Canadian Natural Resources (CNQ) Q1 2018 Results - Earnings Call Transcript
Canadian Natural Resources Ltd. (NYSE:CNQ) Q1 2018 Earnings Conference Call May 3, 2018 10:00 AM ET
Mark Stainthorpe - Vice President, Finance, Capital Markets
Steve Laut - Executive Vice Chairman
Tim McKay - President
Corey Bieber - Chief Financial Officer
Emily Chieng - Goldman Sachs
Paul Cheng - Barclays
Phil Gresh - JPMorgan
Roger Read - Wells Fargo
Amir Arif - Cormark Securities
Phil Skolnick - Eight Capital
Joe Gemino - Morningstar
Mike Dunn - GMP FirstEnergy
Fai Lee - Odlum Brown
Good morning, ladies and gentlemen. And welcome to the Canadian Natural Resources’ Q1 ’18 Earnings Conference Call. After the presentation, we will conduct a question-and-answer session. Instructions will be given at that time. Please note that this call is being recorded today, May 03, 2018 at 8:00 AM 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 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 non-existent 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 to hold 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 billion to $4.6 billion at the strip in 2018. In addition, we're 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 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. While we’re 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 Northwest 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 of 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 use using our oil sands mining and upgrading, significantly reducing fresh water 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’ve made significant progress in reducing our green house gas emissions and there is a pathway to reducing our greenhouse gas emissions intensity from our oil sands production to levels that are well below the average global oil produced. For reference today at Horizon where we recognize our carbon cash initiatives, our mission intensity is only slightly higher 5% than the average for global oil.
The impact technology and effective operations has on lowering Canada’s oil sands greenhouse gas emissions intensity and our ability to leverage technology to continue to reduce the air intensity is generally not well understood. Many external opinions of oil sands operations are based on outdated data from many years ago. A 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 the oil sands will have the lowest environmental footprint and as 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 an offering cost from over $40 a barrel to roughly $16 US a barrel. And importantly, there are no reserve replacement costs; a fundamental factor in Canadian Natural’s strategy to invest in the oil sands and be a leader in research and development. A critical plan in Canadian Natural’s 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 four pillars of cash flow allocation, balance sheet strength, returns to shareholders, reserves development and opportunistic acquisitions.
How we balance our 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 four 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 1.5 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 all 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 staff composition 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 2018 first quarter results. Starting with natural gas, our first quarter production of 1.614 Bcf per day was slightly down from our Q4 2017 production. In the first quarter, third-party plant ran reliable with one train operation where we averaged 78 million cubic feet per day versus the 98 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 as we factored into our Q2 forecast.
We are proactively working with the party to determine the next steps for the plant. Due to low 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, work over activities related to natural gas. Overall, our first quarter natural gas production from North America was 1.547 Bcf per day and first quarter operating costs of $1.31, which is up from Q4, 2017 of $1.26 primarily due to us proactively reducing volumes.
In Q1, we successfully drilled five net gas wells one 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 water flood, drill strategic wells and complete final property acquisitions. Our first quarter operating costs were 1,560 barrel, reflecting higher fuel, power and service costs. 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 currently have 19 wells on production in the Wembley area; one net Montney well is currently producing about 740 barrels a day; in Southeast Saskatchewan, nine net wells that currently averaging 125 barrels per day, six wells drilled in Southern Alberta are currently averaging 120 barrels per day per well; finally, in Northwest Alberta, three net wells are currently producing approximate 145 barrels per day per well. All the wells are performing as expected. At Tower, our [indiscernible] facility construction is on time and on budget as we target start up 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 costs at Côte d’Ivoire was $10.14 per barrel. The drilling rig is now on root 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 and the Ninian South platform in December, which impacted the fourth quarter.
Operational improvements are continuing in the first quarter. Our operating costs in North Sea are down 2% from Q4. With positive tax changes the UK government enacted a couple of years ago, we continue to drill wells in the North Sea. We had one net well drilled by the end of the quarter, and is currently producing at a flush rate of over 2,000 barrels a day. With the whole 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 anomaly in the heavy oil market that we felt it 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 defer completions, re-completions 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 completions, re-completions, workovers where access allowed 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 looked at balanced activity, controlled drilling and completion and facility costs in our heavy oil areas. Our first quarter operating costs were $17.03 per barrel, up from our Q4 2017 costs of $16.28, primarily result of curtailing volumes.
In our thermal properties, we took the same approach 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 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 was down 6% from Q4 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 turnaround here in April and it is target to complete it -- to be complete it by May 6th. Our thermal operations at Primrose continue to be effective and efficient with $16.61 operating costs, including fuel, as well it was impacted curtailed volumes in the quarter.
At Kirby North, the Company’s 40,000 barrel a day SAGD project, which is targeting first oil in Q1 ’20, we had top tier execution last quarter and very strong productivity was achieved. And as a result, the project is currently trended ahead of schedule and cost performance is on budget. Currently, over 75% of essential processing facility equipment has been delivered at site, and SAGD drilling is nearing 25% completion.
As Primrose, we have started drilling our highly profitable pad add and 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 that we target 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 restrictions 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 to some extent operating cost will be an impact. 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 only makes up 25% of our BOE volumes, but for every $1 US 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 a 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 land to polymer flooding. We were on track and as we’re targeting 63% to the under polymer flood by the end of 2018.
As we convert more wells to the more viscous polymer injections modified improved performance in the reservoir, which does impact our production rates in the short-term but will maximize long-term value. Another example is how Canadian Natural maximizes volume. 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 assets and optimized polymer flood.
With our low decline, very low operating cost at Pelican, it has excellent net back and recycle ratios. In Q1, we drilled seven net producers and one 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 VDU furnaces.
During this maintenance activity, the Company identified additional repairs required to ensure reliability. As a result, production will be restricted for additional 15 days. The upgrader and mining operations continue at a reduced rate of approximately 145,000 barrels a day and we target to resume full production on May 07th. Annual oil sands mining and upgrading production guidance remains unchanged.
We are continuing to review our enhanced 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 the 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’re taking a three pronged approach; first, understand the reliability enhancement opportunities we can complete; secondly, with enhanced reliability, we can focus on further reducing our operating costs; finally, complete our engineering work at both sites to increase production by enhancing or modifying equipment to gain creep capacity cost effectively.
We’re receiving good results as we execute this strategy as operations delivered record operating costs of $21.37 a barrels record production of approximately 456,000 barrels a day, a great accomplishment by our team. 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 to $24.50 per barrel.
In summary, Canadian Natural is an effective and efficient operator. We will continue to look for ways to become more effective and efficient in 2018. We’re in a very strong and enviable position to be able to curtail natural gas and heavy oil volumes when pricing anomalies arise due to the Western Canada’s pipeline constraints. 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 Cory will highlight further in the financial review.
With that, I will now turn it over to Cory.
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 compared to $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 US$1 billion in notes and repaid and cancelled a further $275 million of term bank facilities for total repayments of CAD$1.34 billion. 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 reduction 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 interests 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 1.5 times debt to EBITDA with debt to book capitalization in the range of under 35%.
However, we 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, we increased the regular quarterly dividend by $0.06 or 22% effective April 1st. Based upon our estimates of capital required to maintain production, we believe that our current dividend and production levels remain resilient to under US$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 purchases as part of its MCIB 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 resilience to commodity price volatility. And with that, I will 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 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% in 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 four pillars. Canadian Natural will continue to allocate cash flow to our four pillars to maximize value; strengthen our balance sheet; continue with disciplined resource development; return to shareholders with dividend increase to 22% last year and potential share buybacks; 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. Your line is open.
This is Emily Chieng on behalf of Neil. I just wanted to hear about what was going on with the refinery and see what progress was coming online, and how that would hedge your exposure to WCS pricing?
Emily, it’s Steve Laut here and if you’re talking about Northwest refinery?
Yes, the project is on track. As you know, they are processing light oil since last fall. They are ramping up very successfully. It’s been a very successful start up on the light oil portion of the refinery. They are just finishing off the last two units, so the gasifier and the LC Finer. The LC Finer’s mechanic is complete and is starting commissioning. The gasfier will be complete here in the next 10 days. We expect that black oil will be coming into the unit probably in regular basis sometime in July. But if you need more details, you should probably check with Northwest on the Web site.
And then the follow up would be just on the share repurchase program. So you guys have done about $29 million worth of share repurchases that are this quarter. How should we think about the Company’s strategy and doing still and what run rate of purchases should we expect going forward?
I think as Corey said in his comments earlier, we’ll be opportunistic and we’ll do it when we see economic value. As you can tell and you heard us talk many times here in the call this morning about balancing our four pillars, balance sheet support to us resource development where we don’t see increasing that even with increasing free cash flow. Acquisitions, we don’t have any gaps in our portfolios so unlikely to see anything there. That leaves return 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 in how we return value to shareholders, because it has 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, do you want to add anything?
Emily, its Corey. I just wanted to add one additional comment on Northwest red water, the second part of your question. As black oil comes into the refinery that will eventually take off about 80,000 barrels 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 was it just coming off the market?
No, it’s coming just off the market, Emily.
Your next question comes from Paul Cheng from Barclays. Your line is open.
Just curious that given the way 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?
Your question is would we sanction a major project?
Any major upstream production projects before you see a clear margin site for the country takeaway capacity being resolved?
I think, Paul if you look at our full portfolio going forward, we’re looking to do smaller projects to add incremental production. I think Tim talked about it, and we’ve got Kirby North, I think 40,000 barrels a day, Primrose at 2,000 barrels a day and as Tim talked here about both Paraffinic's expansion Horizon, the Ouija expansion. Those are smaller shorter term projects, so in the 1.5 billion type projects 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 of 2,000 barrels a day and we’re confident we’ll have takeaway capacity for that when those projects come on.
Tim, I guess maybe let me rephrase myself. I mean in addition to the projects that those that you mentioned you already sanctioned and you end up in the middle of funding them. So I don’t expect you will stop. But I guess my question is that will you sanction any additional project given the takeaway capacity doesn’t seem that there is a clear phase going to be resolved in any time soon?
I think we have a vast asset base, we have lots of opportunities. And before we would sanction any project, we definitely do the EDS and ensure that we can make return for our shareholder. 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 is really saying is we’re still in the EDS stage of those projects, and we’ll complete that EDS. And before we sanction, we’ll take a view of the market access. Our view on those projects come online, we’ll have market access, we’re pretty confident that up to three pipelines, we think actually all three 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 bitumen in the first quarter you’re welling, and how much you’re selling to the local market? And how much you’re selling through the pipe down to the Gulf?
Most of our heavy oil is sold on a market as sold at Hardisty, to buyers there. Where they take 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 there should be?
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. On the balance sheet, you want to strengthen and it’s 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 shareholders on the buyback?
Paul, I would argue. We actually have already done a lot in terms of returning cash flow to shareholders, the 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 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 three 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 1 times 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 four pillars, be that opportunistic acquisitions, resource development or increased buybacks. So there is nothing wrong with putting capital back into balance sheets to create that opportunity set and 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 that your largest competitor in the country, I think your return cash to shareholder has been lacking behind the other company that has been picking a far more aggressive approach and has been well recognized. And we want that by the market. Thank you.
Your next question comes from Phil Gresh from JPMorgan. Your line is open.
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 on the balance sheet as it is?
No, there is no embedded assumption on that, Phil.
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 that today’s differentials have improved enough that you are going to bring some of that production back online. 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. And I am thinking obviously there’s natural gas side but more specifically on the heavy side.
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 will complete as we can. Obviously, we don’t want to spend a lot of extra money moving equipment around in the break up time. There’s other areas the ramp up of Kirby has started. So it will probably get to 40,000 barrels later in May. Other areas, it’s literally the same. We’re ramping production backup. It’s not instantaneous on the heavy oil side. So we will see very strong production late May, June.
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 what I am asking, and you are comfortable with that.
Notwithstanding differential changes, as I indicated, we’re very active. And as I talked on 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.
And my last question actually that will go over to segue to the light side. We had actually seen some widening of the light differentials as well. So I was wondering if 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 barrels situation as far as we’re concerned. Again, all 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 is a lot more volatility.
Your next question comes from Roger Read from Wells Fargo. Your line is open.
If we could maybe go back to some of the things you talked about early on in the presentation. The CO2 capture reduction, methane reduction, 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 regulatory effect driving some of that. But generally speaking, companies also have discussed how it’s led better uptime performance, as well as a lower cost structure.
I think that’s point 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 also effects operating costs. The biggest component -- one of the biggest components of our operating cost is fuel, and that’s burning fuel for heat, and other electricity and things to drive horsepower. That generates greenhouse gas. So we 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 a Horizon, we’ve done an outstanding job, you heard 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.
We were really -- on the efficiency, we were looking for ways to reduce the 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.
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 expectations, some of the costs per barrel were higher, and the one that really -- I just 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 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 trends.
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. And I think it’s in the $15 range, which is very good and as we figured it but you’ll see that change into Q2.
Your next question comes from Amir Arif from Cormark Securities. Your line is open.
First question is just around the debottleneck opportunities you have at the Horizon. So stage 1 seems like it’s just on reliability but for the first stage 2, probably the 5 to 15,000. Is there a time frame for that, Steve?
Tim S McKay
We’re still working to 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.
But would that 5 to 15 be on upgrading or like synthetic, or is that bitumen production?
Tim S McKay
No, that is upgraded SCO.
That is upgraded, okay. And then the other two work that you’re looking at on the Paraffinic Froth Treatment and VGO. Are those bitumen volumes or are those synthetic as well from 30,000 to 40,000?
Tim S McKay
That would be with the bitumen.
Both of them?
Tim S McKay
On the Paraffinic Froth, yes.
And then the VGO was bitumen?
Tim S McKay
Our VGO is an [indiscernible] product, Amir. So it’s somewhere between light oil and heavy oil and then likewise on the Paraffinic it’s probably more like a medium oil price that will be getting to that Paraffinic product.
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 of -- because I have would have thought that thermal -- I don’t know if there’re any reservoir issues of trying to shut that down or bring it back up versus primary, which probably offers more flexibility?
Tim S McKay
There’s pros and cons on both. What we find at least on 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 look at the areas see what can be done cost effectively without impacting long-term value.
And then just a final question on the gas shut, and 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 and the marketing, or it is the cost structure?
Tim S McKay
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 would just be primarily a cost function in some areas.
And just one final question, if I may, I know you’ve talked before and then again this quarter about potentially allocating more capital to light oil from the heavy oil. What differential does -- or what light oil gets differential does that make sense for you to start making that shift?
Tim S McKay
That’s real tough question, because at the same time as I think it was Phil pointed out that the differentials are on the light oil are widening as well. So we look at it at every week. Looking ahead what’s going on in the market. We have the inventory available, so it’s just a matter 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. Your line is open.
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 does that -- the portion that we saw due to air barrels? And also about the efforts that are being done, because there has been headlines talking about trying to do some tracking and things like that as well. Thanks.
I think really what we’ve got here was we talked before was an anomaly in the first quarter with the backup in Keystone. Just the way the guidelines and rules and apportionment are set up, it creates some function in the system and it creates issues on gas you are 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 differentially are very, very high we actually had 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 was difficult to actually make batches work physically on the pipe.
So it’s really become -- I think the producers, the pipeline companies, the Peter pipes. And the terminals have now started to work very 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 differentials narrow because of it. So it’s really just a -- be more effective and efficient in how apportioned system works.
And just another quick question, just with all the efforts the 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 bucks a barrel. Or 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 is a lot of fixed cost. So every barrel we can get extra to the facility hits the bottom-line very nicely.
So I guess then just on to my last follow-up. Is that because -- do you have to add any labor? I mean I’d imagine it’ll for debottleneck, but how about for the Paraffinic expansion. Do you have to add any labors for that expansion 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. Your line is open.
I wanted to clarify just a comment that was made earlier. Did you say you have the 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.
And maybe you have Keystone XL if you are able to disclose that?
Great, I appreciate that. And one of the topics that was talked about earlier was not sanctioning any major projects unless there is some clear site into the pipeline projects. If the pipeline projects continue to get delayed, do you see yourself in a situation with Kirby or Primrose where you would potential 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 anyways. So obviously, if we were to do one it would be sanctioned by the Board and it would be announced. But the smaller projects are just nice growth projects that we can layer on into our asset base.
Your next question comes from the line of Mike Dunn from GMP FirstEnergy. Your line is open.
I noticed you’ve stopped disclosing the horizon and AOSP financial separately. But can you just maybe talk to qualitatively how volumes looked there, I guess at Horizon relative 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 -- the total number total number suggests you might have? Thank you.
So Mike, we’re disclosing everything as you read now, because that’s how we operate that’s recapture the synergies produced. 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 looks like there might have been a couple of hundred million dollars of the acquisitions in the quarter. Can you tell was that mostly liquids rich, gas or oil, or what can you tell us about that?
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 Brown. Your line is open.
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 into the back half. I am just wondering what the possibility there is if it’s dependent on operating capacity or there’s something else going on to get to that level. And is it dependant on where gas prices follow 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 s operating at one train. We have production capacity at approximately 150 million today. So we just have to work together there and figure back this 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 JP Morgan. Your line is open.
Phil M. Gresh
Actually my question was the same on Horizon cost, so thanks for that color.
There are no further questions at this time. I’ll 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 current 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.
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