of - it looks like capital cost inflation maybe with some of the projects. I think we had the Fort Saskatchewan ethanizer was up around 20 million -- in total.

I just want to focus on the Strachan gas plant. What was really behind that significant increase in cost?

I know the original estimate was 50 million and then jumping to 115 million. Was that just the case of once you started to dive into it, you maybe made some changes to what you originally thought or is there an undercurrent of cost pressure happening here that we might need to deal with in the future?

It’s David Smith here. I will respond to that.

The fertilizer facility at the Strachan gas plant is being constructed by our partner Sulvaris and I think it’s not a new technology but it is a somewhat new effort for them and i think we've been working a lot more closely with them as they’ve revised their estimated cost to complete the construction of the facility. It certainly was a surprise to them and a surprise to us but I think they and Keyera are both quite confident that this is still a very economic project despite the increased -- estimated increase in cost.

So that increase is more maybe just a case of a bit of newer effort, new experience for them, not necessarily anything really pushing up the pressures?

In the case of – I think it was really just mostly due to some poor upfront estimates coupled with the fact that the construction -- the fact that they were constructing during the winter ended up adding a fair bit to the cost that they weren’t expecting.

I appreciate the update on your capital spend for 2014. Can you give us just a consolidated update on how much is related to maybe shift in timing, accelerating from 2015 into 2014, cost increases versus actual new scope and new projects?

Sure, this is Steven here. I would describe it probably more as – probably two different variables – I am not sure I am going to give a little bit feedback here or not but three different variables – one would be that now that we are into Q3, we’ve had more visibility throughout the year in terms of our pace of spend and comfort in terms of that spend profile on projects like Rimbey turbo and Simonette projects, that would be the – one of the key elements in terms of why we adjusted our capital spend range.

Additional products like the Twin River’s expansion scope there going from $25 million to 80 million on that, again some of those projects aren’t all spent in 2014. So there is a lot of puts and takes in terms of how we look at coming up with the capital range but I wouldn’t say it was more acceleration of capital, I would – some projects were as we highlighted in the Q2 experiencing some delay into next year, but the bulk of that really is the greater certainty on the pace of progress on projects like Rimbey and Simonette as well as Twin Rivers and then a minor or smaller piece, 25%, 30% of it will be more with respect to costs on some of the projects there.

And maybe while we're on the subject of higher CapEx, can you talk about maybe your updated financing Plan A for the balance of this year and next year?

Yeah, from what we can see in our view of projects that we've approved to date so far, we are well-funded for project execution and in the past 12 months we’ve raised over $800 million externally through private notes and equity. And again we still have an unused revolver, the liquidity ratios are very strong 1.8 times versus four times covenant that we have.

So right now we feel very comfortable with our current approved project list in term of funding.

Now this CapEx doesn't really include significant acquisitions. I don't know if Jim wants to take this question.

Can you maybe talk about what sort of acquisitions you might be seeing either incremental from producers wanting to shed assets or maybe corporate transactions or anything else?

I think, Linda, we continue to look for things I guess like this Cynthia acquisition we just completed, they are always lumpy, so you never really know how many out there. I would say there will continue to be one-off opportunities for to acquire gas plants but it's lumpy.

In terms of major acquisitions certainly I don’t see anything on the horizon for us.

I was just wondering if you could just talk a bit about the fact that several of your facilities are now operating at or near full capacity, we have an expansion at Simonette. We have something happening at Rimbey.

But what are the opportunities for new debottlenecking projects, and kind of what is your timeline for putting some scope around that?

It’s David Smith here. As you know within our gathering and processing network it's very situation.

As you pointed out we are looking at expansion of capacity at, where we have an expansion underway at Simonette and with the addition of our turbo expander at Rimbey we think we will be able to expand the inlet capacity of that facility, fairly readily with a modest amount of capital as we look forward at continuing growth in volumes in that area. One of the areas that’s very interesting for us right now is that is the whole West Central Alberta area where we have a network of gas plants.

We just recently added the Cynthia gas plant which has unutilized capacity and we are seeing increased volumes of liquids rich natural gas developments throughout that area. The first step for us is to -- basically to debottleneck the gathering system so that we can get the gas to the plants that have spare capacity, like Brazeau River, like West Pembina, like Cynthia.

And we are actively doing that, that's really the thrust behind our Twin Rivers pipeline project is to get the gas into Brazeau River and West Pembina where we have still unutilized capacity. The next step of course is to look at where is the optimal place to expand capacity and we have a study underway right now to understand where the capacity is needed, what's needed and where we can add at most efficiently in the network.

We are actively talking with the producers in the area to try and understand what their plans and preferences are and we would hope to be able to have a plan put together sometime over the course of the next 12 months.

The 12 months is kind of the timeline there –

Well, it could be sooner, the reason I say that is simply because we do still have -- our near-term priority is to debottleneck the gathering as I mentioned and we do still have unutilized capacity at some of the plants. But we are planning for the future and trying to make sure that we’re ready to be able to add capacity when and where it’s needed.

And maybe just take a moment to look at the Alberta EnviroFuels. So if I understand correctly, it was pretty much operating at full capacity.

Is your expectation to continue to operate this at full capacity in Q3 and beyond or is this kind of more seasonal? We'll see the fluctuation in capacity utilization based on the market?

No, I don't really expect that the utilization of AEF will be demand limited. In the past utilization has been limited by our ability to distribute the product.

But now that we have expanded our rail loading capacity at the Edmonton terminal, and added our storage arrangement in the US Gulf Coast, I think those -- I don't expect those constraints on the distribution side to be a factor into the future. And there seems to be pretty healthy markets throughout North America for isooctane.

And we continue to see new customers. So I don't really expect the production there will be demand limited.

I think our expectation -- subject to keeping the facility operating smoothly our expectation is that it will be operating close to hundred percent on a steady state as we look forward.

And maybe one other follow-up question on AEF. In terms of the iso-octane margins that we saw in Q2, it seems like we're seeing something similar, at least CARBOB and butane in Q3.

Is that what you're seeing?

I think that’s fair, yes. The price of isooctane as you know trades -- basically trades in relation to price of gasoline and typically it’s price off of either CARBOB and because of the seasonality of the driving season we see stronger margins in Q2 and Q3 and somewhat weaker margins in Q4 and Q1.

So I would anticipate that Q3 margins would be similar to Q2.

Maybe just staying with David's questions on AEF, because obviously Galena Park down here, our lovely ship channel is obviously giving you guys great access to kind of keep that utilization up at 100%. And I know in times past there has been kind of questions of whether or not you would consider expanding AEF.

Has the recent profitability and percent utilization got you rethinking that at all?

Not in the near term, Carl, I think the challenge with expanding AEF in any material way is that the capital cost associated with that is quite. As you know we purchased the facility at a substantial discount to the cost of a new facility – the replacement costs.

There are some debottlenecking things that we are looking at but they would be very very modest in terms of the additional capacity that we would be able to add. So in the near-term I don't anticipate that we would be looking at an expansion of the capacity there.

Fair enough. And I'm not sure how much granularity you can provide, but as we look at year over year, for instance, over second quarter last year and Steven, I think you said the isooctane margin was significant this quarter.

I wasn't sure if you were talking about the $10 million delta or if you were talking about in fact the composition of the entire margin. But kind of in its broadest sense, I was trying to kind of get a sense of how much did, perhaps, AEF and the AEF opportunities add to these great results here in the second quarter perhaps year over year, if that's something you could give?

I think the primary driver on the increased absolute margin in terms of million dollars is – was the 100% utilization or near capacity compared to last year where we had – we had an outage in June in 2013 last year. So the primary drivers is the volume side, margins themselves in terms of commodity prices were slightly stronger as well, again probably bolstered by continued weak butane prices in North America.

And so you’ve got the feedstock costs on one side, and you’ve got the RBOB or gasoline side on the other side. RBOB was strong just like last year and butane continued to be attractive similar to last year as well if not little bit more attractive.

And then maybe then last question if I could, just trying to turn to the addition of Cynthia and the incremental income that came from the reserves. Is it possible to say how much of the year-over-year delta in GOP and GNP came from the Cynthia-related acquisition?

Yeah, you got to be little bit careful with that. The Cynthia acquisition shows up on two portions of our business, the gathering and processing side, which is collecting the fees from the gas plant, including recovery of the turnaround costs and so I think that was highlighted in the MD&A, and as well under other income, of the producing assets which were producing margin show up there but it’s also burdened with – that same turnaround costs, $5 million of turnaround would show up in revenue on the gathering and processing side but it will show up as an expense on the other income side.

Overall I would say it was relatively modest, pretty modest actually for Q2, the Cynthia contribution, largely because the turnaround is all expensed and incurred within that quarter. We would expect much bigger increases in Q3 and Q4.

Congratulations on the good quarter. I just wanted to touch maybe on the return profile of these gas plants as they fill up.

Should we assume that returns could increase faster than volumes due to either fee increases or potentially producers willing to pay extra to secure access to capacity?

Rob, it’s David Smith here. That’s a difficult question to answer in general terms.

Certainly at plants where there are concerns about availability of capacity we have been working with producers to provide firm service and there is usually a fee associated with that reservation. So I think in certain circumstances that will be the case.

We always have to be cognizant of the long-term outlook for our business. We want to encourage producers to drill around our facilities and we want them to be happy customers.

So we need to make sure that our arrangements with them and our responsiveness to the need for additional capacity which encourages that long-term relationship. So even though sometimes you might assume that there are opportunities in the short-term to make higher fees we’re generally pretty cautious about that.

The thing that is I think quite exciting about what we are seeing here really toward the network is the fact that the increased volumes are leading to opportunities for new investment in infrastructure to debottleneck and expand capacity and add NGL recoveries. And right now we see that continuing into the future.

Maybe just switching gears a little bit, maybe now looking at your condensate infrastructure at the Fort Saskatchewan system, or in the Fort Saskatchewan and Edmonton region. With an expanded Norlite, have you given any thought to how much capital potentially you'll need to invest there to meet existing and future obligations there?

Certainly that’s an important part of our planning. We think we know where the challenges will be, where their constraints will be in the future and we have a plan in place to address those.

There are a lot of uncertainties and moving parts to that question, so it's hard for me to give you anything specific in terms of dollar amounts or timeframes. We are continuing to expand our underground storage capacity really as fast as we can, because that's clearly going to be -- going to continue to be in demand, as Norlite and other pipelines get built.

The Edmonton, Fort Saskatchewan corridor is another area from a transportation point of view that we’re looking at. As you know we have a 16-inch pipeline between Edmonton and Fort Saskatchewan.

It’s adequate for the near-term but that may be something that we need to look at in terms of expanding that, that may be the next increment of capacity that we need. And of course keep in mind that Norlite is one of several condensate pipelines that are underway or being proposed north out of our Fort Saskatchewan Edmonton hub.

So we’re pretty excited about the outlook for future demand across-the-board.

Just a quick follow-up on AEF here, given the current capacity utilization high and the continuing outlook there. Presumably the addition of some trucking capability has more to do with margin expansion than market reach?

I think that’s fair, Rob. As I mentioned earlier we’re not demand limited.

I think so what we’re trying to do is to make sure that we’ve got access to as many different markets as possible. We have local customers in the Alberta area and in Western Canada that we can serve with trucks, and we have new customers that we’ve been developing in the US that we can access by rail.

So I wouldn’t anticipate that any of that is going to materially increase the volume but hopefully over time that it will lead to additional margin.

And then Jim, I wondered maybe if you could talk a little bit about how you see the strategic importance of enhancing the company's gathering and processing capability, specifically in the Montney. And somewhat related to that, what's your appetite like for the buy-versus-build decision?

Do you have an appetite to go ahead and build a greenfield site?

I think Dave talked about some of the things we’re doing right now to expand our capacity and first and easiest and cheapest is always to I think expand your infrastructure -- gathering infrastructure to make sure you fill up what you’ve got. It certainly is easier and cheaper to have a brownfield expansion and I think given our 16 plant locations we’re optimistic that we can expand at existing sites given extensive gathering systems and in some cases frac capacity and pipeline and truck facility.

So if you’ve got to go out and build all that in a greenfield site, clearly is expensive today and very time-consuming and of course burdened by regulatory schedule. So I think our preference is to expand where we’re at.

We’re not afraid to build greenfield and we continue to look at it and we have some opportunities I believe over the next two years to build greenfield facilities given the demand out there. If you can acquire it at the right price, acquisitions certainly fit.

I have always said I think we’re good at fixer-uppers and it’s allowed us to buy plants that we like in areas where we like the geology and build into our system. So I think we’ve looked at all of that and if you look back historically we’ve had a lot of success buying gas plants in areas that we anticipated we’re going to have good geology.

So it always comes down to rocks. So I think we look at all that Robert but we’re certainly not afraid of greenfield, it’s just in today's environment you'd better be honest with yourself about the kinds of capital risks and time you take to do those projects.

But they certainly are needed out there in certain locations.

Yeah, but just to delve deeper on the rocks issue, I'm curious if -- how strategically important is it for Keyera to expand its presence or footprint in the Montney?

Well I think we like the Montney a lot. I mean we've got a very strategic pipeline into the Wapiti area which comes on stream here this quarter.

I think if you look at any of the materials that’s out there, talk to any of the producers that are in those areas, that Wapiti -- that part of the Montney has very liquids rich slightly sour but maybe one of the most economic plays in Western Canada. So we’re certainly going to continue to look for opportunities there whether it's expanding what we've got and that’s probably one area where I think industry does need more greenfield plants, no doubt about it, the Wapiti, [indiscernible] area in the Montney requires plants and as do the key – Simonette, Duvernay play types -- the existing facilities aren’t going to do it there, they’re going to need somebody step up and build a number of hub facilities I believe.

My final question here has to do with sort of the CapEx inflation that was outlined in the quarter. Keyera I think talks more about the need to be cautious on CapEx than probably anyone else publicly.

And yet there's still a little bit of slippage in the quarter on dates and some of the budget amounts. So I wondered maybe if you could walk through a little where you found the biggest surprises, and what the learnings were there.

I will try this, Bob, because it is my job I think to be on top of this stuff. I don't think our experience is any better or worse than others in the industry.

Maybe we’re guilty of perhaps being more honest than others, I don't know. The factors really vary quite widely, in some cases we had some issues with weather in the winter of this year and other cases quite honestly we had some miss-estimates at the early stages of the projects.

It’s a situation where it’s hard to kind of looking back on it, it’s hard to see where we could have done better but we just didn’t estimate very well going in. Keep in mind that many of the projects that -- most of projects that we have underway are not cookie-cutter, these are fairly complicated from an engineering point of view.

You are installing projects at facilities that are already operating 24 hours a day seven days a week. And so it's sometimes difficult to anticipate all of the elements that are involved.

Having said that we’re not happy about some of the slippage that we've seen and we’re trying to make sure that as we go forward that we learn from our experience, that the ethanizer at Fort Saskatchewan for instance is an example of that. We’re embarking on the engineering for the frac expansion, that’s the next big projected for Fort Saskatchewan and we’re spending a lot of time making sure that we apply the lessons we’ve learned at the DS project to the frac expansion project.

David. I didn't mean to imply that you had any particularly adverse experience relative to your peer group.

Just you're a little bit more forthright in acknowledging the risk in the environment.

The other thing I would add, Rob is that couple of the projects, the Hull terminal and Alberta crude terminal for instance, they’re essentially complete at this point. So we don't certainly anticipate any further surprises and we’re still very excited about the economic prospects for those sites once we get them commission and operational over the course of the next couple months.

Most of my questions have been asked. I just wanted to touch on cash tax outlook, maybe Steven it's for you.

But you mentioned the higher profitability driving somewhat higher cash tax, but then again the growth CapEx budgets are rising which gives you more pool. So I'm just wondering if you could give us your balanced outlook for the next couple of years, generically, on cash tax.

Yeah, I am not sure we’re quite in a position to be able to – or willingness to share a couple years out. That’s just again because of the variability of projects and one of the key factors is the available for use element of capital project and so again we’re clearly looking forward to seeing our capital projects come on stream and deliver tax pools but I would be cautious about inferring that you’re going to see the range come down from the $35 million to $40 million range, reality is those projects are going to result in more EBITDA and more profit for the company.

So directionally I wouldn't necessarily be changing things downward, but right now at this time we’re not really prepared to share tax outlook going forward but we are looking forward to seeing the pools come in.

Yeah, I was thinking more about generic rates as opposed to amounts, because I'm not looking for EBITDA guidance for the next two years. Just do you think more or less that the cash tax rates can be contained as opposed to rising in some significant way?

The rate themselves can be contained – the nice thing about some of these projects is that they do have very attractive pool structures to them, whenever you’re doing manufacturing type kind of facility like the ethanizer and the fractionator, so those are the positive in that respect. But again you have to keep in mind that we have a partnership structure, so a lot of the cash tax forecast for this year was based on last year's income.

And so directionally I guess you can take a look at this year's strengthened EBITDA and earnings compared last year and imply what that might look like for next year.

If I can just maybe start here on NGL infrastructure. You were up about 10 million sequentially from the first quarter.

And so it doesn't look like volumes, at least sequentially, were big drivers. I'm just wondering if you can talk about what was driving the increase.

Is it just the fees increases as you rolled into the new NGL year or was it something else?

Robert, it’s David here. I'm not sure maybe we need to get back to you with a more specific answer on that.

I think that what you're seeing generally though within the NGL infrastructure segment is continued growth in cash flow from the investments that we've made over the course of the last couple years, South Cheecham for instance continues to ramp up in volume, our Fort Saskatchewan condensate system is gradually seeing increasing throughput. But I don't have a specific answer for you, so maybe that's a question we can take offline.

Robert, it’s John here. What I would remind you is that the volumes that we show for the NGL infrastructure segment are fractionation volumes only.

So any increase in business -- any volumetric increase in terms of throughput on pipeline systems and so forth would not be captured in the volumetric numbers that we share.

And just kind of directionally, was there a big pick-up in volumes in Q2 versus Q1?

Well there certainly would be continued increase in activity -- for instance the Cochin pipeline, line fill would be line fill that would be going through our system and while we didn't supply that product and it didn’t contribute in the marketing segment it would have contributed in the NGL infrastructure area.

Just on AEF with the plant -- oh, sorry, --

Just going to finish up – with AEF running the full utilization of course the way we allocate costs between marketing group and NGL infrastructure would've resulted in higher recoveries of fees from the marketing group in Q2 versus Q1.

Right. Yes, that looked like it was about 5 million of the 10 million.

But we can certainly maybe take it offline, too. Just on AEF, with the plant running full, I'm wondering do you have any desire or do you think you could transition the revenue model there to something more of a firm service or take or pay with potentially passing through the butane feedstock costs?

We’ve looked at that, I think it’s fair to say, Robert, but it’s difficult to see how that would be achieved. You would need a willing counterparty to be able to essentially take the commodity price fluctuation and turn it into a fee-for-service and we just don't see that that's likely at that facility.

We have such a wide variety of suppliers on the butane side and such a wide variety of customers on the iso-octane side. There is no one party that would make any -- that would be a logical counterparty for that.

Having said that we are looking at various uses for the unutilized land that’s adjacent to the processing facility there at the AEF site and I think it’s quite possible that we would be looking at fee-for-service -- longer-term fee-for-service kind of arrangement for the business opportunities that we see there.

Just the last question I've got is on the oil and gas assets and as you mentioned, you're basically just going to blow down the reserves. I'm wondering --are there any material well abandonment costs that we need to be thinking about?

Yeah there would be the typical abandonment costs to that but again I don’t have that at my fingertips but mostly that was fully incorporated into our view when we negotiated our purchase price of those assets there.

Is there a sense as to whether that would be a material number or is it more likely to be a rounding error?

Yeah nothing too material there, not in the Keyera as a whole. We can get back to you with more feedback on that.

On gathering and processing, if I deduct the additional margins from the turnarounds, the Simonette road, et cetera; I come up with a per-unit margin just a bit higher than in the first quarter. Is this run rate margin, just under $0.50 an Mcf, your sole way of looking at margins for the remainder of the year?

Well, Steven, it’s John. Let me take a cut at that.

I mean looking at our margins obviously is one way of trying to understand what's going on in that sector. Of course as you know the devil is in the details and there are things that contribute to operating margin in the gathering and processing segment that don't relate to processing per se and for instance as we add more gathering pipeline systems we are generating tariff revenue from those pipes that’s contributing to the numerator in that calculation but not adding volumes because again we’re only showing the throughput volumes processed at the plants, so that can skew the margin and that has been resulting in the margin creeping up over the last 12 months.

The other two factors, just a very quick example that you see there is road use revenue was very significant in the second quarter, some of it related to prior periods as we described. That again adds a revenue and but does not add volume.

And lastly we do water well disposal and other fees and other ancillary services that we use our facilities to -- where we create revenue but don’t add volume. So to go to your question I don't think there's anything other than what we described in terms of prior periods and road use and so forth that would be abnormally increasing that margin if that's the metric you look at.

But it is one you have to be a little careful with.

Then I should ask the obvious second question. You had 114 million in revenue.

How much of that was non-processing revenue?

That’s not a number, Steven that we generally share and in fact not a number that I happen to have on my fingertips either.

Well, thank you, John. My final question -- Keyera's moving several different products by rail, crude oil products, propane -- are you seeing enough railcars available to move the oil and products from the terminals that you're operating and building?

Steven, it’s David here. The short answer to your question is that that continues to be a bottleneck, that continues to be a constraint for the industry.

We -- at our crude terminals we don't provide any of the cars – Keyera doesn’t provide any of the cars, those are all customers’ cars. Our arrangements at our crude terminals are generally not of the nature where that constraint would cause any curtailment in our cash flow because of take or pay arrangements.

With respect to our fleet, we certainly are trying to make sure that we have sufficient railcars for moving the propane and butane and condensate and isooctane that we have in our portfolio. And I think it's fair to say that we’re in relatively good shape on that score, we have been staying ahead of our requirements over the course of the last few years.

Right now of course coming into this coming winter propane is going to be something to watch carefully because of the fact we don't have the Cochin pipeline any more, so there will be larger volumes of propane moving in the wintertime on railcars. But like I said I think from our point of view within our particular requirements we think we’re in good shape.

Thanks Steve. This completes our 2014 second quarter results conference call.

If you do 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.