Earnings Call: Q4 2011

Feb 17, 2012

Good morning. My name is Stephanie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Keyera Corp 2011 Year-End Results Conference Call. All lines have been placed on mute to avoid any background noise. After the speakers' remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star, then 1 on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. John Cobb, you may begin your conference. Thank you, Stephanie, and good morning. It's my pleasure to welcome you to Keyera's 2011 Year-End Results Conference Call. With me are Jim Bertram, Chief Executive Officer, David Smith, President and Chief Operating Officer, and Dean Setoguchi, our CFO. In a moment, David and Jim will discuss our results as well as provide additional perspectives on the business. Dean will follow with a discussion of the financial highlights. At the conclusion of the formal comments, 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 beliefs about the relevant material factors, 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 for natural gas and NGLs, the activities of producers, other industries, and other industry players, operating and other costs, the weather, governmental and regulatory actions, and other risks as they're 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 2011 year-end report and our annual information form, both of which were published yesterday. 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 this call. Keyera provided shareholders with exceptional results again in 2011, led by record performance in the gathering and processing business and NGL infrastructure portions of our business. These results were achieved despite a challenging business environment and reflect the stable nature of our fee-for-service businesses. Our goal of providing shareholders with income and growth has remained consistent over the years. Our strong performance allowed us to increase our dividend twice in 2011 to CAD 0.17 per month or CAD 2.04 annually. Excuse me. This represents our ninth dividend increase since going public in 2003. Over that period, we have provided shareholders with a 7.6% compound annual growth rate in dividends per share. Net earnings for the year were CAD 135 million, or CAD 1.91 per share, 50% higher than the same period last year. EBITDA was CAD 255 million in 2011, up 6% from 2010. Higher throughput at several facilities, increasing demand for NGL storage at Fort Saskatchewan, and strong performance through the first three quarters of the year in our marketing business contributed to this increase. Distributable cash flow was CAD 202 million or CAD 2.85 per share, with dividends to shareholders of CAD 136 million or CAD 1.92 per share. This results in a payout ratio of 67% for the year. Dean will talk more about our results later in the call. In the gathering and processing business, the challenges posed by weak natural gas prices presented opportunities and challenges for us in 2011. Total throughput in 2011 averaged 1.2 billion cubic feet per day, 11% higher than 2010. The increase was largely the result of plants acquired in the late part of the year in 2010. Excluding plant acquisitions, throughput was flat year-over-year. Increased throughput in some of our larger plants on the west side of the basin was offset by declining throughput at a few plants more exposed to dry gas production and planned short-term outages at 4 of our larger plants that were undergoing maintenance turnarounds. Being able to maintain throughput at a consistent level, given the low natural gas prices and declines in overall gas production in Alberta over the last few years, is a testament to the processing flexibility and competitive nature of our plants, as well as their location in the liquids-rich part of the basin. In particular, throughput increased significantly year-over-year at Rimbey, Strachan, and Simonette gas plants, as well as at a partner-operated Edson gas plant. Gas deliveries on the Carlos pipeline, completed in the second quarter of 2011, have increased throughput at Rimbey over the year as producers continue to target liquids-rich gas in the Glauconite formation. As a result, today we are processing over 300 million cubic feet per day of liquids-rich gas at that plant. A producer-owned compressor began delivering gas to the Carlos pipeline late in the fourth quarter, and another third-party compressor is expected online early in 2012. Should producers maintain current levels of activity, we anticipate that the pipeline may reach capacity sometime in 2012. As a result, we've begun soliciting interest for an expansion of the Carlos pipeline and the possible construction of a new pipeline that would deliver liquids-rich gas to Rimbey from lands west of the plant. Strachan. Producer activity has been steady throughout 2011, with producers targeting numerous geological zones in the area. As a result of this activity and the resulting increase in capacity utilization, some producers have expressed interest in securing firm processing commitments at the plant. We are currently replacing our turboexpander at Strachan in order to increase the reliability of the deep cut facility at this plant. We have seen throughputs increase significantly at Simonette gas plant as well. Our producer-owned 12-inch gathering pipeline began delivering liquids-rich gas to the plant in December. In addition, our producer east of the plant is currently constructing a 65-kilometer, 12-inch gathering pipeline to deliver gas to Simonette. As a result of this activity, we are evaluating a plant expansion at the facility, which would include additional inlet capacity, installation of deep cut facilities, and the construction of new gathering pipelines. Based on the positive response we've received from producers, we have moved to a more detailed engineering phase of the design. We anticipate having sufficient information to finalize commercial terms by the end of the first quarter, and assuming we're able to secure satisfactory commitments in a timely matter, we believe the new facility could be put into service by late 2013. Certainly, recent producer updates coming from the drilling in this area continues to be positive. The number of liquids rich resource plays, including the Montney, Duvernay, and a number of other Cretaceous zones, are being developed by producers. Independent research shows these plays to have some of the best natural gas economics in North America. Producers continued to invest significantly in acquiring mineral rights in the lands around these plants throughout the year, a positive indicator of future activity in these areas. Much of the land sale activity in Alberta was targeted at the Duvernay Shale in west-central Alberta and east of our Simonette gas plant. The Duvernay lands in west-central Alberta are within the capture area of 10 of our gas plants, including our Rimbey, Minnehik-Buck Lake, Strachan, Nordegg River, Brazeau River facilities. Producers are in the early phases of testing this formation, but initial results are promising, and indications are that the gas produced is rich in NGLs. At our Nordegg and Brazeau gas plants, we have completed process modifications to improve propane extraction efficiencies. We are currently fine-tuning the process of both facilities and are encouraged by the significant improvement of propane recoveries that we are seeing. These projects, resulting from a combination of operational expertise and small capital investments, provide our customers with high NGL recoveries with a minimum increase in processing fees. In the fourth quarter, we were successful in acquiring additional ownership interest in four Keyera gas processing facilities, Strachan, Bigoray, Paddle River, and Minnehik-Buck Lake. Acquiring additional ownership in our existing operating facilities provides numerous benefits and is something we will continue to look at in 2012. Finally, we successfully completed a busy maintenance schedule program in 2011 at four facilities, including Rimbey, Brazeau River, Bigoray, and Minnehik-Buck Lake gas plants. These turnarounds are necessary to ensure that our facilities are able to provide a long-term, efficient, reliable services to our producer customers. With that, I'd like to turn it over to David to review our liquids business unit. David? Thanks, Jim. I apologize up front for my scratchy voice this morning. The liquids business unit also posted strong results again in 2011. In the NGL infrastructure segment, continued strong demand for storage and fractionation services led to record results in 2011 for this portion of our business. In addition, demand for condensate in Alberta resulted in steady rail deliveries at ADT and higher contribution from that facility in 2011. In December, we began providing solvent handling services at ADT under our agreement with Imperial Oil. In order to provide this specialized service, upgrades to the ADT facility were completed in 2011, including a new rail spur, rail offloading facilities, and upgrades to a storage tank and truck loading rack on the site. At Fort Saskatchewan, washing of our 12th storage cavern is well underway. Testing performed in late 2011 indicates that the cavern is developing as expected, and we expect that the cavern will be put into service in 2013. We anticipate proceeding with our 13th cavern in the second quarter of this year. We are continuing to develop plans for a deethanizer at our fractionation facility at Fort Saskatchewan, which will allow us to process some of the growing volumes of ethane plus mix in Alberta. The modifications required are relatively straightforward, as much of the necessary support facilities, pipeline connections, and raw feed storage are already available on-site. We are continuing our discussions with certain producers concerning capacity commitments, and we expect to make a decision in the next few months. We made significant progress on our Fort Saskatchewan condensate system in 2011. This system is an integrated network of infrastructure through which Keyera will provide diluent handling services for oil sands customers, including Imperial Oil and Husky. Our pipeline connection to the Enbridge Southern Lights condensate pipeline was completed earlier in the year, and the majority of work was completed on the new 20-inch condensate pipeline from Fort Saskatchewan to Stonefell. Over the winter, we have continued work on the pipeline and on new pumping facilities at our Edmonton terminal. We anticipate completing these facilities in the first half of 2012 in time to meet the commitments under our long-term diluent services agreement with Imperial Oil that starts on July 1st. In January, Keyera completed the acquisition of Alberta EnviroFuels, an iso-octane manufacturing facility located in Edmonton for approximately $194 million plus working capital. iso-octane is a high-octane, low vapor pressure gasoline blending component used by refiners to reduce volatility, improve combustion efficiency and create cleaner burning gasoline. The facility is connected by pipeline to Keyera's NGL infrastructure in the Edmonton/Fort Saskatchewan area and uses butane as a feedstock. AEF has a very strong team of about 100 employees and we are very pleased to welcome them to the Keyera team. Since acquiring the facility last month, we've been approached by a number of customers interested in sourcing iso-octane, and we are actively investigating alternative delivery methods for the product. Our Edmonton truck and rail loading facilities are already connected to AEF, so we expect to be able to move quickly on these opportunities. Shifting to our Marketing segment. Our Marketing segment had a strong year, led by performance in the butane condensate and crude oil midstream businesses. Overall, sales volumes in 2011 were 76,450 barrels per day, approximately 3% lower than in 2010. Unfortunately, fourth quarter marketing results were negatively affected by abnormally weak propane markets across North America. In the second and third quarters, propane inventories across North America were unusually low, and strong export demand resulted in propane prices that were higher than normal for what is typically a low-demand summer period. As a result, Keyera was able to capture strong margins from propane sales in the first three quarters of 2011 and deliver strong marketing results. However, extremely warm weather this winter has reduced propane demand and put downward pressure on propane prices. Because of the combination of higher cost inventory and lower sales prices, margins from the sale of propane in the fourth quarter were much lower than usual. Although propane prices have been soft, crude prices have stayed strong and the crude oil-based financial contracts used to hedge our propane inventories have resulted in unrealized losses. Continued warm weather in the first quarter of 2012 has resulted in sustained weakness in propane demand and prices, and as a result, we will experience weak propane results again in the first quarter. In addition, the crude oil-based financial contracts are settled as inventory is sold, and the realized losses on those financial contracts will negatively affect cash flow in the first quarter. That's the propane picture. Butane demand and butane margins remained strong and steady again in the fourth quarter, leading to healthy results for the fourth quarter and for all of 2011. Diluent demand was strong throughout the year, driven by increased bitumen production in Alberta, resulting in premium prices for condensate. Again, in the fourth quarter, we were able to import condensate by rail at ADT to meet some of that market demand. Finally, our crude oil midstream activities posted strong results in the fourth quarter and for the full year. As I mentioned earlier, despite the weakness in propane during the fourth quarter, the marketing segment posted another strong year overall in 2011. We benefit from a diversified portfolio of products in the marketing segment, and the markets for each have different characteristics and demand drivers. This helps to diversify the risk in our marketing business and mitigates the effect of occasional short-term market factors on Keyera's financial results. With that, I'll turn it over to Dean to discuss the financial results in more detail. Thanks, David. As Jim and David mentioned, the business performed very well this year. Operationally, the assets we acquired in 2010 have contributed to the growth of our business. Net earnings were CAD 135 million, or CAD 1.91 per share, compared to CAD 87 million or CAD 1.27 per share in 2010. EBITDA was CAD 255 million, a 6% increase over the CAD 241 million reported last year. In 2011, distributable cash flow was CAD 202 million or CAD 2.85 per share, compared to CAD 208 million or CAD 3.05 per share in 2010. Distributable cash flow is lower as a result of higher maintenance capital expenditures relating to gas plant turnarounds and higher long-term incentive compensation due to the appreciation in Keyera's share price. Dividends to shareholders were CAD 135 million or CAD 1.91 per share. This resulted in a full-year payout ratio of 67%. Our gathering processing business posted strong operational results. Fourth quarter operating margin was CAD 41 million and full year results of CAD 153 million represented record results for each period. The increase related to contribution from the Simonette and Minnehik-Buck Lake gas plants that we acquired in the second half of 2010, and higher performance at certain other Keyera gas plants, including Strachan and Rimbey. The liquids business unit also delivered strong results in 2011. Fourth quarter operating margin in the NGL infrastructure segment of CAD 20 million was a new record, as were the full year results of CAD 69 million, which were 8% higher than last year. As David mentioned, continued demand for storage and other logistics services contributed to these results. In the fourth quarter, the marketing business posted a loss of CAD 23 million, largely relating to propane and for the reasons David mentioned earlier. Marketing gains of CAD 16 million from physical sales in the quarter were offset by non-cash unrealized losses from financial contracts of CAD 39 million. On a full year basis, the marketing business added CAD 76 million of operating margin, slightly less than the CAD 79 million generated last year. Keyera's general administrative expenses were CAD 22 million in 2011 compared to CAD 18 million in 2010. This increase was due to higher staff levels as a result of Keyera's growing business and higher consulting and engineering costs associated with a larger scope of projects. Long-term incentive plan costs were CAD 26 million in 2011, CAD 8 million higher than last year due to the growth in Keyera's share price. Finance costs were CAD 42 million in 2011, CAD 25 million lower than 2010. The majority of this decrease related to a CAD 25 million unrealized expense in 2010, resulting from the change in fair value of our convertible debenture derivative liability. NGL inventory at year-end was CAD 137 million, CAD 32 million lower than the end of the third quarter, and about CAD 11 million higher than year-end 2010. As Jim mentioned, we completed four maintenance turnarounds in 2011. The total cost of these turnarounds was CAD 21 million. Under IFRS, turnaround costs are capitalized and amortized over the periods between each turnaround, which in this case is four years. As a result, EBITDA was not affected by the cost of the turnarounds, but the costs were deducted in calculating distributable cash flow. Keyera incurred about CAD 1 million of cash taxes in 2011 compared to a recovery of CAD 300,000 last year. These taxes primarily relate to one of Keyera's subsidiaries. Keyera has reviewed its cash tax forecast for 2012 and estimates that current income taxes will be in the range of 1%-4% of annual 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. Approximately CAD 34 million of turnaround costs are anticipated in 2012. Of that amount, CAD 16 million is expected to be spent at the Brazeau North, Chinchaga, Dealby, Nevis, and Nordegg River gas plants, and also CAD 18 million for the turnaround at AEF. Finally, we've included our fourth-quarter supplementary information on our website, concurrent with the release of our 2011 year-end financial results. This information includes both operating and financial data for each segment of our business. You can reference our 2011 year-end report for details on how to access the supplementary data. That concludes my remarks. Jim, back to you. Thanks, Dean. I'd like to conclude by discussing what I see ahead for 2012. As we've discussed earlier in the call, we faced a number of challenges in 2011, and many of these conditions will continue into 2012. We will probably continue to see low natural gas prices in 2012, and because of that, we are already seeing some producers in the U.S. and Canada reducing their drilling programs and, in some cases, shutting in dry gas production. This pricing environment is similar to the one experienced in 2008. At that time, producers focused on drilling their best prospects and relied on NGLs and the raw gas stream to augment their netbacks. We believe that producers will take the same approach again here in 2012. For our part, we work hard to assist our producer customers, providing a quick tie-in and cost-effective processing solutions. In previous periods of low gas prices, we have been able to acquire gas plants and pipelines from producers who prefer to focus their cash from these transactions on drilling wells. We will seek to do more of these transactions this year should opportunities present themselves. In the oil sands sector, where the economic climate is more positive, producers are continuing to move ahead with a number of projects. We have been strengthening our infrastructure in the Edmonton-Fort Saskatchewan area in order to enhance our service offering, and we continue to work with oil sands producers about potential new business opportunities. We're also looking at expanding our services beyond the Edmonton-Fort Saskatchewan area. In partnership with Enbridge, we are soliciting interest in construction of a rail and truck terminal south of Fort McMurray and possible construction of a diluent delivery pipeline from Fort Saskatchewan to the Athabasca oil sands area. Propane markets in the first quarter will continue to be weak. However, as David mentioned, propane is just one of five products handled by the marketing segment, and the product diversity and different market characteristics diversify risk in this business. I'm also excited about our AEF acquisition and our business and market integration opportunities that are available to us going forward because of this asset and the people. As we look at the future, we have a number of potential growth opportunities available to us. While we are able to act quickly and be responsive to our customer needs, we cannot always control the timing of our capital expenditures. We estimate our growth capital expenditures in 2012, excluding acquisitions, will be in the range of CAD 125 million-CAD 175 million. In closing, I remain confident that Keyera's robust and diversified business model will enable it to weather difficult times in some areas of our business, and I'm confident in our abilities to provide superior service to our customers going forward. This approach to our business has enabled us to provide our shareholders with a track record of income and growth, and I'm confident that it will serve us well in the future. John, that concludes my comments, and we can open up the lines. Thanks, Jim. Please go ahead, Stephanie. At this time, I would like to remind everyone, in order to ask a question, please press star and the number one on your telephone keypad. We'll pause for just a moment to compile the Q&A roster. Your first question comes from Robert Hope with TD Securities. Your line is open. Good morning. You touched on this a bit in the MD&A. I'm just wondering if you could provide some more clarity just on exactly what your outlook is for throughput in the G&P business. There's a few moving parts there. I'm just wondering if overall you expect new volumes will more than offset the loss of dry gas in 2012. Rob, I think you're right. There are a lot of moving parts. I think producers are probably trying to get through the winter drilling season, and then breakup will come in Western Canada. I think what comes out of the back end of that, probably driven a little bit by storage and prices. Having said that, I think that we, certainly when we put our budgets together before Christmas, we were pretty confident that given the feedback we had at that time from producers, that our throughputs would continue to be probably growing at the plants we talked about this year, the big, liquids-rich areas of our business, and probably flat to off in some of the drier gas plants. It's difficult to make that call. What I would say is that, if you look at some of the independent data that's put out there. When I say we, the Western Canada Sedimentary Basin has some of the most economic gas because of the liquids components in North America today. I think you're seeing some Canadian producers bringing some of that capital back from the U.S. dry shale plays, and we hope to redeploy in some of the liquids-rich plays. We're just in the right spot. I think I continue to remain optimistic that the first areas to get shut in and areas that won't be drilled are the dry gas areas. You're starting to hear about those even as recently as this morning. I think a major talked about shutting in some dry gas. Like I said in the call, we saw a lot of focus back in 2008 on the liquids-rich part of the basin, and I think we're going to continue to see that. We watch the Duvernay shale developments with a lot of interest because of the location of our plants. I think people will go slow there. We're very encouraged by what we see so far. I think we're reasonably optimistic that we're still in the right spot in the basin to see drilling. Okay. Thank you for that color. I guess just along the same theme. Given the gas price environment, maybe you can just add some color on what you're actually seeing in the acquisition market right now. Is the spread between the bid and ask prices moving in? Are producers more agreeable to offload plants, I guess new plants as well as increasing ownership interest in your existing plants? Well, I think you're seeing the bid offer is always fun with producers. I think it's a little early. There's a few opportunities out there. I expect more probably after breakup. You are seeing a few instances where producers are probably going to go into an area and develop the play, build the plant themselves, and then sell it to the industry. Especially I think in some of the Deep Basin Montney, where there's liquids-rich areas. I know there's a couple of opportunities like that. I just think you'll probably see more opportunities as the year goes on. Excellent. Thank you. I'll jump back in the queue. Thanks, Rob. Your next question comes from Carl Kirst with BMO Capital. Your line is open. Thanks. Good morning, everybody. Obviously, fourth quarter was challenging and appreciate the color and the commentary as far as that extending into the first quarter. Is there any way to, here we are in mid-February, but obviously lots of moving parts, is there any way to quantify what you think the drag might be in the first quarter from the propane marketing? Carl, I think the short answer is no. It's not our habit to try and provide forward-looking, quantified outlook, and besides which, as you point out, the winter's not over. Based on what we've seen so far, though, we just expect that the prices and demand are going to continue to stay weak. No, understood. Is there, and I apologize, a lot of numbers were flying around, so I'm not sure if this was actually part of the prepared commentary, but is it possible to say, of the propane weakness in the fourth quarter, how much of that came from, what you might call low demand, low volumes, versus shifting correlations, if you will, between propane and crude? Whether or not there's any activity, any ability to actually use more sort of clean propane hedges in the future, or is it just not a deep enough market to do that? Well, I think the two factors, first of all, are inextricably tied together in terms of the way we manage the business. There certainly was softness in demand and softness in price. We're carrying a little bit more inventory at year-end than we would normally, but that's not something that's a huge concern. The volume impact is not something that's a huge concern for us, but it's more pricing related. Then with respect to your question on hedges, this is always something that we're managing carefully, week to week, really throughout the year. We can, of course, sell forward clean products at the U.S. hubs at Conway and Mont Belvieu. That is a possibility that we take advantage of from time to time. The problem with that for us is that most of our exposure is at Edmonton, so you end up with a different kind of basis differential, a different kind of basis risk, if you like. It's also important to remember that, unlike a producer, we're not hedging a stream of production. We're actually hedging an inventory position that changes virtually day to day with the shifting supply and sales volumes that we see. It's important for us to be able to move fairly quickly on financial hedges, which requires a relatively liquid market. That's why we have chosen, for the most part, to go with crude oil-based financial contracts. As I said, we're always evaluating that strategy. I think it's fair to say in hindsight, it didn't work out quite as well for us in Q4 as it has historically. We will continue to evaluate that strategy as we look forward. Great. No, I appreciate all that color. Thanks, guys. Your next question comes from Matthew Akman from Scotiabank. Your line is open. Thanks very much. Hey, Jim, I have a question relating to, I guess, the strategic direction of the company in regards to the iso-octane acquisition and what's happened in marketing in the quarter. There's obviously value in the iso-octane asset, and the synergies are really apparent. You talked about delivery methods improving, maybe moving around the Trans Mountain pipeline. That's obvious, but at the same time, that facility has, at the end of the day, significant commodity exposure associated with butane. I'm just wondering how you're thinking about the company in terms of how much commodity exposure you're really willing to take on to go after that value, as opposed to paying up for more stable assets, some of which have come to market lately that you guys have not acquired, and reducing the company's overall commodity exposure. How are you thinking about that equation these days? Well, I'll take a kick at it, and Dave will have some comments, I'm sure. I think with AEF, the way we looked at AEF, clearly, it consumes a lot of butane, and I think we felt we were a major player in butane storage pipelines, ability to rail, truck. It really felt like there was a very good integration with our business model. I think that the product, the iso-octane is in demand. We think it'll continue to be in more demand as more and more, I think, areas strive for cleaner burning fuel and the properties that this fuel have. I think we feel very good about that. I think we have an opportunity, a unique opportunity to buy a facility at a very good price versus a lot of the facilities that you maybe are mentioning that we think were picked up at very high prices. What you buy assets for in this space certainly have an impact on what you ultimately can give back to your shareholders, and that wasn't lost on us with this acquisition. I think it's very unique asset at a very good price. I think we're really comfortable with the risk profile of it. I guess, we have a fundamental belief that as producers drill more and more liquids-rich gas in North America, that we're going to have access to an awful lot of NGLs on both sides of the border from not only gas plants, but also from refineries. I think that went into our thinking as well. David, do you have anything to add? Yeah, the only thing I would add, Matthew, is that I don't see this as a strategy shift at all. I've always had a certain amount of commodity element to our business. It's something that doesn't faze us particularly, but we want to maintain a balance between stable fee-for-service businesses and the commodity side. We have taken on a little bit more margin risk with the iso-octane business. At the same time, we're adding long-term fee-for-service cash flows with the arrangements that we've got around condensate with Imperial Oil and Husky that will start to generate significant cash flows starting later this year. We like that balance. When it comes to acquisitions, we have some criteria that we stick to. One of the criteria is. Do we see opportunities for further business development and additional growth from the ancillary things that come from those acquisitions? Some of the ones that you're referring to we saw were perhaps more limited. With the AEF acquisition, we think there's lots of those kinds of future business opportunities that result from the integration with our existing facilities. Maybe I could just, as one follow-up, ask the same question about risk tolerance in a different way. In the marketing business in particular, David, given what's happened, I know it's a bit of a one-off, but still quite a big variance. In light of that, would you consider reducing risk in that business, even if it means potentially somewhat lower ongoing profitability expectations? Well, I think, we're always looking at that question. We have a risk management committee that meets weekly, and that's one of the things that's always in our mind. I'm not going to make a categorical statement now because I think it's going to depend on how we see the supply and demand for NGLs in North America unfolding as we look forward. What I would emphasize is we do take a long-term view of the business. We want to manage, as I said before, a balance of margin-oriented business and fee-for-service-oriented business. Okay. Thanks very much, guys. Your next question comes from Robert Hope with RBC Capital. Your line is open. Great. Thank you. Just on propane, I'm sure you don't want to get into the value of the specific propane in inventory, but you did talk about weak margins in the outlook, but not losses, like you had some commentary that you sold some propane at a loss in Q4. Based on that commentary and how propane prices have split since year-end, am I reading too much into it that directionally, the value of the propane is still below the current price? Again, Robert, it's not appropriate for me to be providing specific guidance in that regard. I think we're buying NGL mix and selling propane on a daily basis, and we're only halfway through the quarter at this point. We do expect Q1 is going to be weak, but to be more specific than that is not something I'm prepared to do. Okay. Maybe this is just a question for Jim. You had some comments on the low gas price environment, and you were referencing the previous downturn. You obviously saw some volume losses, but you definitely did benefit from the movement away from dry gas to liquids-rich, which benefited most of your facilities. I guess since a lot of the drilling now is in the liquids-rich zones, how do you see it playing out? Are you expecting producers to have lower cuts and shut-ins because of the liquids netback? Or do you just think that some of the cuts are going to happen away from your plants? I think the difference between now and 2008 that I'd like to make is that back in 2008, we weren't experiencing the amount of horizontal drilling multi-stage frack. That technology was just starting to evolve back here. As I've said in the past, it is really game changing, and it has opened up a lot of zones that people weren't even thinking about in 2008. We've got a lot of additional liquids-rich zones around our plants today like the Montney at Simonette. Even the Montney at Caribou, it's getting drilled pretty aggressively with Petronas and Progress. The Duvernay is the one that nobody really knows, but it's getting a lot of attention, and I don't think there's anybody more exposed to the Duvernay from a facilities point of view than we are. The Cardium, both from a solution gas play, but also as you go west in the foothills front, it's starting to evolve as a very economic gas play. It's difficult, but I believe we're better positioned today than we were in 2008 because of the tight gas around our facilities and the technology that's allowing that to happen. As I said, I read an independent report in the last day that talked about evaluating all the gas zones in North America, and nine out of the top 10 break-even half-cycle zones were in the Western Canada Sedimentary Basin. That's a new phenomenon. People weren't talking about that in 2008. I think I'm optimistic that way. I think the gas that's going to be shut in is going to be dry gas, and that represents a very small part of our portfolio. Nevis, Chinchaga, I think are a couple of plants we have seen a little bit of dry gas at. I believe you're going to see more dry gas shut in the States. I think people are walking away from the Haynesville. It's been announced because it's very dry, very expensive. So we will see it up here, and I don't want to be overly optimistic, but I think the basin is well positioned to, I think, weather the storm. There'll be cutbacks, but I think there'll be, for the most part, on the dry gas side. Okay. That's great. Thank you very much. Your next question comes from Steven Paget from FirstEnergy. Your line is open. Thank you and good morning. The C3 spread between the Gulf Coast and Edmonton has been going up for about three years now. Is there an opportunity for Keyera to connect Alberta NGLs better with the North American grid? If such a connection is made by someone else, could that be a bit of a threat to Keyera's business model? Boy, that's a simple question with a whole bunch of complicated factors to try and work through, Steven. As you've seen at various times in the history of the industry with both natural gas and crude oil, infrastructure constraints will create interesting temporal basis differentials among various geographic points. In the U.S., as you point out, we've seen that with NGLs recently as the growth in NGL production in the U.S. has gotten a little bit ahead of the ability of the infrastructure to handle it. We do pay attention to what's going on in the U.S., and we do, from time to time, look at opportunities to access facilities down there in order to take advantage of those price points. Our business is still primarily a Western Canadian-centric business. It's hard to see in the near term that we would do a whole lot of what you're describing. Okay. Thank you. My second question, just on NGLs, is with your deethanizer at Fort Saskatchewan, would that include an overall expansion of the facility or just expansion, not to throughput, but just in the capability? The first step in our plan would be to add a deethanizer to the facility. We're working through the details of that right now in terms of sizing. What that would do is it would allow us to accommodate C2+ mix, which our plant can't handle today. In effect, what we do is we increase the capacity of the facility to the extent that we can bring in C2+ mix to supplement the C3+ mix that we take into the fractionator today. Overall, the NGL mix that we take through the facility would go up. The actual amount of the increased throughput will depend on the proportions of C2+ and C3+ mix that we would be taking in the future. Okay. I guess, is there spare capacity overall in the Edmonton, Fort Saskatchewan region in NGL fractionators, or are we pretty much full up? There is spare capacity today as we speak. As you know, the four major facilities are Keyera's, Dow's, Provident, and BP's. As I say, there is excess capacity today, but we're anticipating that that capacity is likely to be used up as we see growth in NGL mix production, particularly from the Deep Basin area over the next two or three years. Okay, thank you. Those are my questions. Your next question comes from Robert Catellier from Macquarie. Your line is open. Thank you. I really just have some follow-ups on the propane issue. You gave a good explanation to Carl as to why there's a basis differential in the propane hedging. I wondered maybe if you could comment, whether you'd consider changing the way you hedge. In particular, is there a case to be made that maybe you wouldn't hedge at all? No, I don't think that would ever be the case, Rob. As I said earlier to Carl, we're constantly looking at different approaches to the hedging, but ours is a margin business. We buy NGLs based on NGL prices, and we sell NGLs based on NGL prices. We could not afford to go naked on the underlying commodity price, because we can't afford the risk of having the margin basically eaten away by a significant shift in the underlying commodity prices. If you look back to the fall of 2008 and the winter of 2009, I think that's a perfect example of the risk that we would take if we chose not to hedge at all. Yeah, I agree with that. The other aspect, of course, is the volume aspect and how much you actually put at risk. Are we to understand then, from the comments you've given previously, that you've made no decision, and you're still evaluating whether there'd be a change on maybe the value you put at risk? Potentially. It's more a question of hedging tactics than it is the amount of volume or value that we would look to hedge. That's probably the best way to characterize it. As you know, our contract year for NGL starts April 1st and goes to April 1st. We don't have a whole lot of shift in strategy that we can do in the short term between now and April 1st, but we're certainly looking at it for the coming contract year. Okay. Finally, just on the hydraulic fracking and some of the pressure that's going on with respect to environmental issues and so-called voluntary compliance issues in Canada. Have you seen that change producer behavior? Are they talking about either slowing down or changing the way they approach producing the reserves? Robert, Jim here. I haven't seen it at all. I think if anything, this province, I quote a number, but tens of thousands of wells have been fracked over the last 40 years. I certainly get a sense, we have probably the best regulations maybe in the world with the ERCB. I think they do a very good job of managing and regulating around that. I think CAPP has taken some voluntary measures around completions and fracturing. I just think a lot of that noise is coming from uninformed sources. I think in Alberta, we're informed, and I think that I just don't sense that it's this big issue, and I certainly don't sense that producers are going to change their behavior. You're going to see people drill longer horizontals and have more fracs as we go forward. That's just my view, but I don't sense that fracking noise out there is going to have any impact on how people do their business in a big way here. Okay. Just a quick follow-up for Dean, just on the turnaround for AEF, page 14 of the MD&A, you're talking about CAD 18 million cost budgeted for the turnaround, and then you go on to say maintenance capital of CAD 6 million-CAD 9 million. Is that 6-9 included in the 18, or is that additive? No, that's additive. Okay, thanks. One thing I would emphasize, though, on that point, Rob, is that the 6-9 is sort of an annual average. That's not really intended to be a number for 2012. We're probably not far enough along with the folks at AEF to be able to give you a specific number for 2012. Okay, thanks. Your next question comes from David Noseworthy from CIBC World Markets. Your line is open. Morning, gentlemen. Just a couple of quick questions or a follow-up on the propane. First, in terms of the South American markets, I know that the low propane prices have been generally on weather. The South American markets have tightened up. What have you seen in terms of demand for North American propane in South America since November 16th and the Seaway announcement, which I guess coincides with the Brent WTI collapse? I'll try this one, David. We think that there's going to be continued demand for propane exports from North America. There's propane that goes to Europe seasonally. South America has been a growing demand, as you point out, and we expect other areas around the globe as well. Where that demand gets met from is obviously dependent on supply pricing. The one issue that the North American infrastructure has had is that the export terminal capacity currently is a constraining factor on propane exports. There are two projects that I'm aware of on the Gulf Coast that are currently underway to expand propane marine export terminal capacity in order to be able to move more NGLs generally, but propane in particular, offshore. Once those capacity additions have been put in place, I would expect to see a further increase in export volumes. Again, it will depend a little bit on pricing signals, and those pricing signals are indirectly related to the Brent price for crude oil, because that's the global marker. Right. You're saying that even though that Brent WTI differential came down significantly, I guess, near the end of the year, that you didn't see much of a decrease in demand for North American propane? No, I don't have recent data to refer to, but no, I don't think so. I think the demand is still there. Okay. Thank you for that. Just a quick question. When we look at your marketing results, and we're trying to understand, obviously, there's propane, butane, condensate, and we're trying to understand how those dollars break out in terms of the pie. Can you give us a feel for what percentage is propane versus the other commodities? We don't, as a rule, divulge what the results are on a product-by-product basis, primarily for competitive reasons. Historically, we've seen a relatively even split among the four components that we've had. Propane, butane, condensate, and crude oil midstream. I think it's fair to say that over the course of the last couple of years, condensate has become a somewhat smaller, proportionately, piece of that mix, just as a function of some of the pricing dynamics. But it varies a fair bit from quarter to quarter and year to year. As Jim mentioned earlier, we now have a fifth product in our marketing segment, which is iso-octane, which we expect in some ways will be a bit of a natural hedge on the butane side. Thanks. I guess the last question I have, you have a very enviable dividend increase track record. This is just one quarter, but when you look forward, does this impact how you look at your dividend and how you can grow it? Really haven't thought about our dividend. What I would say, if you look historically, and even with the end of this year, our payout ratio is 67%. Historically, it's been probably that or lower. We've purposely had a lower payout ratio because some of the variability we know we'll see from time to time in the marketing business. I would say our view on dividend hasn't changed as a result of anything that's happened in the last three months. We'll continue to look at it. Our board will continue to look at it. I think it's business as usual from our perspective. Thanks. I appreciate your answer. Thank you very much. David, let me just add to that. I think that we've always been cognizant of the little bit more variability in the marketing business when we've established our dividend level, and it's one of the reasons why we've maintained a low payout ratio. In Q4, even with the disappointing results we had in marketing, our payout ratio is still around 70%. I don't anticipate that this is going to have any bearing on how we might look at dividends going forward. Thanks for that color, David. Your next question comes from Patrick Kenny from National Bank Financial. Your line is open. Hey, guys. Just on the potential expansion at Rimbey, just wondering, given how fast the Carlos pipeline has been filling up here, what sort of lead time are we looking at for expansion at Rimbey? Can you expand it by, say, 100 million a day as quickly as you can expand the Carlos pipeline? I can take a shot at that one, I guess. The short answer is that to do a minor capacity expansion at Rimbey is probably not in the cards. What we're looking at is with the possible addition of a turbo at Rimbey in order to enhance the ethane extraction, that really significantly expands the ability of the plant to handle NGLs. What that means is that any subsequent expansion of the raw gas inlet capacity becomes fairly inexpensive. It's a little bit of a cart and horse question for us, and that's what we're evaluating. In terms of lead time, Pat, unfortunately, we're probably still looking at something close to two years from decision point to the point where we have that project finished. That is probably quicker than any other capacity expansion or new plant construction could be achieved. Even though it's a long lead time, because of the capabilities of the Rimbey gas plant, we probably have the shortest lead time of any competitive alternative. Pat, I'd jump in and say, I think when we're looking at the Glauconite and the Duvernay, because we've been approached by a lot of producers to start thinking about the Duvernay. Obviously, Rimbey's a clear focus because of its size and deep cut capabilities and pipeline connection to Edmonton. You're effectively getting an NGL price connected at the Edmonton-Fort Saskatchewan hub. In the short term, we certainly have full fractionation capacity at Gilby. We're just commissioning a refurbished turbo at Minnehik-Buck Lake as we speak, and we have a 100 million a day plant. Probably half of that is available today. I think ultimately, the Glauconite, you have to think about Strachan because it's going that way. Today, we've got as many Glauconite wells probably drilled closer to Strachan than they are to Rimbey. It's also part of the equation. I think when we talk to producers, we lay out, here's what we can do for you at these 3 or 4 plants in the short term with the idea that we get comfortable with the volume commitments that we can make the major capital expenditures that are going to be required to take Rimbey to the next level. Okay, great. Appreciate the color there. Just lastly, maybe for Dean, just looking at Note 31 there, your operating lease commitments are up about CAD 55 million, I think, year-over-year. Just wondering if you could provide more color on the increase there. The operating lease commitments would include some recent commitments we made on some rail cars. I guess we also took on some additional lease space here in our building, extended that out. Okay. Would the acquisition of AEF boost those commitments even further? Yeah. I don't think materially in those numbers. Okay, great. That's all I have. Thanks, guys. Your next question comes from Joe Gulewicz from AW Solutions. Your line is open. Thank you. Good morning, everybody. Just wanted to say thanks a lot for that excellent overview and good insight on your summary there. A couple of quick questions. You'd mentioned about AEF and the strategic move that that has. Any thoughts of looking at retooling or optimizing that to convert some of that iso-octane potentially into diluent? The short answer is we're looking at a lot of different possibilities, and it's still early days. There's a number of intermediate products that are produced, including a little bit of pentane at that facility. I don't know that it would make a lot of sense to produce a diluent product simply because it would be a premium product that would be more expensive than the alternatives that the bitumen producers have for diluting the bitumen. I guess I didn't mean converting solely away from iso-octane, but some of those byproducts to potentially as the market swings to do more of the higher value potential products. Yeah. No, I appreciate that, and that is something that we're looking at. I think it's likely that producing a diluent would be a fairly small piece of the picture, simply because the concept of a premium diluent is sort of a contradiction in terms. Yeah. Certainly, solvents or other things for the oil sands producers is quite conceivable. Excellent. One other question. You mentioned about expanding beyond the Edmonton-Fort Saskatchewan area. Any thoughts in terms of how far abroad you're looking? I think the intent there, Joe, was we're looking with Enbridge at building a pipeline up into the Fort McMurray region, as well as a rail truck terminal up there short term to accumulate the market. I think we're always looking at where next. We keep coming back to with the foothold we have in Edmonton-Fort Saskatchewan, we continue to see more projects there than we probably have access to people and time right now. I think our competitors probably feel the same way. We're going to stay very focused on Edmonton-Fort Saskatchewan and all the offshoots that the oil sands bring. I think the same on the gathering and processing side. We do look at other basins. We've looked at the Marcellus. We've looked at all the shale plays, and should we be there at this time? We keep coming back to we have more opportunities available to us today in the Western Canada Sedimentary Basin. We think it's far less competitive than a lot of U.S. basins. For now, I think we're going to stay pretty focused here. Never say never. As we get bigger, you always have to look beyond your sight lines, and we'll continue to do that. Excellent. Thank you. Your next question comes from Steven Paget from FirstEnergy. Your line is open. Thank you. Since the Enbridge Southern Lights pipeline has opened, the condensate spread between Edmonton and the Gulf Coast has remained volatile. Why is that even though there's a pipeline with some available capacity to move diluent from Chicago to Edmonton? Steven, I'll take a crack at it. Dave's voice is playing up. I think there's a lot of factors, and we've been saying, I think, for the last couple of years that we think condensate pricing premiums will remain volatile because there's a lot of things that push that number around. Southern Lights is a source of supply. A lot of condensate comes in by rail from different parts of the U.S. Comes in by rail from offshore. But I think the impact there of price swings and the volatility is more a function of the supply coming on. Different projects come on, and it'll trickle on at one barrel at a time. They come sort of blasting into the marketplace. You mean bitumen supply? Bitumen supply, sorry. Not condensate demand. It comes on at chunks of 10,000, 20,000, 30,000 barrels. It creates that volatility until the market responds and brings enough diluent in here. I think the ability operationally to move it in and out of storage, in and out of pipes, creates other forms of volatility. Weather can have a big impact. It's a lot harder to move bitumen when it's 30 below, wish it was 30 below, than it is in the middle of summer. Weather will create volatility for your condensate as well. It's hard to put your finger on any one issue, but I think it's mostly to do with the increasing supply of bitumen that continues to come at this marketplace. Thank you. Since your last conference call, we've seen some pretty serious consolidation in this space. Can you comment on that? Well, it's pretty serious consolidation. I agree with that. I think in some ways, we compete with the parties that have consolidated. We've got less competitors on some fronts than we had before. We've probably got stronger competitors. Having said that, I think we're not surprised by it. I think what I said before was, I just believe there's so many opportunities around the Edmonton-Fort Saskatchewan oil sands hub for us and our competitors that we're all going to be very busy for the next five years trying to accommodate the demands from the customers there. I think it's all healthy. Okay. Thanks, guys. There are no further questions at this time. Thank you, Stephanie. Well, this completes our 2011 year-end results conference call. If you do have questions after the call, please contact us. Our contact information is in yesterday's release. Thank you again for listening, and have a good day. Thank you. This concludes today's conference call. You may now disconnect.