Earnings Call: Q4 2013

Feb 14, 2014

Good morning, ladies and gentlemen. My name is Ryan, and I will be your conference operator today. At this time, I would like to welcome everyone to the Keyera Corporation 2013 year-end results. All lines have been placed on mute in order to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question at this time, simply press star, then the number one on your telephone keypad. If you would like to withdraw your question from the queue, press the pound key. I would now like to turn our call over to John Cobb. You may begin. Thank you, Ryan, and good morning. It's my pleasure to welcome you to Keyera's 2013 year-end results conference call. With me are Jim Bertram, Chief Executive Officer, David Smith, President and Chief Operating Officer, and Steven Kroeker, Vice President and Chief Financial Officer. In a moment, Jim and David will discuss the business, and Steven will provide additional information on our financial results. At the conclusion of the formal remarks, we'll open the call for questions. Before we begin, however, I would like to remind listeners that some of the comments and answers that we will be providing today speak to future events. These forward-looking statements are given as of today's date and reflect events or outcomes that management currently expects to occur based on their belief about the relevant material factors, as well as our understanding of the business and the environment in which we operate. Because forward-looking statements address future events and outcomes, they necessarily involve risks and uncertainties that could cause actual results to differ materially. Some of these risks and uncertainties include fluctuations in supply, demand, and pricing of natural gas, NGLs, isooctane, and crude oil. The activities of producers and other industry players, operating and other costs, the availability and costs of material, equipment, labor, and other services for capital projects, governmental and regulatory actions or delays, and other risks as are more fully set out in our publicly filed disclosure documents available on SEDAR and on our website. We encourage you to review the MD&A, which can be found in our 2013 year-end report and our annual information form, both of which were published yesterday and are available on our website and on SEDAR. With that, I'll turn it over to Jim Bertram, Chief Executive Officer. Go ahead, Jim. Thanks, John, and good morning, everyone. Thank you for joining us this morning on the call. I'm pleased to report that Keyera has delivered very strong results again in 2013 and continued to provide shareholders with stable and growing cash flows. Our success comes from a focused business strategy and a disciplined approach to capital investments. Net earnings for the year were CAD 147 million, or CAD 1.87 per share, and EBITDA was CAD 379 million, up 28% from last year. Distributable cash flow of CAD 288 million or CAD 3.68 per share was 44% higher than last year. With dividends to shareholders of CAD 177 million or CAD 2.26 per share, our payout ratio for the year was 61%. While Steven will talk more about our financial results later in the call, let me just say that the growth of cash flow from the business allowed us to increase dividends again in 2013, this time by 11%, while still retaining a portion of the cash flow to invest in new growth initiatives. Producer activity continued at a high level around many of our facilities in 2013, despite the challenges posed by weak natural gas prices throughout most of the year. This resulted in record performance from the gathering and processing business unit in 2013. Producers continued to focus on gas that is rich in NGLs in order to maximize the value of their production. Increasingly, they are looking to companies like Keyera to provide them with the necessary infrastructure to enable them to get the production to market. This is presenting us with opportunities to invest capital, not only in our gathering and processing business unit, but also our liquids business unit as well. All of this development is gradually increasing throughput at several of Keyera's gas plants, with the potential for continued growth in 2014. The average gross throughput at Keyera's gas plants in 2013 increased 6% compared to the previous year, despite restricted throughput at the Simonette and Strachan gas plants for a portion of the year. This increase was largely a result of increased drilling around our plants and volumes delivered to the plants from new gathering pipelines added during the year. Two areas that experienced significant growth in producer activity include the West Central region of Alberta, where we have several large gas plants and the Deep Basin area around our Simonette gas plant. In addition to the geological horizons like the Montney, Duvernay, and Glauconite zones, we are also seeing considerable producer interest in the Spirit River and Cardium horizons across west central Alberta. Production from these and other zones is driving throughput growth at our Minnehik-Buck Lake, Strachan, West Pembina, Nordegg River, and Brazeau River gas plants. We have a number of exciting initiatives underway to support growth in the throughput at our Rimbey gas plant. The success of producer drilling programs, combined with new pipeline lateral that connected to the Carlos system late in 2013, means that the Carlos pipeline is now full. To remedy this, we are currently undertaking modifications to increase its capacity by as much as 40 million cubic feet per day. Work is currently underway, and we expect the modifications to be completed by the second quarter of this year. We recently signed a gas handling and processing agreement with a producer to underpin construction of the Wilson Creek pipeline system, which will also deliver new production to the Rimbey gas plant. It will consist of a 12-inch raw gas gathering line and a 6-inch condensate line, and will be able to handle approximately 190 million cubic feet per day of gas and approximately 25,000 barrels a day of condensate. The pipeline will run west of the Rimbey gas plant towards the Willesden Green area, where several large producers have started to explore the Duvernay shale potential. We have designed the system to allow us to expand it further west into this area should the Duvernay become commercial there in the future. Unfortunately, the Rimbey Turbo project has been delayed due to the regulatory intervention by three companies operating downstream of the Rimbey gas plant, who believe that they will be economically disadvantaged by the project. The matter is currently before the Alberta Energy Regulator, which will determine whether these interventions have basis. The producers in the area who are the owners of the natural gas and the natural gas liquids are very supportive of Keyera's project because they see considerable value in the additional liquids extraction capability. With their support, we remain optimistic that the project will proceed, but these delays now mean the soonest the project could be operational is early 2015. In the foothills area of Alberta, several producers are actively drilling several liquids rich geological horizons and are looking to us to provide gathering and processing services. In 2013, we purchased two new gathering pipelines that deliver gas into Keyera's Strachan North pipeline system. We are currently working with several producers interested in delivering gas into Keyera pipeline systems connecting the Strachan, Nordegg River, Brazeau River, and West Pembina gas plants. These discussions also involve construction of a new gathering pipeline called the Twin Rivers Pipeline. In the Deep Basin, work has been underway for several weeks on the Wapiti pipeline system, a 90 km pipeline system to deliver raw gas and condensate to the Simonette gas plant from the Wapiti area. This project was underpinned by NuVista, who recently exercised their option to secure additional transportation and processing capacity. We are in discussions with another producer who is interested in securing the remaining capacity on the pipeline and committing to processing at the plant. We continue to expect that the pipeline will be operational in the second quarter of 2014. While we continue to face operational challenges related to the composition of gas we're receiving at the Simonette gas plant, we were able to increase utilization in 2013 ahead of the plant modifications we'll be making this year to support the growing production volumes at the plant. Equipment has been ordered for the new 10,000 barrel per day condensate stabilizer and for the new 100 million cubic feet per day capacity expansion. We currently expect these projects to be completed before year-end. With that, I'd like to turn it over to David to review our liquids business unit. David? Thanks, Jim. The liquids business unit also posted record results in 2013, particularly in the NGL Infrastructure segment, where operating margin was almost 10% higher than in 2012. This was despite two outages at the Alberta EnviroFuels facility, which had a significant impact on the results. The NGL Infrastructure segment continues to benefit from growing demand for fractionation storage and other NGL logistics services as producers increase liquids-rich natural gas production. In 2012, we announced the construction of a 30,000 barrel per day de-ethanizer at Fort Saskatchewan to process an ethane-rich stream of NGLs from producers primarily in the Deep Basin area. We made significant progress on engineering, fabrication, and site preparation in 2013 for this project, and we anticipate completing the project towards the end of 2014. In order to meet the growing demand for fractionation services in Alberta, we recently announced plans to expand our C3+ fractionator by 35,000 barrels per day, more than doubling the capacity at the facility. This project is supported by commitments from producers and is expected to be on stream in the first quarter of 2016, assuming timely receipt of regulatory approvals and no changes to our construction schedule. The gross capital cost of the project is currently expected to be approximately CAD 220 million. Demand for storage in Fort Saskatchewan for NGLs and condensate has been steadily increasing, and Keyera has been meeting this demand by adding to its underground storage capacity. In 2013, we added about 700,000 barrels of capacity in our 12th cavern and are currently in the process of developing two additional caverns at the facility. In a few months, Kinder Morgan plans to take its Cochin pipeline out of service for southbound propane exports and reconfigure it for northbound condensate imports. As a result, more propane will need to move from Western Canada to market by rail. To respond to this need, we have just announced plans to build a new propane loading rail terminal on Keyera's land at Josephburg, which is near our Fort Saskatchewan facility. We believe this terminal will be well situated to meet the industry's growing demand for propane egress and will provide long-term value for Keyera and for our customers. We have also been active developing new infrastructure on the oil sands services side of our business. In October, we began operations at our South Cheecham rail and truck terminal south of Fort McMurray. The site has been loading undiluted bitumen onto rail cars since then, and work was completed recently to allow us to receive diluent and solvents at the site. In 2013, we announced we are partnering with Kinder Morgan to build the Alberta Crude Terminal in Edmonton. We have completed the engineering work for the terminal, as well as site preparation, and we expect to begin construction as soon as regulatory approvals are received. Industry interest in moving crude oil by rail continues to be strong, and we are currently in discussions with companies interested in securing additional rail loading capacity at both the South Cheecham and Alberta Crude Terminals. I mentioned earlier Kinder Morgan's plans for the Cochin Pipeline. Keyera is currently undertaking a project to tie in our Fort Saskatchewan facility with the Cochin Pipeline in order to receive condensate at the facility when the pipeline changes into diluent service later this year. At the present time, Keyera Fort Saskatchewan is expected to be the only outlet from the Cochin Pipeline, and we are in discussions with the Cochin shippers who are interested in securing condensate storage capacity at KFS. With respect to the Norlite Pipeline, we are continuing to work with Enbridge on the documents necessary to define the ownership, operation, and condensate transportation details, and we are making good progress. We have the right to participate in the pipeline as a 30% non-operating partner, and we intend to do so, assuming we are able to reach agreement on the necessary terms. We were pleased with the operation of the Alberta EnviroFuels facility in 2013, despite two outages during the year. We have been successful in developing new markets for isooctane, and this new demand enabled us to steadily increase throughput at the facility during the year. The combination of high North American gasoline prices and soft butane prices in 2013 resulted in attractive margins for isooctane. We are pleased to have recently secured access to storage and rail offload capacity at the Kinder Morgan Galena Park facility, located adjacent to the Houston Ship Channel in Texas. We intend to use this capacity to support and grow our isooctane sales in the United States. The capacity we have at the facility will enable us to deliver isooctane by rail to the Gulf Coast and maintain inventory in what is becoming a key market for this product. We will also be able to use the facility's marine loading terminal to load isooctane onto barges, which would allow us to deliver product to customers in the U.S. with access to the water. Alberta EnviroFuels and our isooctane business continue to be a key piece of our value chain, and we are looking forward to another good year in 2014. Supported by the isooctane results, our marketing segment had a good year, with operating margin 45% higher than in 2012. Strong contribution from all of our product lines, isooctane, propane, butane, condensate, and crude oil midstream, contributed to these results. Overall sales volumes in 2013 were 99,800 barrels per day, 7% higher than in 2012. Propane markets remained weak across North America for most of 2013 as supply continued to exceed demand. Strong demand for propane for crop drying in the U.S. Midwest in the fourth quarter was immediately followed by unusually cold weather across much of North America, and this strong increase in demand has caused propane prices to rise dramatically in December and into 2014. Because of the propane purchase pricing strategy we have had in place since April of 2013, Keyera does not benefit directly from these kinds of swings in propane pricing. Instead, Keyera has made a conscious choice to reduce its risk exposure in favor of more stable propane margins. As a result, the strong propane margins that were earned this year were primarily associated with higher volumes rather than propane price movements. Keyera's propane pricing strategy has not changed in the first quarter of 2014. Butane demand and butane margins remained steady again in 2013, leading to healthy results. As we have done in the recent past, we used our rail cars and infrastructure to take advantage of regional weakness in various North American butane markets during the summer, acquiring butane feedstock for Alberta EnviroFuels at attractive prices. Diluent demand was strong in the first quarter of 2013, but weakened somewhat throughout the remainder of the year, as bitumen production growth in Alberta was somewhat below expectations. This caused condensate prices in Alberta to weaken, and the weaker prices resulted in fewer imports of condensate into Alberta. Longer term, we continue to expect oil sands projects already announced and under development will result in significant growth in bitumen production over the next several years with a corresponding increase in demand for diluent and related logistics handling services that Keyera is well-positioned to provide. Finally, our crude oil midstream activities posted strong results in the fourth quarter and for the full year again in 2013. With that, I'll turn it over to Steven to discuss the financial results in more detail. Thanks, David. As Jim and David mentioned, we are pleased with how well all segments of the business performed this year. EBITDA was CAD 379 million, 28% higher than the CAD 297 million reported last year. The growth we experienced in all three of our business segments led to record operating margin in 2013. Net earnings were CAD 147 million or CAD 1.87 per share, compared to CAD 131 million or CAD 1.71 per share in 2012. The higher operating margin was partially offset by higher long-term incentive plan costs, higher deferred income tax expense, and higher depreciation charges. In 2013, distributable cash flow was CAD 288 million or CAD 3.68 per share, compared to CAD 200 million or CAD 2.62 per share in 2012. The strong operational results were the largest contributor to the higher distributable cash flow. Dividends to shareholders were CAD 177 million or CAD 2.26 per share. This resulted in a full-year payout ratio of 61%. The payout ratio in the fourth quarter was 63%. Overall, approximately two-thirds of Keyera's 2013 operating margin was from fee-for-service businesses and one-third from the marketing segment. Our gathering and processing business posted strong operational results in 2013, delivering a record operating margin of CAD 157 million for the year. These record results were achieved despite a volume curtailment at the Simonette gas plant in the first half of 2013. The liquids business unit also delivered record results in 2013. Full-year operating margin in the NGL infrastructure segment of CAD 123 million was 10% higher than the CAD 113 million recorded in 2012. As David mentioned, these results were achieved despite two outages at the Alberta EnviroFuels facility, which increased operating costs and decreased revenue. On a full year basis, the marketing business generated CAD 133 million of operating margin compared to CAD 92 million last year. Strong results in most parts of the business, including the newly acquired isooctane business, contributed to these results. Included in the 2013 operating margin was an unrealized loss on risk management contracts of CAD 15 million, compared to an unrealized gain of CAD 30 million in 2012. Excluding the non-cash unrealized loss, the marketing contribution in 2013 was CAD 148 million. Keyera's general and administrative expenses were CAD 27 million in 2013 compared to CAD 24 million in 2012. This increase was largely due to higher staff levels and other related costs necessary to support Keyera's growing business. Long-term incentive plan costs were CAD 28 million in 2013, CAD 18 million higher than last year. The higher LTIP expense in 2013 was due to the 30% increase in Keyera share price over the year and higher expected payout multipliers related to the performance awards portion of the plan. Finance costs were CAD 52 million in 2013, CAD 4 million higher than in 2012. The value of inventory at year-end was CAD 176 million, slightly lower than at year-end last year, and CAD 77 million lower than the end of the third quarter. The decrease in the fourth quarter was related to strong demand for both propane and butane. Keyera incurred CAD 2.2 million of cash taxes in 2013, about the same as in 2012. These taxes primarily relate to one of Keyera's subsidiaries. Keyera expects that its cash taxes will increase in 2014 to between CAD 35 million and CAD 40 million. This estimate is based on 2013 tax flow income from the partnership within Keyera's structure that is allocated to Keyera Corp in 2014, as there is a one-year deferral for income tax purposes. The estimated cash taxes represent approximately 12%-14% of Keyera's 2013 distributable cash flow. The increase in cash taxes in 2014 is largely due to the growth in Keyera's business and less available deductions. Certain capital expenditures Keyera incurred in 2013 are not able to be claimed until the assets are put into service. Depending on when major capital expenditures are available for use for the purposes of claiming capital cost allowance, taxable income can vary significantly from year to year. Our capital liquidity continues to be strong, with a net debt-to-EBITDA ratio of approximately two times, compared to our strictest covenant of four times. Finally, we've included our year-end supplementary information on our website concurrent with the release of our 2013 year-end financial results. This information includes both operating and financial data for each segment of our business. You can reference our 2013 year-end report for details on how to access the supplementary data. That concludes my remarks. Jim, back to you. Thanks, Steven. In 2013, Keyera celebrated its 15th year as an independent business and its 10th year as a public entity. These milestones are important as they provide an opportunity to reflect on our accomplishments and a chance to reaffirm the characteristics that have led to our success. Over the years, we've learned a number of things that we practice every day, and I'd like to touch on a few of them today. First and foremost, we've learned that this is a customer service business. If we don't provide a value-added service to our customers, we don't have a viable business model. We've learned that we need to be flexible with commercial terms in order to meet our customers' needs and innovative in the midstream energy solutions we offer to them. We've learned that it is a business driven by assets, and no asset is more important than our people who bring the expertise, integrity, and hard work that enable us to provide our customers with a superior service offering. As a result of this focus, we've established a reputation with our customers of doing what we say we will, working hard on their behalf, and finding opportunities to partner with them to create win-win business arrangements. In addition to these behaviors, we have invested capital over many years to develop and grow a network of interconnected plants, pipelines, facilities, and services that allow our customers to access services across the entire value chain. Our customers, whether they are developing liquids-rich natural gas or producing bitumen from the oil sands, need the services we provide more than ever before. In addition to enhancing the stability of our cash flows, this demand is also providing us with many opportunities to grow our business. Today, we have over CAD 1.1 billion of internal growth projects underway and anticipate spending between CAD 500 million and CAD 600 million of that amount in 2014. We have a number of other projects under evaluation in all segments of our business and hope to be able to develop them to a point where we are able to give them the green light. The future looks very exciting for Keyera, and I look forward to the year ahead. John, that concludes my comments, and we can open up the lines. Thanks, Jim. Please go ahead, Ryan. At this time, ladies and gentlemen, if you would like to ask a question over the phone, please press star one on your telephone keypad. Your first question comes from the line of David Noseworthy from CIBC. Your line is open. Good morning, gentlemen. Morning. Good morning, Dave. Just a quick question on the Josephburg propane terminal. Can you describe why there's a CAD 30 million difference between that 40,000 barrel per day terminal versus your Alberta crude terminal? That would probably require more detail than we can get into this morning, David. Keep in mind that the cost there, it's pretty much a greenfield site, so the cost there includes bullet storage for the propane as well as pipeline access over to the site from our KFS facility. The pieces that we're building there are quite different from the crude facility. Okay. You mentioned in your MD&A that you've signed a new agreement with, I guess, a producer for your condensate system. Can you give us any idea of what kind of incremental facilities require CapEx, EBITDA timing? On that one, David, really minimal. This is a pipeline has capacity, they will tie in, and that gas will show up at Simonette, so minimal incremental capital on our part to fill up that pipe. Oh, sorry, I was talking about the Fort Saskatchewan condensate system. Oh, I'm sorry. Yeah. There's no question, David, that we expect to have to debottleneck the Fort Saskatchewan condensate, particularly the transportation between Edmonton and Fort Saskatchewan, and in particular, assuming we end up tying into the Norlite pipeline 2 years from now. We don't think that we have any imminent constraint with respect to the additional commitment that you're referring to. But we fully expect that within 3 or 4 years, we will be debottlenecking the system. I wouldn't attribute that additional capital to the new commitments that we have this year, but it is in our plan. Okay. In terms of EBITDA from the agreement? I don't think that's something that we're prepared to divulge at this stage. Okay. If I can maybe just quickly on your Galena Park facility. What's the size of the market that Galena Park provides for Keyera for your isooctane sales? It's difficult to quantify. Keep in mind that isooctane is, I refer to it as a niche product. It's sort of a high margin, low volume product in the overall scheme of things. It does command a premium price, and in particular, we expect that we'll be able to command an even stronger price when we can meet the demand when it's there. That's one of the reasons why we want to have a facility in the Gulf Coast with access to rail and to water, with some storage there that we can utilize to meet the demands from both existing and new customers. David, I think it is safe to say that, once you access barge in the Gulf Coast, you have access to a significant number of refineries up and down the Gulf Coast, so it's strategic. That we don't deliver to today, that's right. Fair enough. Do you think that this will basically use up the remaining portion of your available capacity at AEF? I would say yes. With a combination of that and what we've been able to do with rail loading at Edmonton, I would say there's really no constraint on our ability to produce isooctane from a market point of view at this stage. Just finally on your propane margins, you mentioned that you expected them to be flat quarter-over-quarter. I was just trying to understand, are shortages hampering your ability to deliver into what's really a constrained market right now with lots of opportunity? Or do you not expect volumes to be higher, I guess, quarter-over-quarter? First of all, David, I don't think we said margins are flat. I just wanted to point out that with respect to the purchasing and hedging strategy that we've adopted for propane, I want people to understand that we're not expecting to participate in the significant fluctuations in propane price that you've seen over the last few months. We have a pretty solid network of propane distribution and rail facilities, and we've been doing our best to try and make sure that we can meet the market demand and provide egress for propane from Western Canada. I think I'm confident in saying that we've been able to do as well as any in terms of addressing some of the issues that you've heard about over the course of the last three or four months in terms of the high propane demand and logistics challenges. Yes, sir. My apologies. It was stable, not flat. Yeah. Last on that, because you do a lot of your hedging on the propane using Mont Belvieu, but we could see in the quarter, Q1 at least, that pricing in both Edmonton and Conway were considerably above Mont Belvieu. Does that basis differential provide an opportunity for you to make better margins? First of all, David, most of the hedging that we're doing for propane is actually at Conway, not at Mont Belvieu. Conway and Edmonton are fairly well connected, and so that's a primary reason that we've adopted that approach, is to try and make sure that we minimize any basis risk, any geographic basis risk that exists. There's no question that there's been a disconnect between Mont Belvieu and Conway over the course of the last little while, but that hasn't really affected us directly very much. Okay. Well, thank you for your answers. I'll get back in the queue. Your next question comes from the line of Rob Hope from TD Securities. Your line is open. Good morning. Good morning. Maybe just a follow-up question on the Fort Saskatchewan condensate system. What would debottlenecking look like? Would these be relatively minor capital investments, or would you have to re-pipe pretty much from Edmonton to KFS? Without getting into a whole lot of detail, there's a lot of question marks about where the additional supply of condensate is going to come in into the hub and where the outlets will be. Having said that, I think it's fair to say that one of the key additional investments for us would be to twin the existing pipeline that we have between Edmonton and Fort Saskatchewan. We currently have a 16-inch pipeline in our Fort Saskatchewan pipeline system that's used for condensate. It's our anticipation that at some point in the future, that 16-inch pipeline will not be sufficient for the flows that we anticipate. Having said that, it may not be a complete new build. There may be some other alternatives with existing infrastructure in that corridor that we can take advantage of. Okay. Just regarding Cochin, will that be connecting directly into KFS, so it will not use up any capacity on the Fort Saskatchewan condensate system? That's correct. Okay, great. Okay, maybe just one or two last questions. Just on the acquisition front, we're seeing Devon having their natural gas package on the market. Is there an opportunity there for you to pick up some large gas plants? Well, I think Devon has some nice gas plants that certainly we will look at. I'm sure us and others. How Devon ultimately decides to sell that package, I guess it's a little unknown whether it's one big package or broken into 12 separate packages. No, we certainly believe they have some good assets. Okay, maybe just one last final question. With the significant amount of projects in front of you, do you have enough engineering horsepower and people power to secure some additional large projects, or are you full up for right now? Well, I think we have a very seasoned and a pretty large engineering group, but they're busy, as everybody's is. I wouldn't say we couldn't do more, but I think we're very careful about how we select projects, how quickly we jump into new projects. I think in today's world, you take longer to do more engineering, so that you're ready to go when you make that last final investment decision. I think we're in good shape, but I think you have to be very selective. All right, great. Thank you. Your next question comes from the line of Robert Kwan from RBC. Your line is open. Good morning. Maybe just going back to the debottlenecking of FSCS. I'm just wondering, with the development of Josephburg, and if you're going to move propane out from the north, is there an opportunity, or are you still going to see significant north-bound flows to take the C3 pipe out of service and convert it over? Robert, I'm not sure I understand what you're asking. Are you talking about our C3 pipeline in that corridor? Yeah, the pipe coming out of Edmonton. Just given you're going to be moving propane out from Josephburg, is there a possibility to repurpose that pipe? Well, probably not. Anything's possible, and we're certainly looking at all alternatives. As we expand the fractionator at Fort Saskatchewan, that will result in additional propane supply, and there's still strong demand for propane in the Alberta markets. We need to be able to move propane back and forth in and out of storage into rail terminals and truck terminals in a variety of different locations through that corridor. I would expect that that would mean we're not going to be in a position to be able to take the propane pipeline and repurpose it. Okay. Maybe just kind of turning to the protest for the Rimbey Turbo Expander. I guess there was a somewhat similar issue that came up and that precedent would mean that you guys hopefully would win that. What's your willingness, though, to start spending on that project ahead of final regulatory and then what will likely end up being legal challenges? Well, I think it's safe to say we've already spent some pretty significant dollars. We're now, I think, really waiting for regulatory approval to go to the next step, and I think we're confident that the process will happen quickly, and we can continue to move on. Okay, when you get the regulatory kind of full steam ahead, despite if there's anything else on legal, are you going to wait for pretty much final resolution? I think we'll have to wait for final resolution, obviously, before we can get on site and start construction. I think we think that can happen quickly, too. Okay. Just maybe the last question. Just wanted to get your thoughts on potential additional regulations around rail cars, and then specifically to your fleet. If there are some new regulations, do you know who's going to be on the hook for those costs? I know some of the leasing companies have come out and said that the lessee is the party that's going to be on the hook. Robert, it's David here. I think we're waiting to see what some of those new regulations might look like. Our fleet is, with respect to what we call the general purpose cars, the non-pressurized cars. Our fleet is fairly new, so we're not anticipating a significant cost associated with retrofit. The older so-called DOT-111 cars are the ones that are probably looking at significant costs, and we don't have any of those in our fleet. With respect to who bears the cost, that depends a little bit on each scenario, and it depends on the nature of the retrofit that's involved. I can't really comment on that. As we see it today, we don't anticipate that those costs are going to be significant to us. I might add that I think there's a number of other elements to the rail safety picture beyond just the cost of retrofitting the tank cars themselves. We're trying to participate actively in making sure that as an industry, we're operating as safely as we can. Great color. Thank you. Your next question comes from the line of Steven Paget from FirstEnergy Capital. Your line is open. Hello. Good morning, and thank you. Just a question about the Duvernay. If we see the Southern Duvernay take off like the Northern Duvernay, what kinds of liquids pipeline infrastructure might be needed to take condensate and other liquids from the Southern Duvernay to the Edmonton region? Or would it even need to go to Edmonton? Could you build a rail terminal and rail liquids out directly? Well, Steven, I think that whether it goes to Edmonton or around Edmonton to Fort Saskatchewan, I think that the southern region is a lot more prepared for Duvernay. I know we've got 10 plants and probably close to 2 Bcf a day of capacity, but we've got a couple of pipes that can move condensate directly into Edmonton, our Rimbey pipeline, and as well, we're a 50% owner in Bonnie Glen pipeline operated by Pembina, which has ample capacity today. I think that you could move an awful lot of condensate right into the heart of what I'd call our condensate mousetrap before you'd have to go out and spend major capital to get condensate into the hub. It's, I think, a huge competitive advantage if the Duvernay starts to become commercial down here. Now that is good news. Thanks, Jim. A question on isooctane. With isooctane doing well, could another isooctane producer come into the market or expand production? We know there's basically no capacity in the U.S. to make it right now, but there was capacity in the past. Yeah, that's correct, Steven. There's one facility that I'm aware of in the U.S. that's actually currently focused on making a different gasoline additive for export. There's currently no competing merchant facility for the manufacturer of isooctane. When we purchased the facility 2 years ago, we spent a fair bit of time just trying to understand the alternatives for isooctane as a product and what the potential competitive dynamics could look like. We're pretty confident that it's unlikely that we would face additional competition for isooctane specifically. The simple reason for that is because the replacement cost of a new facility to manufacture isooctane is very significant. We estimate that our acquisition cost for AEF was probably 25% or so of what replacement cost for that facility would look like. Let's face it, the industry has lots of other needs for infrastructure for spending new capital. We don't anticipate that the isooctane business is going to attract new capacity. Could you increase the size of your AEF facility? There are no obvious debottleneck opportunities for us to increase the size of the facility. I would describe it as a very well-tuned machine as it is. The cost of that is such that we probably wouldn't be looking at that in the near term. Thanks, David. One final question. If LNG happens in BC, gas moves west and maybe Lessford or Keyera would not be sort of in the thick of it, except for its Caribou facility. Could there be ways that Keyera benefits from BC gas production that goes west? Steven, I think we're a big supporter of LNG. We'd love to see it go. I think a healthy gas business is good for everyone, and certainly a lot of liquids out of those gas streams are going to have to come back to the Fort in my belief. I also think that areas like the Kabob Simon at Wapiti region, where a tremendous amount of gas is going to be developed from the Montney and the Duvernay. I'd be surprised if some of that gas doesn't ultimately flow west as well. I think we believe there's going to be lots of ways to, you know, compete and benefit from a healthy LNG business. Well, that's good news. Thanks, Jim. Those are my questions. Thanks, Steven. Your next question comes from the line of Robert Catellier, you're from NA. Your line is open. Good morning. I have a couple of follow-up questions here. First of all, on the subject of Wapiti, looks like you found a producer there to take up the other remaining capacity. I wondered if there's also an expansion case under consideration. Well, yeah. I think I jumped the gun, but yeah, we do have another producer that would take up the remaining capacity on our 12-inch Wapiti line. Yeah. I think, Robert, that whole area that we've talked about, and I think producers talk about it an awful lot, it's early days on the development of the liquids rich Montney in the Wapiti region. It's very exciting, so I'd be very surprised if us and others aren't going to be pushed for more infrastructure development in the area. It's simply needed. Okay. We'll keep an eye open for that. Now on the Norlite situation, it looks like it's still a question of ironing out the details of the contract, but this has gone on for a couple months. Is this still a situation where it's a collaborative process and it just takes this long to iron out the details? Is there some situation where maybe Enbridge has ultimately a veto or some way that the Norlite investment just doesn't come to fruition for Keyera? No. It's very much the former, Rob. The relationship that we have with Enbridge right now is very good, and I think they continue to see the value in what Keyera brings to the equation here. It has been slower than I would've hoped to get to the finish line, but we're making progress. The reality is that when they announced the go ahead on the project, we had not really been involved very much in the details of the ownership agreement, the transportation connection onto our FSCS system, et cetera. And a number of those details have just taken more time than I would like to get sorted out. I'm optimistic now that we're close to the end. Okay. That's good news. On AEF and the Galena Park opportunity, that's interesting to me. I wonder if you could describe or sort of attribute the upside there between volume, in other words, growing the market and pricing realized prices. It's hard to be specific, Rob. What our strategy has been since we bought the facility is to try and diversify the customer base. When we bought it, we only had a handful of customers in Western Canada and Western U.S. That's been a very successful strategy. I think eventually that translates into both greater assurance of volume as well as stronger margins because you've got options when you're looking at where to move the product. Beyond that, it's hard for me to be specific. It sounds like it could ultimately be both. In either case, it looks like it's going to be more business for AEF. I think that's fair. Finally, it's not a big project, but on the sulfur side, the price tag for that Strachan project looks like it's gone from CAD 40 million to CAD 60 million, and you're reevaluating the project. There's so much going on in Alberta and CapEx inflation risk and things of that nature, can you isolate what happened on the sulfur project to take the price tag up as significantly as it's gone up? Is there something systemic there or is it isolated to that one project? I think it's probably a little bit of both. There's no question that we've seen cost inflation on certain types of projects in Western Canada. There is a rail element to the project at the Strachan gas plant, and as you can appreciate, there's lots going on the rail side of things in the industry. So that general cost inflation is part of it. I also think it's fair that as we got a little deeper into the details, we realized that the scope probably needed to be defined somewhat differently. I wouldn't describe it as a huge issue, but as Jim mentioned earlier, we're trying to be as careful as possible going into new projects to make sure that we have a realistic estimate of costs and schedule, and that we're being upfront and honest with our customers when we go into projects so that we maximize the chances of being successful and being on budget and on time. This is just one example of that, where we don't want to get ahead of ourselves and end up with an unpleasant surprise at the end. Okay. Very helpful. Thanks. Your next question comes from the line of David Noseworthy from CIBC. Your line is open. Hi, gentlemen. Just maybe a couple quick other questions here. Just with producers hedging a significant portion of their 2014 production, do you expect this to have any impact on the producer activity you see around your plants? I think producers obviously are going to benefit from the movement of the gas curve in the last six weeks, and that's With more cash in their hands. I think, yeah, you'd probably start to see maybe a slight expansion of some of their capital programs. I think there's certainly some optimism that maybe we are through the very soft gas prices we've seen over the last three or four years. I think that gas is certainly a component of their net back as is are the NGLs. I think that's a fair statement, David. In just regards to your Wilson projects, can you talk about some of the producer activity you're seeing that could eventually find its way onto the Wilson pipelines and perhaps the incremental capital projects these volumes would require? Well, I think it's no secret that the biggest player in that part of the world is Bonavista drilling their Glauconite play. I think they've said publicly that they're having more success drilling longer horizontal wells. Certainly, that's driving a lot of the activity there. There are certainly three or four other pretty active players in the Glauconite, Conoco, Apache, Encana, that will benefit, I think, from the infrastructure changes that we're putting out there. I think if you look at who the Duvernay players in the Willesden Green area, and Encana clearly have a big land picture over there. There's been some wells that have been tested. Conoco's over there. Recently Shell and Talisman have announced some interesting tests. I think it's early days, and I don't think that the Duvernay is anywhere near the development stages of the north. I think we continue to probably preach that there's better infrastructure existing. We hope that people are more active in the play this year. With the capital costs, say, expand to the full 190 or to condensate stabilization, would that be minor costs or are there more significant costs? Well, I would argue that to go get the Duvernay to the west, we probably have another 10 or 15-mile extension of that type. There will be some capital, but it's not going to be extensive capital to go get that. I think where we want producers to communicate and let us know their timing because we've got a gas plant back at Rimbey that's starting to fill up and get very tight. Now we have other things and debottlenecking we can do, but it takes time, takes money. That sounds like more opportunities there as well. Absolutely. Great. Thank you. Those are my questions. Your next question comes from the line of Matthew Akman from Scotiabank. Your line is open. Thank you very much. I wanted to know if you guys have any update on your pipeline strategy following the Western Reach efforts and whether you've updated that. It feels like there's a lot of activity around connecting existing field plants to new pipes and expanded pipes and extending those, which is obviously a pretty profitable activity. I'm just wondering if there's anything over and above that vis-a-vis trying to get pipes into Fort Saskatchewan. Matthew, I'd say that we're certainly going to watch closely after breakup to see what kinds of volumes are evolving in the Deep Basin, Simonette, Wapiti, Kabob area. I wouldn't say we've moved the project along too aggressively. I think it's still a wait and see whether the market needs another pipe and if they do, when. Okay, thanks for that. Also, the only other question I had was whether you have any comments on fractionation kind of supply and demand. There was some commentary in the MD&A about how tight market conditions for fractionation drove higher profitability in NGL infrastructure in 2013, and I'm just wondering how you see that shaping up over the next year, I guess, and whether you're seeing any new competition from maybe some of the legacy assets floating around Alberta. I'm not sure what you meant by the second question, but let me try and address the first one. There's no question that the fees that we and others are charging for fractionation have gone up in the last couple of years as capacity's gotten tight. That really is simply a reflection of the incremental capital cost of new fractionation capacity. So the fees now are approaching what is required really to support the cost of the incremental fractionation capacity. That's part of the picture with our recently announced capacity expansion at Fort Saskatchewan. I suspect Imperial is looking at a similar kind of equation at their Redwater facility. I'm not sure what you meant by the second question. What I'd maybe add to that, Matthew, maybe answer your second part of the question. I think that frack capacity in general is getting tighter in Alberta, and the obvious place that people want to take their mix is to Fort Saskatchewan, where you have the market hub. But there are a few plant facilities that have fractionation, and I think we saw it last year, and we're certainly going to see it this year as well, where you're going to see just about anybody that has frack capacity in Alberta utilizing that frack capacity. So there's some small plants. I know we have a couple of small debottlenecking projects that we're looking at Nevis and Rimbey, and I'm sure others are looking at it. I know Devon has some of that in their package as well. Frack capacity will continue to be tight, I think, for the next 18 months till some new capacities comes online. Okay. Thanks very much, guys. Those are my questions. Thank you. The next question comes from the line of Steven Paget from FirstEnergy Capital. Your line is open. Thank you. Just a follow-up question on how might you finance Norlite. Would Keyera need to come up with the debt capital, or could the project be an LP that raises its own debt, meaning you would only need to inject the equity? It's probably fair to say. This is Steven Kroeker here. It's probably fair to say it's still early days on financing that, just given the on-stream date for that project. Probably the default position is more just off our balance sheet in terms of funding that project. We'll obviously be looking at all alternatives as we go forward. Okay. Thank you, Steven. We have no further questions in the queue. I got to go. Okay. Thank you, Ryan. Well, then this completes our 2013 year-end results conference call. If you have any other questions, please call us. Our contact information is in yesterday's release. Thank you for listening, and have a good day. This concludes today's conference call.