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Good morning, ladies and gentlemen, and welcome to the Canadian Natural Resources Q1 '18 Earnings Conference Call. [Operator Instructions] Please note that this call is being recorded today, May 3, 2018, at 8 a.m. mountain time. I would now like to turn the meeting over to your host for today's call, Mark Stainthorpe, Vice President Finance, Capital Markets of Canadian Natural Resources. Please go ahead, Mr. Stainthorpe.
Thank you, Christina. Good morning, everyone, and thank you for joining our First Quarter 2018 Conference Call. This morning we will be discussing our strategic focus on both responsible operations and creating shareholder value. Additionally, we will provide an update on our operations, ongoing projects and our strong financial position. With me this morning are Steve Laut, our Executive Vice Chairman; Tim McKay, our President; and Corey Bieber, our Chief Financial Officer. Before we begin, I would like to refer you to the comments regarding forward-looking information contained in our press release, and also note that all amounts are in Canadian dollars and production and reserves are expressed as before royalties unless otherwise stated. With that, I'll pass the call over to Steve.
Thanks, Mark, and good morning, everyone, and thank you for joining the call this morning. Canadian Natural is in a very strong and enviable position. We are generating significant and sustainable free cash flow. Cash flow that is growing, driven by our world-class, long-life, low-decline assets and complemented by our high quality, low capital exposure assets. In today's commodity price world, long-life, low-decline assets are very valuable and give Canadian Natural a competitive advantage. Reservoir risk is low to nonexistent and the scale of these operations matters allowing Canadian Natural to leverage technology and use continuous improvement processes to minimize our environmental footprint, maximize utilization, reliability and deliver ever-increasing effective and efficient operations. The impact of long-life, low-decline assets on our sustainability is significant. Our corporate average decline rate is targeted at 9%. As a result, our maintenance capital of whole production flat is significantly less compared to our typical E&P company, making Canadian Natural more robust and generating more free cash flow, $4.2 million to $4.6 billion at the strip in 2018. In addition, we were able to use Canadian Natural's size to drive economies of scale across all our businesses. As you know, Canadian Natural has always been focused on value growth, not growth for growth's sake. As we become larger, more robust and more sustainable, the opportunities for Canadian Natural to execute on value-adding opportunities has increased significantly. As Tim goes through his comments this morning, you will see how we're creating value for the near- , mid- and long-term. Part of creating long-term value is reducing our environmental footprint. We've taken significant steps to reduce our environmental footprint and delivered meaningful results. Since 2012, we reduced our methane emissions in our conventional heavy oil operations by 71%. In addition, we've invested significant capital to capture and sequester CO2. We have CO2 capture and sequestration facilities at Horizon. Our 70% interest in the Quest Carbon Capture and Storage facilities at Scotford, and the capture and sequestration facilities at North West refinery when it's up and running. As a result, Canadian Natural will be conserving roughly 2.7 million tonnes of CO2 a year, equivalent to taking 570,000 vehicles off the road, making Canadian Natural the third largest owner of global oil -- in the global oil and gas sector of CO2 capture and sequestration capacity, and the fourth largest of all industries in the world. This makes a significant impact on reducing our greenhouse gas emissions intensity with more reductions to come. In addition, Canadian Natural minimizes our land usage and recycles 90% of our water used in our oil sands mining and upgrading, significantly reducing freshwater usage. Canadian Natural is also the largest investor in research and development in the oil and gas sector, and the fourth largest in all sectors in Canada. With investment in technology, we made significant progress in reducing our greenhouse gas emissions, and there is a pathway to reducing our greenhouse gas emission's intensity from oil sands production to levels that are well below the average global oil produced. For reference, today at Horizon, where we recognize our carbon capture initiatives, our emission intensity is only slightly higher, 5% than the average for global oil. The impact technology and effective operation has on lower Canada's oil sands greenhouse gas emissions intensity, and our ability to leverage technology to continue to reduce the intensity is generally not well understood. Many external opinions of oil sands operations are based on outdated data from many years ago. The long-life, low-decline nature of oil sands assets allows producer to continue to leverage technology, further reducing our environmental footprint and drive ever increasing effective and efficient operations. That is exactly what has happened and continues as we achieve further improvements. The value of Canada's oil sands is very important to Canada and Canadian Natural. We believe the oil sands will ultimately stand the test of volatile oil prices and any potential demand forecast scenario. As we believe oil sands will have the lowest environmental footprint, and at Horizon, as we said earlier, our intensity is within 5% of the average, and we have a defined pathway to take it below the average. And we have the lowest total cost. At Horizon, we take operating cost from over $40 a barrel to roughly USD 16 a barrel and importantly, there are no reserve replacement costs. A fundamental factor in Canadian Natural strategy to invest in the oil sands and be a leader in research and development. A critical plank in Canadian Natural strategy is to balance and optimize the allocation of cash flow to maximize value for shareholders. We strive to balance and optimize what we call the 4 pillars of cash flow allocation: balance sheet strength, returns to shareholders, resource development and opportunistic acquisitions. How we balance the pillars depends on where we are in the commodity price cycle, the risk of creating cost inflation and other potential opportunities. At all times, the primary goal of balancing the 4 pillars is to maximize shareholder value. Canadian Natural is delivering substantial, sustainable and growing free cash flow, and as you will hear this morning, we're effectively balancing the pillars by strengthening the balance sheet, debt-to-EBITDA to 1.5x by year-end, increasing returns to shareholders, increased 22% this year, and taking a disciplined approach to resource development. We are maintaining our capital budget and production guidance. There are very few E&P companies that can deliver substantial, sustainable and growing free cash flow. And at the same time, deliver production growth per share, which is driven by our organic growth in oil sands mining and upgrading, our thermal assets as well as our heavy oil and light oil assets. We also delivered top-tier effectiveness and efficiency, a flexible capital allocation program to maximize value for shareholders and drive ever increasing returns on equity and returns on capital employed as well as increasing returns to shareholders. And at the same time, strengthen the balance sheet. Canadian Natural is robust, sustainable and clearly a unique E&P company. Not surprisingly, Canadian Natural's management and staff compensation is directly tied to the key metrics that make us sustainable and maximize value. These key metrics include environmental and safety performance, returns on capital, total shareholder return, effectiveness and efficiency, balance sheet strength and production and reserve growth. With that, I'll turn it over to Tim.
Thank you, Steve. Good morning, everyone. I will now do a brief overview of our assets and talk to our 2018 first quarter results. Starting with natural gas, our first quarter production of 1.614 Bcf a day was slightly down from our Q4 2017 production. In the first quarter, the third-party plant ran reliable with one train operation, where we averaged 78 million cubic feet per day versus the 98 million cubic feet per day in Q4 2017. As reported last quarter, with one train operation, the capacity of the plant is approximately 80 million a day and has been factored into our Q2 forecast. We are proactively working with the party to determine the next steps for the plant. Due to low gas -- natural gas prices in the first quarter, we proactively shut-in production, which impacted the quarter by approximately 14 million cubic feet per day as we proactively deferred recompletions, workover activities related natural gas. Overall, our first quarter natural gas production from North America was 1.547 Bcf per day and first quarter operating cost of $1.31, which is up from Q4 2017 of $1.26, primarily due to us proactively reducing volumes. In Q1, we successfully drilled 5 net gas wells, 1 net well at Wild River came on stream late in Q1 at 15 million cubic feet per day. Our natural gas portfolio is diverse with 32% used internally, 29% exported and with only 39% exposed to AECO pricing. In Q2, 2018, the natural gas guidance is targeted to be 1.515 to 1.565 Bcf per day. Our North American light oil and NGL production in Q1 2018 was 93,158 barrels a day, comparable to Q4 2017 and is up 3% when comparing to Q1 2017. In all areas, we're continuing to optimize the waterflood, drill strategic wells and complete minor property acquisitions. Our first quarter operating costs were $15.68 barrel reflecting higher fuel, power and service cost. For Q1, we successfully drilled 30 net light oil crude wells across our vast asset base, which shows the strength of our asset base. We are currently have 19 wells on production in the Wembley area, 1 net Montney well is currently producing about 740 barrels a day; in Southeast Saskatchewan, 9 net wells are currently averaging 125 barrels per day. 6 wells drilled in Southern Alberta are currently averaging 120 barrels per day per well. Finally, in Northwest Alberta, 3 net wells are currently producing approximately 145 barrels per day per well. All the wells are performing as expected. At Tower, our battery facility construction is on time and on budget as we target startup early Q3 at a capacity of 3,000 barrels a day. Offshore Africa production was 19,438 barrels a day, which is flat to our Q4 2017 of 19,519 barrels. And our operating cost in Côte d'Ivoire were $10.14 per barrel. The drilling rig is now on route to Baobab and scheduled to commence late Q2, drilling 1.7 net producers and 1.2 net injectors with a targeted production add of approximately 5,700 barrels a day by Q4. While in the North Sea, we averaged 21,584 barrels a day in Q1, up from Q4 of 19,500. Primarily as a result of unplanned outage on the Forties Pipeline in Ninian South platform in December, which impacted the fourth quarter. Operational improvements are continuing in the first quarter, our operating costs in the North Sea are down 2% from Q4 with positive tax changes in the -- changes the U.K. government enacted a couple of years ago, we continue to drill wells in the North Sea. We had 1 net well drilled by the end of the quarter, and it's currently producing at a flush rate of over 2,000 barrels a day. With a full drilling program consists of 5.5 net wells, 4.6 net producers, and 0.9 net injectors. The Q2 international production guidance is 41,000 to 45,000 barrels a day. In heavy oil, Canadian Natural is focused on creating value; an important part of value creation is not producing into near-term anomalies in the heavy oil market that we felt would correct itself in the near term. As a result, our Q1 heavy oil production was down averaging 89,176 barrels a day, as we curtailed production of approximately 7,100 barrels a day due to widening differentials. In Q1, we did confer -- did defer completions, recompletions, workovers and by the end of the quarter, we had not completed 31 net wells. Subsequent to the quarter-end and the rapid improvement with differentials, we have now started to do work to completions, recompletions, workovers where access allows us. And we have begun the ramp-up of wells drilled in the first quarter again. In the first quarter, we drilled 64 net wells down from 122 net wells in Q1, 2017, as we look to balance activity, control drilling and completion and facility cost in our heavy oil areas. Our first quarter operating costs were $17.03 per barrel up from our Q4 2017 cost of $16.28 primarily a result of curtailing volumes. In our thermal properties, we took the same approach as in heavy oil and curtailed production volumes producing 111,851 barrels a day, down from the Q4 production of 124,121 barrels a day as we restricted production by approximately 9,700 barrels a day due to the widening differentials. At Kirby South, the first quarter production was approximately 37,000 barrels a day, up from Q4 of 35,000, which had a very good thermal efficiency of 2.5. As we talked about last quarter, we slowed the ramp up of what new wells and as well we completed plant maintenance activities in April. Our Q1 2018 operating costs were excellent at $9.13 per barrel including fuel, which is down 6% from Q4 of 2017. At Primrose, Q1 production was 71,875 barrels a day as we curtailed volumes there due to the widening differential. As we talked to last quarter, we were able to start a turn around here in April, and it is targeted completed -- to be completed by May 6. Our thermal operations at Primrose continued to be effective and efficient with $16.61 operating cost including fuel, as well it was impacted by curtailed volumes in the quarter. At Kirby North, the company's 40,000 barrel a day SAGD project, which is targeting first order, the first oil in Q1 [ 2018 ]. We had top-tier execution in the last quarter and very strong productivity was achieved. And as a result, the project is currently trending ahead of schedule and cost performance is on budget. Currently, over 75% of the central processing facility equipment has been delivered to site and SAGD drilling is nearing 25% completion. At Primrose, we have started drilling our highly profitable pad adds and it is currently trending on cost ahead of our targeted schedule of Q4 2019, which is targeted to add approximately 32,000 barrels a day. We were executing on our growth projects at Primrose and Kirby North, both are on track and with combined retarget at production capacity of over 70,000 barrels a day in 2020. The Q2 production guidance is 103,000 to 109,000 barrels a day. With the current pipeline restriction for both crude oil and natural gas, the company will be proactive in our actions to manage our assets and preserve long-term value. As such, volumes and some -- to some extent operating cost will be impacted. As an example, the total impact of our first quarter production was almost 17,000 barrels a day, which does impact our volumes and our operating cost efficiency. However, this quick action did preserve huge value for our shareholders as differentials have tightened once again. As a reminder, heavy oil only makes up 25% of our BOE volumes, but for every USD 1 dollar change in the differential, it is approximately $90 million of after-tax cash flow to our company. The key component to our long-life, low-decline transition is our world-class Pelican Lake pool, where our leading-edge polymer flood is driving significant reserves and value growth. Q1 2018 production was 63,274 barrels a day, down from the Q4 average of 65,654 barrels a day. Due to the fact we have started converting the existing water flood area on acquired lands to polymer flooding. We are on track and as we're targeting 63% to be under polymer flood by the end of 2018. As we convert more wells to the more viscous polymer, the injection is modified to improve conformance in the reservoir, which does impact our production rates in the short term but will maximize long-term value, another example, how Canadian Natural maximizes its value. At Pelican Lake, Q1 operating costs on a combined basis were $7.07 per barrel, up from $6.81 per barrel as we integrated the acquired asset and optimized polymer floods. With our low decline and very low operating cost at Pelican, it has excellent net back and recycle ratios. Q1, we drilled 7 net producers and 1 net injector by the end of the quarter. Currently, all the net producers are on production and performing as expected averaging 110 barrels per day per well. At our oil sands operations in the first quarter of 2018, we've produced a record 456,076 barrels as we had very good operational excellence at both sites. Our first quarter operating costs on a combined basis were very strong at $21.37 per barrel. As a result, we have lowered our annual operating cost guidance by $2 per barrel. At Horizon, the plant work began in April on the vacuum distillation unit. Furnaces which to complete the maintenance involve decoking of the BDU furnaces. During this maintenance activity, the company identified additional repairs required to ensure reliability. As a result, production will be restricted for an additional 15 days. The upgrader in mining operations continue at a reduced rate of approximately 145,000 barrels a day, and we target to resume full production on May 7. Annual oil sands mining and upgrading production guidance remains unchanged. We are continuing to review our enhancement capacity opportunities at Horizon. This engineering study is aimed at capturing process enhancements at Horizon, that allow us to take advantage of any potential creep capacity. We anticipate completing this study this quarter. At Horizon, our IPEP project is on track and is currently in the process of commissioning. As we talked last quarter, at both Horizon and Albian, we were taking a 3-pronged approach. First, understand the reliability enhancement opportunities we can complete. Secondly, with enhanced reliability, we can focus on further reducing our operating cost. Finally, complete our engineering work at both sites to increase production by enhancing or modifying equipment to gain creep capacity cost-effectively. We are seeing good results as we execute this strategy as operation has delivered record operating costs of $21.37 a barrel and record production of 400 -- approximately 456,000 barrels a day, a great accomplishment by our teams. The oil sands Q2 production guidance is 393,000 to 423,000 barrels a day, as well we have lowered our yearly operating cost to $20.50 from $24.50 per barrel. In summary, Canadian Natural is effective and efficient operator. We will continue to look for ways to become more effective and efficient in 2018. We are in a very strong and enviable position to be able to curtail natural gas or heavy oil volumes when pricing anomalies arise due to the Western Canada's pipeline constraint. This enhances our capacity to create value for our shareholders. We will continue to focus on safe, reliable operations. And enhancing our top-tier operations. We will continue to balance and optimize our capital allocation, delivering free cash flow, strengthening our balance sheet that Corey will highlight further in the financial review. With that, I will now turn it over to Corey.
Good morning, everyone, and thank you, Tim, for that comprehensive update on the company's operational performance in the first quarter of 2018. We also had strong financial performance during the quarter. Net earnings of almost $583 million were achieved in the first quarter of 2018 as compared with the $245 million during the same period of 2017. This improvement reflects higher crude oil production volumes and the effective and efficient operations that Tim spoke about as partially offset by lower heavy oil and natural gas pricing. Adjusted earnings for the quarter were $885 million as compared with $565 million for the prior quarter reflecting the same underlying trends. Quarterly funds flow for the corporation was a robust $2.3 billion, 42% higher than that recorded during Q1 of '17. First quarter funds flow was $884 million in excess of capital expenditures and dividends, with the majority of that free cash flow being allocated towards debt repayment, consistent with our prior commentary. During the first quarter, we permanently retired USD 1 billion in notes and repaid and canceled a further $275 million of term bank facilities, for total repayments of CAD 1.34 billion. At the end of the company -- at the end of the quarter, the company utilized available liquidity to settle the deferred AOSP acquisition payment to Marathon for $481 million, resulting in quarterly net debt repayments of $855 million. At quarter-end, available liquidity was a very strong $4 billion. Since completion of the AOSP acquisition last June, the company has reduced debt and deferred acquisition payments by about $1.9 billion, even while financing the completion of Horizon Phase 3 and the acquisition of the interest in Pelican Lake. Clearly, the company has transitioned into a very robust free cash flow enterprise with continually improving debt metrics. Based upon current strip pricing, we expect to exit the year in the range of 1.5x debt-to-EBITDA with debt to book capitalization in the range of under 35%. However, returns to shareholders are also a critical pillar of our strategy. Based upon the financial resilience and the operational robustness of the company's assets and the board's confidence in the business plans in the company. In March, they increased the regular quarterly dividend by $0.06 or 22%, effective April 1. Based upon our estimates of capital required to maintain production, we believe that our current dividend and production levels remain resilient to under USD 40 WTI, a rarity in our industry. This substantial increase in the dividend represented the 18th consecutive year of increases, also a rare achievement for any company in any industry. Additionally, subsequent to quarter-end, the company initiated share repurchases as part of its NCIB program, evidence of our commitment to deliver returns to our shareholders. The company will look to continue share purchases throughout the year on an opportunistic basis if it makes economic sense to do so. In closing, I believe that Canadian Natural continues to represent a sustainable, flexible and balanced E&P company with a high degree of resilience to commodity price volatility. And with that, I'll hand it back to you, Tim, for your closing comments.
Thanks, Corey. In summary, Canadian Natural has many advantages. Our balance sheet is strong and will continue to strengthen in 2018. We have a well-balanced, diverse and large asset base. A significant portion of our asset base is long-life, low-decline assets, which require less capital to maintain volumes. We have a balance in our commodities with approximately 50% of our BOEs in light oil and SCO, 25% in heavy and 25% natural gas, which lessens our exposure to the volatility in any one commodity. We can deliver sustainable free cash flow, which we are effectively allocating to our 4 pillars. Canadian Natural will continue to allocate cash flow to our 4 pillars to maximize value, strengthen our balance sheet continue with disciplined resource development, return to shareholders with the dividends increased 22% last quarter and potential share buyback, and finally, if we choose so, optimistic acquisitions. All driven by effective capital allocation, effective and efficient operations and by our teams delivering top-tier results. With that, I will now open the call to questions.
[Operator Instructions] Your first question comes from Neil Mehta from Goldman Sachs.
This is Emily Chieng on behalf of Neil. I just wanted to sort of hear about what was going on with the refinery? And sort of see what progress was like coming online and how that would sort of hedge your exposure to WCS pricing?
Emily, it's Steve Laut here. If you're talking about North West refinery, yes, the project is on track. As you know they're processing light oil since last fall, they're ramping up very successfully. It's been a very successful startup on the light oil portion of the refinery. They're just finishing off the last 2 units, was sort of the gasifier and the LC Finer. The LC Finer's mechanically complete and is starting commissioning. The gasifier will be complete here in the next 10 days. We expect that black oil will be coming into the unit probably in a regular basis sometime in July. But if you need more details, you should probably check with North West on their website.
Okay, great. And then the follow-up would be just on the share repurchase program. So you guys have done about $29 million worth of share purchases sort of this quarter. How should we think about the company's strategy in sort of doing so and what kind of run rate of repurchases should we expect going forward?
I think, as Corey said in his comments earlier, we're -- we'll be opportunistic and will do it when we see economic value. And as you can tell, we've heard us talked many times here in the call this morning about balancing our 4 pillars, balance sheet is important to us. Resource development, we don't see increasing that even with increasing free cash flow. Acquisitions, we don't have any gaps on our portfolio, so unlikely to see anything there. That leaves returns to shareholders, and as Corey pointed out, we have increased our dividend and have started to buy back some shares. For us, as you know, we're biased towards dividends because we believe that provides, I would say, enhanced discipline and how we return value to shareholders because they have to do it every year. But we're not averse to buying back shares, and we'll continue to look at it as we go forward. Corey, you want to add one thing?
Emily, it Corey. I just wanted to add one additional comment on North West Redwater, the second part of your question. As black oil then comes into the refinery, that will eventually take off about 80,000 barrels a day of heavy blend off the market -- off the pipeline. So that will have a positive impact as well in differentials as we move forward.
Is that directly integrated with CNQ's production or is it just coming off the market?
No, it is coming off the market, Emily.
Your next question comes from Paul Cheng from Barclays.
Just curious that given the way that how you look at the takeaway capacity situation in Canada. Will you sanction any new major projects until you get a clear sight that is going to be resolved?
The -- so your question is would we sanction a major project?
Right. Any major upstream production projects before you see a clear line of sight for the country's takeaway capacity being resolved?
Yes. I think, Paul, if you look at our whole portfolio going forward. We're looking to do smaller projects to add incremental production. And I think Tim talked about it. We've got Kirby North adding 40,000 barrels a day, Primrose, adding 32,000 barrels a day, and as Tim talked to you about the Paraffinic's expansion Horizon, the VGO expansion; those are smaller shorter-term projects. So in the $1.5 billion type project, capital spend and that gives us the amount of capital flexibility we look forward to going forward. At this point in time, we're fairly confident that takeaway capacity will be there as we need it. But as you know, we haven't sanctioned the Horizon projects at this point. Kirby North is going ahead, 40,000 barrels a day. Primrose is going ahead at 32,000 barrels a day, and we're confident we'll have takeaway capacity for that when those projects come on.
Right. Tim, I guess maybe let me rephrase myself. I mean, in addition to the projects that those -- that you mentioned you're already sanctioned and you are in the middle of funding them. So I don't expect you would stop. But I guess my question is that will you sanction any additional project given the takeaway capacity doesn't seems like there's a clear sight that's going to be resolved in any time soon?
I think we have vast asset base. We have lots of opportunities, and before we'd sanction any project we'd definitely do the EDS, and ensure that we can make a return for our shareholders. So the answer is really we haven't done any work to say any project would get sanctioned in the near term.
I think, Paul, what Tim's really saying is we're still on the EDS stage of those projects. We'll complete that EDS and before we sanction, we'll take a view of the market access. Our view when those projects come online we will have market access. We're pretty confident that up 3 pipelines, we think actually all 3 will get built, and we're confident in that approach. So, obviously, it takes time but it takes time for us to do the engineering and construction as well.
Steve, can you guys share that how much is your heavy oil or plant bitumen in the first quarter you were welling, and how much are you selling to the local market and then how much are you selling through the pipe down to the Gulf?
Most of our heavy oil is sold on the market and it's sold at Hardisty to buyers there. Where they take the oil is their choice, we don't actually know where it ends up. I suspect most of it ends up in the Midwest. Some will end up in the Gulf coast.
But you don't necessarily say they have any commitment on the well or the pipeline that distribute yourself?
At this point, no. Obviously we're committed to Keystone expansion, and we're committed on Trans Mountain.
And maybe this is either for Steve or for Corey, then on the balance sheet you want to strengthen, understandable. So how much more money that you want to put on the balance sheet before you will put more emphasize into the returning cash to the shareholder on the buyback?
Paul, I would argue, we actually have already done a lot in terms of returning cash flow to shareholders, dividend increased 22%, and we have to make sure that, that is sustainable throughout the commodity price cycle, so we don't want to get ahead of ourselves on that. And I think there's still a debate, whether we are really in $55 world or $65 world. So better to be cautious, you never want to reduce dividends, you want to make sure it is sustainable. Certainly, we have reinitiated the share buyback but your question in terms of the balance sheet strength, we are getting stronger each and every quarter as you can see on the trends over the last 3 quarters, and we don't have a firm target in terms of where we want to get to. I can tell you that for much of the last 10 years our debt-to-EBITDA has been running in that 1x range, and we've been towards the lower end of our book-to-cap ratio target range. What we believe is that provides dry powder and facilitates any of the other opportunities on the other 4 pillars, be it opportunistic acquisitions, resource development or increased buybacks. So there is nothing -- certainly nothing wrong with putting capital back into the balance sheet to create that opportunity set in that capacity.
I guess that the only comment I would make is that, yes, I think we all appreciate that the increase in dividend but comparing to at least at your largest competitor in the country, I think your return cash to shareholder has been lacking behind. The other company that has been picking up far more aggressive approach and has been well recognized, and we want to buy the market.
Your next question comes from Philip Gresh from JPMorgan.
Just one additional follow-up on the buyback. Corey, with your leverage target for the year-end. Is there a certain assumption being -- around buybacks that's embedded in that? I know you don't really keep much cash in the balance sheet as it is.
No, there's no embedded assumptions on that, Phil.
Okay. And then just in terms of the second quarter and the guidance there and the commentary around the shutting in of production that happened in the first quarter. I guess, my interpretation was today's differentials are -- have improved enough that you're going to bring some of that production back on line. But I wasn't entirely clear if there's still a certain amount of shut-in that would be embedded in that guidance for the second quarter. I'm thinking, obviously, there's the natural gas side but more specifically on the heavy side.
Yes, So Phil. It's Tim here. There is production that will not be incorporated into the guidance there because what's happening is we're in break up, so those heavy oil wells, we'll complete as we can. Obviously, we don't want to spend a lot of extra money moving equipment around in the breakup time. There's other areas, the ramp-up of Kirby has started. So it'll probably get to 40,000 barrels later in May. Other areas, it's literally the same. We're ramping production back up. It's not instantaneous on the heavy oil side. So we'll see very strong production late May, June.
Okay. So I guess if I look at your second quarter guidance versus your full year guidance, what you're basically saying is the differentials are in a place where you're comfortable ramping. It's just a timing factor but if you look at the second half, it implies a pretty healthy ramp up, I guess, is kind of what I'm asking and you're comfortable with that.
Yes. Notwithstanding differential changes as I indicated, we're very active and as I talked about last quarter, if we see widening differentials, we have lots of opportunities on our light oil side and we'd reallocate capital to those areas.
Okay. And my last question actually that was a little bit of a segue to the light side. We had actually seen some widening of the light differentials as well. And so I was wondering if some -- perhaps some -- perhaps it's pipeline allocation or other things going more towards the heavies that are tightening up the lights. But just curious if you have any view on that.
Really, a big part of it still seems to be tied up into this apportionment air barrel situation as far as we're concerned. Again, all of the oil, whether it's heavy or light, is moving. And so I think when you have these incidents or problems on the pipeline, it backs up oil and creates these anomalies. So we're very confident that it will sort itself out, but yes, there are -- with these pipeline constraints, there's a lot more volatility.
You're next question comes Roger Read from Wells Fargo.
If we could maybe go back to some of things you talked about early on in the presentation, the CO2 capture reduction in methane, reduction in water usage. Could you give us an idea of maybe what the operating cost savings or cash flow impacts of that have been? I mean, I understand it's a regulatory effect driving some of that, but generally speaking, companies also have discussed how it's led to better uptime performance as well as a lower cost structure.
Thanks, Roger. I think, that's -- you pointed out a very good point really because if you look at oil and gas companies, we're no different than any other company. Reducing our greenhouse gas emissions is important from an environmental point of view and it also affects operating cost. The biggest component -- one of the biggest components of our operating cost is fuel and that's burning fuel for heat, another high -- electricity and things to drive horsepower, that generates greenhouse gases. So if we can reduce our fuel consumption, we reduce greenhouse gases and reduce our operating cost. So it has had an impact, I don't have that number off the top of my head exactly what the impact is. But obviously, you can see, particularly, at Horizon. We've done an outstanding job here of dropping the operating cost overall. And part of that is due to the fact that we're burning less fuel, and we're more reliable, and more effective and efficient.
Really at both sites.
Yes.
We're really -- on the efficiency, we were looking ways to reduce our fuel and really it's all embedded into our operating cost, which you can see, we're very focused on reducing and so there is some impact.
Okay, great. And then maybe something a little more specific just to Q1. And I'm sure some of this is related to the curtailed production but relative to our expectation, some of the cost per barrel were higher, and the one that really, I just want kind of wanted to sound out with you, the transportation and blending in the E&P space, also in the OSM, it was higher than our number but it wasn't higher really than the recent trend. I just wanted to make sure kind of what's driving that. Is it the obvious issues here or is there something you can do to adjust for that in coming quarters just some of the new production with designated pipeline capacity moderate that cost trend some?
Yes. So what you're seeing in the first quarter is pretty much all related to this differential issue. As the differentials blew out in the first quarter, that's embedded into our blending transportation cost. So as -- in the second quarter, these have really tightened in, I think it's in the $15 range, which is very good and as we kind of figured it would. But you'll see that change into Q2.
You're next question comes from Amir Arif from Cormark Securities.
First question is around the debottleneck opportunities you have at Horizon. So stage 1 seems like it's just on reliability. But for stage 2, the 5,000 to 15,000. Is that -- is there a timeframe for that, Steve?
The -- it's Tim here. We're still working through the engineering piece. We should have that by the end of May here. That's -- until we actually see it, see what they need to do, I can't give you a cost or a real good time yet.
Okay. But would that 5 to 15 be on upgrading or like synthetic or is that bitumen production?
No, that is upgraded SCO.
That is upgraded, okay. And then the other 2 work that you're looking on the Paraffinic froth Treatment and VGO, are those bitumen volumes or those synthetic as well, 30,000 to 40,000?
No. That would be with bitumen.
Okay, both of them?
On the Paraffinic Froth? Yes.
Yes, and then the VGO was bitumen?
VGO was an [ intermediate ] product, Amir. So it's somewhere between light oil and heavy oil. And likewise on the Paraffinic, it's probably more like a medium oil price that we'll be getting for that Paraffinic product.
Okay, sounds good. And then a question just on the shut-in volumes. Just out of curiosity in terms of how you decide to shut in thermal versus primary heavy. Just would love to hear some thoughts in terms -- because I would've thought the thermal just it's -- I don't know if there are any reservoir issues of trying to shut that down or bring it back up versus primary, which probably offers more flexibility?
There is pros and cons on both. What we find at least with the thermal side, we can modify our steaming profiles and therefore, hold back oil to some extent a little bit easier whereas in heavy oil, it takes basically 60 to 90 days to ramp back up. So there's that pros and cons on both sides but we kind of look at -- to the areas, see what can be done cost-effectively without impacting long-term value.
Okay. And then just a final question on the gas shut-in, it seems to be a smaller percentage relative to some of the shut-ins on the heavy oil side. Is that just because of the internal gas consumption you have in the marketing? Or is it the cost structure?
It's more to do with the cost structure. With the $14 million that we did shut in, we're being proactive but also for certain areas where the access was poor, we didn't really do any maintenance activities on those areas. So that when they froze off in the winter, they just stayed down. So it's just be primarily a cost function in some areas.
Okay, and sorry, one final question if I may. Just on the -- you've talked before and again this quarter about potentially allocating more capital to light oil from the heavy oil. At what differential does or what light oil -- yes, I guess, differential does that make sense for you to start making that shift?
Boy, that's a real tough question because at the same time as I think it was Phil pointed out that the differentials on the light oil are widening as well. So we look at it every week, looking ahead what's going on in the market. We have the inventory available, so it's just a matter of pulling the lever to understand what's going on with the market. So it's just straight capital allocation, and we make sure that we're allocating it appropriately.
Your next question comes from Phil Skolnick from Eight Capital.
Could you just talk a little bit more about the whole air barrels issue, and what are your thoughts in terms of -- can you quantify what the impact was in Q1 and -- or perhaps how much of that -- apportionment that we saw was due to air barrels and also about the efforts that are being done because there's been headlines talking about trying to do some tracking and things like that as well.
Phil, Steve here. I think really what we've got here was -- we've talked about it before, it was an anomaly in the first quarter with the backup in Keystone. Just the way the sort of guidelines and rules on apportionment are set up, it creates some, sort of, I would say dysfunction in the system and it creates issues in actually getting barrels to the pipe because of people's reaction to restricted capacity. As I think we've talked before, actually in the first quarter when differentials were very, very high we actually had at times 50,000 to 125,000 barrels a day of space on the Enbridge pipeline system that actually wasn't being utilized, mainly because it was just so many change orders coming in with apportionment that it was difficult to actually make the batches work physically on the pipe. So it's really become, I think, the producers, the pipeline companies, the feeder pipes and the terminals have now started to work more closely and to understand how to work the system and the rules that are in place right now to basically be more effective and efficient and take up that space that's been on the pipe. I think that's been done and I think you can see the differential is narrow because of it. So that's -- it's really just a be more effective and efficient in how that portion system works.
Okay. And just another quick question. Just with all the efforts of debottlenecks in the Paraffinic expansion. I guess is it safe to assume that at some point in time, your overall mining OpEx would be sub-$20 a barrel, is it crazy to think it could be $2 less than that or $3 less than that?
I don't think it's crazy. We're always looking for opportunities to be more efficient and effective and as you know, on the mining oil sand side, there's a lot of fixed cost. So every barrel we can get extra through that facility hits the bottom line very nicely.
So, I guess, then on -- just on that -- it's my last follow-up. Is that because, like, do you have to add any labor, I'd imagined you don't for the debottlenecks but how about for the Paraffinic's expansion you have to have add any laborers for that -- essentially with that when that comes online?
Yes, there would be a little bit of labor and a little more trucks but that's really it. So it can be very cost effective.
Your next question comes from Joe Gemino from Morningstar.
Great. I wanted to clarify, this comment that was made earlier. Did you say you have committed capacity on the current Trans Mountain or you have commitments for the Trans Mountain expansion?
We have commitments on the Trans Mountain for 75,000 barrels a day, expansion.
Expansion, yes.
Expansion, okay. How many do you have in Keystone XL if you're able disclose that?
150,000.
Great, I appreciate that. And one of the topics that was talked about earlier was not sanctioning any major projects unless there's some clear sight into the pipeline projects. If the pipeline projects continue to get delayed, do you see yourself in the situation with Kirby or Primrose where you would potentially delay construction and bringing on the production online in the timeline that you outlined?
No, not on those projects. And just for clarification, it was really targeted at the bigger projects where we're doing engineering and design piece. So those projects are long-term projects anyway. So obviously, if we were to do one, it would be sanctioned by the Board and it'd be announced. But these smaller projects are just nice growth projects that we can layer on into our asset base.
Your next question comes from Mike Dunn from GMP FirstEnergy.
I noticed you've stopped disclosing the Horizon and AOSP financial separately. But can you just maybe talk to qualitatively how the volumes looked there, I guess, at Horizon relative to the -- to your last guidance there in early March? And did you average less than $20 in Q1 at Horizon for OpEx? I was suspecting you might and the total number suggests you might have.
So Mike we're disclosing everything as a unit now because that's how we operate that's -- we capture the synergies between the 2, so it's just the right way to do it. But yes, your assumption is probably correct; you can back up the numbers.
And then, if I may, you usually don't talk about reasonably small acquisitions but it looked like there might have been a couple of hundred million dollars of net acquisitions in the quarter. Can you say -- is that mostly liquids rich gas or oil or what you can tell us about that?
It was -- it's a very small acquisition under that $200 million. And it's just essentially cleaning up partners and liquids.
Your next question comes from Fai Lee from Odlum.
It's Fai here. I'm just wondering about this full year natural gas production guidance. It seems to imply that you're going to have quite a big increase compared to the first half of 2018 and to the back half. I'm just wondering what the pathway there is, if it's kind of dependent on Pine River operating at capacity or there's something else going on to get to that level, and is it dependent on where gas prices fall out in the back half of the year?
Yes, it depends on gas prices as I've indicated. If we see very low prices, we obviously will shut in volumes. Yes, it is predicated on Pine River where we're working with the party there. It's operating at 1 train we have production capacity at approximately at 150 million a day. So we just have to work together there and figure that piece out. And the third point is, we do have some very good drilling prospects here that could add later in the year.
And your next question comes from Phil Gresh from JPMorgan.
Actually my question was the same one on Horizon cost.
There are no further question at this time. I turn the call back over to Mark Stainthorpe.
Thanks, Christina and thank you everyone for attending our conference call this morning. Canadian Natural's large, well diverse asset base continues to drive significant shareholder value. The impact of our long-life, low-decline assets makes Canadian Natural more robust, generating growing and sustainable free cash flow while at the same time delivering increasing returns on capital. This combined with effective capital allocation and strong teams to execute contribute to achieving our primary goal of maximizing shareholder value. If you have any further questions, please give us a call. Thank you again, and we look forward to our second quarter conference call in early August. Bye for now.
This concludes today's conference call. You may now disconnect.