Pembina Pipeline Corp (PBA) 2012 Q3 法說會逐字稿

Good morning, everyone. My name is Sarah, and I will be your conference operator today. At this time I would like to welcome you all to the Pembina Pipeline Corporation 2012 third quarter results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. (Operator Instructions).

Thank you. I would now like to turn the call over to our host, Mr. Bob Michaleski, Pembina's Chief Executive Officer. Sir, may begin your conference.

Thank you, Sarah. Good morning, everyone, and welcome to Pembina's conference call and webcast to review our third quarter 2012 results. I am Bob Michaleski, Pembina's Chief Executive Officer; and joining me today are Peter Robertson, Pembina's Vice President of Finance, Chief Financial Officer; and Scott Burrows, our Senior Manager of Corporate Development Planning. As usual, I will review the quarterly results we released yesterday, spend a few minutes providing an update on recent, and then open up the line for questions.

I will start with a reminder that some of the comments made today may be forward-looking in nature and are based Pembina's current expectations, estimates, projections, risks and assumptions. I would also points out that some ofthe information I provide refers to non-GAAP measures. To learn more about these forward-looking statements and non-GAAP measures, please see Pembina's various financial reports available at pembina.com and on both SEDAR and EDGAR. Actual results could differ materially from the forward-looking statements we may express or imply today.

I will start off by reviewing you are Q3 2012 results, followed by along at our growth projects, and then we can get to your questions. As you know, this is our second quarter reporting on a combined entity since closing our acquisition of Provident on April 2. I am happy to say that during the third quarter we maintained steady performance across all areas of our business and made strides on growth projects while completing the majority of the integration work we needed to do.

We have a few things to wrap up with respect to the information systems integration, but we expect to have this completed by the end of the year. Looking at revenue, operating margin, gross profit EBITDA and earnings during the quarter, you can see that each of these metrics has increased for the quarter and year-to-date, mainly as a result of the acquisition, but also due to continued solid performance in all of Pembina's legacy businesses.

Turning now to look in more detail at each business, throughput and our Conventional Pipelines averaged just about 444,000 barrels per day during the quarter, approximately 3% higher than the same period in 2011. On a year-to-date basis throughput is up by 9% compared to the same period of 2011. In the third quarter this business generated revenue that was consistent with the same period of the prior year.

Operating margin improved by 8%, largely because our operating expenses were lower as a results of the timing of integrity and geo-technical work, and our power costs were down. On a year-to-date basis revenue and operating margins were both up for the first nine months of the year by 8%.

Our Oil Sands & Heavy Oil business delivered a 19% increase in revenue and a 21% increase in operating margin in the third quarter of this year. These increases were largely because of contributions from our Nipisi and Mitsue Pipelines, which began adding to our results in the third quarter of 2012. Those pipelines drove up the year-to-date performance as well, with revenue in operating margin up by 55% and 37% respectively compared to the first nine months of last year.

Gas Services processed higher volumes that our Cutbank Complex due to an increase in producer activity and the new 50 million cubic feet shallow cut expansion, which was put into service and operational near the end of the quarter. The Cutbank Complex now has an aggregate raw shallow gas processing capacity of 410 mill cubic feet per day, 355 million net to Pembina, which is an increase of 16% to net to Pembina.

We also now have our Musreau Deep Cut Facility up and running, but volumes [processed as] deep cut don't impact Gas Services overall processing volumes, since they are already counted in the volume process to the shallow cut. In this business we realized an increase in revenue of 26% and operating margin by 40% compared to the third quarter of 2011. The same factors drove up the year-to-date results, with revenue and operating margin both increasing 24% compared to the same period of 2011.

We have combined the former Provident business results with our Midstream group, so that accounts for the majority of the large increase on a consolidated basis in this segment during the three and nine months ended September 30, 2012. Our crude oil midstream business, which represents Pembina's legacy Midstream & Marketing segment, contributed operating margin of CAD27.2 million, an increase of almost 41% compared to the same quarter of 2011.

Year-to-date operating margin was CAD87.4 million, which is roughly 25% higher than the same period last year. These increases were driven by higher pipeline volumes, wider margins and additional services offered at the Pembina Nexus Terminal near Edmonton.

Our Redwater West and Empress East assets, which were both acquired through the acquisition and make up our NGL midstream business, generated operating margin of CAD46.6 million and CAD11.6 million respectively, excluding realized losses from commodity related derivative financial instruments. This represents an overall increase of 52% when compared with the second quarter operating margin of CAD36.2 million for Redwater West and CAD2.2 million for Empress East respectively.

We have commenced the process of mitigating a portion of the frac spread risk by protecting a base level of cash flow to cover a minimum of 50% of the related natural gas costs. These transactions will cover the period April to October 2013 to coincide with the expiring of existing instruments and extend to the end of the gas contract year.

Corporately we incurred general and administrative expense of CAD26.9 million during the quarter, compared to CAD13.8 million during the third quarter of 2011 due to the addition of employees who joined Pembina from Provident, an increase in salaries and benefits from existing and new employees and increased rent for new and expanded office space. For the first nine months of the year G&A totalled CAD70.2 million, up from CAD41.2 million during the same period of 2011 for the same reasons as our quarterly increase in G&A.

I will now provide some highlights with respect to our growth projects, startingwith our Conventional Pipeline business. As you know, during the second quarter we were happy to announce that we reached our contractual threshold to proceed with the 352,000 barrel per day northern NGL expansion. Even with the first phase of this expansion we don't believe we will have enough capacity to accommodate our current volume forecasts.

We are continuing to see strong demand for capacity in our operating regions, namely the Dawson Creek, Grande Prairie and Kaybob/Fox Creek areas, and many of our pipelines are sequentially full. This as good problem to have of course, and is lending confidence in the two new expansions to our Conventional Pipeline systems, which were approved at the Board of Directors meeting yesterday. We have issued a news release regarding those projects after markets closed yesterday, so please refer to those for complete details.

I will just provide the highlights here. The first expansion is phase two of the Northern NGL expansion. This project will increase the NGL capacity on both our Northern and Peace systems from 167,000 barrels per day to 220,000 barrels per day. It's expected to costs approximately CAD330 million and should be completed in early 2015.

To accomplish this expansion there are a number of things we have to do. We plan to in stall four new pump stations, upgrade three existing pump stations, add additional operational storage, reconfigure existing pipelines, and build a total of approximately 94 kilometers of new pipeline.

The other expansion mentioned in the release is on our Peace crude oil and condensate pipeline. This project will increase our crude oil on Peace from 195,000 barrels per day to 250,000 barrels per day. It's expected to cost approximately CAD250 million and should be completed in 2014. To accomplish this expansion we plan to install five new pump stations, upgrade six existing pump stations, add additional operational storage, reconfigure existing pipelines and build a total of ten kilometers of new pipeline.

There will be additional capital of approximately CAD125 million required to tie in producers to both the expanded systems, so all-in we're looking at total capital investment of about CAD670 million over the next 2.5 years. Given this large capital investment, we're looking to underpin these expansions with commercial arrangements with our customers.

We're confident that the support will be there since we were recently able it secure contracts for our Northern NGL expansion and capacity is still at a premium. We will also be required to attain customarily regulatory and environmental approvals before we about able to proceed.

This is truly a remarkable growth story. Three years ago these assets were in modest decline, but as we have said plane times, our assets are located in the right geology. By the middle of 2015 we expect to have added 250,000 barrels a day of capacity, which a 40% increase across our major systems.

For the pipeline portions of the Resthaven and Saturn projects we are looking to break grounds on construction shortly. We have received the required regulatory approvals, have awarded construction contracts, and expect to begin construction on both projects during the fall and winter of 2012, 2013.

Now turning to Gas Services, the Resthaven -- for the Resthaven and Saturn facilities we have now order a significant portion of the major equipment, and we have begun to receive that major equipment at the site. Once complete, these facilities are expected to add and additional 330 million cubic feet a day net of enhanced liquids extraction capability, and approximately 25,000 barrels a day of NGL volumes to Pembina's Conventional Pipeline systems, further evidencing the need for the expansions I just talked about.

In our Midstream business we are also working on a number of growth projects. Our crude oil midstream group is continuing to develop plans to build out our truck and full service terminal footprint. During the third quarter we broke ground on the new joint venture of full-service terminal in Judy Creek, Alberta, area that we expect to complete in April of 2013. This project will provide additional services for customers in the area and will help secure additional volumes for our Conventional Pipeline systems.

Our NGL midstream group continues to be very busy, particularly at the Redwater site. On September 1 we brought on our first of seven fee-for-service cavern storage facilities at the site, and we are aiming to have another completed in the first half of next year. We also completed and brought on stream the 8,000 barrel per day expansion of the Redwater fractionator on time and under budget.

This expansion will help ease capacity stream, but we also continue to progress our proposed 70,000 [C2-plus] fractionator at the Redwater site. In the long run we see the requirement for more frac capacity in Alberta and so are continuing to solicits customers for and are completing preliminary engineering work for the project. Should we receive the customer support to proceed, we expect the new fractionator would costs approximately CAD400 million.

Also looking long-term, we recognize that having export options for Canadian based production will benefit pricing environments and allow for the continued development of our resources, especially in light of changes to the Alberta energy industry such as the [cogen] pipeline reversal. We're looking for ways in which we can participate on this front.

While it's still early in the game, we are investigating offshore exports opportunities for propane and butane that would allow Pembina to leverage our existing assets and provide a solution for Canadian producers. Given our existing rail assets, we are also investigating options for how we can optimize and expand our footprint.

In terms of financing, on October 22 we closed the offering of CAD450 million of senior unsecured medium term notes, which have a fixed interest rate at 3.77% per annum and will mature on October 24 of 2022. We're currently in a position of strong liquidity with cash and unutilized debt facilities at the end of the third quarter of about CAD690 million.

After taking the CAD450 million medium term notes into consideration, the proceeds of which were used to repay a portion of our existing credit facility, we currently have about CAD1.1 billion in cash and unutilized debt facilities. Our [drip] also continues to be a source of consistent cash and is raising approximately CAD20 million per month, or about CAD240 million per year. Given this, we believe we have the financial flexibility to pursue our capital plans and execute on the projects we discussed today.

Now prior to opening up the lines for questions I would like to remind you that Pembina will be hosting and Investor Day in Toronto on December 4. Our executive leadership team and business vice presidents will be giving presentations on our growth strategy and discussing in detail our 2013 capital spending plan. I would like to invites anyone wanting to attend to contact our Investor Relations department or access the details on our website under presentations and events. We will be issuing a press release with webcast information in the coming weeks as well as for those who won't be able to attend in person.

So with that I will now ask the operator to open the call for questions and answers. Over to you, Sarah.

(Operator Instructions). Linda Ezergailis of TD Securities. Your line is now open.

Thank you. With respect to your phase two expansions that you announced last night, I realized there's strong fundamentals kind of the backstopping that, but what level of contracts and what other attribute in terms of term, et cetera, would you require forward to proceed, and when do you expect to get those contracts?

Linda, it actually depends a little bit on each of the expansions, but when we had the phase one expansion for the NGL business we looked at ten year terms, and our target was approximately 75% of the expansion volumes to give us a comfort to proceed. We did in fact get something that was probably closer to 90% on that. Contracts [were] phase one.

So for phase two we're exacting about 75%, and again, ten year term take or pay contracts. On the HVP system we're looking at shorter term contracts, probably five years will be sufficient for us. And so, again, targeting about 75% of the expanded volumes.

Okay. Thank you. And how might we think of notional financing for that in terms of capital structure? Will it come off your balance sheet? And what sort of returns might we expect?

As we have indicated in the past, Linda, go forward projects will generally be financed on 50/50 debt/equity basis, and as you know we've got a lot of undrawn credit facility available to us, but -- and we have strong [direct] participation level.

And how much --

In terms of -- sorry, Linda. In terms of project returns, I think these are not going to necessarily be dissimilar to what we have experienced in the past. AndI don't think that we actually disclosed returns, but I think you can kind of calculate them from based on past experience.

Okay. And just as a follow-up on other part of your business, are you seeing any inflationary pressures in your projects? Can you give us a sense of what percentage of costs you have now locked down for Saturn and Resthaven?

Yes. Saturn and Resthaven, the gas processing facilities, Linda, we're still expecting the project to come in on time and on budget, so as far as gas processing is concerned I think we're okay. We're not seeing a lot of inflationary pressure there yet. Lead times are, of course -- that is something that we have to keep be mind l.

As far as the gathering systems are concerned, I think we are starting to see some inflationary pressure there. There's I think higher demand for contractors, and that's translating to higher costs. Fortunately for us that the gathering lines and cells are not that significant in terms of costs, but I think it's fair to say that we are starting to see some inflationary pressure on the pipeline part of the initiative. The gas line so far is coming in on time and on budget, and, Scott, what portion of our costs have we secured on the gas [plants]?

Yes, so on the Saturn facility we've ordered 95% of the major equipment and 25% of the site construction is completed. So he we only really have about 75% of the site construction left which would be subject to labor inflation. And then on the Resthaven plant we have about 80% of the major equipment ordered and about 10% of the on-site construction completed.

Okay. Thank you.

So I think with respect to the gas processing assets, I think we are feeling pretty good about our costs to date.

Great, thank you.

You're welcome.

Your next question comes from Robert Kwan of RBC. Your line is now open.

(Inaudible -- no mic) on the Northern NGL phase two expansion, and I guess this ties a little bit into the potential Redwater fractionation expansion. Are you trying to tie kind of those two processes together? And if there's anything even more specifically, are you offering preferential pricing for customers that would underpin the frac?

I don't think we really can get into the details of our contracting strategy, Robert, but what I can say is that it's pretty apparent to us that our customers are going to understand that our pipelines are full and we have to have room for additional processing capability in Alberta. So given that I think that if you're a customer that's looking for a home for your liquids, your probably going to be talking about where those liquids might go and [who] might fractionate them. So I think they are linked, but they're not directly linked at this stage, Robert.

Okay. And I guess with that phase one and the underpinnings that you got there, and then obviously your -- based our your discussions you feel pretty confident about being able to contract out phase two. Why haven't we maybe seen enough support for the Redwater fractionator expansion? Do you feel that -- I think it's a 70,000 barrel a day number that you've been talking about. Is the feedback that maybe that's a little too large, and they're worried about getting some protection on spots rates, or is there some other dynamic going on?

I think its just to complete the story, Robert. I don't think our customers really have a full appreciation for how much liquids potentially might be coming our way, and I think with the announcement of the HVP phase two expansion it's going to be pretty -- become pretty apparent. And with it we're seeing that actually -- once we complete that expansion, based on producer forecasts, Robert, we're going to be close to being full again.

And so that would suggest that there is demand at least for one additional frac, and who knows, if developments take place, there could be a demand for further fractionator at Redwater. But it's a matter of getting our complete story out there, Robert, to get people to stand behind it. We know we've got a lot of interest in a fractionator at Redwater.

Okay. Just a last question related to that expansion. You drilling caverns like crazy on the Redwater site. Do you feel that you have enough caverns based on the pace of development to get ahead -- or to move forward with a 70,000 barrel a day expansion or --

Yes,I think, Robert, we probably require one more cavern, and yes, so I think we're in good shape there.

Okay. That's great. Thanks, Bob.

Thanks, Robert.

Your next question comes from David Noseworthy of CIBC. Your line is now open.

Hey, gentlemen. Just a quick follow-on -- and you kind of touched on the phase two expansion in the sense that you expected it to be fully utilized by the time it came online. Can we assume the same with when your completed phase one expansions?

Yes.

Okay. Fair enough. And then in terms of the fractionator, in light of recent announcements of other fractionators, is there a possibility that what's needed incrementally, at leas near term, is more [C3-plus] as opposed to C2-plus?

Well, I still there I additional C2-plus, and I think our customers are trying to establish a commercial arrangement where they can get a deal for the ethane. So that is part of the package, David, is that I think C2-plus fractionator similar to what we have is still in demand to satisfy the chemical folks in Alberta.

Okay. And then just a bit of a change of pace here. You mentioned that you're exploring offshore propane export opportunities. In terms of the counterparties that are showing interest, is it more from the producer perspective, or is it from an Asia buyer's perspective? Like, what are you seeing there.

I would say the buyer.

Okay.

Rather than the producer. I think some -- let just say that -- yes, I think producers obviously will benefit from having and alternative market, and so in a sense we're hoping we can do the industry some good here.

Absolutely. And then in terms of the need for the buyer, is there a timeline that you're seeing that they're working towards?

We don't have specific time frame at this point, David. I mean, there's more work being done here in the next month or so, and we may have more to say maybe by the end of the year.

Fair enough. Okay. And then perhaps one last question. Can you discuss what liquids-rich gas processing opportunities you're seeing beyond [Musreau], Saturn, Resthaven, and perhaps if you could frame it in the context of what you have seen recently with Paramount's recent decision to [back itself off of DSI support in] Saskatchewan and [Canada selling preserver arch] midstream assets to [Umbridge]?

Well I think that if you look at where our pipelines are situated and you look at the geology under you are pipelines, what you're going to see, David, is that it's all very consistent geology. I think there people are still talking about our need for more liquid extraction. So I can't talk about specific projects, but we have probably two or three on the books currently that we are addressing, and we hope to have more to say about that next year.

Okay. And then one last question. You did mention the phase two expansion, which seems to go up into Northeast British Columbia, Northwest Alberta. What are your thoughts about expanding further south into the southern region of the Duvernay?

Well, I would say it's really early innings here, David. I don't think that there's been a lot of Duvernay development as yet. But what we are hearing for the developments that are taking place, albeit they are very, very early, that there's a lot of -- potentially a lot of condensate that might come out of the Duvernay, but more so in the area around Fox Creek. So I think we have to wait for the industry to get further along their own drilling plans to be able to assess what needs to be done next.

Thanks a lot, Bob. I appreciates your answers.

Okay, David.

Your next question comes from Juan Plessis of Canaccord Genuity. Your line is now open.

Great. Thanks. It looks likes you had added financial contracts in the quarter to hedge a portion of the NGL volumes. Have you fine-tuned your strategy with respect to hedging this business?

We've looked at in more depth now, and certainly has Bob mentioned on the call, our intent is to lock in cash flow [could of terminum] of 50% of the gas supply costs, and then -- and we will do that as we -- as our [create our] contracts for the gas supply itself. And then we will supplement that with additional derivatives from time to time to effectively lock in up to 50% of our cash flow [really] from the gas supply side of the business. And so as you indicated, we have commenced that process now, and we'll continue that for the balance of this year to certainly lock in a portion of the cash flow for 2013.

Okay. Great. Thank you. And it's mentioned in your MD&A that propane industry inventories have impacted the propane margins. Can you tell us what your shorter term outlook is for propane margins, say over the next couple of quarters?

Well, what we are leak at right now is propane prices I would say on average are roughly around $1 a gallon at Mont Belvieu, and we created a discount to Mont Belvieu in Edmonton, so I don't see any real significant change here, Juan, at this stage. Typically when you look at some of the folks that do projections, they're looking for stronger fourth quarter, first quarter of next year, but we're staying right in around $1 per gallon at this stage until we see some movement. And it's probably going to take something like colder weather or something of that nature to be -- see movement in price, because there continues to be an oversupply of propane in the market.

Okay. Great. Thank you.

You're welcome.

Your next question comes from Carl Kirst of BMO Capital Markets. Your line is now open.

Thanks. Good morning, everybody.

Good morning, Carl.

I think just two cleanup questions from my end, and I apologize, Bob, in you mentioned this in the prepared commentaries. I was scribbling in my notes. But what's been the recent experience with the Empress extraction premiums? We were hearing different things from different players, and just as we enter into the new contract year I wasn't -- I wasn't sure what you guys were seeing.

Carl, I don't know that we have seen a lot of change in the extraction premiums at Empress. We've heard that at times people were trying to get -- basically get rid of their product at depressed prices, but I still think that the premiums are going to be fairly consistent to where they have been historically. And although gas prices seem to be firming up a bit, so perhaps you might see some reduction in premium, but at this stage we're staying the course.

Okay, so basically 2013, more like 2012, which does kind of put us at risk with propane prices, but basically no change on that front.

Yes,I think it's fair.

Yes, and Q3 was basically within pennies of where we were at in Q2.

Okay. Thanks, Scott. And then maybe just a broader question. Bob, I'm not sure how much commentary you can put around this, but I know one of the larger projects in the CAD4 billion backlog was potentially a new bitumen and diluent pipe to the oil sands west of the river, and we recently saw another competitor go into that area. You have been working closely with someone though for some time. Has that dynamic shifted at all for -- with any color you can perhaps share with us?

Well, no, Carl, I think that we're continuing to work with a couple of parties in an area, and we have got some engineering support with respect to carrying on with the work that we're doing. So I think what it is, Carl, is that these projects, of course, they are large, they require significant capital investment, and certain processes have to go through the organization before they can be advanced to a point of where they are approved. So I think we're quite a ways along the path, but we're not home yet, so we're continuing to work on it.

Great. Thanks for the color.

You bet, Carl.

Your question comes from Robert Catellier from Macquarie. Your line is now open.

[Catellier] from Macquarie. Good morning. Just a couple questions. One of them have been asked but again along the fractionator side, I'm curious, it does seam like there's evident demand for fractionation capacity, both now and in the future as production grows. I think [Kiara] and some other participants see it the same way. So I'm wondering what your appetite is to build a C3-plus fractionator that might not have the usual level of contractual commitment? In other words, do you have any appetite to maybe take that on a little bit more on I spec basis than a contracted basis?

Rob, I don't think we're going to change the approach that we would take. And I think to give you a little bit of flavor to this, there is a huge demand for additional fractionation capacity right now, and so we have got a lot of people that are looking for service, and I think they appreciate that if we're going to build a facility and it's going to costs close to CAD400 million, then they're going to have to contract out for that capacity. So, no, I don't think we'll be looking at building anything really on spec here, Rob.

Another potential alternative for the propane market, you're obviously considering offshore, but railing -- you already have a very good position in Sarnia, but railing to the US is another alternative. Is that a strategy you're exploring in greater detail, perhaps getting some terminal assets down in the US and positioning yourselves that way?

It hasn't been on the top of the list of priority at this stage, Rob. I think we're more focused on what we do with Western Canada, particularly in light of the fact that if we expect to have another fractionator at Redwater, that's going to give us a lot more propane and butane to deal. And so our focus really has been where there's the most interest at this stage, which appears to be a terminal on the West Coast.

Okay. Thank you.

Okay, Rob.

Your next question comes from Matthew Akman of Scotiabank. Your line is now open.

On the integration of Provident, I'm just wondering if you could provide an update in terms of organizational side of it?I noticed that the G&A still remains pretty high. Sounds like so far you have pretty much kept everyone. How is the integration going? Are there any potential costs synergies that you might see over the next 12 to 18 months there?

Well, just to comment on the integration. I think it's gone quite well. You are right, we have hired the majority of the people from Provident to -- well, that we wanted to hire. We are running a bit of a dual track here in the sense that we have different, if you like, information systems that we're using, and so hopefully we're going to see a consolidation of those systems by the beginning of next year. So that's on the positive side.

Also in looking at it as well as, Matthew, when we put together, if you like, the Pembina budget with the Provident budget that was adjusted to reflect the removal of some of the corporate related costs and senior executive staff, that we did achieve a CAD10 million reduction compared to the two companies on a standalone basis. So there were some cost savings, and those were pretty much identified at the time of the acquisition. So at the time of the acquisition. So I think it's proceeding according to plan.

The one thing you have got to appreciate is that we got -- so we've got a much larger organization now with significant growth continuing. So we still have to have the people internally to be able to handle the growth, and growth in areas that perhaps we hadn't considered in the past, whether it's an export terminal, or whether it's building a new fractionator or expanding our pipeline system. So that these a lot of stuff going on here right now.

But I would say that my comment on the integration itself is it has gone as well as we could expect, and so we're going to [go here] by the end of the year as far as all systems are concerned, and we have got the people as physically integrated as we can. Our only issue here is we may not have enough space for everybody.

All right. Another question on the costs side relating to the pipeline business, the Conventional business. I noticed costs were down year-over-year, and you attributed that partly to power expense, but in a world where there's increased scrutiny by regulators on integrity management, I'm just wondering if you feel like you're in good shape that, or whether you see possible cost escalation on Conventional, especially the expand and kind of stressed the existing pipes to full, for maintenance capital?

Matthew, we've got a significant integrity related program under way currently. We're spending a lot of money in the fourth quarter of this year. In fact, I think this year we'll be spending probably in total about CAD50 million dollar on integrity related expenditures. And that would compare to say about CAD30 million in the past. And I think for 2013 we're probably going to be somewhere in that CAD40 million to CAD50 million range again. So we are front-ending a lot of the work to ensure that when we see the increased volumes in our pipelines that we're satisfied that the integrity of the pipelines is there to handle the increased pressures.

Yes, that's good. Peter, is that being expensed or capitalized?

Where we can associate integrity work with increased volumes or increased operating pressure, then those amounts would be capitalized. But other than that, our routine integrity inspection [type] work would all be expensed.

Okay. Thanks very much, guys. Those are my questions,.

Thanks, Matthew.

Your last question comes from Steven Paget of FirstEnergy. Your line is now open.

It's just a follow-up to a previous one. And just how much of Saturn/Resthaven's costs are going to be on major equipment? How much is for the Lego set, I guess, and how much is for putting it together, the site construction?

That's a good question, Steven. I don't know that I've actually got the details. Scott, do you have anything roughly?

Roughly 50/50.

Roughly 50/50. Okay. So -- and once something is ordered, the price is locked in?

Yes.

Excellent. Excellent. Okay. Thank you.

Thank you.

There are no further questions queued up at this time. I will turn the call back over to presenters.

All right. Well, thanks, Sarah. Thanks for everybody that participated on the call this morning. I guess to the extent that we tried to answer your he is questions, but if we haven't I will let you know you can call Scott, because he's got all the answers that I don't have. Thanks very much.

This concludes today's conference call. You may now disconnect.