Pembina Pipeline Corp (PBA) 2011 Q2 法說會逐字稿

Good morning ladies and gentlemen and welcome to the Provident Energy second quarter conference call. I would now like to turn the meeting over to Kim Anderson, Director of Finance and Investor Relations. Ms. Anderson, please go ahead.

Thank you operator and good morning everybody. Leading our discussion this morning we have Doug Haughey, President and Chief Executive Officer, and Brent Heagy, Senior Vice President and Chief Financial Officer. Also available with us today we have Murray Buchanan, who, along with Andy Gruszecki, run our Midstream operations.

It is important to note that we will be discussing forward-looking information on the call today. This forward-looking information is based on a number of important factors and assumptions. As a result, actual results could differ materially from those discussed during the call. Information concerning the underlying factors and assumptions is available in yesterday's news release and is also discussed in our annual information form under the heading risk factors which is available on Provident's website or SEDAR. Also, be advised that comparative 2010 results exclude results from the Upstream business which was sold in June of 2010 as well as the buyout of financial derivative instruments and strategic review and restructuring costs. Further, please note that all dollar figures are given in Canadian dollars unless otherwise noted and that our financial statements have been prepared in accordance with IFRS. With that being said, I would like to turn the call over to Doug Haughey. Doug?

Thanks Kim and good morning everyone. Obviously, we're very pleased with our financial and operating results for the second quarter and we're very excited about the growth opportunities we continue to see emerge for Provident. Our second quarter adjusted EBITDA of CAD51 million marks the second highest Q2 Midstream EBITDA in Provident's history. Our balance sheet remains very solid and we continue to be extremely well positioned to capture growth opportunities as they occur.

NGL business fundamentals were very favorable in the quarter, natural gas liquids prices were strong with propane averaging a $1.50 per US gallon and frac spreads averaging close to CAD54 per barrel. As you know, strong NGL pricing has resulted in natural gas producers targeting liquids rich natural gas plays. At our Redwater facility and our Corunna storage and terminalling facility in Ontario, we are well-positioned to benefit from increased NGL focused natural gas drilling activity in the Montney and the Marcellus areas respectively. The demand outlook for natural gas liquids also continues to be very strong. Record exports of propane and strong petrochemical demand have helped tighten the North American supply offsetting incremental natural gas liquids production from increased US drilling activity. North American propane inventories are significantly below last year's levels and are also below the 5-year average. This tighter supply is a result of stronger year over year propane pricing, in addition strong petrochemical refiner heavy oil producer demand has had a positive impact on butane and condensate pricing.

So given our solid financial results to date and based on the current market conditions, Provident is narrowing its 2011adjusted EBITDA guidance range to CAD210 million to CAD250 million from the previous real range of CAD200 million to CAD250 million, subject of course, to market and operational assumptions including normal weather conditions. The revised range increases the midpoint of Provident's guidance from around CAD225 million to CAD230 million and it does incorporate the reduction in crude oil and liquids prices we have seen over the past few days. Please see our press release and MD&A for additional details including pricing assumptions.

Down the growth front, we continue to focus on the execution of our expanded 2011 capital program spending CAD47 million during the first half of the year. This includes CAD38 million of growth capital and CAD9 million of sustaining capital, which is primarily comprised of the sustaining capital component of the Taylor to Boundary pipeline project. During the second quarter we significantly advanced a number of our 2011 capital projects. At Corunna, we are near completion of our new 16 spot multi-commodity rail loading and offloading terminal and expect to commission it in the third quarter of this year. The rail terminal will provide enhanced flexibility to move and NGL and related products in and out of the Sarnia area.

At Redwater our 5 cavern development program is preceding as planned and construction of the Septimus to Younger pipeline is also well underway. We are also able to materially advance our project to upgrade and replace an aging section of the Taylor to Boundary Lake pipeline on the Liquids Gathering System. A significant portion of new pipeline segment was placed into service during the second quarter and subject to final regulatory approval, the final leg of the pipeline is expected to be completed by the end of 2011.

During the second quarter we also announced an agreement to purchase a 2/3 interest in Three Star Trucking, a Saskatchewan-based oil field trucking company serving Bakken-area crude oil producers. Three star is a privately held enterprise based in Alida, Saskatchewan providing fee-for-service trucking of crude oil and related oil-field liquids for major Bakken-area producers. NGL logistical services are a key component of our business and we therefore view this acquisition as an ideal platform to vertically integrate our operations and expand the fee-for-service revenue we generate along the NGL value chain. The transaction is valued at about CAD20 million and we expect it to close by October 1, 2011. So I'd now like to turn the call over to Brent who will discuss our second quarter financial results. Brent?

Thanks Doug and good morning everyone. During the second quarter of 2011 we generated gross operating margin of approximately CAD74 million, an increase of 51% over 2010. The increase reflects higher contributions from both Redwater West and Empress East. Strong Redwater West results were driven by favorable pricing for all NGL products, particularly at Younger where frac spreads were significantly higher as compared to the prior year. Empress East results were also strong, driven by higher demand for propane and butane, which increased Empress East sales volumes relative to Q2 2010. Strong frac spreads also contributed to our Empress East margins, however, a portion of these margin gains were offset by higher extraction premiums, which have increased approximately 50% relative to the second quarter of 2010.

Year over year second-quarter commercial services margin was down approximately 5% due to lower condensate terminal revenues which resulted from the Southern Lights pipeline commencing operation in mid 2010. Second quarter 2011 adjusted EBITDA increased to CAD51 million from CAD34 million in the second quarter of 2010. The 51% increase was largely a reflection of significantly higher gross operating margins, partially offset by higher realized losses on financial derivative instruments which occurred as a result of a much more favorable pricing environment. In addition, the second quarter of 2011 includes other income of CAD4.3 million reflecting certain nonrecurring payments received from third parties in connection with contractual volume commitments at the Empress facilities.

Distributable cash flow for the second quarter was approximately CAD40 million, approximately 4% higher than the prior year. Significantly higher adjusted EBITDA was partially offset by higher sustained capital in Q2 2011 including CAD2.2 million relating to the Taylor to Boundary Lake pipeline replacement. In addition, in the second quarter of 2010, distributable cash flow benefited from the cash tax recovery that was a result of the buyout of financial derivative instruments. Cash dividends to shareholders in the second quarter equaled CAD0.14 per share, representing a payout ratio of 91%. Provident exited the second quarter with approximately CAD485 million of total debt representing a ratio of total debt to adjusted EBITDA of 1.9 to 1. We continue to maintain our strong financial position with significant capacity available under our revolving credit facility and leverage ratios, which places us at the low end of our peer group.

We continue to execute a disciplined hedging program that provides for the routine hedging of approximately 50% of our natural gas and natural gas liquids volumes on a rolling 12-month basis, and this is particularly important in these volatile times. As of June 30, 2011 we have had approximately 96% and 64% of our NGL and frac spread volumes for the third and fourth quarters of 2011 respectively. We have also hedged approximately 86% and 60% of our natural gas for the third and fourth quarters of 2011. In order to facilitate a better understanding of our commodity risk management program we have recently updated and enhanced our hedging disclosure. In addition to providing weighted average hedge prices and volumes by commodity, we now also provide disclosure around market frac spreads, which are based on forward pricing indications and hedge frac spreads, which represent the weighted average fixed prices and our hedged volumes, and you can visit our website for all the full details around our hedging program.

Provident has approximately CAD1 billion of tax pools and non-capital losses available to claim against future taxable income. Using the current strip, we anticipate these pools will offset material cash, Canadian cash taxes through 2015. I would now like to turn the call back over to Doug who will provide some comments around our growth strategy.

Thanks Brent. This is always the fun part. In Q1 we increased our 2011 capital budgets to CAD105 million, and as we mentioned earlier, execution of our growth strategy is proceeding very well. For the balance of 2011 our capital expenditures will be focused on 4 main areas.

First, cavern and facility development at Corunna designed to enhance operations capability and increase connectivity to additional infrastructure in the area, and this is turning into a great asset for Provident. Number 2, continued cavern development at Redwater. We expect to complete 5 caverns between now and 2014 and are seeing substantial demand for new cavern development. Redwater is very well positioned for strong growth in this area. Number 3, we are completing the Septimus to Younger pipeline and the Taylor to Boundary Lake pipeline. Number 4, we have continued development of our previously announced project to provide incremental volumes to our Empress East system.

Longer term, we continue to be very excited about our portfolio of growth opportunities. Our assets are new, highly efficient, and strategically located to benefit from growth in the Montney and Marcellus natural gas plays, the Bakken oil play, and the Alberta oilsands. In Northeast British Columbia we continue to be encouraged by the increase in drilling activity in the liquids-rich Montney natural gas play. Over the past year we've seen through-put at our Younger facility increase significantly and have seen increased supply at our fractionator at Redwater. In fact, given the strong outlook for volumes at our Redwater facility, we are now considering accelerating the timing and increasing the scope of our fractionation debottleneck project at Redwater. This is a very cost-effective project that can be brought into service quickly providing a material increase in fractionation capacity in the Edmonton area.

Also at Redwater, we are well-positioned to provide a full suite of storage and terminalling services to the growing oilsands sector in Alberta. We have sufficient land available at the site to significantly expand our facilities. Our outlook for butane and condensate demand by heavy oil and oilsands operations continues to grow. At Corunna we continue to receive strong demand for new storage and terminalling services. In addition, there are currently 3 pipeline projects being proposed to bring ethane and potentially other liquid products from the Marcellus natural gas play into the Sarnia area. Regardless of the successful project our facilities at Sarnia and Corunna are ideally situated to provide storage and terminalling services which will be required to accommodate new supply.

Finally, we're developing opportunities to provide additional services for Bakken producers. They will require trucking and logistical services, which we will be able to provide when we close the Three Star Trucking transaction. We also plan to attract additional NGL volumes to our Empress East system in the foreseeable future. Overall, we continue to believe that we can successfully deploy at least CAD70 million of growth capital annually over the next 5 years and meet our long-term financial target of a solid base annual EBITDA growth of 5% to 7% per year, a comfortable payout ratio of less than 80%, a total debt to EBITDA ratio of less than 2.5 to 1. And we intend to fund internal growth through -- fund the growth through internally generated cash flow, proceeds from our DRIP, and perhaps modest amounts of additional debt. So that concludes the prepared comments that we had for today. I'd now like to turn the call over to the moderator here and open the line for questions.

Thank you I'll take questions from your telephone lines.

(Operator Instructions)

Linda Ezergailis, TD Securities.

Can you give us a sense of what the cost might be for the Redwater caverns capital expenditures, 2012 to '14 and what the timing might be?

We are developing 5 caverns right now. We continue to have a pipeline of interest in leasing those caverns for storage. Our average cost to develop a cavern, depending on the complexity of the cavern, is between CAD12 million and CAD15 million, and we are going to be developing that over the next 2 to 7 or 8 years. We've got lots of room for growth.

If you look at us bringing 2 caverns on a year and expenditures are flat, you could assume your development somewhere in the CAD26 million to CAD30 million, roughly. Just kind of a way to look at it. The caverns don't all come on, so you need to keep that in mind on the range of numbers.

Would it be Provident's intention to keep the DRIP on through to 2014?

Yes currently we are planning on keeping it on, Linda

And maybe just a more strategic question. You've entered the trucking business now in the Bakken. Is that a new platform for growth for you -- the trucking business? Or was that kind of a unique opportunity?

We believe that it's an integration process. We do, because were in the business, truck a lot of natural gas liquids to our facilities. Be that on the LGS system or to other locations, and we do see the opportunities for integration into other areas of the business.

We just looked at this one; it was in an excellent area; it's a growing area of the country's economy and it was up and running. The opportunity to roll this platform out to other areas where we operate is definitely there. That doesn't mean we are going to do it, but that opportunity is there and if it's prudent for us to do it and the margins are strong we will certainly be looking at it hard.

So that could be through either organic growth or further trucking acquisitions?

Yes, Linda. I think that's a good way to look at it. When you look at the NGL value chain, trucking is actually a pretty important part of it, and we are a big consumer of trucking services.

Our view is that generally the more times we touch a molecule, the more money we can make through the value chain. And this is just one more opportunity to do that. In terms of the potential for trucking acquisition, that's always there. And frankly it's one of the things that attracted us to the Three Star opportunity.

Matthew Akman, Scotia Capital.

Wanted to ask a couple of questions on the future growth that you're talking about for next year at Redwater. And the acceleration of de-bottlenecking there. It sounds like a great opportunity.

I'm trying to square that with the fact that it looks like NGL sales volumes so far year-to-date are actually down at Redwater West, which is surprising in light of the need to de-bottleneck and the fact that you said Younger volumes are actually up. Maybe you could just clarify that inconsistency.

Certainly part of your sales volumes is projected on having the ability to get the product fractionated, and to be honest our NGL mix, the volumes we are seeing coming to us out of Taylor, as has already been mentioned, coming to us out of the Montney third-party gas plants, is quite a bit stronger than it was a year ago.

One of the things you are seeing is the additional mix we have. The opportunity rests on the fact that our mix volumes are pretty high and we're experiencing that growth. It isn't showing up in the sales numbers yet, but we have done some things to address getting that process for this year on a short term, and then we're looking at being able to deal with that ourselves internally next year.

I think it's fair to say we've run in -- we're full. Redwater's full. In hindsight, we probably should have done this fractionator project this year and not next year, but having said that, we see continued growth. It's a great opportunity, and it will be a great project

We're seeing the increased liquids coming at us, and the Montney is real. We have a lot more certainty on the production capability of liquids coming out of the Montney than we had a year ago, so we're much more comfortable. We tried to do analysis a number of times to make sure that we've got it right before we step out and do this.

We have the lowest cost ability to expand, to handle the ethane plus mix, for us it's a de-bottlenecking, and we now have first-hand seen the liquids. We know they're there and we're having to deal with them through some other processing arrangements.

Is it sort of an analogous situation on storage because there was a comment in your disclosure that condensate volumes were off, but you are expanding storage. Is it the same kind of thing, you're playing a bit of catch-up here?

To a certain degree. Keep in mind we've always talked about there is more than just storage of propane, butane and condensate. There's other products and opportunities to store too. There is potential interest and storing drill bits for example -- one example that's out there.

The desire for storage is very strong. We analyzed pretty hard before we stepped forward on this and we are developing 5 caverns so it's not just for the base products.

You continue to sort of emphasize this no more than 2.5 to 1 debt to EBITDA which is, I think, the most conservative out there. You do have some commodity exposure in there, but as you build out and reduce overall commodity exposure, is that possibly a moving target? Could you move that a little bit higher?

I think that's a fair comment. We have been sticking to that 2.5 to 1 given our current profile, but it's fair to say that all of our growth capital is focused on fee-for-service opportunities. So our fee-for-service business will grow and at some point, it will make sense to maybe lever the company up a little bit more.

Robert Catellier, Clarus Securities.

You touched on this a little bit, and I'm not sure if it's appropriate to delve into it any deeper given the acquisition hasn't closed, but when you look at the Three Star Trucking acquisition and the platform for growth there, can you provide a little bit more color? Do you think the growth comes from adding new trucks or can you add other assets as well to enhance that platform?

Our view is it's both. They have grown significantly organically. It's our view that there is lots of organic growth there as well. There's some potential for trucking acquisitions, kind of a consolidation thing on a regional basis.

Listening to you talk about the Redwater opportunities. It sounds to me like you have the possibility of adding more de-ethanizer capacity in mind as well?

Absolutely. That is exactly what we're targeting, and as I mentioned in response to the earlier question, we could use more capacity today as we speak, we're having to make other arrangements. Definitely with the growth in the Montney production and the current interest in the producers to produce ethane plus, we are well-situated.

We have the best facility to deal with that. And we have the opportunity to get the economies of scale through de-bottlenecking and tying in, because we have the infrastructure for the raw feed caverns and finished product. We're well-situated to capture the Montney growth.

It looks like producers are increasingly considering outsourcing some of their midstream assets, particularly raw gas processing plants, likely because they're trying to conserve capital for land and drilling.

Doug, you have a deep background through Spectra and its related income fund and the raw gas processing side, is that something the company might consider as an avenue for growth given your background and the fact that it could enhance your access to NGL sales volumes?

I would say we would always look at it, but there is always the strategic sideboards. I doubt that Provident would step out into a purely sour gas processing opportunity, for example. It would have to have a strong fit with our existing NGL business. Having said that, I am very comfortable with the business and it is something that we would certainly look at if it fit strategically.

My final question for Murray. You've increased your percentage assumption of propane relative to crude for the rest of the year to 72%, presumably because of the current state of the market. I'm wondering what the market is telling you with that 72% being of notable increase over what you had in the guidance previously.

The current market as of yesterday -- I didn't get a chance to check this morning, the markets weren't open or trading with enough liquidity to tell -- but yesterday that ratio was almost 76% it was about 75.7%. What's interesting, which I find quite fascinating maybe because I've been in this business for a long time, is that 3 months ago oil was CAD30 higher per barrel and liquids were, propane in Mont Belvieu was the same price.

So your ratio has moved up from 58% to, as I said yesterday, 75.7% and the frac spread margins have stayed very strong. Normally you would use WTI as your barometer to say what the business has been, but we've watched crude come back CAD17 in the last pullback, CAD17 since the announcement of US debt ceiling agreement and propane prices have held very strong, in the same $1.50 range.

We decided to run our guidance based on the most current data we had and ran it this week in terms of our forecast; we ran it on current assumptions. I'm comfortable in those numbers out to our guidance period for sure

It looks to me what happened then is, unlike the price of crude, the natural gas liquids market didn't have the run-up due to the geopolitical events and therefore it doesn't have to have the blow off there.

True. What happens is that as the spreads go very, very wide people are willing to take their margins and go. It's not really being sold as a percentage of crude all the time on the propane side.

Similarly, when it contracts, especially as we're heading into winter, parties who have put this in storage are saying we're waiting for winter because if it's 74%, 75% or 76% today, it might be 85% in the winter. The parties who go to storage tend to have good balance sheets, so they are not going to react to a change in WTI because in the end it's what's the value of propane in the international market. And that demand's been strong.

Exports are at record levels. And the pet-chems are running very, very high as well; their margins are still very strong in propane.

Robert Kwan, RBC Capital Markets.

Question on extraction premiums and the new guidance. You bumped that up, and certainly we've seen frac spreads continue to be very, very strong. Do you have a sense as to what percentage, if the frac spread is going up, how much extraction premiums are eating into frac spread increases say on a percentage basis?

I don't have it on that basis. I can tell you that what happens is that as the frac spread widens your participants at, for example, Empress all have margins and of course there's more capacity to process gas than there is gas, so people tend to move up the curve with the frac spread margins opening up. But to give you a correlation, I don't have that and I don't know that there would be a correlation.

It's more kind of what you're seeing --

Linear relationship to frac spreads, I can assure you that.

The interesting thing, though, is we've generally found that as frac spreads widen extraction premiums will tend to widen because people are making a lot of money. And as frac spreads tighten the extraction premiums will tighten accordingly. It's a bit of a shock absorber. I think that's a little bit of what we're seeing right now.

That's basically what you see, but to give a relationship that says if frac spread goes up by CAD2, extraction premiums go up 25% of that? I can't give you that. Not everybody's economics that have facilities at Empress is the same either.

I think it's fair to say we tried to figure this one out ourselves.

When you are looking at how you're trying to hedge your frac spread exposure, how do you take into account that you are trying to lock down the frac spread, yet extraction premiums have the potential to move around on you based on where actual frac spreads end up falling?

They do, but keep in mind that we are not out 5 years. At one point in time we used to do oil to gas at 5 years; we're not that far out. We can get forward visibility on the extraction premiums a year out or year and a half out. We know what we can do in terms of potentially in those markets. When we're locking it in, we have the comfort of being able to see that far.

Where we you would get concerned is if we went out on a forward strip 5 years out, even products to gas, and didn't have any visibility on extraction premiums. That would be reckless to be out 5 years when you don't know. There's some visibility in the front end for extraction premiums for sure.

My last question is also related to Empress. What kind of volumes are you seeing right now particularly in light of where you're starting up and are you seeing increased flows as gas gets backed up the western leg?

Empress has been in the 4 to 4.5 range pretty steady. There's been some days where you're seeing a little bit higher than that. And at reasonable levels. The west leg has dropped off a little bit. Some of that gas is going to storage. People are looking at the price and saying 335, or 340 doesn't cut it for us, so product is going to storage, which is in my mind, deferred gas to be processed at Empress in the winter. But it's not all again pushed out the eastern gate because the market has to be there for gas in the and, as we know, North America has sufficient supplies of natural gas.

Carl Kirst, BMO Capital Markets.

I think all my questions were hit but maybe just one follow-up. With respect to your comments of increasing the scope potentially at Redwater. Is there any way to quantify what we are talking about here from a cost standpoint?

We are looking at different options for the expansion. De-bottlenecking is really what it is. It's not going to be a new train, but rather making our current facility more efficient, allowing it to process more. We have some different options at this point in time, we're looking at those options trying to find the one that is most cost efficient. At this point in time we can't provide those specific numbers.

And a clarification to Linda's question on the storage caverns. It was mentioned as far as thinking roughly 2 caverns per year CAD12 million to CAD15 million. In the CAD70 million per year guidance beyond 2011, is roughly CAD25 million to CAD30 million of that, should we attribute to the storage caverns?

To Redwater West, yes. I think that's reasonable at this point time. We haven't finalized our 2012 capital budget and we will have more definition on that when we go through it. We have a number of projects to go through, and deal with the ones that have the highest returns. I think generally for now that's a reasonable assumption to have.

And we will make sure we revise. That's not a lockdown number but just as a general indication of where we could be I think that's fair.

(Operator Instructions)

Steven Paget, First Energy.

You talked about in Q1 CAD10 million in new growth capital for a new NGL project for incremental volumes at Empress East. Could you provide a little more color on that?

We're still not saying much about that. We have committed the capital and we are proceeding with the project. We haven't disclosed the commercial details yet because we are putting a bow around it and from a competitive point of view the timing is not right. You will hear more about it in terms of the details, but we can confirm that we are moving ahead with the project.

Could you also comment on the CAD4.3 million from third parties related to volume commitments? Does that mean there will be a downward change in volumes? Are they buying out a contract?

It's not going to have a impact go-forward. It's volumes on contracts related to past performance. It doesn't involve the termination of any contracts at all.

It is a nonrecurring event; if you're looking forward to next year, you can't assume we're going to have that next year. But it doesn't result in a buyout of a business transaction. There's certain volume commitments in our contract that have to be provided and they weren't met historically, but we don't expect it to be a recurring incident.

Strategically looking forward, TransCanada says it's filing this next process with the National Energy Board. Where do you anticipate coming in on the hearings that may be held on this?

We don't believe that it adds any value for any parties. If there is no value in the process, we have other important issues that we think TransCanada and the industry should be dealing with. To be quite honest, we fail to see a value-add for any participants in the value chain on that.

This is a funny one, because we don't see any huge downside, but then we don't see any huge upside for anybody. Rather than debate it here, we will have something to say if they go to a hearing, and our expectation is that will probably happen within the next few quarters.

Right now they have mainline to deal with and other issues, this is, in terms of the priority issues that they need to deal with, pretty far down the list.

Patrick Kenny, National Bank Financial.

With respect to the incremental throughputs, are volumes up at Younger from the Septimus pipeline? Is that a pure frac spread cash flow stream or is there some fee-for-service or product margin within that contract?

There definitely is fee-for-service and product margin in that. We have contractual arrangements in place right now. The portion that is frac spread based on what we have in place is relatively low. To assume that would all be frac spread in the model would be, in all likelihood with frac spreads being high, resulting in an overestimation of our earnings from there.

But our risk profile and the deals we are putting together is significantly lower and it involves fee-for-service in some cases and purchasing a product based on Edmonton prices. At this point in time, it could be a low percentage of the Septimus pipeline that we're purchasing product from that's tied to frac spread.

With respect to the lower condensate imports due to Southern Lights. As we look out over the next few years, are we just waiting for a few major projects to come online up in the oilsands like Sunrise? Just a little bit more color on that.

The development of the oilsands, the growth in the oilsands, and the projections we've seen from both the NEB, RCB, and the independents show strong growth in oilsands development and strong demand for condensate. As a matter of fact, the premiums to WTI are fairly strong right now.

We do see some recovery occurring right now, and we are looking at importing some condensate by rail from the United States again. It's already starting to ramp up; demand is starting to come and its going to be higher in the winter. The thing about the rail is that it can get to plants that aren't connected to Southern Lights, for example, so there are new plants being developed, or response in areas not well connected by pipeline that we can purchase condensate and it now makes sense to come here.

The beauty of this is we've got that condensate rail rack, which is, I think the biggest rail rack in Western Canada and it provides great optionality. We paid for the thing a number of years ago and so now at the margin any significant growth in the oilsands, there will continue to be rail -- (multiple speakers) And we are seeing it and we are participating in the market.

The other thing we have is optionality. You're not locked into firm service on Southern Lights in our business. If there's an opportunity to pick up 25 to 30 rail cars a month from a plant in Texas and it makes sense, we can do it and we'll sell the other side in the forward market and lock in CAD4 to CAD5 a barrel margin.

If it's not there, we're not locked into it. That facility has paid out already for us, gives us optionality to participate in that market. And high grade our margins.

Stephen Paget.

Looking back at your presentation you made last October, your gross margin was CAD40 million, or sorry 40% frac spread, 30% fee-for-service, 30% product margin. Are you still targeting those margins in that same proportion?

We're pretty close to that. We haven't calculated that to the last percentage, but we haven't seen anything to indicate that's materially different. I think that's the best way to summarize it. We're pretty close to that.

It'll change over time, though. As we mentioned all of our extension capital is focused on fee-for-service business, so over time, that fee-for-service and product margin proportions will move up for sure.

Thank you. We have no further questions at this time.

Well, thank you everyone on behalf of the Provident management team, we will see many of the analysts in Sarnia at the beginning of October, and of course, I think that analyst meeting will be webcast as well. Thanks, everyone, for their time and we will talk to you soon.

Thank you. The conference now ended. Please disconnect your lines at this time. We thank you for your participation.