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Executives

Robert B. Michaleski - Chief Executive Officer, Director and Member of Special Committee

Peter D. Robertson - Chief Financial Officer, Vice President of Finance and Vice President of Finance - Pembina Management Inc

Scott Burrows

Analysts

Linda Ezergailis - TD Securities Equity Research

Robert Kwan - RBC Capital Markets, LLC, Research Division

David Noseworthy - CIBC World Markets Inc., Research Division

Juan Plessis - Canaccord Genuity, Research Division

Carl L. Kirst - BMO Capital Markets U.S.

Robert Catellier - Macquarie Research

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Pembina Pipeline (PBA) Q3 2012 Earnings Call November 7, 2012 11:00 AM ET

Operator

Good morning, everyone. My name is Sarah and I will be your conference operator today. At this time, I'd like to welcome you all to the Pembina Pipeline Corporation 2012 Third Quarter Results Conference Call. [Operator Instructions] Thank you. I'd now like to turn the call over to our host, Mr. Bob Michaleski, Pembina Chief Executive Officer. Sir, you may begin your conference.

Robert B. Michaleski

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'll review the quarterly results we released yesterday, spend a few minutes providing an update on recent developments and then open up the line for questions.

I'll start with a reminder that some of the comments made today may be forward-looking in nature and are based on Pembina's current expectations, estimates, projections, risks and assumptions. I will also point out that some of the 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.

And I'll start off by reviewing our Q3 2012 results, followed by a look at our growth projects, and then we can get to your questions.

As you know, this is our second quarter of reporting on a combined entity since closing our acquisition of Provident on April 2. I'm 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 charge and 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.

I'm turning now to look at more detail at each business. Throughput on 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 result of the timing of integrity and geotechnical work and our power costs were down.

On a year-to-date basis, revenue and operating margin were both up for the first 9 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 2011. Those pipelines drove up year-to-date performance as well with revenue and operating margin up by 55% and 37%, respectively, compared to the first 9 months of last year.

Gas Services processed higher volumes at the our Cutbank Complex due to an increase in producer activity and the new 50 million cubic feet a day 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 million cubic feet per day, 355 million net to Pembina, which is an increase of 16% 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 of 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 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 3 and 9 months ended September 30, 2012. Our Crude Oil Midstream business, which represents Pembina's legacy Midstream & Marketing segment, contributed operating margin of $27.2 million, an increase of almost 41% compared to the same quarter of 2011. Year-to-date operating margin was $87.4 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 $46.6 million and $11.6 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 $36.2 million for Redwater West and $2.2 million for Empress East, respectively.

We have commenced the process of mitigating a portion of the frac spread risk by projecting a base level of cash flow to cover a minimum of 50% of the related natural gas cost.

These transactions will cover the period April to October 2013, to coincide with the expiry of existing instruments and extend to the end of the gas contract year. Corporately, we incurred G&A expenses of $26.9 million during the quarter compared to $13.8 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 9 months of the year, G&A totaled $70.2 million, up from $41.2 million during the same period of 2011 for the same reasons as our quarterly increase in G&A.

I'll now provide some highlights with respect to our growth projects, starting with 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 52,000-barrel per day Northern NGL Expansion.

Even with the first phase of this expansion, we don't believe we'll have enough capacity to accommodate our current volume forecast. We are continuing to see strong demand for capacity in our operating regions, namely, the Dawson Creek, Grand Prairie, and the Kaybob, Fox Creek areas. And many of our pipelines are essentially full. This is a good problem to have, of course, and is lending confidence in the 2 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'll just provide the highlights here.

The first expansion is Phase II 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 cost approximately $330 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 install 4 new pump stations, upgrade 3 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 capacity on Peace from 195,000 barrels per day to 250,000 barrels per day. It's expected to cost approximately $250 million and should be completed in 2014. To accomplish this expansion, we plan to install 5 new pump stations, upgrade 6 existing pump stations, add additional operational storage, reconfigure existing pipelines and build a total of 10 kilometers of new pipeline.

There will be an additional capital of approximately $125 million required to tie in producers to both the expanded systems. So all in, we're looking at total capital investment of about $670 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 to secure contracts for our Northern NGL Expansion and capacity is still at a premium. We will also be required to obtain the customary regulatory and environmental approvals before we are able to proceed.

This is truly a remarkable growth story. Three years ago, these assets were in modest decline. But as we said many 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 represents a 40% increase across our major systems.

For the pipeline portions of the Resthaven and Saturn projects, we are looking to break ground 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. For the Resthaven and Saturn facilities, we have now ordered a significant portion of the major equipment and we've begun to receive that major equipment at the site. Once complete, these facilities are expected to add an additional 330,000 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 first full-service terminal footprint. During the third quarter, we broke ground on the new joint venture of full-service terminal in the 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 7 fee-for-service cabin storage facilities at the site and we're aiming to have another completed in the first half of next year. We also completed and brought onstream 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 the proposed 70,000-barrel per day C2+ fractionator at the Redwater site. In the long run, we see the requirement for more frac capacity in Alberta, and so are continuing to solicit customer support and are completing preliminary engineering work for the project. Should we receive the customer support to proceed, we expect the new fractionator would cost approximately $400 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 Cochin Pipeline Reversal. We're looking for ways in which we can participate on this front.

While it's still early in the game, we're investigating offshore export opportunities for propane and butane that would allow Pembina to leverage our existing assets and provide a solution for Canadian producers. Given our existing real assets, we're also investigating options for how we can optimize and expand our footprint. In terms of financing, on October 22, we closed the operating of $450 million of senior unsecured medium-term notes, which have a fixed interest rate at 3.77% per annum and will mature on October 24, 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 $690 million. After taking the $450 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 $1.1 billion in cash and unutilized debt facilities.

Our DRIP also continues to be a source of consistent cash and is raising approximately $20 million per month or about $240 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'd like to remind you that Pembina will be hosting an 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'd like to invite anyone wanting to attend to contact our Investor Relations department or access the details on our website under Presentations and Events. We'll be issuing a press release with webcast information in the coming weeks as well for those who won't be able to attend in person.

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

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Linda Ezergailis of TD Securities.

Linda Ezergailis - TD Securities Equity Research

With respect to your Phase 2 expansions that you announced last night, I realize there's a strong fundamental backstopping that. But what sort of level of contracts and what other attributes in terms of term, et cetera, would you require in order to proceed? And when do you expect to get those contracts?

Robert B. Michaleski

Well, it actually depends a little bit on each of the expansions, but I want to head the Phase 1 expansion for the NGL business. We looked at 10-year terms and our target were approximately 75% of the expansion volumes to give us comfort to proceed. We did, in fact, get something that was probably closer to 90% on that contract for Phase I. So for Phase II, we're targeting about 75%, and again, 10-year term, take-or-pay contracts. On the HPP System [ph], we're looking at shorter term contracts, 25 years will be sufficient for us. And so, again, targeting about 75% of the expanded volumes.

Linda Ezergailis - TD Securities Equity Research

Great. 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?

Peter D. Robertson

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

Robert B. Michaleski

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

Linda Ezergailis - TD Securities Equity Research

Okay. And just as a follow-up on other parts of your business, are you seeing any inflationary pressures on your projects? And can you give us a sense of what percentage of cost you've now locked down for Saturn and Resthaven?

Robert B. Michaleski

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 the 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 mindful of. 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 themselves are not that significant in terms of cost. But I think it's fair to say that we are starting to see some inflationary pressure on the pipeline part of the initiatives, but gas plants, so far, coming in on-time and on budget. And Scott, what portion of our cost have we secured on the gas plants?

Scott Burrows

And so on the Saturn facility, we've ordered 95% of the major equipment and 25% of the site construction is completed. So we only really have about 75% of site construction left, which will 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.

Robert B. Michaleski

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

Operator

Your next question comes from Robert Kwan of RBC.

Robert Kwan - RBC Capital Markets, LLC, Research Division

On the Northern NGL Phase II expansion, and I guess this ties a little bit into the potential Redwater fractionation expansion, are you trying to tie kind of those 2 processes together? And if there's anything even more specifically, are you offering preferential pricing for customers that would underpin the frac?

Robert B. Michaleski

You know what, I don't think we can really 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, you're probably going to be starting to talk about where those liquids might go -- might fractionate them. So I think they're linked, but they're not directly linked at this stage, Robert.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Okay. And I guess with that Phase I and the underpinnings that you got there, and then, obviously, based on your discussions, you feel pretty confident about being able to contract out that Phase II, why haven't we may be seeing enough support for the Redwater fractionator expansion? Do you feel that just -- I think it's the 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 spot rates? Or is there some other dynamic going on?

Robert B. Michaleski

I think it's just -- to complete the story, Robert, I don't think that 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 HPP Phase II expansion, it's going to become pretty apparent. And we're seeing that actually, once we complete that expansion, based on producer forecast, Robert, we're going to be close to being full again. And so that would suggest that there's a demand, at least, for one additional frac, and who knows? If developments take place, there could be a demand for a further fractionator at Redwater. But I think it's a matter of getting a 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.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Okay. And just the last question related to that expansion. You’re 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 this 70,000 barrel a day expansion or...

Robert B. Michaleski

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

Operator

Your next question comes from David Noseworthy of CIBC.

David Noseworthy - CIBC World Markets Inc., Research Division

Just a quick follow-on and you kind of touched on the Phase II expansion in the sense that you expect it to be fully utilized by the time it came online. Can we assume the same with -- when you've completed Phase 1 expansions?

Robert B. Michaleski

Yes.

David Noseworthy - CIBC World Markets Inc., Research Division

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 least in your term, is more C3+ as opposed to C2+?

Robert B. Michaleski

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

David Noseworthy - CIBC World Markets Inc., Research Division

Right, okay. And just to have 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 like an Asian buyer's perspective? Like what are you seeing there?

Robert B. Michaleski

I'd say the buyer.

David Noseworthy - CIBC World Markets Inc., Research Division

Okay.

Robert B. Michaleski

Rather than the producer. I think that some -- [indiscernible] to say that, yes. I guess the producers, obviously, will benefit from having an alternative market. And so in a sense, we're hoping we can do the industry some good here.

David Noseworthy - CIBC World Markets Inc., Research Division

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

Robert B. Michaleski

We don't have a specific timeframe 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.

David Noseworthy - CIBC World Markets Inc., Research Division

Fair enough. Okay. And then maybe for us just one last question. Can you discuss what liquids-rich gas processing opportunities you're seeing beyond Musreau, Saturn and Resthaven? And perhaps, if you could frame it in the context of what you've seen recently with Paramount's recent decision to back out [indiscernible] for Saskatchewan and Canada selling its pre [indiscernible]mid-stream assets to Enbridge?

Robert B. Michaleski

Well, I think that if you look at where our pipelines are situated and you look at the geology under our pipelines, what you're going to see, David, is that it's all very consistent geology. I think they're -- people are still talking about a need for more liquids extraction. So I can't talk about specific projects, but we have probably 2 or 3 on the books currently that we are addressing. And we hope to have more to say about that next year.

David Noseworthy - CIBC World Markets Inc., Research Division

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

Robert B. Michaleski

Well, I'd say it's really early innings here, David. I don't think that there's been a lot of Duvernay development as yet. What we are hearing for developments that are taking place, albeit they are very, very, early, that there is 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 in their own drilling plans to be able to assess what needs to be done next.

Operator

Your next question comes from Juan Plessis of Cannacord Genuity.

Juan Plessis - Canaccord Genuity, Research Division

It looks like you added some 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?

Peter D. Robertson

Yes. Well we have looked at it in more depth and now and certainly as Bob mentioned on the call, our intent is to lock in cash flow equivalent term minimum at 50% of the gas supply cost. And then we will do that as we -- as a creator's contract for the gas supply itself. And then we'll supplement that with additional derivatives from time to time to effectively lock in up to 50% of our cash flow 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.

Juan Plessis - Canaccord Genuity, Research Division

Okay, great. And it's mentioned in the 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?

Robert B. Michaleski

Well, what we're looking at right now for propane prices, I'd say on the average, are roughly around $1 a gallon at Mont Belvieu. And we'd created a discount to Mont Belvieu and 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 are looking for a stronger fourth quarter, first quarter of next year. But we're staying right in around that $1 per gallon at this stage until we see some movement. It's probably going to take something like colder weather or something of that nature to be -- see a movement in price because there continues to be an oversupply of propane in the market.

Operator

Your next question comes from Carl Kirst of BMO Capital Markets.

Carl L. Kirst - BMO Capital Markets U.S.

I think just 2 clean-up questions from my end, and I apologize if 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 sort of enter into the new contract year, I wasn't sure what you guys were seeing.

Robert B. Michaleski

You know what, Carl, I don't know that we've seen a lot of change in the extraction premiums at Empress. We've heard that at times, people were trying to 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.

Carl L. Kirst - BMO Capital Markets U.S.

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

Robert B. Michaleski

Yes, I think that's fair.

Scott Burrows

Yes. And just Q3 was basically within pennies of where we were at in Q2.

Carl L. Kirst - BMO Capital Markets U.S.

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 $4 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've 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?

Robert B. Michaleski

No, Carl. I think that -- we continue 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 where they're approved. So I think we're quite aways along the path. But we're not home yet, so we're continuing to work on it.

Operator

Your next question comes from Robert Catellier from Macquarie.

Robert Catellier - Macquarie Research

Catellier from Macquarie. Just a couple of questions. One of them had been asked, but again, along the fractionator side, I'm curious, it does seem like there's evident demand for fractionation capacity both now and in the future as production grows. I think Kieran [ph] and some other participants see it the same way. So I'm wondering what your appetite is to build a C3+ 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 a spec basis than a contracted basis?

Robert B. Michaleski

I don't know, 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've 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 cost close to $400 million, then they're going to have to contract up for that capacity. So no, I don't think we'll be looking at building anything really on spec here, Rob.

Robert Catellier - Macquarie Research

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

Robert B. Michaleski

It hasn't been at the top of the list of priorities at this stage, Rob. I think we're more and more focused on what we do in 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 with. And so I think our focus really has been where there's most interest at this stage, which appears to be a terminal on the West Coast.

Operator

Your next question comes from Matthew Akman of Scotia Bank.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

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

Robert B. Michaleski

Well, just a comment on the integration, I think it's gone quite well. You are right, we have hired the majority of the people from Provident that, well, 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 see that we're going to see a consolidation of those systems by the beginning of next year. So that's on the positive side. Also and looking at it as well, 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 $10 million reduction compared to the 2 companies on a standalone basis. So there were some cost savings, and those were pretty much identified at the time of the acquisition. So I think it's proceeding according to plan. One thing here you've got to appreciate is that we got -- so we 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 systems, there's a lot of stuff going on here right now. So -- but I'd say, 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've got the people as physically integrated as we can, our only issue here is we may not have enough space for everybody.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Right. Another question on the cost side relating to the pipeline business, the conventional business. And 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 way or whether do you see possible cost escalation unconventional, especially if you expand the kind of stress the existing pipes to full for maintenance capital?

Robert B. Michaleski

Yes. You know what, Matthew, we've got a significant integrity-related program underway 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 $50 million, 5-0, on integrity-related expenditures. And that would compare to, say, about $30 million in the past. And I think for 2013, we're probably going to be somewhere in that $40 million to $50 million range again. So we are funding a lot of the work to ensure that when we see the increased volumes on our pipelines, that we're satisfied that the integrity of the pipeline is there to handle the increased pressures.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Yes. And Peter, is that being expensed or capitalized?

Peter D. Robertson

Well, 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 dig work would all be expensed.

Operator

Your last question comes from Steven Paget of FirstEnergy.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

It's just a follow-up to your 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?

Robert B. Michaleski

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

Scott Burrows

Roughly, 50-50.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Roughly, 50-50, okay. So -- and once something's ordered, the price is locked in?

Scott Burrows

Yes.

Operator

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

Robert B. Michaleski

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

Operator

This does conclude today's conference call. You may now disconnect.

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