Pembina Pipeline Corporation (PBA) Q3 2014 Earnings Report, Transcript and Summary

Good morning. My name is Rachel, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation Third Quarter Results Conference Call. [Operator Instructions] I will now turn the call over to Scott Burrows, Pembina's Vice President of Capital Markets. Please go ahead.

Thank you, Rachel. Good morning, everyone, and welcome to Pembina's conference call and webcast to review our third quarter 2014 results. I'm Scott Burrows, Pembina's Vice President of Capital Markets. Joining me on the call today are Mick Dilger, President and Chief Executive Officer; and Peter Robertson, Senior Vice President and Chief Financial Officer. For this morning's call, Peter will begin by reviewing our third quarter results, which we released after market yesterday, followed by Mick providing an update on Pembina's growth projects and strategy, including our recent Bakken acquisition and other new growth projects that we announced in September and October. I will then discuss our recent financing and financial position, before returning the call back to Mick once again for closing comments before we open the line up for questions. I'd like to remind you 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 must also point out that some of the information provided refers to non-GAAP and additional GAAP measures. To learn more about these forward-looking statements, non-GAAP and additional GAAP measures, please see Pembina's various financial reports, which are 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. Peter?

Thank you, Scott. Overall, all of our businesses performed well so far in 2014, as evidenced by our year-over-year improvements in operating margin, gross profit, earnings and cash flow from operating activities. The company also performed well over the third quarter of 2014. However, we experienced some irregular events, that had an impact on our results. Outside of these events, Pembina's underlying operational and financial performance was strong. In general, our positive results were primarily driven by completing our Saturn I Facility and Phase 1 Expansion in October and December of last year, combined with strong crude oil and NGL midstream results, given the better year-over-year market fundamental, higher volumes and propane pricing. Strong operational performance was offset by irregular expenses of $14 million and higher G&A due to a 26% increase in the company's share price from December 31, 2013, which led to a 1% decrease in EBITDA during the third quarter compared to the same quarter last year. On a year-to-date basis, EBITDA grew 26% to $750 million compared with $597 million for the same period last year. Our cash flow from operating activities systemically increased by 100% to $188 million or $0.57 per common share during the third quarter from $94 million, $0.30 per common share, for the same quarter last year. This was due to the higher earnings and our reduced change in noncash working capital during the 2014 period compared to the third quarter of 2013. For the first 9 months of 2014, cash flow from operating activities was $604 million or $1.87 per common share compared with $477 million or $1.56 for the same period last year. The year-to-date increase was primarily due to higher earnings and a decrease change in noncash working capital in 2014 compared to 2013. Adjusted cash flow from operating activities was $158 million during the third quarter compared to $188 million for the same quarter last year. On a per share basis, adjusted cash flow from operating activities was $0.48 per share compared with $0.61 per share for the same period. Although we had an increase in operating margin, the quarter-over-quarter decrease in adjusted cash flow from operating activities is primarily a result of increased current taxes, share-based payment expenses and preferred share dividends declared. For the first 9 months of the year, adjusted cash flow from operating activities increased by almost 14% to $613 million, up from $540 million for the same period last year. The company's earnings increased to $75 million, $0.20 per common share during the third quarter of 2014, compared to $72 million, $0.22 per common share during the third quarter of 2013. This increase was due to higher profit, which was offset by increased general and administrative expenses due to higher share-based compensation and other expenses, with an offset to per-common-share metric from increased shares outstanding. Earnings were $299 million, $0.85 per common share during the first 9 months of 2014, compared with $256 million, $0.83 per common share during the same period of the prior year. The year-to-date increase was mostly due to higher gross profit, partly offset by increased general administrative expenses and income taxes. Also impacting earnings in the third quarter and the first 9 months of 2014 was share of loss from equity-accounted investees, which includes accelerated depreciation of $25 million for certain out-of-service assets at the Fort Saskatchewan ethylene storage facility. Now moving on to each of our business units. In our Conventional Pipelines business, average throughput during the quarter increased by over 15% to 564,000 barrels per day compared to the third quarter last year. For the first 9 months of the year, average throughput increased by 15% compared to the first 9 months of 2013. Increased throughput was mainly a result of Phase 1 Expansions being placed into service in December 2013 as well as higher truck terminal volumes and additional throughput from new connections. Higher volumes in the third quarter led to increased revenue, which was up by 24% to $128 million from $103 million in the same quarter last year. On a year-to-date basis, revenue grew by over 22% to $367 million in the first 9 months of 2014 from $300 million for the same period in 2013. This revenue increase was due to increased volumes for the same reasons I previously noted, along with additional volumes from Saturn I and higher toll. Offsetting higher revenue in Conventional Pipelines were operating costs, which increased by approximately 49% and 26% during the third quarter and first 9 months of the year, respectively, compared to the same periods last year. These increases were largely due to higher costs associated with our integrity dig program and other integrity initiatives being completed post spring breakup. We also had higher power costs associated with Phase 1 Expansion and expenses related to the purchase of friction-reducing agents, which allowed for more efficient flow of product within our pipelines. As a result, operating margin in Conventional Pipelines saw increases of 12% for the third quarter and 19% for the first 9 months of 2014 compared to the previous year. Our Oil Sands & Heavy Oil business generated improved results for the first 9 months of 2014 compared to the same period of 2013. This was largely due to higher interruptible volumes and revenue generated by certain connections on the Nipisi system. The operating margin increased by almost 5% for the first 9 months of the year compared to the previous year. For the third quarter, operating margin in this business increased by 6% compared to the third quarter of 2013. Gas Services increased average processing volumes by over 48% to 427 million cubic feet per day compared to the third quarter of last year. On a year-to-date basis, volumes have increased approximately 68% compared to the same period last year. These increases were largely a result of bringing our Saturn I Facility onstream in late October 2013, which operated above its nameplate capacity of 200 million cubic feet per day during the first 9 months of 2014. Placing Saturn I into service and the associated new volumes, higher throughput at the Cutbank Complex and improved facility reliability drove an increase of almost 19% in revenue during the third quarter and 35% increase for the first 9 months of 2014 compared to the same periods in 2013. Offsetting revenue increases were higher operating expenses, which were largely associated with Saturn I being placed in service as well as higher volumes at the Cutbank Complex, including turnaround costs at the Musreau and Cutbank Gas Plants. The turnaround costs are recovered and flowed through to customers. Overall, operating margin in Gas Services increased by over 9% for the third quarter and almost 37% for the first 9 months of the year compared to the same periods last year. Midstream also continued to deliver improved results. Our NGL-related operating margin increased over 10%, and NGL sales volumes increased by 8% in the third quarter of 2014 compared to the same period last year. Year-to-date, NGL sales volumes increased by over 10% and operating margin jumped almost 42%. A significantly stronger year-over-year propane market during the first 9 months of the year -- for several months of the year combined with increased fee-for-service storage cavern revenue at Redwater West helped drive the strong results for the first 9 months of the year. Operating margin generated by our crude oil midstream activities grew 62% during the third quarter and by 52% for the first 9 months of the year due to higher volumes and wider margins. The expansion of condensate-related services, crude by rail activities and increased volumes at our full-service truck terminals, increased storage opportunities that materialized in the first quarter of the year also benefited our year-to-date results. On the whole, I am happy with the results we've achieved to date in 2014. I will now pass the call over to Mick, who will give an update on how our growth projects are progressing.

Thanks, Peter, and good morning, everyone. As an overarching comment, I would like to say I'm very pleased with how all of our projects are progressing. A few are slightly delayed and a few are slightly early. So on the overall portfolio, I'm pleased to report we are tracking on time and on budget. We were very pleased to close the acquisition of the Vantage Pipeline and associated assets on October 24, including the remaining 10% interest in the Saskatchewan Ethane Extraction Plant or SEEP. The acquisition was discussed at length in our quarterly results released yesterday, so I won't reiterate the transaction details here. We are very excited about owning these assets and the prospects associated with both Vantage and SEEP. Vantage will provide long-term, fee-for-service cash flow and strategic assets -- access to the prolific and growing Bakken play for future NGL opportunities. With this asset and SEEP, we now have a meaningful footprint in the Bakken and we'll be able to explore integration and growth opportunities in this area. For further clarification, in future reporting periods, Vantage will be included in our Conventional Pipeline business, while SEEP will be included in our Gas Services business. Turning now to Conventional Pipelines. Our Phase 3 Expansion plans continue to grow to meet customer demand. The original Phase 3 Expansion announcement contemplated constructing one new pipeline between Fox Creek and Namao, but on September 10, we announced that we plan to put 2 pipelines in the ground in this corridor. One will be the 24-inch diameter and the other will be a 16-inch diameter. In total, we expect these pipelines to provide a combined initial capacity of 420,000 barrels per day and an ultimate capacity of over 680,000 barrels per day with the addition of midpoint pump stations. These pipelines, along with our existing assets, will bring total capacity between Fox Creek and Namao to over 1 million barrels a day. Pembina submitted its regulatory application for both pipelines from Fox Creek to Namao on September 2, 2014. We also announced another segment associated with the project, a new pipeline spanning 70 kilometers between Wapiti and Kakwa, which will feed into downstream expansions. These additions are expected to bring total project spending to $2.4 billion. Our in-service date remains late 2016 to mid-2017 time frame. In connection with the Phase 3 Expansion, we are recontracting the majority of existing crude and condensate volumes on our Peace and Northern systems under long-term service contracts. Pembina has now secured approximately 650,000 barrels a day of crude, oil, condensate and NGL through its recontracting efforts and its Phase 1, 2 and 3 conventional pipeline expansions. As a result, once the Peace Phase 3 Expansion is brought into service, virtually all of the throughput on Peace -- Pembina's Peace and Northern systems will be under long-term, take-or-pay contracts. For the crude oil and condensate portion of our Phase 2 Expansions, we expect the project to be mechanically complete in early 2015 and commissioned in the first quarter of 2015, which is a slight delay. And subject to regulatory approval, we expect the NGL component of the project to be in service in the third quarter of 2015. Now moving to our Midstream business. We're happy to announce that on September 2 that we selected a site in Portland, Oregon for our proposed West Coast propane export terminal. Our initial development plans include a 37,000-barrel per day propane export facility for an expected capital investment of approximately $500 million and with an anticipated in-service date of early 2018. In accordance with the agreement we signed with the Port of Portland, we're progressing preliminary engineering design work, extensive environmental and regulatory reviews and assessments, local consultation efforts and beginning the process of obtaining the required permits and approvals to develop the terminal. We also announced on October 9 that we are developing a new condensate, diluent and crude oil terminaling site at our Heartland property that we're calling the Canadian Diluted Hub or CDH for short. CDH is really an extension of our Pembina Nexus Terminal concept. Our initial plans for the CDH, which will evolve as we continue discussions with our customers, are expected to cost $350 million. We will be phasing in pipeline connections and storage once we receive further regulatory and environmental approvals, and we expect CDH to be in service in the second quarter of 2017. The idea behind CDH is an extension of the condensate and diluent services we already offer. Once we complete our pipeline system expansions and NGL fractionators, which I'll talk about momentarily, we expect to be the largest domestic supply source of condensate in Alberta. Further, we are anticipating additional future supply from the increasing production volumes out of the Montney and Duvernay plays. CDH will be the terminus of our Peace condensate pipeline and is ideally located adjacent to all major diluent pipeline servicing the Athabasca Oil Sands producing region. At the site, the goal is to have a range of infrastructure and pipeline connections and will provide a variety of condensates and diluent service for our customers. At our Redwater site, I'm very happy to share that all of our towers are now erected for RFS II, our second fractionator at the complex. And we are making impressive progress on construction. The project is tracking on schedule and is expected to be on stream in the fourth quarter of 2015. Procurement of the longest lead items is now underway for RFS III. Regulatory and environmental applications are scheduled for submission by the end of November, which should support the start of construction in the second quarter of 2015. Now on to Gas Services. Our Resthaven facility was successfully commissioned and is now operational. On October 10, we announced that we are planning a $170 million expansion of the Resthaven facility, which includes a construction of a new gas pipeline. The expansion is underpinned by a long-term, fee-for-service contract and will increase the facility capacity by 100 million cubic feet per day, bringing total capacity to 300 million cubic feet per day. Should all the partners in the existing Resthaven facility participate in the expansion, our capital for the plant will decrease and incremental expansion capacity will be 69 million cubic feet per day net to Pembina. Subject to regulatory and environmental approvals, the gas gathering system portion of the Resthaven Expansion is expected to be in service by the second quarter of 2015, followed by the gas processing expansion in mid-2016. The volumes from the Resthaven Expansion will feed our Phase 3 Expansion on our conventional pipelines and our Redwater fractionation and storage facility under a -- on a long-term contracted basis. Construction of the Musreau II and Saturn II gas plants is progressing and these facilities are expected to be on stream in December 2014 and late 2015, respectively. The original in-service date for Musreau II was in the first quarter of 2015. So I'm very pleased that we may be able to bring this facility onstream ahead of schedule. With these facilities and SEEP in service by mid-2015, we expect our net processing capacity to be over 1.3 billion cubic feet per day. Amidst all the good news at Pembina and our strong growth story, we had a disappointing -- disappointment regarding our Cornerstone Pipeline Project. Unfortunately, our partner shelved the upstream development that the pipeline system would support, so we've in turn had to cease activities on this project. This was out of our control, but the good news is that Pembina will retain the right to use the engineering completed for the project for other commercial discussions. I'm optimistic that we'll earn our share of future Oil Sands & Heavy Oil infrastructure projects. Our overall capital expenditure forecast for this year is now approximately $1.4 billion, down from $1.8 billion, which is mainly a reflection of timing with the majority that capital -- of that capital slipping into 2015. All in all, I continue to be very pleased with the progress we are making on executing our growth plans. I cannot stress enough how pleased I am with the efforts of Pembina's employees and contractors for continuing to move our growth projects forward, meeting or exceeding our targets, all while continuing to do so with a focus on safety and responsibility. Scott?

Thanks, Mick. We continue to remain focused on maintaining the financial strength and flexibility to execute on our robust growth plans that we have ahead of us. So far this year, Pembina has had 3 successful financings. We've completed 2 preferred share offerings, one in January for gross proceeds of $250 million, and our most recent offering in September for gross proceeds of $250 million. We also issued $600 million of 30-year notes earlier this year. At the end of the third quarter, we had approximately $329 million in cash and our $1.5 billion credit facility is subsequently undrawn. Subsequent to the end of the quarter, Pembina paid cash of approximately $413 million and 5.6 million shares to complete the acquisition of Vantage. With the closing of this acquisition, we have eaten up the $329 million of cash and are slightly drawn on our credit facility. Mick?

Thanks, Scott. Before closing, I'd like to take a moment to acknowledge our recent organizational changes that we communicated last month. As announced in September 2013, after a remarkable 30 years of service with the company, Peter will retire as CFO at the end of this year, and Scott will succeed him as Vice President, Finance and CFO effective January 1, 2015. Peter has had a remarkable career at Pembina, and I would personally like to thank him for all of his contributions over the years for helping to preserve the company's strong balance sheet and solid financial health that we experience and enjoy today. With Scott soon to be stepping into the CFO role, I'm very confident that he will continue in Peter's legacy of maintaining Pembina's prudent capital structure and financial strength well into the future. In summary, 2014 has been a great year for us, looking back at all what we've accomplished. I'm very impressed with how the year has progressed, both on an operational and financial side as well as with project execution, safety and business development. Though we are currently facing some commodity headwinds, I believe very strongly in Pembina's future and the strategy we have in place will continue to drive long-term value for our shareholders for many years to come. With that, we can start the Q&A. Operator, please go ahead and open up the line for questions.

[Operator Instructions] Your first question is from the line of David Noseworthy with CIBC.

First, congratulations, both to you, Peter, on your retirement, Scott, on your new appointment.

Thank you.

Thank you.

And then just maybe to start off on one kind of detailed item. In terms of the general administrative expenses, the $53 million, can you provide any kind of breakdown of the components of that? And is this a good run rate -- quarterly run rate going forward?

David, it's not necessarily reflective of our quarterly run rate. Really, it reflects some accruals in our share-based compensation and other compensation. But normally, we would look at in Q4 of the year. So if you go back to last year, we did not accrue for it in Q3, which is why you had the $26 million number. And then in Q4 last year, you saw that run up to $40 million because some of those multipliers that were applied. This year, just given where we were tracking against our budget and on a total return versus our peers for some of the compensation metrics, we made a decision to accrue for that in Q3. So you saw some of the activities that can happen in Q4 move forward to Q3 of this year. So another way of saying that is absent a move in our share price, next quarter should be lower than where we were this quarter.

Okay. And I was wondering while -- normally, you'd just be lower. I mean, there's been a fairly material correction. Should it not be a complete reversal and you're now going to be below perhaps your run rate next quarter?

I mean, if you look at where the share price is this morning. Yes, I believe we exited Q3 at around 46, 50 or something like that. So there would be a decrease potentially.

Okay. Okay, that's helpful. And then more strategically, I'm wondering if you could give, Mick, you could just talk about how you expect to leverage your new asset footprint in the Bakken. I mean, obviously, expansion advantages is the obvious piece. But what else are you looking at and kind of how quickly do you expect to come develop this new basin?

Well, the way we look at Vantage. I mean, there is quite a bit of spare capacity. So that's job one, always to fill your spare capacity. But it's in the business that we know so well. The pipeline business, it's with a customer who we know very well. But -- it's kind of a pilot project for us in terms of U.S. assets. So it's a very safe entrance into the Bakken while we get to know the basin. I mean, we've observed over the years, a lot of organizations have -- thought things might be a little easier down south and we're not taking that approach. We're taking a very measured and patient approach to learn that basin by operating in it. But we'll have to wait and see whether that catapults us into a full-on investment into the Bakken or we stay where we are. I think we just want to get to know the basin by operating in it.

Fair enough. And then with that in mind, are there other basins in the U.S. that you'd like to get a toehold into kind of get a similar feel for what's going on there?

Nothing comes to mind. I mean, we do obviously get paper and opportunities from all over North America. But our strategy is pretty disciplined. We do one step out at a time. And in ideal situations, we always touch or have synergy with our existing assets through their value chain. So making an acquisition in the Gulf Coast or somewhere, you haven't seen us do that. And it wouldn't be something we'd be likely to do.

Fair enough. Maybe on that point, regarding your midstream assets, most of what you've been doing has been focused in Western Canadian Sedimentary Basin. Do you see any opportunities with your Sarnia/Corunna assets where you might be able to leverage them to capture growth in either Marcellus or Utica?

We have been growing that asset pretty steadily in terms of new caverns and brine and trucking and rail offloading, so we are investing there. We are awake to that. And frankly, I've wanted to move a little bit more decisively over there, but it's really been a matter of resources. We've had so much activity. If you look at the last couple of years, we've won billions and billions of dollars worth of projects. So frankly, we just haven't gotten to it. We would have liked to, because we do see opportunities there and we have a great asset. In fact, kind of reminiscence of what Redwater looked like 30 years ago. So the stage is set there, but we just need to get to it. And that's something I hope our team can find the resources to do over the next couple of years.

All right. And just 2 quick cleanup questions -- or just one on the remaining [indiscernible] of SEEP. How much was that?

It was small, David. It was a couple of million dollars.

Okay. And with respect to the Resthaven Expansion, when do you expect to understand whether or not your partners will participate or not?

I think some of them have -- we've granted them options to participate. I can't remember the timing. But it's not -- overall, it's not that material to us whether they do or they don't. And just to clarify, if they do participate, it's in the plant only. They will not be participating in the gathering line.

Your next question is from the line of Steven Paget with FirstEnergy.

Peter, best wishes in your retirement.

Thank you, Steve.

I remember you found some 6% debt and I think it was April 2009 at the bottom of the markets. And when -- and I know it seems like a high rate now but at the time, it was very good money. So I think that was a tribute to Pembina's financial strength at the time. On Phase 3, once Phase 3 is done, you note in the quarterly that all the Peace and Northern system throughput will be under long-term contracts. And that's great for Pembina in one way, but I'm sure you're also considering that small producers, new producers need available pipeline transportation capacity to grow and, ultimately, I think, maintain a healthy business environment. So what might Pembina do to ensure that non-contracted production might still have access to pipeline space?

Yes, Steven, so 2 things: Number one, keep in mind that when we talk about that number, that includes the capacity that we've contracted to date that we publicly announced on Phase 3. But initial capacity of that pipeline is 420,000 barrels a day. So there still is ample capacity on the Phase 3 plus the expansion for additional producers on that pipeline. And secondly, we say substantially all, but there will be a portion that will be kept open for interruptible volume.

We'll always keep some interruptible available for smaller producers as we have over the decades. That's not going to change.

If we see gas moving less as LNG by the end of the decade, wouldn't some of the gas need the liquid stripped out of it within B.C. before it heads west? And could Pembina be part of this with your liquids extraction at Younger?

Yes, most certainly, that's an opportunity. It remains to be seen on those projects how rich they want the gas at the coast, and that will depend, I think, a little bit on who the offtaker is and what country it's going to. But most certainly, even you know the best condensate markets, maybe on the face of the earth, are in Edmonton. It's a pretty good butane market, a very good ethane market on average, over time. And so if we can get the propane to the market through Portland, we think it can be a good propane market as well. So I think there's lots of reasons to keep that product in Alberta. And I think we can play a big role in that. That's not to say though that none of the NGLs will leave. I mean, you look at what's happening with -- Alliance is a competitor of ours and some of these LNG export lines could have some liquids in train. So -- but we're awake to that. We think it's much more of an opportunity than a threat.

Given the Cochin line reversal, could you give us some insight into what your outlook is for the Western Canadian propane market for this upcoming winter?

In terms of our ability to move product? Is that what the question is, Steven? Or pricing?

Both, actually.

I'm not a commodity forecaster, so I'm going to steer away from that one. But in terms of Cochin, I mean, I think we prepared ourselves knowing that this was coming and so we've added additional rail cars. As we've talked about over the last little while, we're preparing ourselves to rail cars. There will be a little bit slightly higher cost just because you are railing, not moving on Cochin. So we feel like we're in a good position to be able to move the product out of Redwater this winter. Obviously, it will be tight until we get some additional export capacity through our propane terminal.

And of course, a large factor is weather. And if we had a winter like last year, we should be in very good shape. And if we had a winter like 2012, it'll be tougher. So it's just really hard to predict that.

When -- we've seen some major petrochemical expansions at the Gulf Coast with the long-term incremental ethane supply. And I mean, you've dealt with petchems. Are you seeing the possibility of a major petchem expansion here in Western Canada with the incremental supply we've got here?

There certainly appears to be adequate supply to support that. Whether it's an incumbent or a new entrant is unknown. But there's been a lot of interest by people registered with us on that subject.

Your next question is from the line of Matthew Akman with Scotiabank.

I guess in this oil price environment, it's about protecting the downside as much as grabbing the upside. So in that vein, you guys did disclose that you've contracted up a lot of the base volume on Peace and Northern as well as contracting some of the expansion. I'm just wondering if you see further opportunities to do that while the market remains robust, either on pipelines or other assets like some of the base Redwater assets.

Well, I'm glad you brought that up. There's really nothing we could have done over the last 3 years more than what we did to beat the risk out of our business. You think about the recontracting, the great job the guys have done on fixing our debt over, I think, it's average term of 19 years. So there's really -- we really were on that mission right from the day we acquired Provident, is to derisk our business. So we're on that every day. So there's really -- and we are placing hedges. We're just doing everything possible to derisk our business and I think it's serving us very well. I mean, we certainly didn't see the market turmoil or turbulence coming. But when we look back, we're glad we did what we did.

Okay. Is there anything at Empress that can be done on a multiyear basis? Or is that still going to be mostly based on spot, Mick?

Yes. I mean, that is the business. We do place reasonable hedges. They're in terms of gas purchase hedges, product sale, hedges when we can, power hedges. But those are only effective for 1 year to 2 years at the most. So that business is what it is. But if you kind of layer in our growth, I think our growth is now around $6 billion, which is almost exclusively fee-for-service. We do still see our fee-for-service business growing from what it is today, around 2/3 of our NOI to upwards of 80%. So that diversification is in the works as we speak.

Your next question is from the line of Robert Catellier with GMP Securities.

Can I can just start with Cornerstone? You've taken an impairment charge. But can you discuss whether it's been -- the development expenditure there has been written off completely? And what you see is a prospect for perhaps repurposing that project?

Yes. In terms of how -- Rob, there was a couple of million dollars of land and other things that didn't get written off. So we kept that. And then we've written off our 20% of the ESA. So we shouldn't see any impact to that on a go-forward basis in our financial results. Unless, of course, we can reuse that agreement in the future. And then we might have a positive revision.

Yes. I mean, we've got kind of a engineering-ready, high-quality cost estimate there. I think we call it a class 3 cost estimate, which has a great deal of precision and regulatory application that's almost done. And so that work product could, for another customer, dramatically accelerate their time to readiness and perhaps, take advantage of the softer construction market that we foresee and perhaps, even more favorable steel prices. So we're going to flog that product and, I guess, what, about $30 million worth of work. More importantly, it's the time. So that's kind of job one for our oil sands group when they hit the ground running in '15 and even in late '14. Just to close off on that, we -- there are still people out there that do need service. So it's not like there's nobody to talk to. But nothing beyond that.

Yes, that's helpful. And then just on the proposed propane terminal. I'm wondering if you could discuss sort of the steps towards a final investment decision and the timing around that. In particular, when you think you might be in a position to go to market and solicit -- have an open season or expressions of interest?

Well, let's just talk about that in 3 steps: supply, approvals, propane supply approvals, and then propane demand. We are very comfortable we have adequate supply for this terminal now, given its proposed size. So that is not really something we're waiting to figure out. And I think that does differentiate us from some of the other projects that are out there. Second of all, regulatory approvals. We have formed and appointed a Vice President of Marine Terminals. So we've moved that project from kind of a business development project into a mini business unit in its own right that focuses to get those approvals. We've got support from the governor. We've got support from the mayor. We are meeting with stakeholders down there and it's progressing as well as we could hope at this time. That said, there's still a lot of work to do. And then, the last part of it is demand. We don't go a month without somebody calling us and asking if they could buy that product. And I think the output of that terminal is around or a little less than 1% of the total demand in Asia, and it looks very favorably positioned from a cost perspective. So we anticipate getting these approvals done and then commencing on our offtake arrangements. So those are kind of the 3 steps we're going through.

So you would want the regulatory apps first and the permits before you went to market?

Yes, we would. It's just kind of interesting but not that relevant to talk about a theoretical terminal with an offtaker. Because they've got to make tough decisions about how long they want to commit to and things like that and you just can't have those discussions on a hypothetical basis. Now all that being said, our engineering work is going full speed and in tandem with the regulatory, so that we will have a very crisp plan in place and maybe even some long-lead equipment ordered subject to cancellation penalties, for example, to keep us on track.

Okay. That's helpful. And then on the marketing side, it looked to me that the numbers were pretty strong, even in the context of adding new assets. And I'm wondering maybe you can comment how we should look at the crude oil midstream outlook on sort of an annual basis. Obviously, price fluctuations have something to do with that too. But in the context of the current environment, how should we be looking at the annual contribution from the crude oil midstream?

Yes, the way I look at it is with general drop in commodity prices and we make -- in the crude business, we make some fee-for-service, some marketing. And some of the marketing profits are the result of arbitraging different commodities. And so generally, when commodities fall, you can still, on average, make the same percentage but it could be slightly less dollars. So -- but offset by that are ever-growing receipt volumes on Peace and the other systems and so those are kind of the 2 things in play. The question is, with a lower price deck, will the margins drop in dollars be offset by the increase in volumes? And that's what we're just having a look at as we work on our 2015 budget.

Well, can you give the number then on sort of a backward-looking basis? If you were to look just at the third quarter in isolation, how do those 2 factors play off? Clearly, you made more just on the volumes.

I don't know how that played off exactly in the third quarter. Scott, do you know?

Not on a percent basis. No.

Your question comes from the line of Robert Kwan with RBC Capital.

Just wondering if you could talk about the nature of some of the discussions you're having with possible customers right now with respect to the potential RFS IV project. And specifically, if you had any early feedback from potential customers, either positive or negative, about the possibility of RFS IV being off or materially off the Redwater site?

So there's -- I heard 2 questions. One was, are we talking about RFS IV? And the second one, where might it be?

Well, yes. I guess, are you talking about it with customers and if nature of kind of where those discussions might? And if you had those discussions, just if you had any early feedback, whether it good or bad, about RFS IV, either being adjacent to Redwater, potentially being materially further away from Redwater?

Yes, for sure we're having those discussions. That's our next aspiration is to build that. I would say those kinds of discussions were generally positive. But I -- it remains to be seen with the sharp changes in commodity prices, if that's going to slow anybody down, whether our customers are going to drill as many wells or what their plans are. But in absence of that, Robert, I think those discussions were progressing. And I think, we've done an assessment and we do believe that we have sufficient land to put it on the site that we have now. But there's also merits in certain circumstances to locate it at a site nearby that site. But in terms of not in the province or a very different site, we don't see the merit of that yet.

Okay. I guess, maybe as an offshoot of your initial commentary, Mick, was the discussion seemed to be progressing nicely in terms of interest. But with the commodity price move, I guess, more broadly or even the directional nature of the conversation, say, in the last 2 or 3 weeks, have you noticed a change in tone then from the producing customers getting a little more cautious, just with respect to looking at committing to new infrastructure?

I -- our people have not communicated. We just had a board meeting yesterday. And that topic did not come up. But I -- during my career, I've also realized that it takes a while for inertia to change. And so I think it'd be too early to respond to that. I think if you ask us that in another quarter, we'd have a better sense. Because these big machines, they -- of our customers, they move forward and they don't just change on. It's been pretty quick that everything's happened. So I think we'll have a better sense of that in the next quarter. But so far, we have not seen anything.

Okay. I guess just the last question here. What do you see is the expected cost to move propane from Alberta to Portland and then through your proposed terminal? Or put differently, have you looked at what the lift to net back would be when you look at the cost to get to Portland, and then the price in the Pacific Basin versus disposing of the propane into the U.S. market and the cost to put it into the U.S. market?

Yes, we've studied that quite extensively. And we do not have the rail arrangements totally figured out yet. The beauty of Portland is that it's accessible by more than one railway so -- versus when we're looking at Rupert, it's a single rail. So I think we at least have some leverage on that. I mean -- but there is -- the landed cost or the FOB cost at Portland is quite a bit lower than the -- let me restart. There is an opportunity for a significant uplift from the cost of landing it in Portland to what we might get as a net back. Now that said, the offtaker might want some of that uplift as well. And that's one of the reasons we've taken the approach we have with getting our regulatory approvals first and then auctioning off that product so that we can keep for our customers the majority of that uplift. And just a reminder, the majority of that uplift will go to our customers because we're the agent for them in this project. And only a small part of that propane will be our proprietary propane. Because it is -- it's a fee-for-service business, the propane terminal. But if we could get all the uplift that was available, the customers in behind our Redwater complex would see a significant improvement in their net backs.

That brings us to the end of today's Q&A session. I'll turn the call over to Mick Dilger for any closing remarks.

Well, thanks, everyone, and thanks in particular to Peter for the many years of great service. And he's smiling, so that's a good thing. And also to our employees who work extremely hard. When we go back and look at what we accomplished in the third quarter, let alone this year, it's just an amazing accomplishment. And so many things are happening behind the scenes to position Pembina to have a very strong set of services and to be able to perform at a greater level. So thanks to everybody there. And I think one thing I want to note, too, that doesn't come up often is that we have 0 lost time incidents so far this year. So 0 is possible. And thanks to all our people in the field for making that happen.

Thank you.

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