Earnings Call: Q4 2017

Feb 16, 2018

Good morning. My name is Jody, and I will be your conference operator today. At this time, I would like to welcome everyone to the Keyera Corp 2017 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'd like to ask a question during this time, simply press star, then the number one on your telephone keypad. If you'd like to withdraw your question, press the pound key. Thank you. Lavonne Zdunik, Director of Investor Relations, you may begin your conference. Thank you, and good morning. It's my pleasure to welcome you to Keyera's 2017 year-end conference call. With me today, David Smith, President and CEO, Steven Kroeker, Senior VP and CFO, Bradley Lock, Senior VP of the Gathering and Processing business unit, and Dean Setoguchi, Senior VP of the Liquids business unit. In a moment, David will provide an overview of the year, followed by an operations update from Brad and Dean. Steven will provide additional information about our financial results, and then we will open the call for questions once we have completed our prepared remarks. Before we begin, however, I would like to remind listeners that some of the comments and answers that we will be providing today speak to future events. These forward-looking statements are given as of today's date and reflect events or outcomes that management currently expects to occur based on their belief about the relevant material factors, as well as our understanding of the business and the environment in which we operate. Because forward-looking statements address future events and outcomes, they necessarily involve risks and uncertainties that could cause actual results to differ materially. Some of these risks and uncertainties include general economic market and business conditions, fluctuations in supply, demand, inventory levels, and pricing of natural gas, NGLs, isooctane, 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 essential for our capital projects, contractor performance, counterparty risk, governmental and regulatory actions or delays, competition for, among other things, business opportunities and capital, and other risks as are more fully set out in our publicly filed disclosure documents available on our website and SEDAR. We encourage you to review the MD&A, which can be found in our 2017 year-end report published yesterday and available on our website and SEDAR. With that, I'll now turn it over to David Smith, our President and CEO. Thank you, Lavonne, and good morning, everyone. Keyera had another successful year in 2017, and it was primarily due to the performance of our core fee-for-service businesses and contributions from our capital projects completed over the last few years. Our key financial metrics all increased over the prior year with adjusted EBITDA of CAD 617 million, distributable cash flow of CAD 510 million, and net earnings was a new record at CAD 290 million. The Liquids Infrastructure segment once again generated record results and for the first time contributed the greatest amount to Keyera's annual operating margin. These results were driven by increased demand for our condensate services, the completion of the Norlite Pipeline, and high utilization of our expanded fractionation capacity. Our Gathering and Processing volumes steadily increased throughout the year as drilling activity recovered from the lows of 2016. Our marketing team executed well on our seasonal propane strategy, resulting in strong fourth quarter results. With confidence in our business outlook, we increased our dividend by 6% in May. This was Keyera's 16th consecutive dividend increase since going public in 2003 and represents an 8% compound annual growth rate in dividends per share over that period. Steven will speak more about our financial results later in the call. As our 2017 results demonstrate, demand for Keyera's essential services continues to be strong, and we are making great progress on our major capital projects. In mid-2017, the Norlite pipeline was completed and began generating incremental cash flows. At the Baseline tank terminal near Edmonton, we recently placed the first 4 tanks into service, with the remaining 8 tanks on track to be phased in throughout 2018. Our Keylink NGL gathering pipeline system is on schedule for completion in the second quarter. The liquids handling expansion at our Simonette gas plant is also on track to be completed in the second quarter, and our new Wapiti gas plant and North Wapiti pipeline system are scheduled to be operational in 2019. All of these investments position Keyera for future growth in some of the best areas of the Western Canada Sedimentary Basin. I'll now turn it over to Brad Locke, who will discuss our Gathering and Processing business unit results. Thanks, David. The Gathering and Processing business unit delivered an operating margin of CAD 275 million in 2017, with the processing volume steadily increasing through the year. In the fourth quarter, gross processing throughput averaged 1.526 billion cubic feet per day, a 12% increase over the same period in 2016. Although natural gas prices in Canada were weak in 2017, prices for crude oil and natural gas liquids strengthened in the second half of the year, further supporting an increase in drilling activity across the liquids-rich areas of the Western Canada Sedimentary Basin. The liquids-rich Montney and Duvernay development areas continued to be the major area of focus for producers. For Keyera, this resulted in new well tie-ins and increased utilization at our Simonette gas plant, which achieved record throughput volumes in 2017. As a result of the increased activity in this area, we have multiple capital projects underway at our Simonette gas plant. We are expanding the liquid stabilization capacity, enhancing the inlet liquids handling capability, and adding acid gas injection facilities. These projects are expected to help enhance producers' netbacks while providing additional long-term growth opportunities for Keyera. Construction of our Wapiti gas plant near Grande Prairie, Alberta continues to progress well. The site has been cleared, pilings and foundations are nearly complete, storage vessels are being constructed, and fabrication and erection of major equipment continues. Phase one of the Wapiti gas plant includes 150 million cubic feet per day of sour gas processing capacity and is backed by agreements with Paramount Resources Ltd. To extend the plant's capture area north of the Wapiti River, we are also developing the North Wapiti pipeline system that includes a 12-inch sour gas gathering pipeline, an 8-inch condensate and water pipeline, and a compressor station. The pipeline system is underpinned by a long-term take-or-pay agreement with privately owned Pipestone Oil Corp. Both projects are expected to be in service in 2019. Altogether, the approved projects at our Simonette and Wapiti gas plants total approximately CAD 800 million. Keyera has an excellent understanding of the infrastructure that will be required to develop the Montney and Duvernay in a safe, cost-effective manner that supports producer netbacks and respects community and landowner interests. As a result, we are considering expanding the processing capacity of the Simonette gas plant and sanctioning phase two of the Wapiti gas plant. We continue to have discussions with existing and new producers in the area to understand their development plans so we can align our further capital investment decisions with their production profiles. The liquids-rich Spirit River and Glauconite geological zones in West Central Alberta are also experiencing increased activity. In late 2017, Keyera entered into an agreement with a producer active in the Glauconite to construct a new 10-inch sweet gas pipeline, which connects our Strachan and Ricinus gas plants. This will allow incremental volumes to flow to Ricinus for processing under a long-term take-or-pay arrangement. The pipeline not only supports Keyera's objective of maximizing throughputs at our facilities by enhancing plant connectivity, but provides area producers with added flexibility, efficiency, and low-cost processing solutions. We are targeting an in-service date for the pipeline in the second quarter of 2018 to coincide with the start of the Strachan plant turnaround that is currently scheduled for June. This will allow us to offload volumes from Strachan to Ricinus for processing during the turnaround. I will now turn it over to Dean to discuss the Liquids business unit. Thanks, Brad. Liquids Infrastructure business unit also performed very well in 2017. Liquids Infrastructure segment generated a record operating margin of CAD 285 million, up 16% over the prior year. These results were driven by increased demand for our condensate services, the startup of the Norlite Pipeline and related take-or-pay contracts, and incremental fractionation volumes. 2017 was the first full year of operations for our second fractionation facility in Fort Saskatchewan. Overall utilization for the two KFS frac units, which have a combined net capacity of 50,000 barrels per day, was approximately 91% for the year. Keyera operates an industry-leading condensate system in Western Canada, and the volume of condensate delivered to our system grew by 21% in 2017 compared to the prior year. We continue to enhance this network, and over the last eight months, we have added the Norlite Pipeline, new condensate storage tanks at Keyera's Edmonton terminal, as well as connections to the North West Redwater Sturgeon Refinery and Pembina's Canadian Diluent Hub. In 2018, we expect to complete the South Grand Rapids Pipeline, which will add additional capacity between Edmonton and Fort Saskatchewan to meet producer diluent needs. The demand for condensate continues to grow in Alberta. To support this growth, in the fourth quarter of 2017, we signed two new agreements for condensate storage services and recently secured two new shippers on both the Norlite Pipeline and Keyera's Fort Saskatchewan condensate system. These commitments are long-term take-or-pay contracts that increase the utilization of our existing capacity and begin generating incremental cash flow in 2018. Also adding incremental cash flow to the Liquids Infrastructure segment in 2018 is the Baseline tank terminal. As David mentioned earlier, the first four tanks are now in service, with the remaining eight tanks to be completed throughout 2018. To position the Liquids Infrastructure business for future growth, in 2017, we acquired almost 1,300 acres of heavy industrial zoned, undeveloped land strategically located in Alberta's industrial heartland. We continued to develop our underground storage cavern capacity and entered into a 20-year midstream agreement with Chevron Canada and their partner, KUFPEC, to process 50% of the natural gas liquids from their Kaybob Duvernay development. Assets and service agreements like these provide Keyera with a strong foundation for the future. Marketing segment continued to contribute to Keyera's integrated value chain during the year, generating a realized margin of CAD 128 million compared to CAD 137 million in 2016. Results were primarily affected by a lower isooctane contribution due to the 9-week unscheduled outage at AEF in the first half of 2017 and higher average butane feedstock prices relative to the prior year. After completing the necessary repairs at AEF, the facility has been running very well. In early 2018, we experienced some challenges with our rail service, causing us to operate AEF at reduced levels. We are currently working on solutions with our service providers to restore shipments of isooctane to normal levels. Keyera's Marketing group also manages the sale of propane, butane, and condensate. In the fourth quarter, propane generated strong margins as we executed on our strategy of utilizing our storage assets to build propane inventory during the summer and then leveraged our transportation assets and logistics expertise in the winter to sell inventory at seasonally stronger prices. I'm pleased with the liquids business unit's performance in 2017 and look forward to 2018 as we ramp up our new capital projects and continue to look for opportunities to increase shareholder value. With that, I'll turn it over to Steven to discuss the financial results in more detail. Thanks, Dean. As mentioned earlier, we had a successful year with our key financial metrics all increasing over 2016, even with the nine-week unscheduled outage at AEF in the first half of the year. The strong 2017 results were driven by a record operating margin from the Liquids Infrastructure segment, solid performance of the Gathering and Processing segment, and a strong contribution from Marketing despite the unplanned outage at AEF, as previously discussed by Dean and Brad. Net earnings for the year were a record CAD 290 million compared to CAD 217 million in 2016, mainly due to higher operating margin from the Liquids Infrastructure segment. Adjusted EBITDA was CAD 617 million compared to CAD 605 million in 2016, while distributable cash flow was CAD 510 million or 11% higher than the prior year. Distributable cash flow in 2017 benefited from the strong operating margin generated by Liquids Infrastructure segment and lower maintenance capital. Maintenance capital in 2016 included the costs associated with the scheduled turnaround at AEF. On a per-share basis, distributable cash flow for 2017 was CAD 2.70, representing a 5.5% increase from the prior year. Keyera announced a 6% dividend increase in May 2017 and continued to have a conservative payout ratio, averaging 61% for 2017. Keyera's two fee-for-service-based business segments more than covered our annual dividend payments to shareholders in 2017. In 2017, Keyera invested CAD 658 million, mainly related to the Norlite Pipeline, Diamond NGLs handling expansion, Baseline Terminal, Keylink, and phase one of the Wapiti gas plant. With respect to 2018, we plan to invest between CAD 800 million and CAD 900 million on projects that are already underway, as well as on the acquisition of a 50% interest in the South Grand Rapids Pipeline. Our 2018 maintenance capital budget is forecast to be between CAD 40 million-CAD 50 million and includes turnarounds at the Strachan, Nevis, and Brazeau North gas plants. Cash taxes for 2018 are now estimated to be between CAD 40 million-CAD 45 million, and we estimate Keyera's tax pools to be approximately CAD 2.2 billion as of December 31st, 2017. In the second half of the year, we increased our financial flexibility by announcing two public BBB investment-grade corporate credit ratings from DBRS Limited and S&P Global. We also completed a successful common share offering that generated gross proceeds of CAD 494 million. As of December 31st, 2017, our net debt to EBITDA ratio was 2.26 times. This financial flexibility positions us well to execute the CAD 1.6 billion in announced growth projects we currently have underway while maintaining the flexibility to pursue opportunities as they arise. That concludes my remarks. David? Thanks, Steven. While the past few years have been difficult for many of our customers and business partners, I am proud of Keyera's teamwork and accomplishments. Over the past three years, we have placed into service CAD 1.6 billion worth of capital investment projects and increased our distributable cash flow on a per-share basis by 14%. Since the downturn in late 2014, we have reduced operating costs in our Gathering and Processing segment for the benefit of our customers. We have continued to enhance our industry-leading condensate hub by adding more receipt and delivery points. We have sold non-core assets such as our Paddle River gas plant and Wabasca River and North Cenex pipelines. We have strengthened our financial flexibility by obtaining two investment-grade corporate credit ratings. We also continue to focus on operational excellence. Our goal is to consistently execute our business strategy while delivering first quartile health, safety, and operational performance, proactively managing our environmental responsibilities, achieving high reliability, and leading cost performance. In 2017, our operated gas plants achieved 97% reliability, which is a tremendous accomplishment and very important to our customers. We take a long-term view of our business, and as the industry shows signs of recovery, Keyera is well-positioned for growth. Our assets are strategically located within the Western Canada Sedimentary Basin above some of the most economic liquids-rich geological zones, and we continue to expand our presence in the Montney and Duvernay areas. As oil sands production continues to grow, our extensive and reliable condensate system provides producers with an effective way to source, store, and transport their condensate. Our balance sheet is strong, and we continue to pursue opportunities to generate shareholder value, balancing risk and reward expectations. On behalf of Keyera's directors and management team, I would like to thank our employees, customers, shareholders, and other stakeholders for their continued support. With that, I'll turn it back over to the operator. Please go ahead with questions. At this time, I would like to remind everyone, in order to ask a question, press star, then 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 the line of Linda Ezergailis from TD Securities. Your line is open. Thank you. Can you give us some more context around your condensate operations? How active are you in discussions right now for further contracts? Do you prefer to keep a certain amount of your operations as spot for flexibility in case of disruptions or to keep some optionality there? Did the new contracts, were they additive to your business, or were they displacing some spot activity? Hi, Linda. This is Dean. Good question on the condensate system. One thing that we've done over the last several years is we've made some very significant investments to our condensate system, including the capacity between Edmonton and Fort Saskatchewan, particularly when we add the South Grand Rapids Pipeline to our asset base and put that into service. Also, the four condensate tanks at Edmonton and the additional storage that we've added at KFS. I should also mention the Norlite Pipeline as well. This whole system has added a lot of extra capacity. We are constantly working with oil sands producers and their needs to continue to bring more volumes and business to our system. We expect that to continue to grow over time and with minimal capital investment. Again, we believe that the returns generated from those assets will hopefully continue to increase over time. With Norlite coming into service, has that accelerated your discussions, or would we expect kind of a regular tempo of ramp-up as you describe, maybe commensurate with new production coming online? Yeah, we certainly hope so. We are always actively talking to any parties that need long-haul transportation needs for diluent. We're very happy to sign two customers that are going to commence using our services this year, and we're talking to others. Yes, we will continue those discussions and certainly expect over the short, medium, long-term to add more business to that pipe. Okay. That's helpful context. Now, maybe moving on to your gas processing business. I guess there's a lot of talk about the potential for bottlenecks again this coming summer. Can you give us a sense, based on your discussions with your customers in your capture areas, what you see as the volume outlook for the balance of the year and, I guess, activity levels beyond this year? Hi, Linda. This is Brad. I think, certainly as we look into 2018, we're cautious about the continued rate of growth. Some of the bottlenecks that we've seen in past years, we certainly expect to continue, and the forward curve for gas certainly shows some softness in pricing as you get into the summer. We're certainly wary of that. That being said, we've been pretty pleased with the drilling activity that's been going on through the winter. While producers have recently announced some budget cuts, the drilling activity through 2017 into 2018 has been as strong or stronger than it was last year. That certainly bodes well for volume growth as we look forward. It's one of those things we try to stay in tune with our producers and understand their needs and make sure that we can provide them the service if and when they need it and respond to the market as it kind of evolves. Okay, maybe that's a segue to my follow-up question with respect to the potential for future projects, Wapiti phase two and maybe the Simonette expansion possibilities as well. Are you increasingly optimistic that you can meet your customer needs through some sort of FID? And what sort of timing are you thinking of might be possible and other factors at play that you need to see before you commit to those projects? I think as we mentioned, it's just staying in tune with producers' development plans. They're also certainly wary of commodity prices and managing their budgets. The advantage up in both the Wapiti area and the Simonette area is condensates and NGLs play a much bigger piece of the producer net backs than gas do. Consequently, their producers are certainly more optimistic up in that area because of the added value that they get from the liquid side. We continue to work with them. I don't have a timing as to when we think we might be able to announce those, but certainly discussions continue to progress positively. Okay. Thank you. Your next question comes from the line of Robert Hope of Scotiabank. Your line is open. Good morning, everyone. Two questions. The first is just on the potential for M&A in the basin. When you look at your strong balance sheet and the potential that your producer customers could require some capital, are you seeing an uptick in potential opportunities to acquire infrastructure? Rob, this is Dave. I'll take that one. I think we're always on the lookout for acquisitions that fit our criteria. I think it's fair to say that in the environment we've been in the last three years, that a number of producers have been looking at monetizing facilities as one way of raising funds for drilling activity in the low cash flow environment. Having said that, I think we're pretty disciplined and we're kind of picky, I guess I would say, with respect to the kinds of assets that fit our criteria. If the right thing comes along we'll certainly look at it seriously. As I say, we have a pretty well-developed discipline around what makes sense and what doesn't. Beyond that, it's hard to comment on anything specific. It's just not appropriate. Yep. Thank you. Then the second question regarding propane. There was some disclosure in the MD&A that on an annual basis, propane margins remain relatively small to Keyera's Marketing business. I do understand that there is a summer/winter kind of interplay here. Looking out to 2018, just given you could have had some inventory at good levels in the cold that we saw in January in certain markets, how are you looking at your propane business in 2018 and I guess the larger business as well? We feel overall pretty good about our business in 2018. I would say though, that our annual contract season for our NGL supply, including propane, starts again in April. We're working on those contracts today as we speak. Overall, I would say that the higher NGL pricing and the dynamics for NGLs today continue to be fairly strong in 2018. Thank you. I'll jump back in the queue. Your next question comes from the line of Ben Pham of BMO. Your line is open. Okay. Thanks. Good morning. I wanted to go back to Marketing, and are you able to talk about the Q1 2018 expectation? I think last quarter you mentioned significantly higher margins in Q4 and Q1, and wanted to check if that's still the case or if there are real issues of maybe change of view on that. Well, overall, specifically, we talked about the seasonality of our propane business. We certainly expect, and we saw strong margins in Q4 for propane, and we expect that to continue in Q1. Offsetting that would be seasonally it's weaker for our isooctane business because the summer months are generally stronger for isooctane because it's driven by summer driving demand. The other thing I'd mention is that we did have a slight curtailment in the first part of the year with respect to our isooctane production and sales. That's because of some of the rail service issues that we've been dealing with, but it's certainly not material to our results at this time. Anything with the crude oil? Oh, sorry. Overall, it is going to be a strong quarter, but there's offsets, I guess, with our isooctane business because it's a weaker part of the season. Can I ask anything with the crude oil side? I know typically smaller contribution. Is there anything going on with more resources or looking at that a bit more? I think our crude oil business, I would expect that to be fairly stable. Okay. On some of your commentary, take-or-pay has been talked about quite a bit through your prepared remarks, and are you able to quantify where that take-or-pay exposure is heading to and you look out 2019, 2020 in your business plans? Ben, overall, it's been increasing for sure. I think we can probably give you a little bit more specific numbers if you're interested in that. With the addition of the investments that we're making in the baseline tank terminal on top of the Norlite Pipeline and some of the Gathering and Processing investments, we do expect that the amount of fixed commitments in our overall cash flow will continue to grow gradually. Okay. All right. Thanks for answering my questions. Thank you. Your next question comes from the line of Robert Kwan of RBC. Your line is open. Good morning. Just in your prepared remarks around Wapiti Phase 2 and Simonette, you listed a number of factors, and you'd mentioned community and safety. I'm just wondering, based on where your Wapiti plant is located and the pipe project extension you've got north of the river, is there anything that you are seeing that's kind of evolved with respect to proposed facilities closer to Grande Prairie and how that might better position your facilities? I think. Certainly, we're aware of the increased population density as you get closer to Grande Prairie and certainly on the north side of the river. To date, our discussions with landowners and residents in the area have been extremely positive. Certainly our vision as we looked at Wapiti development was to move sour gas away from that area down to an area that is less populated. Consequently, our North Wapiti compressor station is really driven around getting that sour gas away from a more populated area. We think that's a positive for the landowners in the area, and I think certainly in our discussions, there's been some acknowledgment of that to date. Okay. Acknowledgment kind of is one thing. Are you seeing, though, a growing concern with respect to other kind of physical processing plants proposed north of the river? Or put differently, are producers, have you seen them become more interested in just staying away from that aspect and potentially underpinning expansion for your facilities? Yeah, I can't really comment on the other players who are looking at developing infrastructure north of the river. Our strategy has been kind of founded around, as I described, saying, the more I can do to pull that sour gas away from a more populated area, that should be viewed positively. That certainly been acknowledged, and we think that we don't see any issues with advancing our project to the timelines that we've communicated of a 2019 startup. That's our strategy going forward, and we continue to move down that path. Got it. Dean, you had mentioned earlier, obviously, you're in the negotiations for the start of the next NGL year. Is there any color that you can provide, recognizing it's still early, even if it's just around, is the expectation that the propane side of things will operate the same way that it's operated in the past year, Conway indexing, and therefore you have that seasonality? I really can't provide a lot of color at this point. I'd just say that we're sort of well positioned to compete for our NGL supply. Again, until that season is complete and those contracts are signed, I really can't say much more than that. Okay. Understood. Maybe I'll just finish. Is there anything, just given the tightness on the oil side of the market, around the South Cheecham Terminal? I think originally that was designed more for importing various products and materials. Is there anything at work there to try to help producers get oil out of the province? Well, I guess I can't elaborate on specific negotiations we're having with anyone, but I would say that we are very open for business. It's a very well-situated facility, and as you know, we completed our assets to provide solvent to the Fort Hills shippers or partners, and we continue to look for other opportunities to provide sort of oil sand services to the producers that are up in that area. That could include crude by rail. Okay. That's great. Thank you. Your next question comes from the line of Andrew Kuske of Credit Suisse. Your line is open. Thank you. Good morning. I think the question's probably for David, and it's just really on a broader basis, when you look at what TransCanada announced yesterday with pretty long-duration contracts on no new expansion. They've been very clear about the potential restoration of mainline capacity and a bunch of other options that go with that. It's directionally positive for your business and overall the basin. How do you start to frame the opportunity and the potential upside coming out of the basin in your asset positioning today? Andrew, there's a lot of potential in that question. What we find is we're no smarter than anybody else in terms of what the overall outlook is for natural gas egress out of the basin and what that means for pricing. Obviously, whatever is done to eliminate constraints and enhance the access to market, whether that's within the basin or on pipelines like the TransCanada pipeline mainline, which has excess capacity today. We think there's been a lot of positive developments, if you look back over the last couple of years in terms of improving that situation. How that plays out specifically this year and next year with respect to pricing and volumes is, it's a little bit difficult for us to predict. Interestingly enough, what we saw in 2017 was Keyera's plants really weren't affected very much by specific outages. We were affected by the fact that the AECO price was very low in September and October, and certain producers chose to shut in production rather than produce at low price levels. We may see a similar phenomenon for short periods of time in 2018 as well. From where we sit, it's kind of difficult to predict what the impact would be. I think what I would emphasize is that from a longer-term perspective, we're very encouraged with the continued improvement in the cost competitiveness of the basin. As long as we can resolve those market access issues, we think that the outlook is very positive for Canada. That's helpful. Then maybe just continuing on just the duration issue and then some of the contracts that have been signed in the past. Clearly, there's been a transition in part of your business where you've got a greater take-or-pay contracts and duration on that. Do you see this as being a broader industry trend? Because for years we talked about the U.S. style model coming into Canada and potentially changing things for the processors where you'd have more volumetric exposure, more commodity exposure, but things have really gone the other way, where there's longer term agreements, capacity type payments, tolling payments. Do you see that trend continuing for yourselves and more take-or-pay, longer duration of the take-or-pay contracts? Well, on your last point, I don't think that we would see that the duration of the contracts is likely to increase materially. I think, it depends on the nature of the service that's provided. Certain types of assets, like rail terminals, will typically have shorter-term contracts associated with them. On the other end, some of our condensate transportation capacity arrangements are as long as 25 years. I don't expect that's going to change materially, but that's what we see. With respect to your question about whether we're going to see more of it, I would point out that most of the long-term contracts that we have are associated with new investments. Typically, when we're looking at making a major investment in something like the Norlite Pipeline or a new plant, we're looking for some kind of long-term volume commitment in order to reduce the volume risk associated with that new capital. It's more challenging to get a producer to sign up to a long-term contract on an existing plant that has available capacity. In those situations, you're likely to continue to see more shorter-term contracts and more volume sensitivity. I don't see that likely changing a whole lot. That's the way we see it. Okay. Very helpful. Thank you. Again, if you would like to ask a question, press star, then the number one on your telephone keypad. Your next question comes from the line of Robert Catellier of CIBC Capital Markets. Your line is open. Hey, good morning. I'd just like a little bit more detail on the rail issues at AEF. Is this issue about access to rail cars or is it something else? Hi, Rob, it's Dean. The issue with rail is that there's been high demand over the last several months for rail service, and specifically in the Edmonton, Fort Saskatchewan area. That's really affected service for everybody that operates in that area. What I can say is that, I think we're very well-positioned to deal with that with our assets. As you know, on the isooctane, we rail most of that out of our Edmonton terminal. I mentioned earlier that the impact to our isooctane business hasn't been material so far. We do have the ability to do other things to manage that service. We're working very closely with our provider, CP. On top of that, we started transloading this week. Essentially, we're moving some of our isooctane by truck over to EDT, where we have a lot of tank and also 350,000 barrels of storage if we think this will last for a prolonged period. We could repurpose some of the tank capacity there to store isooctane if we had to. I think short-term and long-term, we're working on solutions with our service provider, but also the potential utilization of our assets to manage the situation. I think I read in the MD&A that Josephburg went to a 24-hour shift, so they're not impacted by this? Like I say, everybody's been impacted, including our rail service at Josephburg. Again, I think it has a minimal impact so far, at least on our Q1 results. Part of that is because we've invested in extra track storage there. We have a lot of extra track storage. We have our own rail movers, so we can fill and stage all the cars so that when we do get service, it's very easy for our rail provider to come in and hook up and take our cars away. The other thing is that we're pipeline connected to our Edmonton Terminal and also down to our Rimbey gas plant. We've been utilizing the different facilities again to maximize the deliveries of our propane. Okay. Just wanted to ask a little bit about U.S. tax reform. Obviously, you don't have a huge asset position in the U.S., but it is one that's developing. I'm wondering if the lower tax rate, how you see that impacting the attractiveness of opportunities there. Obviously, it helps. Do you think that has a material impact on your willingness to deploy capital there? Yeah. Thanks for the question. Steven here. Yeah, you're right. As it stands right now, it's pretty well a neutral impact on us because of the size of our current U.S. operation. Yeah, and as well, you're right that on a marginal basis, it does make investments down there more attractive because of the lower tax rate. At the end of the day, it doesn't really change our overall strategy with respect to U.S. We're always open to look at acquisitions. We've been, as you heard from David, always been pretty selective about what to look at in that respect. No real change to our strategy about how we look at assets in the U.S. Actually, Steve, wouldn't it make the acquisitions a little bit tougher because some of the tax arbitrage that you may have had, being a Canadian company, is probably narrowed a bit, but I think anything you build or own there domestically probably is more economic. Yeah, that's what I'm saying. It's slightly more attractive because the after-tax cash flows are more attractive down there. Right. As well, you're a little bit closer to the local competition in terms of their taxability as well. On the flip side, I just don't think it's a material change to our strategy as to how we look at U.S. operations and U.S. acquisition targets. Yeah. Okay. Thank you. Your next question comes from the line of Patrick Kenny of National Bank Financial. Your line is open. Yeah. Good morning, guys. David or Dean, could you expand on the evolution of your crude oil midstream JVs and what opportunities you might be looking at to help backfill any drop-off in contributions? Well, we had one joint venture that expired at the end of last year. I would just say that we have a very experienced team that continues to look for opportunities around our assets to enhance that business as much as possible. Okay. Maybe if I could just ask for Strachan. As you bring down the sour gas processing capabilities, could you just comment on the plan to backfill some of those volumes, those sour gas volumes, or should we expect it to be material? I think, over the last number of years, we've seen sour gas volumes certainly decline at Strachan. That's really what led us to the decision to shut in the sour gas processing side. The added fact was that the margins that we were making on the sour gas processing were rather modest. While you might find a volume impact, I would suggest that the margin impact of those going away might be not very significant. You add to that, the drilling activity as you go up and down that Strachan to Drayton Valley corridor has been rather robust over this past winter. We've seen outstanding volumes through the facilities coming out of Q4 and certainly looking positive into Q1. We think there's lots of opportunities for volume backfill. So much so that we initiated the connection down to Ricinus to help manage volumes through the portfolio. We're very optimistic as to what that area looks like in the years to come. All right. That's great. Thanks, Brad. Patrick, it's David here. I'm going to add to that a little bit. I think the question speaks to the flexibility of our network. Strachan will, in not too many years, be 50 years old. We've invested consistently in all of our plants over the years as circumstances have changed. The reason why our network has been as successful as it has been is because of the diverse geology that we have. That diverse geology can lead to changes in gas composition over time. I think it speaks to the flexibility of our network, where we can, for a fairly modest amount of money, shift gears at Strachan away from the sour gas that it was built for to the more liquids-rich sweet gas, which we're seeing as being the focus of activity today. We can do all that without having to build new capacity and accommodate the producers. I think it's a very good news story. It's also an example of how we're responding to the changing needs of our customers. Great. Thanks a lot, guys. There are no further questions in the queue. I turn the call back over to Lavonne Zdunik. Thank you very much for everyone for participating today. That completes our year-end 2017 conference call. If you have any further questions, please do not hesitate to either contact myself or Nick. Our contact information is in yesterday's release. Again, thank you, and have a good day. This concludes today's conference call. You may now disconnect.