Earnings Call: Q4 2012

Feb 15, 2013

Good morning, everyone. My name is Sarah, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Keyera Corp. 2012 Year-End Results Conference Call. All lines have been placed on mute 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 during this time, simply press star, then the number 1 on your telephone keypad. If you'd like to withdraw your question, please press the pound key. Thank you. I would now like to turn the call over to our host, Mr. John Cobb. You may begin your conference. Thank you, Sarah, and good morning. It's my pleasure to welcome you to Keyera's 2012 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 our business. 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 reflects 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 conditions, they necessarily involve risks and uncertainties that could cause actual results to differ materially. Some of these risks and uncertainties include fluctuations in the supply, demand, and pricing of natural gas, NGLs, iso-octane, and crude oil, the activities of producers and other industry players, our operating and other costs, the availability and cost of materials, equipment, labor, and other services for capital projects, governmental and regulatory actions, 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 2012 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, and thank you for joining us this morning on the call. Before I start, I'd like to welcome Steven as our new CFO, and congratulate him on his new title. Keyera delivered solid results in 2012 and once again provided value to our shareholders. Our goal of providing shareholders with income and growth has remained consistent over the years. We increased our dividend again in 2012, the third time in the last two years and the tenth time since going public in 2003. At the time of our IPO, our dividend was 9.08 cents per unit per month or CAD 1.09 per unit per year. Today, we pay 18 cents per share per month or CAD 2.16 per share annually, virtually double the amount paid to shareholders 10 years ago. We are very proud of having provided shareholders with a 7.5% compound annual growth rate in dividends per share since 2003. Net earnings for the year were CAD 131 million, or CAD 1.71 per share. EBITDA was CAD 327 million in 2012, up 28% from last year. The acquisition of Alberta EnviroFuels early in 2012 and increasing demand for NGL services at Fort Saskatchewan contributed to this increase. For 2012, distributable cash flow was CAD 200 million, or CAD 2.62 per share, with dividends to shareholders of CAD 157 million, or CAD 2.06 per share. Steven will talk more about our financial results later in the call. We were very encouraged by producer activity levels in our gathering and processing business in 2012, despite the challenges posed by weak natural gas prices again this year. As has been the case for the past few years, producers are continuing to focus on gas that is rich in NGLs or natural gas liquids in order to maximize the value of their production. As a result of this focus, several of our plants are seeing increased throughput. While gross throughput in 2012 was effectively the same as 2011, about 1.2 billion cubic feet per day. On a net basis, throughput increased 9% compared to last year. This increase was largely the result of increasing our ownership in existing gas plants, as well as increased throughput at certain facilities. In particular, throughput increased significantly year-over-year at the Rimbey and Minnehik Buck Lake gas plants. Producers continue to target liquids-rich gas in the Glauconite, Cardium, Duvernay, and other geological formations in the lands around these facilities. At Minnehik Buck Lake, a group of producers southwest of the plant have agreed to deliver gas to the plant for processing and are in the process of building a 12-inch pipeline to the plant. Keyera has agreed to purchase this pipeline upon completion, which is expected to be in the second quarter of 2013. In October, we announced that we would be enhancing the NGL recoveries at the Rimbey gas plant by installing a 400 million cubic feet per day turbo expander at the facility. When completed, the plant will be able to extract up to 20,000 barrels per day of ethane from the raw gas stream, as well as provide high recoveries of propane, butane, and condensate. The project is underpinned by an ethane sales agreement with a petrochemical producer and a gas handling agreement with a significant land dedication from a large producer in the area. We believe the turbo expander will be very attractive to other producers, particularly if the Duvernay geological zones are developed west of the plant. Producer activity is also driving increased throughput at the Strachan and Caribou gas plants. Producer-built pipelines completed in late 2012 to deliver gas to both facilities have resulted in new incremental volumes being delivered to both plants. In the case of Strachan, we purchased the pipeline when it was completed and began flowing gas to the plant in December 2012. At Caribou, drilling activity on the Progress lands to the south of the plant have been ramping up recently, and so far in 2013, we are seeing increasing throughput at that plant compared to last year. Keyera has entered into an agreement with Sulvaris to build a sulfur fertilizer production facility at the Strachan gas plant. Because the fertilizer facility would use sulfur as its feedstock, the Strachan plant, with its significant sulfur infrastructure, is an ideal location for the facility. A final investment decision remains to be made, but this project is another example of the types of synergistic projects that allow us to leverage off our existing infrastructure. We continue to see considerable producer activity in the lands around our Simonette gas plant in 2012. Earlier in the year, a producer east of the plant tied a 12-inch diameter pipeline and began flowing new gas to the plant for processing. There were a number of new producer-licensed wells around the plant during the year in the Montney, Duvernay, and other liquid-rich zones. Included with these producers were some multinational companies who had not been active in the Western Canadian Sedimentary Basin for some time. This activity, along with other activity in the area, is encouraging and may provide the production necessary to underpin an expansion of the plant. Late in the year, changes in the composition of the gas being delivered to Simonette resulted in the plant having difficulty meeting regulatory requirements for sulfur recovery levels. In order to address this issue, in the fourth quarter, we voluntarily curtailed deliveries of gas to the plant and are required to curtail throughput until mid-May. We were successful in finding alternative processing solutions for most of the production affected by this curtailment. After May, we expect volumes to grow, and we expect to be able to meet required sulfur recovery levels. We experienced two other operational challenges that affected our results in 2012. At Strachan, repairs to the sulfur plant and to the propane refrigeration compressor resulted in throughput being curtailed at the plant in the second half of the year. Fortunately, much of the gas was able to be redirected to other Keyera plants in the area for processing. This benefited both our customers as well as Keyera. At Chinchaga, a release of product from the Cranberry pipeline, which handles condensate and crude oil from the plant, required cleanup and remediation of the land in the area around the release. These expenditures reduced operating margin in the gathering and processing business unit by CAD 6.5 million in 2012. Of this amount, CAD 4.5 million was expensed in the fourth quarter to cover work completed through the year-end. Included in this amount is an accrual for work that is expected to be completed in 2013. Finally, we successfully completed a very large maintenance turnaround program in 2012 at five gas plants, including the Nevis, Brazeau North, Nordegg River, Gilby, and Chinchaga facilities. These turnarounds are necessary to ensure that our facilities are able to provide long-term, efficient, reliable services to our customers. With that, I'd like to turn it over to David to review our liquids business unit. David? Thanks, Jim. The Liquids business unit posted strong results in 2012, particularly in the NGL Infrastructure segment, where operating margin was 63% higher than 2011. Contribution from Alberta EnviroFuels, combined with continued strong demand for storage, fractionation, and condensate terminaling services, led to record results in 2012 for this segment of our business. In addition, our diluent handling agreement with Imperial Oil began in July, adding additional cash flow and augmenting our solvent agreement with Imperial, which began in December of 2011. Cash flows from the Imperial diluent handling agreement are expected to increase in 2013 as the Kearl project starts up. Cash flows from our agreement with Husky are still expected to begin in 2014. Keyera's NGL fractionators operated at or near capacity for most of 2012, as increased liquids-rich drilling resulted in higher NGL volumes in Alberta. At the Alberta Diluent Terminal, deliveries of condensate via rail into Alberta increased during the year. As a result of this increase in business, ADT moved to a 24-hour-a-day operation in December. In order to meet the demand for services from NGL and oil sands producers in 2012, we kicked off a number of exciting projects. At Fort Saskatchewan, our 12th storage cavern is currently undergoing integrity testing before being put into service later this year. Washing of our 13th cavern will be underway very soon. To support this additional storage capacity, we began construction of a new brine pond in 2012, which we expect to be completed this year. In September, we announced our plan to construct a 30,000-barrel-per-day de-ethanizer at Fort Saskatchewan. When it's complete, expected in 2014, this facility will allow Keyera to accept a C2+ mix of NGLs for processing at Fort Saskatchewan. A producer has entered into a long-term fee-for-service agreement at the facility for a substantial portion of the capacity. To meet the needs of our oil sands customers, we began construction of the South Cheecham Rail and Truck Terminal in 2012. Located approximately 75 km south of Fort McMurray, the terminal will provide oil sands producers with the ability to receive condensate via railcar for bitumen blending and to deliver diluted bitumen via railcar to the market. Since announcing the project in June last year, producers have expressed considerable interest in the facility, particularly for the delivery of dilbit via rail. As a result, we have modified the initial design to accommodate additional rail loading locations for that service. Work at South Cheecham is well underway, with the majority of the civil work complete. Construction of pipelines is progressing, as is the erection of tanks and structural steel. Although work has been slowed a little bit by cold weather, we continue to anticipate that the facility will be operational in the second half of 2013. In the fall, we acquired an NGL rail and truck terminal in Hull, Texas. While the acquisition was modest in terms of the capital investment, the terminal has the potential to become a significant piece of our NGL value chain with its connections to storage processing and terminal facilities in the Mont Belvieu area. Initially, we will activate the site to handle propane, butane, and NGL mix. Longer term, there may be opportunities to deliver crude oil and other products to the terminal. We are currently refurbishing the facility and anticipate that it will be operational later this year. A few weeks ago marked the first anniversary of our acquisition of Alberta EnviroFuels. Over the past year, the facility has met or exceeded all of our expectations. The facility is world-class, as are the employees who operate the facility. In December, we completed modifications to the rail rack at our Edmonton terminal to enable delivery of iso-octane via railcar, and the first deliveries left Edmonton for the Gulf Coast in December. We expect to increase rail deliveries of iso-octane through 2013, which could reduce the impact of apportionment on Trans Mountain and result in an increase in utilization at AEF. In the fall, we successfully completed a major maintenance turnaround at AEF. Like most of Keyera's other facilities, AEF is taken offline every four years for scheduled maintenance and to perform the necessary inspections of equipment. Because of the size of the facility, the turnaround lasted for 50 days and cost CAD 18 million. While the plant was offline, we spent another CAD 7.5 million on catalyst replacement and other maintenance capital projects at the facility. Our marketing segment had a good year, with operating margin 20% higher than in 2011, despite challenging market conditions for propane throughout the first part of the year. Strong contribution from our butane, iso-octane, condensate, and crude oil midstream businesses contributed to these results. Overall sales volumes in 2012 were 93,100 barrels per day, 22% higher than in 2011. This volume increase was primarily due to the addition of iso-octane to Keyera's marketing business in 2012. Propane markets were weak across North America in 2012. Beginning with the new contract year in April, we have been using more propane forward contracts to protect the value of our propane inventory. These hedges have proven to be effective, and as a result, Keyera's propane business did not suffer from the same challenges as we had in 2011. Butane demand and butane margins remained steady again in 2012, leading to healthy results. Keyera was able to use its railcars and infrastructure to take advantage of regional weakness in butane markets during the summer, acquiring butane feedstock for Alberta EnviroFuels at attractive prices. Diluent demand was strong throughout most of the year, driven by increased bitumen production in Alberta. This resulted in premium prices for condensate in Alberta and enabled us to import condensate via rail at ADT to meet some of that market demand. Our crude oil midstream activities posted strong results in the fourth quarter and for the full year. With that, I'll turn it over to Steven to discuss those financial results in more detail. Thanks, David. As Jim and David mentioned, we are pleased with how the business performed this year. Operationally, the assets we acquired in 2011 and 2012 have contributed to the growth of our business. EBITDA was CAD 327 million, 28% higher than the CAD 255 million reported last year. The growth was primarily due to continued growth in our liquids business unit. Net earnings were CAD 131 million, or CAD 1.71 per share, compared to CAD 135 million or CAD 1.91 per share in 2011. Higher operating margin and lower long-term incentive plan costs in 2012 were more than offset by higher deferred income tax expense and higher depreciation charges. In 2012, distributable cash flow was CAD 200 million, or CAD 2.62 per share, compared to CAD 202 million, or CAD 2.85 per share in 2011. Distributable cash flow was lower as a result of higher maintenance capital expenditures relating to the turnaround at AEF last fall and the impact of weaker results in the propane business earlier in 2012. Dividends to shareholders were CAD 157 million, or CAD 2.06 per share. This resulted in a full-year payout ratio of 79%. The payout ratio in the fourth quarter was 55%. Our gathering and processing business posted strong operational results in 2012, delivering operating margin of CAD 151 million for the year. Results for the fourth quarter and the year were negatively affected by remediation costs associated with the Cranberry Pipeline and repairs at the Strachan Gas Plant. Partially offsetting these factors was higher throughput at the Rimbey and Minnehik Buck Lake Gas Plants. The liquids business unit delivered exceptionally strong results in 2012. Full-year operating margin in the NGL Infrastructure segment of CAD 113 million was a new record, 63% higher than the CAD 69 million recorded in 2011. As David mentioned, the contribution from AEF and continued demand for fractionation, storage, and other logistics services contributed to these results. On a full-year basis, the marketing business generated CAD 92 million of operating margin, compared to CAD 76 million last year. Strong results in most parts of the business, including the newly acquired iso-octane business, were partially offset by weak propane results in the first three quarters of 2012. Fourth quarter propane results were strong, reflecting an effective hedging strategy and more typical winter demand. Included in the 2012 operating margin was an unrealized gain on risk management contracts of CAD 30 million, compared to an unrealized loss of CAD 14 million in 2011. Keyera's general and administrative expenses were CAD 24 million in 2012, compared to CAD 22 million in 2011. This increase is largely due to higher staff levels as a result of Keyera's growing business and a one-time expense of CAD 1.8 million related to the foreign currency contract used to fund the acquisition of AEF. Long-term incentive plan costs were CAD 10 million in 2012, CAD 16 million lower than last year. The higher LTIP expense in 2011 was due to the significant growth in Keyera's share price that year. Finance costs were CAD 48 million in 2012, CAD 6 million higher than 2011. The majority of this increase related to higher debt balances associated with the acquisition of AEF in January 2012, as well as other capital projects. The value of NGL inventory at year-end was CAD 183 million, CAD 13 million lower than the end of the third quarter, and about CAD 46 million higher than year-end 2011. Inventory associated with Alberta EnviroFuels operation, primarily butane and iso-octane, was the primary reason for the higher inventory values in 2012. As was mentioned earlier, in addition to the AEF turnaround, we completed five other maintenance turnarounds at our facilities in 2012. The total cost of these turnarounds, together with other maintenance capital projects, was CAD 52 million. Keyera incurred about CAD 2 million of cash taxes in 2012, compared to CAD 1 million last year. These taxes primarily relate to one of Keyera's subsidiaries. Keyera has reviewed its cash tax forecast for 2013 and estimates that current income taxes will be in the range of 1%-3% of annual operating cash flow before taxes. This forecast is based on Keyera's estimates of future cash flow and the timing of future growth projects and is subject to change. Finally, we've included our fourth quarter supplementary information on our website, concurrent with the release of our 2012 year-end financial results. This information includes both operating and financial data for each segment of our business. You can reference our 2012 year-end report for details on how to access the supplementary data. That concludes my remarks, Jim. Back to you. Thanks, Steven, and I'd like to conclude by discussing what I see ahead for Keyera. Most forecasters are predicting that 2013 will be another challenging year for producers in Western Canada. Many forecasters are predicting weak commodity pricing in Western Canada again in 2013, particularly for natural gas and propane prices. The oil price differentials that have affected the price of Western Canadian producers received for their crude oil will also likely continue throughout the year. These factors have the potential to reduce producers' cash flow and possibly limit the amount of activity for some companies. With these challenges, producers are increasingly looking to Keyera to help find solutions. We are working with our producer customers on a number of new business opportunities. The prospectivity of the geological horizons around many of Keyera's plants means that producers are able to capture sufficient economics to support continued drilling, despite the weak markets for natural gas and propane. This was demonstrated in 2012 when several international energy companies returned to Western Canada, many of them in the lands around our Simonette gas plant. These producers need the gas processing, transportation, and fractionation services that Keyera is able to provide. We are evaluating and working on a number of initiatives tailored to meet their needs, including the potential future expansions at the Simonette gas plant and our Fort Saskatchewan fractionation facilities. While some producers in the oil sands sector are slowing down development in response to the oil prices, others who are further along in their developments are proceeding as planned. Companies like Imperial Oil at Kearl and Husky at Sunrise, both of whom Keyera has contracts with, are continuing work. In response to this, Keyera is continuing to develop new storage caverns at Fort Saskatchewan, rail loading and offloading facilities, and other infrastructure to meet the sector's service needs. Oil producers in the province are interested in finding alternative ways to deliver their product to market. Many are actively seeking rail delivery options, a service Keyera is well-positioned to provide, as we currently have rail cars and logistics expertise that comes from our NGL business. Our South Cheecham rail and truck terminal, just south of Fort McMurray, is scheduled to be operational later this year. In addition to receiving diluent via rail at the site, we are also building 10 rail loading spots for dilbit. Producer interest in this service has been very strong, and the terminal has been designed for easy expansion. With rail terminal sites in Edmonton and undeveloped land adjacent to rail lines in the Edmonton Fort Saskatchewan area, we are currently evaluating other service options for our customers. In November, we estimated that our growth capital expenditures in 2013, excluding acquisitions, would be in the range of CAD 250 million-CAD 300 million. Today, it appears that we will be at the high end of that range. The challenge for all of us in Alberta is to manage these projects so that we can provide accretive cash flow growth for our shareholders. This is a responsibility that we take seriously at Keyera, and I'm confident that this approach will serve us well in the future. John, that concludes my comments, and you can open up the lines for questions. Thanks, Jim. Please go ahead, Sarah. At this time, I'd like to remind everyone, in order to ask a question, please press star then the number one on your telephone keypad. Your first question comes from David Noseworthy of CIBC. Your line is now open. Morning, gentlemen, and congratulations on a good quarter. The first question I have is just around your Simonette and just can you describe the nature of the fee amendment at Simonette and what exactly is happening there? David, really at Simonette, and I think you see it at a number of sour gas plants in the province, is the lack of sour gas impacting some of these older sulfur trains. It's really just trying to battle through the fact that you got gas streams that are significantly changing around Simonette with less sour gas available to process and more gas that has higher CO2 or just sweet gas. It creates a challenging environment for these sulfur plants, and it's not a long-term problem. It can bounce you around when you've got new and increasingly big volumes coming at you at a plant like Simonette. As I said, I think we're experiencing it at other locations, just more so here. Certainly, we don't see it as a long-term solution, and we don't see it as anything that impacts the future expansion of this plant as we go forward. Fair enough. Sorry, it's John. Just to add to Jim's comments, we did have a fee adjustment in the fourth quarter, and that really was a prior period adjustment relating back to the beginning of 2012. Just as I understand, looking forward, you mentioned in the comments that you're able to find solutions for most of the gas processing. If I look at your gas processing volumes between now and May, is the impact basically just a rearrangement from one plant to another, and so the impact is minimal? Yeah, in the short term, that's right. Well- Sorry. David, if I understand your question, the gas that we've redirected at Simonette has gone to other facilities, not Keyera facilities. Okay. That's what I was asking. Thank you. Just maybe moving over to the NGL mix recontracting season starting April 1. I was wondering what opportunities and changes you're seeing around this recontracting? David, it's a little early for me to speak specifically because a lot of those discussions and negotiations are ongoing as we speak. I think the direction that we're going, particularly for propane, is to make sure that some of the challenges that we've had in the North American market for propane aren't unduly affecting our risk and our margin. The concept would be that some of the arrangements that we will put in place this year will allow us to flow the actual price back to the producer in some form. A good opportunity. Then, just a quick question on your hedges. In terms of the propane hedges in your strategy, how do you expect infrastructure projects like the Cochin Reversal, Sand Hills, Sterling 3, for example, to impact your propane hedging strategy going forward into 2013 and 2014? I don't know that it's going to affect our hedging strategy, per se. We will continue to do as much as we can in terms of future forward contracts, both physical and financial, in propane, because those are cleaner hedges. The Cochin Reversal will affect the logistics requirements that the industry needs, and what we're working on is trying to expand the options that we have, the alternatives that we have to move propane out of Western Canada by rail to various markets throughout North America. That really represents an opportunity for us to do more for the producer community by finding additional outlets for the propane. It may have some temporary effect on propane prices in Western Canada, but we don't anticipate that it will have any kind of negative impact on our margins. Okay. It was just more to see if you think that it changes differentials that doesn't change your strategy in hedging the propane? No, I think we continue to work on ways in which we can get the propane into markets like Conway and Mont Belvieu that are more liquid, and that have more liquid forward markets. Those differentials may move somewhat, but it's something that we feel at this stage that we're on top of. Excellent. One last question, just with respect to your Sulvaris joint venture or post-joint venture. Is it too early, or can you provide us any kind of idea of what capital a potential sulfur handling fertilizer production facility would entail? I think it's a little early, but I'll put a broad range out there. I think Keyera probably expects to spend somewhere between CAD 25 million and CAD 35 million if the project goes ahead. We still have lots of negotiating to do. Sounds like you have a lot of good things on the plate. Well, I will get back in the queue, but thank you very much for your answers. Thank you. The next question comes from Carl Kirst of BMO. Your line is now open. Thanks. Good morning, everybody. Actually, some of my questions have been hit, but just let me clarify something that David was hitting on, which is with respect to potential changes in propane hedging, only because just reading one of the phrases in your MD&A, just sort of a reference to as propane markets evolve, we'll continue to adjust our strategy. I wasn't sure if that was sort of just an open-ended, we're always kind of assessing new data or if it was to kind of David's question about Cochin and the like. Is there specifically any changes afoot on the propane hedging that we should be aware of being contemplated or otherwise? I just want to make sure that we're on the same page on that. Carl, circumstances can change, and I guess that's why we always kind of hedge our words a little bit. Our plan would be, at this stage, to continue to use propane forward contracts, both physical and financial, in liquid hubs like Conway and Mont Belvieu, at the same time adjusting our logistics capabilities to try and make sure that we can move as much propane as possible into those kinds of markets. As I indicated, we are looking at some different arrangements on the supply side in terms of the way in which the supply side of our portfolio is priced with the producers that are our suppliers. It's possible that that could lead to an adjustment in the hedging strategy. I see. Maybe not necessarily giving them a point specific price, but we're kind of moving basically to index price plus kind of. I mean, is that the way we should be thinking about it? Well, in some cases, we're actually looking at the possibility of a flow through of the actual realized price as well. Okay. Which would obviously change our hedging requirements. Okay. No, I appreciate that. The second question, just also on marketing, because you guys clearly had just a bang-up quarter here in the fourth quarter with marketing. Is there any way to break down that as far as was there any one or two big drivers? Was the vast majority of that just propane marketing working this quarter when it wasn't really structurally able to work prior, or was it coming from condensates, et cetera? I just wanted to try and get more color by product, if that was at all possible. Well, as you know, we don't make a habit of disclosing specific results by product. What I can comment generally a little bit, as you know, we have a diversified product mix with butane, propane, condensate, crude oil, and now iso-octane. Iso-octane was part of the reason why we saw a rebound in Q4 because the Q3 results were affected by the turnaround that we had at AEF. I think propane, both from a seasonal point of view as well as from a structural point of view, propane recovered significantly in the fourth quarter from what we saw earlier in the year. Those are probably the two products that were the biggest piece of the Q4 recovery. The other elements, butane, condensate, and crude oil, have been pretty steady. Great. One other question, just on marketing, just to make sure I understand. It was mentioned the CAD 30 million of non-cash hedge gains at the end of the year. Are those hedging gains effectively, are those margins locked in such that they'll mature to cash in 2013? Or are they still somewhat open positions that we could see that CAD 30 million non-cash gain sort of come back down if it's unrecognized at this point? We tried to show the disclosure in the Q4 report. That $30 million is really just a change in what the fair market value of those contracts were at the end of 2011 versus what they were at the end of 2012. Really, you went from a $20 million loss position or fair market value at the end of 2011, and it went up to about a $9 or $10 million at the end of 2012. It is really that change that caused that $30 million increase to show up as a gain throughout the year of 2012. Got it. All right. Thanks so much. Your next question comes from Robert Hope of TD Securities. Your line is now open. Good morning. Maybe we can switch gears just a little bit to the rail side. Regarding your iso-octane deliveries to the Gulf Coast, I'm just wondering how much capacity you have coming out of the Edmonton region to move that product. Would you potentially be able to totally offset your apportionment on TMX? It's possible. I don't know that we've sort of tested the capacity of the facility. Right now, we're moving something like 2 rail cars a day or roughly 60 cars a month. We could do a fair bit more than that out of our facility. The thing that we're working on right now is to identify customers that can accept the iso-octane by rail. Some of the customers we're talking to are working to make sure that they can implement facilities so that they can take the iso-octane by rail. There seems to be demand out there. This is really the first time in North America that iso-octane has been made available to those customers by rail. We think we have the capacity to increase those shipments significantly, and I think possibly to fully offset the apportionment issue, at least as far as we're seeing it today. It will take some time to develop the markets. Interesting. Just a clarification there. On the receiving end, the refiners or the customers would have to, I guess, invest a little bit of capital to configure their rail facilities? That's right. In many cases, it's really not significant capital. It's just that they have to be able to segregate the products because of the quality specification. Okay, that's great. Maybe just another rail question, just a clarification on your crude by rail in Edmonton and Fort Saskatchewan. Would that be new facilities construction next to your existing facilities, or would it be changing some of your infrastructure from one product to another? Well, I think it's potentially both. We have land right near Fort Saskatchewan, at a place called Josephburg. We also have our existing terminal sites at Edmonton, both at our Edmonton terminal and at Alberta Diluent Terminal. Mm-hmm. I think any of those possibilities are things that we're certainly currently considering. All right, great. Thank you. Your next question comes from Robert Catellier of Macquarie. Your line is now open. Yes. Thanks for taking the question. I got two questions, one for Jim, but I'll start with David on the marketing side. If you look how the business has evolved over the last number of years, it's really changed quite a bit in terms of the product mix. You've gone from really an NGL business to one that now includes iso-octane and crude. I'm wondering if you can tell us what, in percentage terms, the business mix is today. As it evolves with the additional rail for the iso-octane business and development of the crude business, where you see that product mix going? Well, from a volume point of view, Robert, I guess the short answer to your question is we'll probably have to get back to you on the details. From a volume point of view, the crude oil piece is very small, because we don't really report the volumes. We're not strictly speaking a marketer of crude oil. The other products will tend to vary a fair bit, but propane is still the largest commodity by volume. In terms of financial contribution, we'd have to look at those numbers and try and give you a better sense. I would expect that iso-octane is going to grow as a proportion relative to the other products. As things have evolved, a product like condensate is probably a fairly small contributor to the overall mix. Things change, and we're simply trying to use the facilities that we have at our disposal to respond to what the industry needs. Sort of what I was getting at is, it seems to me that with the increased flexibility, both on the product side, but also on the infrastructure side, it seems to me that the risk in the business, despite the fluctuating prices, is actually, you could argue the risk is coming down. Possibly arguing for a higher payout ratio. In the past, you've never really paid out anything that you've generated out of the marketing business, but it seems to me that's becoming a more reliable business. I think that's probably fair to say with respect to the traditional products, propane, butane, and condensate. What I would just say maybe as just a little bit of a cautionary note is that the margins on iso-octane are driven by gasoline prices in North America. Those margins, time will tell, but those margins may be a bit more variable as we look forward. I think generally speaking, what you're saying is probably accurate. Keep in mind that our strategy is driven by the facilities that we own and operate. We're not driven by the marketing business. It's really the other way around. We take advantage of the opportunities we have to respond to industry needs with the facilities that we have available to us. Okay. Jim, I'd appreciate an update on the prospects of the Simonette expansion. Some of the things we're looking at here, on the producer side, there's been quite a bit of M&A activity, which effectively looks to be like a recapitalization. If you could also address the curtailment issue and how that might impact producers thinking on Simonette. Some of the recent success that Aux Sable's had booking some volumes beyond 2015. Yeah. I think, Robert, what I would say, I would start with the Simonette geology. I think every quarter, we continue to get better information. I think they're very excited by what's happening there. More wells being drilled into Duvernay. I think more realization that the Montney in that area is. It's very liquids rich and prospective. I think that the timing issue for us and around Simonette is really, we got a number of new players that have come in there in the last year who have gone from minimal, to owning land to now having significant gas volumes, needing solutions. I think you've got new players that are coming in through the M&A activity that are. Some of that hasn't even closed yet, so there's the uncertainty there of timing of closing. You've got I think just new players coming into the area. We still are aggressively working this. Simonette expansion is going to be a big project. I think we've got a number of things on the go, and we just want to get it right. I think that, I'd say if you go back a year, when you try to put a pin in this, along comes a new formation with new geological parameters, and you step back and say, "Let's look at the design." I think it's probably gotten bigger over the last year in terms of what we need, what industry probably wants. The other thing that I think is playing out here is that it's not just good enough to process gas for some of these big plays. Now they know they're going to be looking for liquid solutions, fractionation solutions, transportation solutions. Before you go ahead and have a major expansion at a gas plant, producers want to know that you can accommodate them downstream, and fractionate, and the products are going to get into the right market. That actually it can get to market. A major gas plant expansions have become, I think, a lot more complicated in this environment. We're working it hard at trying to make sure we get it right. Sooner or later, you got to put a pin in it, but you got a constantly changing database there. I can assure you that we're still very excited by the area. The geology is very prospective, and nothing's really changed. We're just, I think, very careful about how we look at this design and the ultimate delivery of the liquids and trying to provide the whole suite of services. Well, it sounds to me, hearing you talk about it, though, that maybe it has changed. The timing's maybe a little frustrating, but it sounds to me like the solution is larger and more comprehensive. Well, I think if you are watching what's going on in that area, from Kaybob up through Simonette, up through the Wapiti to the Alberta-B.C. border, it's an area that's getting attention from the majors who are coming back into this basin. It's an area that's getting attention from a lot of joint venture activity and offshore money. Yeah, I think we're not the only midstream that's trying to figure out the solutions out there. I think there's dozens of producers. It, yeah, it has changed. This is probably one of the most prospective parts of the basin because of the liquids-rich nature of the gas. There's numerous solutions required out here, and probably plant expansions to accommodate what we see coming over the next 5-10 years. Okay. Thank you. Next question comes from Matthew Akman of Scotiabank. Your line is now open. Thank you. My first question's on AEF, and in particular, I'm wondering if you can talk generally about how the facility did in 2012 versus the historical average. When you acquired the facility, I think you said that the last several years has done on average, somewhere in the mid-CAD 30s million of EBITDA, and you did disclose that I think it did CAD 21 million in the infrastructure segment, and that I think you had a pretty decent year on butane, because you were able to put some in storage at relatively low prices. Did you get close to the historical average despite the maintenance outages in 2012? I guess the short answer is, Matthew, we were very pleased with the performance of AEF in 2012. I think it's fair to say it exceeded our expectations. When we acquired the facility, one of the concerns we had was the turnaround that was planned for the September timeframe. Although it took a little bit longer and cost CAD 2 million more than we originally planned, we're still very pleased with how that was handled and how we came out of it. From a contribution point of view, I think certainly we were, despite the fact that we had the turnaround in 2012, the contribution was higher than we had forecast and probably similar to what the average was that we've seen over the course of the last two or three years. That, of course, is despite the fact that the facility was operating at somewhere in the 60%-70% of capacity range, because of the apportionment on Trans Mountain. As we try and alleviate that constraint, I think we're very optimistic about where the business could go. Okay. Thanks for that, David. Follow-up question is on potential for increase in crude oil type marketing. Probably one of the things you guys have that's unique or at least in scarce supply is rail. You are going to be using more of your rail capacity for iso-octane, I guess. I'm just wondering, do you have enough rail capacity for all this, or do you need more rail cars? Or what's going on there in the next couple of years? Well, good question. There's a number of elements to that. We have increased the size of our rail car fleet quite substantially, and we're continuing to grow it. One of the advantages we have relative to other players is that we've been in the rail car business for a while. We have the logistics expertise. We have existing leases of rail cars. It's fairly straightforward for us to continue to expand. Keep in mind as well that a lot of the terminal activity and a lot of the expansions and new construction that we have underway will be filled with cars that we don't own. It's simply a fee-for-service business that we provide for the producers who provide their own rail cars and their own fleet logistics. It's a mix of different types of business models in that way. Yes, there are constraints. With respect to the actual terminal capacity, we have substantial room for expansion at ADT in Edmonton, a little bit of room for expansion at the Edmonton terminal, not a whole lot. We have, as I mentioned earlier, some vacant land up at Fort Saskatchewan that we're looking at. Finally, at South Cheecham, we have set that up so that we can expand that fairly significantly without a lot of additional reconfiguration. Thank you for that. My last question is a cleanup on tax. I don't know if it's too early to talk about when you guys start paying any significant cash taxes, if it's 2014 or beyond. We're still pretty comfortable with our tax situation. Again, you can apply from the 1%-3% in 2013 that it's going to be a pretty gradual move into the next couple of years there. Again, as we continue to invest capital, we're continuing to hope to be able to continue to push off that cash taxability. Great. Thanks, guys. Those are my questions. Thank you. Your next question comes from Robert Kwan of RBC. Your line is now open. Morning. If I can just start with the iso-octane and some of these new customers that you're trying to rail into. Do you see them as being ongoing customers for the product, or are they generally just wanting it for some of the startup optimization? No, I think, Robert, the markets that we've seen so far and the customers that we've been selling to are actually long-term customers. It's an interesting mix. There's some big refiners, but there's also some small blenders, and I think that these are long-term markets. Sorry. Long-term guys who would have been taking it off of Trans Mountain, but with the apportionment, you're railing into right now? No, these are folks that really have been finding other solutions for octane. In many cases, they're taking advantage of the ability to get iso-octane that they couldn't get before. Okay. That's great. If you look at just that overall market, then what's the opportunity? What percentage of refineries, or how do you think about it with respect to getting that into guys who are already using iso-octane but just not yours? That's a hard question to answer at this stage. I'd have to think about that and get back to you. Yeah. Again, AEF is the only merchant facility in North America, and so you're really competing against alkylates. We're not really trying to compete against other suppliers of iso-octane in particular. Got it. I think a good way to look at it, Robert, is that we've now, with our rail capacity, have really opened up every refinery in North America potentially as a customer, and we don't have to be just focused on West Coast refiners. In fact, the new customers we've seen are in other parts of North America. Sure. If I can just ask on pricing, what we've seen, I guess, year to date, and I recognize we're looking at CARBOB and not iso-octane, but CARBOB as a spread to butane. We're in the winter here, and it seems like we're pretty much at peak summer pricing in most of the historical years except for suppressed 2010. Is that what you're seeing as it translates to iso-octane pricing? Are we set up for, at least as it stands right now, a very nice pricing environment for 2013? I'd say the short answer is yes. What I would say is that the traditional markets for AEF, which are the West Coast refiners, have been priced off of CARBOB. What we're seeing with some of the new customers is that those contracts may be priced off of RBOB. Okay. Because they're not in California. Right. Just the last on the rail. How do you think about your car situation? I know you're talking about fee-for-service and others will bring cars to you, but you do have a lot of cars. How do you think about repurposing them if you see better profitability? I know that's maybe a little bit more of a near-term trade-off versus weighing that at the expense of the existing core business and your core customers. Do you have enough rail cars coming at you to expand that the way you'd like, or what's the upside from repurposing the existing cars? The sort of adjustment of the fleet is something that's ongoing all the time. What I would say is that a lot of the new cars that we are adding to the fleet are non-pressure cars, what we refer to as general purpose cars. The reason for that is because those are more suitable for iso-octane and for condensate movements. We still have a substantial portion of our fleet that are in pressure cars for propane and butane. As I mentioned earlier, one of the things that we need to continue to do for the industry here is to find rail markets for propane because of the fact that that will be a growing part of the product movement for export. We are adjusting it all the time. Obviously, our first priority is to take care of the NGL supply that we are purchasing in Western Canada. Okay. That's great. Thank you very much. Okay. Next question comes from Steven Paget of FirstEnergy Capital. Your line is now open. Thank you and good morning. First question is about Strachan. If you go ahead with the Sulvaris joint venture, if one or more producing wells goes down and sulfur supplies are restricted, what could the impact be on Keyera? Or would there be an impact? Steven, I think, clearly Strachan is a sour gas plant, so it certainly has some impact on the sulfur that comes in there. I think, going ahead with Sulvaris is driven by the fact that we bring sulfur into Strachan from a number of other gas plants in the area, both by truck and we can by rail. I also think that if you look at where your biggest source of sulfur is going to be over the next 20 or 30 years in this province, it's probably sulfur out of the oil sands. I think us and our customers in Sulvaris are certainly looking much broader than just the sour gas wells behind Strachan gas plant. Sulfur could go from the oil sands to Strachan. Sulfur can go into Strachan really from anywhere in Alberta if the economics work. We've trucked a lot of sulfur in there, remelted it in the past from other blocks and other plants. It certainly can come from as far away as the oil sands. Yes. Thank you, Jim. Could you please list your expected plant turnarounds in 2013? I think we have four. Simonette is one. Simonette, Paddle River, Pembina North. A compressor at Bigoray. A compressor at Bigoray. It's a pretty light year. Thank you and have a good morning. Thanks, Steven. Your next question is a follow-up from David Noseworthy, CIBC. Your line is now open. Just one follow-up question on Robert's RBOB, CARBOB pricing. If you look at the forward curve for RBOB and butane Mont Belvieu pricing, it looks like all of 2013 has a very wide differential there. Can you comment on how much of this you've been able to lock in? As you probably know, David, the forward market for RBOB is fairly liquid. I think it's fair to say that RBOB is sort of the key marker for gasoline hedging in North America. Our approach will continue to be to look out the curve in the six-month kind of timeframe. I can't be real specific about what we have in place right now, but I expect that will be our approach as we look forward. CARBOB is a far less liquid market, and you really do some hedging on CARBOB as well, but it's very short-term. The other thing I would say about RBOB and CARBOB is that they are very seasonal. What you'll see if you look at the forward curve for RBOB is a fair bit of fluctuation from the summer driving season to the winter. That's something we pay attention to in our hedging strategy as well. Do you think there might be an expectation that even though it's really looking very good right now, it could look even better in the summer driving season? Oh, I think you're seeing a lot of what we anticipate in terms of the uplift for the summer driving season. I think you're seeing that already. Okay in the forward curve. We have been taking advantage of that. Okay. Maybe move to the gas plants. You talked about the addition of the potential construction of a new pipeline to Rimbey and that we're seeing utilization rates are up to, what, 317 MM SCF per day. Is there an opportunity to expand the processing capacity at Rimbey related to the addition of the turbo expander and these new pipelines? Yeah. David, I think we talked about it a little bit maybe last quarter when we announced the turbo. Clearly if there are growth in volumes out there past the 400 million a day turbo, we've got a very efficient lean oil system at Rimbey. For some capital, and it's not real expensive, but for some capital, we certainly could expand beyond the 400 million a day at Rimbey by CAD 200 million or CAD 300 million, or 200 or 300 million a day, making it a very big plant. We're certainly not planning for that today. It'd be a nice problem to have. It's very efficient capacity to add if Duvernay turns out to be as prospective as some think out there. maybe it's my misunderstanding, but I always thought that the turbo expander is basically taking the NGLs out, but that you needed gas processing on top of that for the CO2 and the sulfur and whatever else. I was talking more about that side of the expansion. No, I think, as I say, that plant's a very big and very sophisticated plant. By adding a turbo there, for some incremental dollars could see an expansion of the whole processing arena. Excellent. Okay. Thanks very much. I guess maybe just to put it a different way, the expensive part of the processing is the liquids extraction. Once we've spent the money on the turbo, the inlet separation and the compression that's required is, relatively speaking, a fair bit less in terms of capital. Thank you. Those are my questions. Thanks, David. There are no further questions queued up at this time. I turn the call back over to presenters for closing remarks. Thank you, Sarah. This completes our 2012 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 the conference call. You may now disconnect.