Keyera Corp.

Lavonne Zdunich - IR David Smith - President and CEO Steven Kroeker - SVP and CFO Brad Lock - SVP, Gathering and Processing Business Unit Dean Setoguchi - SVP, Liquids Business Unit

Robert Hope - Scotiabank Linda Ezergailis - TD Securities David Noseworthy - Macquarie Andrew Kuske - Credit Suisse Robert Catellier - CIBC Capital Markets Robert Kwan - RBC Capital Markets

Thank you and good morning and welcome to Keyera's second quarter conference call. With me today is David Smith, President and CEO; Steven Kroeker, Senior Vice President and CFO; Brad Lock, Senior Vice President of the Gathering and Processing Business Unit; and Dean Setoguchi, Senior Vice President of the Liquids Business Unit.

In a moment, David will provide an overview of the quarter, followed by an operational update from Brad and Dean. Steven will provide additional information about our financial results.

We will open the call for questions once we complete our prepared remarks. Before we begin, I would like to remind listeners that some of our 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 general economic market and business conditions, fluctuations in supply demand, inventory levels and pricings of natural gas, NGLs, isooctane and crude oil; the activities of producers and other industry players, including our joint venture partners and customers; our operating and other costs; the availability and costs of materials, equipment, labor and other services essential for our capital projects; contractor performance; counterparty risk; governmental and regulatory actions or delays; competition for among other things business opportunities and capital; and other risks as are more fully set out in our publicly-filed disclosure documents available on our website and SEDAR. We encourage you to review the MD&A, which can be found in our 2017 second quarter report published yesterday and is available on our website and SEDAR.

With that, I'll turn it over to David Smith, our President and CEO.

Thank you, Lavonne and good morning, everyone. Keyera recorded solid financial results in the second quarter of 2017, as our integrated fee-for-service assets continued to provide a strong foundation for our business.

Gross processing throughput volumes in the gathering and processing segment increased slightly over both the prior quarter and the same period last year, as the recovery in drilling activity is beginning to generate renewed volume growth in areas rich in natural gas liquids. The liquids infrastructure segment generated record operating margin for the fourth consecutive quarter as Norlite became operational and condensate deliveries to the oil sands continued to grow.

Also contributing to the strong results from the liquids infrastructure segment was a 19% increase in utilization at Keyera's fractionation facility in Fort Saskatchewan compared to the first quarter of 2017. Our marketing segment's results in the second quarter were reduced, primarily by an unscheduled outage at AEF that lasted from late February until late April, along with lower margins for both isooctane and propane.

As a result, our second quarter adjusted EBITDA was $133 million compared to $158 million in the same period of 2016 and distributable cash flow was $108 million versus $138 million in the same period last year. Net earnings were $67 million or $0.36 per share, increasing from the $60 million or $0.34 per share recorded in the second quarter of 2016.

Steven will speak more about our financial results later in the call. We continued to expand and enhance our integrated network of assets and are very pleased with the progress we are making on our growth projects.

Currently, most of our projects are coming in on schedule and under budget with the approval of the Wapiti gathering and processing complex, we increased our expected capital investment to between $800 million and $900 million for the current year. A number of these projects are expected to be in service and generating incremental cash flow within the next year.

With our strong balance sheet, we are well positioned to pursue business development opportunities that will add to our growth profile. With that, Brad Lock will now discuss our gathering and processing business unit.

Thanks, David. The gathering and processing business unit delivered an operating margin of $67 million and processed gross throughput volumes of 1.4 billion cubic feet per day in the second quarter of 2017, slightly higher than the previous quarter.

With the year-over-year recovery in commodity prices, we are seeing increased drilling activity in areas rich in natural gas liquids. For example, throughput at our Simonette gas plant increased by 16% compared to the prior quarter and reached a record high in June.

The capture area served by our Simonette gas plant and Wapiti pipeline systems include the Montney and the Duvernay, which are some of the most exciting plays in the Western Canada sedimentary basin. To further support development in the Montney zone, we are very pleased to be constructing Phase 1 of the Wapiti gas plant and associated gathering system.

The site has been cleared, major equipment packages are ordered and we are on track to complete this phase by the middle of 2019. Phase 1 is underpinned by a long term fee-for-service gas handling agreement that includes an area dedication and take or pay commitments.

Subject to the clothing of a third-party transaction, Paramount Resources Limited will assume these commitments. We have developed other projects with Paramount and are looking forward to working with them as our primary customer for Phase 1.

We also continue to negotiate with other producers in the area to commit additional volumes to support a second phase. Phase 2 would add an incremental 150 million cubic feet per day of processing capacity and extend the initial gathering system.

The estimated capital cost of phase 1 is $470 million, while the total estimated cost of both phases is expected to be approximately $625 million. We are also investing about $100 million to further expand Simonette's liquid handling capabilities.

This project includes increasing our condensate storage capacity, enhancing our liquids recoveries, adding new truck loading capabilities and enhancing our pipeline connectivity. Our goal is to maximize producers' netbacks and in turn provide long-term growth opportunities for Keyera.

Assuming timely receipt of regulatory approvals and construction proceeding as planned, we expect to complete the project by mid-2018. Looking ahead to the third quarter, throughput volumes at several Keyera gas plants may be intermittently affected by maintenance related curtailments across TransCanada sales gas pipeline system.

Volumes will also be affected by a scheduled maintenance turnaround at our Simonette gas plant which began this week. To minimize the impact on our customers, we have planned this 19 day turnaround to coincide with TransCanada's pipelines most significant forecasted curtailments.

The turnaround is expected to cost approximately $13 million. I will now turn it over to Dean to discuss the liquids business unit.

Thanks, Brad. Operating margin for the liquids infrastructure segment was a record 67 million.

During the quarter, the Norlite diluent pipeline came into service and volumes on our condensate system continued to grow. Norlite is backed by take-or-pay agreements with the owners of the Fort Hills oil sands project.

Keyera began collecting take-or-pay fees under one of the contracts in May and the other two will commence August 1. Norlite is a joint venture with Enbridge and we are working to attract additional customers to utilize available capacity on the pipeline and to provide other complementary oil sands services.

Other investments that are nearing completion include the four 60,000 barrel condensate storage tanks in Edmonton as well as the South Grand Rapids pipeline and associated pump station. Both projects will enhance Keyera's capacity and reliability on its condensate network.

At the baseline terminal, construction of the 12 above ground crude oil storage tanks is well underway. The first four tanks are scheduled to be commissioned in early 2018, with the remaining eight tanks completed in phases shortly thereafter.

This project is fully contracted by eight customers with take or pay contracts up to 10 years.

Thank you everyone for waiting. Apologies for technical difficulties and I will turn it back over to Dean Setoguchi to continue his discussion about the results from the liquid business unit.

Dean?

Thanks, Lavonne. I'll perhaps just start back from the top again.

Operating margin for the liquids infrastructure segment was a record 67 million. During the quarter, the Norlite diluent pipeline came into service and volumes on our condensate system continued to grow.

Norlite is backed by take-or-pay agreements with the owners of the Fort Hills oil sands project. Keyera began collecting take-or-pay fees under one of the contracts in May and the other two will commence August 1.

Norlite is a joint venture with Enbridge and we are working to attract additional customers to utilize available capacity on the pipeline and to provide other complementary oil sands services. Other investments that are nearing completion include the four 60,000 barrel condensate storage tanks in Edmonton as well as the South Grand Rapids pipeline and associated pump station.

Both projects will enhance Keyera's capacity and reliability on its condensate network. At the baseline terminal, construction of the 12 above ground crude oil storage tanks is well underway.

The first four tanks are scheduled to be commissioned in early 2018, with the remaining eight tanks completed in phases shortly thereafter. This project is fully contracted by eight customers with take or pay contracts up to 10 years in length.

To add to Keyera's growth profile, we continue to expand our underground storage cavern capacity at Fort Saskatchewan and advance work on our Keylink NGL pipeline system. Keylink will connect eight of our gas plants to provide customers with a safe, reliable and economically beneficial transportation alternative to truck and rail.

A $147 million project is targeted for completion in mid-2018, subject to third party consent and regulatory approvals. Based on the significant capital projects underway, the liquids infrastructure segment will continue to serve our customer needs, while growing cash flows over time.

Turning to our marketing segment, we generated operating margin of 21 million in the second quarter or 23 million, excluding unrealized gains and losses. These results were affected by a $15 million lower contribution from isooctane, primarily due to sales volumes and margins that were reduced by a nine-week unplanned outage commencing in February.

Following the completion of the repairs to one of the process reactors at AEF, isooctane production reached full capacity in early May and has continued to perform well since that time. Lower propane margins were also a factor in the performance of our marketing segment.

Strong competition for NGL supply volumes for the contract year commencing April 1st led to competitive pricing for propane and lower margins. Keyera is also storing more propane in the summer months and plans to sell additional products in the winter to capture higher pricing.

This strategy will result in more seasonal variability as we incur fixed costs, while recording limited sales revenues in the second and third quarters and realize stronger results in the winter months. While AEF has been operating at capacity since early May, overall, we expect a lower contribution from the marketing segment in 2017 versus 2016, mainly due to the unplanned outage as well as lower propane margins that we expect to continue in the third quarter.

With that, I'll turn it over to Steven to discuss the financial results in more detail.

Thanks, Dean. As mentioned earlier, we reported a solid quarter with our integrated fee-for-service business delivering strong results.

Realized operating margin for the quarter was 161 million, 14 million lower than in the second quarter of 2016. As a reminder, realized operating margin excludes unrealized gains and losses relating to the marketing segment.

The primary reason for the decrease in our realized operating margin relate to the marketing of isooctane and propane as Dean discussed earlier. This caused the marketing segment's operating margin to be 23 million than the same quarter last year.

But on a consolidated basis, it was partially offset by record results for the liquids infrastructure segment. Adjusted EBITDA was 133 million, 25 million less than the same quarter last year, due to the lower realized operating margin and a 6 million increase in long term incentive plan costs due to the increase in the Keyera's share price during the second quarter.

These same reasons contribute to the $30 million reduction in distributable cash flow compared to the same period last year. Distributable cash flow was also affected by an 8 million increase in maintenance capital compared to the low maintenance capital activity in the second quarter of 2016.

Net earnings for the second quarter were $0.36 per share compared to $0.34 per share in the same period of 2016. Net earnings including $22 million gain on the sale of the Paddle River gas plant and Judy Creek Pipeline, which were non-core assets and an $18 million impairment charge on the Caribou gas plant that seized operation in December 2015.

During the quarter, the dividend was increased by almost 6% to $0.14 per month, beginning with the dividend paid at June 15, 2017. The payout ratio was 72% for the second quarter and 66% year to date.

We have a strong balance sheet with a net debt to EBITDA ratio of 2.92 times. During the quarter, we enhanced our financial flexibility by agreeing to a private placement of 10-year unsecured notes, totaling $400 million with a group of institutional investors.

The transaction is expected to close in September and the notes will bear interest at an attractive interest rate of 3.68%. That concludes my remarks.

David?

Thanks, Steven. Our second quarter and year-to-date results demonstrate solid demand for Keyera's products and services.

With the start-up of the Norlite diluent pipeline, Keyera begins its next wave of growth projects that will add incremental cash flows over the next 12 to 18 months. Looking beyond this time horizon, there are a number of other business development opportunities that we continue to develop.

We remain committed to our successful business strategy and delivering long-term shareholder value growth. In closing, I want to thank all of our employees, customers, shareholders and others stakeholders for their continued support.

And with that, I'll turn it back over to the operator. Please go ahead with questions.

Maybe a first question on marketing. The $8 million reduction in propane margins, given the supply demand dynamics in Western Canada.

Just given the amount of fractionation capacity that's entered the market recently, would it be fair to assume that these competitive pressures likely will persist into 2018?

Well, certainly frac capacity, there's a lot of extra frac capacity today again because of a lot of the infrastructure that's been built primarily in Fort Saskatchewan over the last couple of years. So we expect that trend to continue.

So it will be a competitive environment, but from year-to-year, there are certainly changes in the environment that will affect contracts going forward as well.

Rob, it's Dave here. I guess the thing I would add is that we do expect our propane contribution to be a bit more seasonal than it's been in the last couple of years.

So Q2 and Q3 are likely to be quite marginal in terms of contribution from propane. Q4 and Q1 will be relatively stronger.

And then moving over to Wapiti, with the change in the anchor tenant there, just when you look at how cost effective the expansion would be as well as how, oh, I guess, all the positive data points from producers in the area, is the intention still to get additional third parties to anchor an expansion there or could you see Paramount potentially anchoring an expansion there as well?

This is Brad. Ultimately, we're going to be looking for an appropriate balance of contracted volumes to go with potential volumes on the come before we would sanction train 2.

Paramount is, we've had some preliminary discussions with them. They're busy trying to close their transaction and hopefully, we will engage them more actively once their transaction closes and we can talk about further growth opportunities with them both around Wapiti and in the Simonette region.

I appreciate the guidance for marketing contribution in 2017 versus 2016. I'm wondering how we might think of the key variables that might cause the contribution to vary in the second half of the year and kind of what the range of possibilities we might think of, I'm assuming that for Alberta EnviroFuels, that's substantially locked in, but is there still some uncertainty with respect to isooctane margins or volumes that might be contributing in addition to the propane outlook or other factors.

Hi, Linda. It's Dean.

I guess, we don't provide specific guidance, but there is some - there are seasonal components to our marketing business and when you look at our isooctane business, the strongest months are in the summer months, which is obviously the peak of driving season. So typically, our gasoline prices are higher in the summer months and this is why this outage really affected us a lot relative to our turnaround late last year, because we missed a lot of sales again during the peak months of the year.

So as we go into the wintertime, typically, they are, Bob, gasoline spreads are over WTI or are lower. So we have that seasonal element in the second - towards the end of the year.

And as David mentioned, there is going to be a larger seasonal component to our propane business. So what we do is we allocate a portion of our fleet specifically for our propane business, our rail fleet.

But we're incurring those fixed costs and recording those fixed costs in the summer months you know in the second and third quarters in addition to our storage costs as well to store that propane. And during that time we're recording limited fill revenues.

So with that that leads to poor results in the second and third quarters. We're going to sell a lot more of that propane in the winter months.

So in the fourth quarter and into the first quarter of next year, and again, we're going to see much stronger results from our propane book in those two quarters. That's going to create some variability in our results from quarter to quarter more so than last year.

So it's more the pricing than the volumes at this point?

Well, for propane it will be both because we'll be selling a lot more propane in the winter time and again the pricing and margins will be stronger.

And just as a follow up with respect to Norlite, how might we think of the magnitude of this step up in starting in August and how might we think of the run rate or the slope of the declines in the long term contracts? And how that might that be offset, would it be offset potentially entirely by additional volumes or how am I can think of trending that both for the balance of this year as well as in the outer year.

I guess generally I mean you know I guess for the conference call script I mean we - the first contract commenced already in the, you know, there is three separate contracts with Fort Hills shippers. The first contract basically was activated in the second quarter and the other two will be activated in August.

So we will see a step up in revenues from those two contracts. The way the contract structure has worked is that they will be slightly higher in the earlier years of the contract and it will decline over time.

But it's a little bit more front end loaded. As I mentioned, we do have extra capacity in this pipeline and we are working with other customers to add additional volumes to the pipe which will you know we hope will contribute to additional cash flows over time from this project.

So a one thing I'm just focusing in on the comments you made in prepared remarks and also in your domestic shareholders, they are being well positioned for business development opportunities. In the near term do you see more of those opportunities coming from acquisitions or organic growth?

Yes. Sorry David, I don't mean to be good.

But we are always looking at both. And I think what we're seeing right now is somewhat of a recovery in industry activity, although it's been you know it's been cautious and gradual.

I think the effect of the downturn that we've seen in the last three years is that in the gathering and processing business unit we have unutilized capacity at most of our facilities which gives us the opportunity to grow volumes without having to invest organically and in new capacity in most areas. I guess the one exception would be the Simonette, Wapiti where as you know we're investing a fair bit of capital in growing our capacity in response to the growth in volumes in that area.

In the liquids business unit, I think most of what we're looking at there would be organic growth opportunities. But in both business units there's acquisition opportunities that we you know that we continue to look at.

And I would say we're encouraged by what we see in terms of the opportunities both organically and acquisition wise. But we don't comment on specific opportunities until such time as we've got them ready to commission.

Maybe just on the organic side of the equation, do you - in your discussions with producers, do you get the indication from them that they're prepared to make commitments to incremental capital at this stage. Is that becoming more likely or is it kind of similar to what you've experienced over the past 12 months.

I would say it hasn't changed a whole lot. I mean producers are always reluctant to make commitments.

And I think in each region is a little different in terms of what the competitive dynamics are. But with the Wapiti facility, we have a portion of you know a healthy portion of phase one underpinned but we have one of the things we like about that area is that there's eight or ten different producers that all have very attractive acreage that are quite interested in developing it.

I don't think that dynamic has changed a whole lot. Producers understand that we need some level of commitment before we're going to commit the capital to a project.

And maybe just to build on Linda's earlier question, on the marketing and the idea that will see lower contribution in 2017 versus 2016. Is that just a reflection of the fact that the first half of 2017 was lower than 2016 or do you also anticipate second half 2017 to be lower than the second half of 2016.

We have to go back on that, I don't want to be too specific. I mean we don't generally provide guidance, but we thought in this case it was appropriate to let people know that we are seeing somewhat lower margins for propane and price of octane than what we've seen over the course of the last two or three years.

The marketing business is one that does vary year to year as a result of the market conditions. The business is still healthy, it's just that you know we felt that it was appropriate to let people know that our near-term outlook is probably not quite as rosy as what some folks are assuming.

Steven here, in building I would also would add to that too is, when you think of the first half versus second half in particular in something like iso-octane, two of those six months in the second half were the strong driving months, but certainly September going forward into the year that's when you have your more seasonality coming in. So that would be a difference to between first half and second half.

And maybe just one last question, with regards to your write down of Caribou gas plant and then I guess in also in light of [indiscernible] developed projects coming up. Do you see the Caribou gas plant as an asset you could potentially sell if there is someone interested to fund your development projects going forward or is that still an asset you might see strategic value in going forward.

This is Brad, I think there's a - we've looked at a variety of alternatives for Caribou, whether it be divestiture or a restart or potentially moving components of that facility to other locations where it can be utilized better. So we haven't made any conclusion about what our vision is, but we continue to look at all the alternatives and try to make a decision that works best for both us and the producers in the region.

Probably a question for David and it's how you think about marketing as a proportion of the overall cash flows of the entire company. And when you think about some of the assets you have coming on line, so Norlite just came on line, you've got some other good line of sight in the next year, year and a half of other projects coming on line that were more traditional infrastructure assets.

So are you are you really anticipating a greater pace of growth and cash flows from those kinds of assets and then effectively just a smaller proportion of earnings coming out of marketing activities.

The marketing contribution to our bottom line has varied in past years from 20%, 25% up to 30%, 35%. Currently it's at the low end of that range.

I think we are in the process of adding a bunch of fee for service cash flows from projects like Norlite pipeline that just came on in the baseline terminal that will start generating cash flow in 2018. And so that provides a good financial foundation.

But those assets also provide a good foundation for additional marketing opportunities and that's kind of the way we look at the business. So marketing will ebb and flow probably a little bit more than the fee for service segments.

I think in the near term we would anticipate that the percentage coming from fee for service and from take or pay contracts will be higher. So in the next year or two I think that's probably the case.

Longer term, we don't apologize for making good money from marketing when we can, but we don't count on it.

I don't think you need to apologize, it just sort of curious too on this - I was expanding on that. Do you think about something like a Norlite having a baseline level of return that's satisfactory for you from a cost of capital standpoint?

But then it gives you this enhanced connectivity and effectively optionality to do things like marketing that can give you greater returns. And so do you think of baseline level of return that's satisfactory and then effectively like an option value that gives you the extra juice.

It depends on the asset, with an asset like Norlite, I think the upside comes from filling up the unutilized capacity and bridging Keyera together made the decision to build a 24-inch pipeline. The additional cost of the 24-inch pipeline relative to the 20-inch that would have been adequate is quite small relative to the additional capacity it gives you.

And so we see the upside there in terms of just more fee for service income from additional throughput and we've had encouraging conversations with a couple of producers at this point. One of the real advantages though of Norlite is that it connects into our infrastructure in the Edmonton and Fort Saskatchewan area which we continue to expand and enhance.

And it's in that area where we could see marketing upsides with the benefit of the storage and the transportation and the terminal capacity that we have at Edmonton and at Fort Saskatchewan.

Maybe just one final question, so you're washing cavern '16, '17 right now at Fort Sask. How much more physical room do you have to do anything beyond that.

We have more room for expansion on site. I mean we've never disclosed what that is, but certainly we can do.

We have more capacity for cavern growth at Fort Saskatchewan.

Okay. That's worth a try.

Eventually we reach a limit there. And I think that's one of the reasons why we've gone out and acquired some very attractive land very close by, so that it would be fairly simple proposition for us to create more caverns on the land that we just bought earlier this year from Sasol for instance because we own this all rights and it's a fairly easy matter to build [indiscernible] and access the water that we would need.

So we have provided for the future with the acquisition of that land.

I've got two related questions here. I just wanted you to talk about the volume outlook first and producer behavior.

And if you could specifically address recent industry announcements such as the investment TransCanada is making to expand the NGTL system and how that might impact your assets base.

This is Brad, I think we are cautious optimistic where volumes are heading. If we look at kind of the growth over Q2 versus Q1 and even last year, we're starting to see some of the drilling activity translate into volumes behind our gas plants.

Certainly TransCanada's announced expansions are a positive because that is a bottleneck that producers have right now in terms of getting volumes through the system. But I think we work pretty cooperatively with our producers to ensure that both plant capacity and NGTL capacity kind of come together.

And when there are gaps then we work with them to find solutions through some of our other infrastructure in the area.

Rob, this is Dave here. I might add to that because I think there's sometimes a little bit of a misconception that we're capacity constrained in Western Canada.

There's plenty of mainline capacity to get the gas out east and south on pipelines like TransCanada and Alliance and PGT. The bottlenecks that we've run into are because most of the growth in gas volume has come in Northwest Alberta, Northeast D.C.

area. I mean the bad news is that we do have constraints that have affected us and affected producers more so.

But the good news is that the capacity expansions that are necessary to address that bottleneck are fairly short term and in fairly limited in scope. So it's the kind of thing that's likely going to continue to affect us over the next year or so.

But beyond that I think the news is good.

That sort of dovetails into my follow-up question here, it's apparent in this report that there's a dichotomy between - in your G&P business between Simonette and everything else, with Simonette reporting outstanding results on the throughout side. So understanding that you're already committing to a significant investment in Wapiti, I'm just wondering if you feel it's a strategic imperative to invest more money in Montney.

I think we like the assets that we've got right now. A large core of our assets are based on the Spirit River play, which is continues to be one of the most attractive gas plays in Western Canada and has seen significant volume growth.

So we've actually seen volume growth at plants beyond Simonette. Simonette and Wapi though, certainly we've recognized that we are under levered to the Montney play and we've been looking to try to find ways to enhance that because the producers that we deal with continue to talk about the play up there.

And as we reviewed the geology it is spectacular up in that region. So us investing capital up in that area and looking to grow volumes is really a strategic focus for us.

But it doesn't undermine the attractiveness that we see around our base plants and the Spirit River plays around them.

And this last question just for Dean, a quick clarification here. You mentioned looking at complementary services associated with Norlite and other than the condensate network and related marketing opportunities is there something else there or is that really what you're referring to.

I'm referring to a lot of that but I think I mean we already have some contracts to provide solvent to oil sands players. So anything that we can help to enhance economics of our oil sands customers we believe that we have good assets to help them out with that.

Maybe I'll start with Simonette, just with the volume so strong and it seems like you're quite upbeat on the outlook for volumes there. What's bias, is it to expand Simonette or do you think about redirecting some of the gas that's coming in on the Wapiti pipe to the new Wapiti plant.

I think we think about all those options. Simonette is in a very unique location and that it services the Wapiti to the west and the Duvernay to the east and we've got pipelines that advance into both plays.

So it's well positioned to service kind of two very unique bases. The Wapiti plant that we're building is very much a Montney focused plant.

And I think long term we like the idea of interconnecting the Montney plant with our existing Wapiti pipeline and provide that same connectivity that we have in our west central plants to that region up there. So I think we look at each producer's economics independently and try to find the best solution for them whether it be to expand or to tie them into our new Wapiti or utilize the existing Simonette infrastructure.

And as you think about some of those options just given you've got phase one going ahead and you're in the discussions on phase two, how quickly I feel like it's a better way putting it, would you envision making a decision either around phase two or Simonette expansion?

Really the progress on that is really going to be driven by the, you know, how rapidly the producers want to advance development. So as I mentioned, we were very keen to develop phase two but we're not going to do that without sufficient underpinning behind it.

So as we work with producers their willingness to commit volumes to our infrastructure will dictate the timing as to when we decide to kick off and sanction the phase two project.

Just a couple of clean-up questions around marketing. With the guidance for being down from 2016, I just want to confirm what's the basis when you're looking at 2016, are you looking at the reported operating margin which I think was 101 million in 2016 or you're looking at the realized margin ex-all of the non-cash marks which was closer to 137.

This is Steven here, we're looking at the realized operating margin.

And then just the last, the inventory value at the quarter was almost double Q1. Is that or can you give some color as to whether that's mostly volume versus price and whether that's mostly propane.

Well that's a combination of both those factors. Again the more aggressive bidding for propane volumes and NGL mix volumes led to more inventory and again the seasonality that Dean referred to, but as well as pricing.

Okay that's great, thank you.

And AEF I guess.

The AEF outage that extended into April resulted in higher butane inventory.

Thank you everyone that completes our second quarter conference call. If you have any other questions, please feel free to either call Nick or myself.

Our contact information is in the news release. Thank you for listening, participating and your patience today and have a good day.

Thank you.