Edited Transcript of HSE.TO earnings conference call or presentation 27-Feb-20 4:00pm GMT

U.S. crack spreads were also very weak, resulting in an impact of about $120 million. The Keystone Pipeline outage in November and narrower location differentials negatively affected our infrastructure and marketing segment by about $50 million. And we also incurred $74 million in severance costs related to staff reductions that took place in October. Looking at the annual result, we wrote off $2.3 billion in after tax impairments and other charges in the fourth quarter. And Jeff will address this in a little more detail in his section.

On the operations front, we made good progress in 2019 on safety. This included reductions in our total recordable and lost time injuries and Tier 1 process safety incidents. This will drive more consistent operational performance as we accelerate our transformation to a high reliability organization. We have set a target to become top quartile in process and occupational safety by the end of 2022 as measured against global benchmarks. The progress we’ve made on these metrics in 2019 gives us confidence that we are well on our way to achieving that goal.

And as a safety-focused employer and as a business with operations in China, I’d like to talk about how we are responding to the virus outbreak. After the extended break for the Chinese New Year, our workers have returned to their offices. Our Asia Pacific facilities have continued to operate under strict health protocols throughout this period and we are continuing to monitor developments in all regions in which Husky operates to ensure the well-being of our staff and their families.

In terms of how this is impacting our Asia Pacific volumes, typically our buyers take reduced volumes from the Liwan Gas Project at this time of year due to lower demand related to the Chinese New Year. This shortfall is usually offset later in the year when they take more than their contracted rate. However, given the extended holiday because of the precautions surrounding the virus, demand for Liwan gas was lower for longer than usual. In the past few days, however, we have seen an uptick in demand to full rates.

Overall, we made good progress in 2019 on the critical business milestones that we set out for the year. This was despite headwinds created by the government-mandated curtailments in Alberta and a slower-than-anticipated return to full volumes in the Atlantic region.

Production of 290,000 barrels of oil equivalent per day was at the bottom end of our guidance. The annual capital expenditures were also at the low end of our guidance. And we maintained the strength of our balance sheet and stayed within our debt targets.

Annual funds from operations were $3.3 billion compared to $4 billion in 2018. This reduction is due to the following factors. The extended maintenance outages at the partner-operated Toledo Refinery, the extended shutdown at Lima that I spoke about earlier, the slow startup of the SeaRose in the Atlantic region, which is now at full rates, the Alberta quotas and, of course, lower commodity prices when compared to 2018.

Touching on a few project highlights from 2019, starting with the Integrated Corridor. Our latest Lloyd thermal project at Dee Valley came online ahead of schedule in the third quarter, and we continued to advance 3 near-term thermal developments – Spruce Lake Central and Spruce Lake North will start up later this year, Spruce Lake East will follow in 2021. All 3 projects are making good progress and are on schedule and on budget.

In the Downstream, at Lima all the units are now running and we expect to ramp up to full crude rates by March. Heavy crude processing capacity has increased to 40,000 barrels a day, up from 10,000 barrels a day, providing the crude supply optionality that will lead to improved margins over time. We also closed the sale of the Prince George Refinery in the fourth quarter, which has further focused our Integrated Corridor business.

In the Offshore business, starting with the Atlantic, production at the 3 White Rose drill centers was restarted in the first half of the year and the remaining 2 drill centers were brought online in August. The White Rose project is now 57% complete and we’re continuing to see good project execution and productivity with first oil by the end of 2022.

In Asia, construction of the 29-1 field at Liwan continues to progress and we are on pace for first gas in the fourth quarter of this year.

As these projects come on stream, they’ll further grow our funds from operations. At the same time, their completion allows us to reduce our capital spending.

When we released our capital guidance a couple of months ago, we said we would reduce spending by $100 million in 2020 and a further $400 million in 2021, compared to our previous plan that we had set out in Investor Day earlier that year. We remain committed to maintaining this capital discipline with a priority on returning value to our shareholders through a strong dividend while investing for margin growth.

We are also advancing our work on carbon targets and will update you on these later this year.

Now I’ll turn the call over to Jeff to review our Q4 financial results.

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Jeffrey Ryan Hart, Husky Energy Inc. – CFO [4]

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Thanks, Rob. I’ll start with the asset impairments and other charges that we booked in Q4. The impairments were largely driven by lower commodity price assumptions and a reduction of future capital investments in the Canadian Upstream business. And they primarily impacted the book value of our Upstream assets, including Sunrise, the White Rose field and gas resource plays in Western Canada. The other charges included asset derecognition at the Lima Refinery associated with redundant equipment following the completion of the crude oil flexibility project. Excluding the impairments and other charges, we had net earnings of $5 million in the quarter.

In regards to net debt, we exited the year at $3.7 billion, and total liquidity is now $5.7 billion in cash and unused credit facilities.

In terms of reserves, total proved reserves before royalties at the end of 2019, were 1.4 billion BOE, about the same as the previous year. And with the deferral of capital programs at Sunrise and Ansell, we had a probable reserves reduction of 395 million BOE. The average 3-year proved reserves or placement ratio was 166% excluding economic factors. And the proved reserves life index remains at 13.5 years.

Turning now to the fourth quarter. Funds from operations were $469 million compared to $583 million in the year-ago period. This was mostly due to the lower U.S. crack spreads and the extended Lima shutdown.

Our operating costs at the refinery are largely fixed and there was little revenue contribution in the quarter. As a result, the U.S. Refining segment had a negative operating margin of about CAD 170 million. And for context, the U.S. Refining segment posted an average operating margin of CAD 190 million per quarter in the first 3 quarters of 2019. This means the delta in the quarter was about $360 million. And as mentioned earlier, we booked $74 million in severance costs.

Turning to Upstream operations. Overall production was 311,000 BOE per day in Q4, compared to just over 304,000 BOE per day in Q4 of last year. These barrels received an average realized price of about $46 per BOE compared to about $25.50 in the prior year quarter. The Upstream operating netback averaged $27.48 per BOE compared to $9.42 a year ago, reflecting higher realized pricing for heavy oil. Upstream per unit operating costs were $15.25 per BOE compared to $13.75 per BOE at this time last year, due in part to higher energy costs and lower production.

The Offshore business delivered an operating netback of $61 per BOE, and the operating margin in the Infrastructure and Marketing segment was $12 million compared to $175 million in Q4 of 2018. And this was largely because of the tighter location differentials and the Keystone Pipeline outage in Q4 2019.

The U.S. refining and marketing margin was USD 7.85 per barrel of crude throughput, which included a negative pretax FIFO impact of USD 0.24 per barrel.

We also realized $116 million in pretax insurance proceeds related to business interruption at the Superior Refinery.

Capital spending in Q4 was $894 million compared to $1.3 billion at this time last year. This includes rebuild costs at Superior of $48 million, which are expected to be largely recovered from insurance.

Looking forward, this year is expected to mark a step change in our 5-year capital program. By the end of this year, we will have started up the 29-1 field and the Spruce Lake North and Spruce Lake Central thermal projects. In addition, the bulk of our spending at West White Rose will be behind us as the project advances toward first production around the end of 2022.

However, we expect a few headwinds in Q1. This includes the potential for a slower recovery in gas demand in China related to the virus. And at Lima, we had an average throughput of 105,000 barrels per day in January. We’re now at about 140,000 barrels today as we continue to run off intermediates. We expect throughput to increase, but we will still run off intermediates through March. Also, production at the partner-operated Terra Nova FPSO remains suspended.

Just a reminder that beginning next quarter we will be adjusting the way we report our financial results to reflect the Integrated Corridor and Offshore segments. This will better align our reporting to the 2 businesses and provide for greater transparency and ease of modeling.

Finally, our priority remains maintaining capital discipline and returning value to our shareholders through sustainable dividend increases. We are maintaining the strength of our balance sheet. On top of that, we are continuing our strategic review of the commercial fuels and retail business. We are also continuing to pursue other opportunities to further reduce capital and expenses. This will see us through to next year when we expect to reach a positive free cash flow inflection point. For this quarter, the board is maintaining the current level of dividend at $0.125 per common share.

And now I’ll pass the call over to Robert W. Symonds.

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Robert W. P. Symonds, Husky Energy Inc. – COO [5]

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Thanks, Jeff. Overall, thermal production from Sunrise, Tucker and Lloyd averaged about 138,000 barrels a day net to Husky in Q4. This compares to 133,000 barrels a day in the same period last year. We have set a target to reach 90,000 barrels a day of Lloyd thermal production by the end of 2019, and we met this with a December average of 92,000 barrels per day.

In the area of thermal operating costs and emissions intensity, we’ve been active on several fronts. Artificial Intelligence pilot program to enhance steam utilization at the Sandall project has been successful. We’ve seen reductions in steam requirements of approximately 10%. Concurrently, production has improved around 2%, meaning greater operating profitability with less environmental intensity. This program is now being extended to Edam, with plans to roll it out to all of our producing projects in Saskatchewan later this year.

We also have pilots underway at Sunrise and Pikes Peak South that use noncondensable gasses to lower steam ore ratios. As we expand these programs, they will provide for increased production to the redeployment of the steam that is being freed up, further reducing the environmental footprint of our operations.

Another big milestone in 2019 was the startup of the Aberfeldy facility. This is our first full fuel polymer inject project in Saskatchewan and will increase oil recovery from this heavy oilfield. It’s also the first of several potential longer term, lower cost EOR applications across our heavy oil business as we move forward from our legacy CHOPS production.

In the Downstream, overall upgrading and refining throughputs in Q4 averaged just over 203,000 barrels a day compared to 287,000 barrels a day in Q4 of 2018. This included 79,600 barrels a day at the Lloyd Upgrader and 28,200 barrels a day at the Asphalt Refinery.

In the U.S., we saw combined volumes at Lima and Toledo of 91,700 barrels a day. This takes into account the full shutdown at Lima as well as extended maintenance at the partner-operated Toledo Refinery. With Lima now online, overall downstream processing capacity is 355,000 barrels per day, including 195,000 barrels a day of heavy oil upgrading and conversion capacity. Overall capacity will grow to 400,000 barrels a day when Superior comes back online around the end of 2021, with total heavy processing capacity of 220,000 barrels per day.

In Western Canada, during the fourth quarter, we started up 6 liquid rich wells in the Montney formation at Wembley. In the Offshore business, construction of the 29-1 field at Liwan is about 80% complete and remains on track to start up in Q4. All 7 wells have been drilled and completed and the subsea floor lines have been installed. Work is now underway offshore again and next up is the installation of the control system connecting and dewatering the various flow lines. Once fully ramped up, this field will add about 9,000 BOEs a day to our Asia production.

Offshore Indonesia, the BD Project, the FPSO was taken offline for 2 weeks in January for maintenance, but is now back producing at full rates.

In the Atlantic, overall net production was about 24,000 barrels a day in the quarter, inclusive for the impact of the partner-operated Terra Nova shutdown that occurred in late December.

The West White Rose project is now 57% complete and remains on schedule.

At Argentia, the final quadrant of the concrete gravity base was completed ahead of schedule in the fourth quarter. We’re preparing now for the main shaft slip [fault] which will start in the second quarter of this year.

And at Ingleside, Texas, stacking of the individual decks is now underway. This was a major milestone that will allow the topsides construction to continue its upward progress.

Combined, average net production for Asia and the Atlantic in Q4 was 70,000 BOEs a day Husky working interest, up from about 64,000 BOEs a day a year ago.

As for our planned 2020 turnarounds, on the corridor, we will be completing a project in the second quarter at the Lloyd Upgrader to increase our diesel capacity to almost 10,000 barrels a day. This will take about 6 weeks. The partner-operated turnover FPSO in which we have a 13% working interest, is currently scheduled to be offline for up to 7 months. We also have regular maintenance scheduled at Liwan and Sunrise in the second quarter and on the SeaRose in the third quarter. The details of all of these are available on our website.

And now I’ll turn the call back to the operator for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from Greg Pardy of RBC Capital Markets.

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Greg M. Pardy, RBC Capital Markets, Research Division – MD & Co-Head Global Energy Research [2]

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Three quick ones for you. I guess the first is just on the severance charges. How much will that reduce your run rate G&A in 2020?

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Jeffrey Ryan Hart, Husky Energy Inc. – CFO [3]

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Yes. Greg, it’s Jeff here. Kind of think of it as it’ll be split. But about $50 million to $60 million will be in SGA, and then we’ll have [same things] in the other cost categories in the P&L. And that will total about $75 million we’d expect in ongoing savings on a run rate basis.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [4]

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It’s kind of a payback on the charge.

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Greg M. Pardy, RBC Capital Markets, Research Division – MD & Co-Head Global Energy Research [5]

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Okay. Yes. Okay. So it’s an annual number. Okay. Great. When you take down the upgrader, I guess that Rob was mentioning at whatever it is, 6 weeks or so, that’ll just be a partial shutdown? Or is it more dramatic than that?

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [6]

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I’ll let Jeff Rinker answer that.

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Jeffrey E. Rinker, Husky Energy Inc. – SVP of Downstream [7]

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Greg, this is Jeff. I mean we’re taking the whole upgrader down. We take the full upgrader down once every 4 years and we take 1 of the hydrocrackers down every second year. So this will be a full shutdown.

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Greg M. Pardy, RBC Capital Markets, Research Division – MD & Co-Head Global Energy Research [8]

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Okay. Great. And the last question is just on the reduced capital spend and so forth and then just the impact on reserves on both a 1P and a 2P basis. Could you dig into that a little bit about where those changes were made and then what the implications are, if any?

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Jeffrey Ryan Hart, Husky Energy Inc. – CFO [9]

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Yes. No, and I’ll break it out into 2 categories. We’re talk to the proved reserves and then just the probable impacts. If you look at proved as the impacts really on the side is the reductions are really in the gas business and it’s really reducing capital in Ansell and Kakwa. And that is really driven by price and us cutting back the capital frame, maximizing free cash flow.

And on the probable side, it is again, and if you look at the gas side, it’s the same thing, Ansell and Kakwa. And then you’ll see a similar impact or an impact in our bitumen product line, and that’s really cutting back future phases on Sunrise and focusing on free cash flow as well. So it’s really in those 2 areas and it’s really capital reductions.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [10]

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Yes. And the only thing I’d add to that, Greg, is, again, as we know, those barrels have not really gone anywhere, it’s just that under the reserve recognition rules, if you’re not spending capital in the next sort of 5 years, you have to derecognize them. So that’s the driver, of course. And then once you derecognize them, that flows back into your impairment calculations and how you value those reserves.

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Operator [11]

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Our next question comes from Benny Wong of Morgan Stanley.

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Benny Wong, Morgan Stanley, Research Division – VP [12]

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Rob, want to thank you for the update and your prepared remarks around China and the coronavirus.

There seems to be quite a bit of concern around your natural gas pricing contract in the region, just given where regional gas and LNG prices have been moving. Can you maybe provide some perspective around that and if the perceived risk is warranted? And curious if you’ve had some dialogue with CNOOC around the situation.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [13]

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So Benny, I think, clearly, looking at the whole situation in Asia at the moment, although it does seem to be kind of spreading across the world. There are issues with total gas demand, although as I said earlier in the call, we’re actually almost pleasantly surprised at the moment that they have now ramped up to kind of full rates even a little higher than the normal full rate. So we are seeing a bounce-back in those volumes at the moment.

Again, the history here is we have a very strong relationship with CNOOC. And the last time we got involved with CNOOC on discussions around this contract when there were major differences, I think both sides walked away feeling they got what they needed, which was we needed to preserve value and we were able to do that in those negotiations. We did at the time agree a small decrease in the gas price over time. But in return, they also offered us some things like extensions around Wenchang and things like that. So value was preserved under the nature of the contracts.

At the moment, we are just continuing to deliver the gas and we haven’t really heard much from them.

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Benny Wong, Morgan Stanley, Research Division – VP [14]

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Great. Appreciate those thoughts. Second one is more around your retail sale process. South of the border there’s a big refinery that’s selling their retail business as well and there’s been recent headlines of interest of an overseas buyer. Just curious and just in general how your process is going and if you’re seeing the same interest as well, understanding that the business, the asset, might be a little bit different.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [15]

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Yes. I guess what I’d say there is we’ve run an extensive process. We certain did see interest from buyers, from a wide range of buyers, including overseas buyers. We believe, until things are signed, we believe we’re in the relatively late stages of that process, and we’ll update you sort of when we have something specific to say.

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Benny Wong, Morgan Stanley, Research Division – VP [16]

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Great. And just my final question, and it’s related really to Jeff’s prepared remarks. I think you mentioned you guys are looking at opportunities to further reduce capital. Just wondering if you’re able to provide some kind of early sense of what you’re looking at and sense of magnitude that we should be thinking about.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [17]

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I’ll let Jeff if he wants to add in a second. But let me just give you the kind of overall context. First, just, clearly, when we put out our guidance at the end of last year, we did actually reduce our CapEx guidance relative to what we had said we were going to do at the Investor Day earlier in that year. We took $100 million out of 2020 and $400 million out for next year, and kind of again indicating that we would expect that the run rate capital level will drop on a more sustaining basis beyond 2021. And so we’ve already baked that into the plan.

We are, of course, and I’m sure most of our colleague firms out there will be looking at capital programs again, given what we’re seeing with oil prices and margins, given the virus outbreak and all these things going on. So what I assure you is we’ve done enough to understand we do have more capital flexibility. There is more room that we can reduce CapEx this year. We haven’t finalized those plans. But our finger’s over the trigger, I guess you could say, if they’re required.

And then in terms of at the back of all this, I think there’s always going to be a little bit of concerns when things turn very south in the industry around the dividend.

But we’re still feeling very good about our ability to sustain the dividend; hence, the board’s decision to continue to pay the divided at current levels. That’s on the back of a balance sheet that is still very strong in terms of the industry overall, the potential retail sale I spoke about earlier and, of course, this idea that we do have some potential additional capital flexibility if we need to go that way in the year.

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Operator [18]

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Our next question comes from Prashant Rao of Citigroup.

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Prashant Raghavendra Rao, Citigroup Inc, Research Division – Senior Associate [19]

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Rob, wanted to touch back on something you said there about the dividend program, appreciating that there’s leverage you can pull for further CapEx reduction and the balance sheet being still fairly solid. How do you think about debt leverage levels from here, especially given that — I’m trying to rope this in with the impairments, which, obviously, reflect a lowered, a more conservative commodity price outlook.

Is there room to lever — to take a little bit more incremental leverage? What’s your comfort level as you sort of move towards your targeted free cash flow positive inflection point sort of next year? Where could we see that go? And how should we think about that with respect to the sanctity of the dividend?

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [20]

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That’s great. I’m going to let Jeff Hart talk on that.

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Jeffrey Ryan Hart, Husky Energy Inc. – CFO [21]

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Yes. So we finished quarter here at around $3.7 billion. And the way to think about our target is, is we always say 2x net debt to FFO at the bottom of the cycle. And kind of that triangulates now with what we can generate at a $40 TI is, about [$4.5 billion] in net debt. And so that’s where we’re comfortable. We’ll kind of manage around that because we don’t want to do anything imprudent to the business, and obviously we’ve got the retail process going as well. And so we feel we’ve got the options there and we’ve got a few hundred million to $0.5 billion or a little bit more in room in the balance sheet. So that’s where we’re thinking about it and we’ll manage in and around that.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [22]

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I think the only thing I’d add to Jeff’s remarks is, of course — and as we outlined at Investor Day next year, I mean, as you go through this year, we finished the COF project (inaudible) now, which was a substantial spender of CapEx. We’re going to finish 2 more thermals as we go through the year, one about the middle of the year and one toward the back end of the year. So those will be out. 29-1 in China will be finished. So all those turn from net capital consumers now to actually revenue generators.

And then if you look at the West White Rose project, next year and the year after are much less heavy spending years because assembly — I kind of think of them as assembly years.

We largely have built all the major components. And then in 2021 they’re all assembled, then in ’22, they’re deployed to the field. So those are much less spending year. So we still see this inflection point in kind of capital spending where that is growing to drop very significantly as we go from this year to next year.

As I say, I think we have some additional capital flexibility we can pull this year if we need to. But in any case, we’re going to see a big inflection down in capital as we go into next year and we have — and between all those projects, we’ve got about another 30,000 barrels a day of production coming on stream effectively by the end of the year. And we also have the COF project at Lima up and running, so it gives us more flexibility, better opportunity to drive higher margins.

And I guess the one other project that we didn’t mention explicitly, but as part of the upgrader turnaround, of course, we’re going to finish the work on the diesel enhancement project that takes our diesel rates up at the upgrader from about 6,000 to just under 10,000 barrels a day and actually incrementally adds a little bit of capacity to the upgraders throughput as well.

So all those things are kind of moving in the right direction. So I just wanted to give you a sense as the board’s thinking about the dividend now, they’re also saying, look, we’ve got all these levers as we manage this year and actually as we go to next year, we actually see a very big inflection point driven by lower capital spending plus all this additional production and margin enhancement projects coming on stream.

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Jeffrey E. Rinker, Husky Energy Inc. – SVP of Downstream [23]

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Yes. To Rob’s point, as you’re looking 9 to 10 months and you’ve got 2 thermals on 29-1, and so you’re really stepping down that capital frame. So the risk profile’s a little bit different.

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Prashant Raghavendra Rao, Citigroup Inc, Research Division – Senior Associate [24]

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Okay. Appreciate the detail in that answer from all of you. Next question I had was sort of related. It’s a question on the commodity price outlook change. As it relates to the impairments, Rob, you talked already about some of the derecognition process in terms of reserves and how that works. But other two big levers here, one is commodity price when we think about impairment, right? The other is really discount rate that’s applied.

And so to the extent that you could talk about it or give some color, I’d like to know how much of the impairments are purely a function of a commodity price environment and how much could be potentially the auditors even looking at discount rate assumptions on some of these projects (inaudible), particularly on the gas side.

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Jeffrey Ryan Hart, Husky Energy Inc. – CFO [25]

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Yes. It’s Jeff here. I’ll talk to that. Broadly speaking, and I’ll get into, its vast majority of the impairments are really driven by commodity price. Obviously, you go through your process, you assessed a third-party [debt and the like]. But that’s really the drive and that’s the way people should be thinking about it is, is the revision down in the long-term price lines we saw in third parties and the like.

So the discount rate, there’s a bunch of accounting things that go on with that to make sure that it’s a reasonable rate and reflects the cash flows of the individual assets. But broadly speaking is the way you should be thinking about it is the vast majority is price.

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Prashant Raghavendra Rao, Citigroup Inc, Research Division – Senior Associate [26]

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Okay. Great. And just one last one for me. On the crude oil flexibility impairment, it looks like there was some redundant equipment that’s really the impairment once you’ve come out of that now. Was part of that sort of known that you might have some redundancies there or did you kind of discover that as you went through the process?

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Jeffrey Ryan Hart, Husky Energy Inc. – CFO [27]

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Yes, I’ll talk to that. Is you go through and, obviously, this quarter we did a lot, we’re doing work on — or this past quarter, the distillation, the coker. And yes, what I’d say is, is individual small subcomponents of the major units. And as you’re going through and pulling that out is, is that at that point should derecognize. And there’s nothing to read into that other than just you can’t have to sets of [pipe] on the book and the like. And they’re all kind of subcomponents of the major units.

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Operator [28]

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Our next question comes from Phil Gresh of JPMorgan.

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Philip Mulkey Gresh, JP Morgan Chase & Co, Research Division – Senior Equity Research Analyst [29]

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First question just on Superior in light of some of the recent news flow around the tower there. It sounds like you’re still confident in the 2021, end of 2021 timing. But maybe you can just frame what happened there and how confident you are in that timing still and just where you are in the process, a little bit more on that. Thank you.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [30]

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So I’ll get Jeff Rinker to answer that. He’s been close to that the last few days.

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Jeffrey E. Rinker, Husky Energy Inc. – SVP of Downstream [31]

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Yes. Phil, thanks for the question. Yes. So just to what happened. Last Thursday, the construction workers that were working on the project heard this loud noise that came from the FCC stack at the site. And these are construction workers that are experienced, not really normally affected by noises. So it was a serious noise and we took it seriously. We evacuated the area around the stack until we had a chance to inspect it and find out if there was anything wrong with the stack. Subsequently, we’ve done visual inspection. We’ve done measuring the movement of the stack. We don’t see anything at all wrong with the stack. But we are going to complete a thorough mechanical inspection of the stack and make absolutely sure there’s nothing wrong with it. So that’s going on.

We did pull the workers away from the site around the stack. We’ll lose about a week of time in the field. This is not going to affect the overall project schedule, though, because the critical path right now isn’t in the field. The critical path is with fabrication of long-lead equipment and detailed engineering, which is happening in shops and offices around the country. So we’ll be back to work at the site soon, as soon as we have the stack secured with a crane. And we don’t expect to lose any time on the project. So we’re still on track for late 2021 startup of the refinery.

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Philip Mulkey Gresh, JP Morgan Chase & Co, Research Division – Senior Equity Research Analyst [32]

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Okay. Great. And then my second question, I guess for Rob. I’m looking at the Analyst Day slides here from last year and just some of the 2020 specific data points and the guidance that you’ve provided back in December. If I look at the production and the cash flow, well, the CFO obviously you’ve changed your CapEx. But thinking about more of the production and CFO, and in light of the 2019 performance and the fourth quarter shortfall, I mean, is there anything from your perspective that you would be carrying through to 2020 or reading through to 2020 as a result of 2019? Or is your view that this is mostly one-time transitory factors? Just any thoughts you could provide. Thanks.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [33]

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Yes. Thanks for the question. I mean I see almost everything that happened in 4Q as onetime factors that departed from the norm. Hence, as I said, one of the things that is an obvious question for me to ask as well as I’m going through all this. So one of the things I wanted to be clear in my mind was if you bridge back to normalized sort of levels of funds flow from operation and that what is the bridge? And the bridge was really around the Lima downtime. As I said, we had planned for $90 million of that. We got an extra $90 million because it was extended. And then the lower U.S. crack spread was about $120 million. At the moment, crack spreads, they come up off the bottom, but they’re certainly going up and down with the different views of the virus situation. But it’s too early to call the view that they’re going to be lower throughout the year or something.

Severance costs were all one-off items. And the Keystone outage, the force majeure on the Keystone Pipeline, I’m hoping we don’t see that again as well.

The other little thing that was in 4Q that we didn’t explicitly bridge to in previous comments was just that there’s always a time lag as we see the differential narrowing or expanding in our operations the way the Integrated Corridor works. And in this case, we saw the differential expanding, so we lost some of the income from the upstream, but, of course, it didn’t get replaced in the downstream.

In addition, because of the Keystone Pipeline outage but even where some of that will flow through, some of that’ll flow through in the first quarter, we estimated that as like around $20 million. It would have been larger, except for the Keystone issue.

But so those all felt like sort of one-off sort of issues. And when I look back at the guidance for this year, I think it really comes down to price and margin at the moment that has a potential.

There is the Terra Nova off station which was budgeted, in the plan, it’s budgeted for about 7 months. So it is quite extensive in the budget for this year. We didn’t expect it to be shut down for the first month or two here, prior to going off station. So we’ll see if the operator’s able to recoup a little bit of that. But we’re only 13% of that project, so it isn’t a major impact one way or another.

So I guess the answer to your question is, there isn’t any — it’s really about price, and we’ll see how that plays out as we go through the year.

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Philip Mulkey Gresh, JP Morgan Chase & Co, Research Division – Senior Equity Research Analyst [34]

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Great. That’s really helpful. Then I guess, obviously, you called out some first quarter headwinds. But from your perspective, it sounds like nothing that would make you uncomfortable the full year outlook or guidance on production?

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [35]

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Yes. No, I think on the fundamentals, like on the controllables, I’m feeling pretty good. I wish the year started a little bit better on the pricing front. But we’ll see how that plays out.

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Operator [36]

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Our next question comes from Emily Chieng of Goldman Sachs.

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Emily Christine Chieng, Goldman Sachs Group Inc., Research Division – Associate [37]

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Just maybe coming back to the CapEx piece of the equation before — and I just wanted to dig a little deeper into West White Rose. I believe when this was sanctioned, it was about a $2.2 billion project net to Husky. Can you remind us exactly where we’re standing in terms of spend thus far and how much maybe we should be budgeting for 2021 and ’22, given that I think we should be coming to the tail end of spend there, please?

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [38]

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Yes. So Emily, what we’ve done here like let me first say one thing. The price of that project hasn’t changed since our Investor Day last year. So it hasn’t changed in over a year, but it hasn’t changed since the Investor Day last year. In fact, it’s been tracking, if anything, slightly better than what we set out at the Investor Day last year.

So all the capital that we put in, in Investor Day that we outlined at our Investor Day last year, included the full cost of West White Rose along with the current estimates. So none of those estimates change on the back of sort of anything to do with West White Rose. And when we said in our guidance call this year that we were going to bring capital down from those levels by $100 million and $400 million next year, that also reflected the current status of West White Rose. So all those numbers are still current.

And as I said, we believe, and we’ll look at the pricing environment this year, we know we have further capital flexibility if we need to pull it this year in order to just ensure we can kind of preserve the funds from operations in order to sort of bridge the dividend payments and maintain our debt levels as we move into next year when we should see much more room around the extra free funds from operations that we have to support the dividend.

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Emily Christine Chieng, Goldman Sachs Group Inc., Research Division – Associate [39]

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Got it. That’s helpful. And just one follow-up, and this might be a little tricky to answer. But just on the I&M segment, can you quantify how much of the miss might have been due to the Keystone outage versus the differential?

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [40]

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Do you have that, Jeff? I think I…

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Jeffrey Ryan Hart, Husky Energy Inc. – CFO [41]

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Yes. It’s Jeff Hart.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [42]

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I think we did ask that question of Jeff, so he should have that.

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Jeffrey Ryan Hart, Husky Energy Inc. – CFO [43]

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I don’t have the specific numbers up here. But basically, the way to think of it is the vast majority of it really is, is the quarter-versus-quarter is the narrower location differential. In order of magnitude, the outage did cost us money, but it really is the way to think about it is the location differential primarily. And then that was compounded by the outage.

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Operator [44]

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Our next question comes from Mike Dunn of Stifel First Energy.

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Michael Paul Dunn, Stifel Nicolaus Canada Inc., Research Division – Director of Institutional Research [45]

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Two questions from me, and apologies if I missed the details in the prepared remarks. But regarding the impairment at West White Rose, just looking for a bit more detail on that, folks. Your partner had recorded an impairment on the asset in their Q4 report a few weeks ago. I believe what I understood from that was it was an increase to the post-startup cost assumptions for the project. And I know that the impairment was based on 3P reserves — or the impairment test is based on 3P reserves. The possibles aren’t disclosed. So just wondering if there’s any changes to the 3P outlook for West White Rose.

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Jeffrey Ryan Hart, Husky Energy Inc. – CFO [46]

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Yes. So it’s Jeff here. The color on that is the majority of it really is, is price. I can’t — every (inaudible) or company has their own process that they run. But for us, inclusive of White Rose — and I’ll remind you, it’s not just West White Rose. It’s the existing lands, everything that runs through the SeaRose FPSO. So you can’t look at it in isolation and view it as just West White Rose. It really is the entire White Rose CGU. And the way to think about it really is, is price-related and price-driven. And we haven’t this year seen a substantive move in the reserves.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [47]

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Yes. Either, any the proved or the 3P reserves.

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Jeffrey Ryan Hart, Husky Energy Inc. – CFO [48]

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Yes, that’s right.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [49]

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They’re all very, very similar.

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Michael Paul Dunn, Stifel Nicolaus Canada Inc., Research Division – Director of Institutional Research [50]

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Okay. Thank you. And then secondly, I’m just wondering if you could provide an update. I mean I don’t have much of an update with regards to the status of GHT taxes in Saskatchewan, and what the federal government’s trying to apply those. I mean any sense of what they might be for your company if, let’s say if there was a similar policy to Alberta’s? I think you’re not paying those yet. But maybe if you can just provide an update that.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [51]

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I’ll let Janet give you a brief answer on that. We can always get back to you with more detail.

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Janet E. Annesley, Husky Energy Inc. – SVP of Corporate Affairs & HR [52]

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Yes. It’s Janet Annesley here. So Saskatchewan has a large emitters program very similar to Alberta. And our facilities are covered under this large emitters program. And so we’d be very glad to follow up with you. I don’t have the quantum of carbon taxes that we’re paying, if that’s your question. But we can certainly walk you through the methodology that is applied to the facilities.

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Michael Paul Dunn, Stifel Nicolaus Canada Inc., Research Division – Director of Institutional Research [53]

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Okay. Great. And then, Janet, did these payments just start this year or were you subject to them prior to this year?

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Janet E. Annesley, Husky Energy Inc. – SVP of Corporate Affairs & HR [54]

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They just started this year.

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Michael Paul Dunn, Stifel Nicolaus Canada Inc., Research Division – Director of Institutional Research [55]

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Okay. Yes, I’ll follow up with somebody later.

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Operator [56]

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Our next question comes from Matt Murphy of Tudor, Pickering and Holt.

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Matthew Murphy, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division – Director of Integrateds and Upstream Research [57]

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Just wondering on the 29-1 extension if you could remind us, one, I guess if the pricing structure has been settled, what sort of area code that it shook out in or if, perhaps, it’s still under negotiation. Any comments on where we should be thinking relative to existing pricing?

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Robert W. P. Symonds, Husky Energy Inc. – COO [58]

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This is Rob Symonds. So 29-1, the pricing is fixed. I believe we put that out to you a little while ago. About 10% less than the numbers that you see from the existing contracts. And it is set. It’s signed and so no issue from our perspective.

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Matthew Murphy, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division – Director of Integrateds and Upstream Research [59]

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Okay. And I guess on Liwan as a whole, can you remind us when the current price contract or just general contract is due to end? I think 2021 is the time frame, if I’m not mistaken. And just any thoughts on any discussions that you’ve held this far with the operator of that project on potentially extending that contract longer term. Thanks.

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Robert W. P. Symonds, Husky Energy Inc. – COO [60]

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So that contract is a life of field contract. There is, as you note, a price reset point in, I believe the end of 2021, when we will go into a [collared] arrangement. I think, again, what we’ve talked about historically is you should think about — and it’s based on Guangdong City Gate. As Guangdong floats, we will go down no more than $2 and we will go up no more than $2.

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Operator [61]

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This concludes the analyst question-and-answer portion of today’s call. We will now take questions from members of the media. (Operator Instructions)

Our first question comes from Alex Bill of allNewfoundlandLabrador.

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Alex Bill;allNewfoundlandLabrador;Editor, [62]

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Somebody asked my West White Rose impairment charge question earlier. But I’m wondering if you can provide more details on reductions in capital investment in Atlantic Canada as mentioned in the MD&A.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [63]

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Alex, this is Rob. I think the only — so clearly, we’re moving ahead with West White Rose, and so there’s no significant reductions associated with that. As we went through last year, we did have some capital invested in a potential sort of Northwest White Rose, some early work around that. We actually pulled that back with the kind of commodity price assumptions we were looking at, at the moment. But the major capital investment we’re rolling forward with is continuing.

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Alex Bill;allNewfoundlandLabrador;Editor, [64]

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And my other question also regards the question or the statements from your partner on West White Rose made earlier this month regarding concerns over overspending at West White Rose. Is that something you feel has been addressed from the switch to a sort of aggressive schedule basis to this cost efficiency basis? Or would you kind of contest the overspending description?

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [65]

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Well, I think actually even our partner actually said they were satisfied that this was now progressing very well. In fact, they went — yes. So they said, and I think their message was consistent with our message, which was there were early days of the project, there was some low productivity in that, which we addressed when we kind of reworked the schedule. And since then, we’ve been seeing actually excellent productivity by the workforce out in Newfoundland. We’ve been very happy with the crew on site and the progress we’ve been seeing. And I think our — I know our partner shares that view as well. So that’s where we are now.

And as I’ve said earlier, the kind of cost estimate for the project hasn’t changed in over a year. And from a Husky point of view, in all our analyst presentations and everything, we’ve been using the same price forecast for over a year.

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Operator [66]

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Our next question comes from Rod Nickel of Reuters.

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Rod Nickel;Reuters;Senior Correspondent, [67]

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Rob, I’m just wondering if you can flesh out a little bit more about why Husky has a, I guess, more pessimistic view of oil prices being lower for longer than it did before.

And then just secondly, Teck came out, of course, with some concerns this week about there being unresolved debate between climate change concerns and energy growth. Wondering if you can maybe give us your thoughts on that issue that they raised?

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [68]

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Super. Okay. Well, I think in terms of oil price, I’d just say that we don’t have a crystal ball. I’ve been in this industry a lot of years, almost whenever everybody has a consensus view of oil price it always turns out to be wrong. I guess the good news there is, everybody’s consensus view is low at the moment. So maybe that’ll eventually solve — in the past, low prices tend to be the solution to low prices, and we might be going through that again.

But all we do with oil price is, when we set the numbers, we basically look at the forward strip. And that’s all we did when we looked at our guidance for this year, we looked at the forward strip. And at the time, that was consistent with a long-term flat Brent price of around $60. And a long-term WTI flat price of about $55. And so that’s what we use. But I wouldn’t want anybody attaching too much importance to our view of it, because I haven’t seen much fidelity in anybody’s views of being able to predict this stuff.

In terms of the Teck decision, I think the only comments I’d make there is companies cannot control commodity prices. But regulatory processes, they’re in the government’s control, and governments should make every effort to ensure the companies in any industry don’t invest significant dollars in project applications only to be derailed by policy or political uncertainty at the very last moment. And we’ve seen a whole string of projects here, to some extent in the U.S., but worse in Canada, where people, proponents have spent $1 billion or more before they get a negative decision from the government to go forward. That certainly is a situation that has to be rectified if people want projects to move ahead.

And I think the other comment I’d make specifically more to Canada than even the U.S. is that we absolutely expect that large projects need to undergo detailed regulatory reviews to ensure they meet high environmental standards. And certainly, the Teck project seemed to do that, while creating jobs, taxes and other benefits that really net benefit Canadians and the country. And I think what we see in Canada is a regulatory process that just takes so, so long and it has an unpredictable length. And that’s what we have to get on top of, because as anybody who is very close to business, you know all you got to do to frustrate large project investment is if you make the regulatory process take longer than sort of 5 years, say, as a nominal point. The stars that need to align for businesses that often have partners that also have to be aligned on the idea of a large investment, those stars rarely align for more than 4 or 5 years. So I have some people kind of like they try to point fingers ultimately. And the [tech] process is what killed Teck. Well, what killed Teck ultimately was a regulatory process that just went on and on and on and on. Had that process concluded in a sensible time frame, I’m sure we’d have a Teck project under construction today because there were proponents that were set and keen to move forward with that project. But if you wait long enough, that sort of coalescence on the idea of spending that sort of money eventually unravels, and that’s what we’re seeing.

So I think the number one thing we need to address is ultimately is around the regulatory process to tighten up time frames and to put more certainty in it, while not giving away any of the requirements. The projects have to meet very high standards and be in the interest of the country.

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Operator [69]

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Our next question comes from Dan Healing of The Canadian Press.

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Dan Healing;The Canadian Press;Reporter, [70]

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I was just wondering about the rail blockades. I realize Husky doesn’t use the rail to move a lot of oil. But what kind of impacts are you seeing on that front and also in being able to access products that you need for your operations?

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [71]

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I’ll just answer that at a high level. We don’t use the rail very much because we have good pipeline access because of our history of investments and commitments on pipeline. So it’s not a big issue for us as a company. But that said, eventually we have asphalt to move on rail later on in the year and things like that, when we would certainly hope that the government takes the required actions to ensure that the infrastructure of Canada works properly. And that’s kind of where we are.

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Dan Healing;The Canadian Press;Reporter, [72]

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Okay. I just had a follow-up question on Teck. In view of the situation there, and you’re saying that it’s related to the regulatory process, do you think that means that large oil sands projects can’t be built in Canada right now?

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [73]

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I’d hate to draw that conclusion necessarily. I actually think the issue is far more about all projects in Canada. And I think people are attaching this to Teck. But I think building major highways, building pipelines, building major infrastructure projects around cities and things like that, I think this applies to everything. And so I wouldn’t draw the conclusion that it’s really an oil sands issue.

Certainly, it’s a concern, I think, when you think about the renewable energy agenda, because renewable energy requires things like wind farms that also contribute — also are quite controversial at times; hydro projects which are a key part of Canada’s energy picture. I mean we actually generate more power from renewable sources than most countries in the world because of the huge hydro positions we have. And as we’ve seen in this country, if you want to increase the size of that source of power, that’s also a big issue.

So I think this is interesting. It was Teck. It was an oil sands project. But I think it’s just endemic of a much bigger problem.

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Operator [74]

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This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Rob Peabody for any closing remarks.

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Robert J. Peabody, Husky Energy Inc. – CEO, President & Director [75]

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Well, thanks, everybody, for taking the time today and thanks for your question. We’ll release our 2020 first quarter results on Wednesday, April 29. And following the call, we’ll hold our Annual Meeting of Shareholders in Calgary. So thanks again for calling in today.

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Operator [76]

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This concludes today’s conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.