Many governments around the world are looking for ways to incentivize reductions in greenhouse gas (GHG) emissions and two approaches have received the most attention: cap-and-trade and a carbon tax. The European Union (EU) has chosen the former, Canada has opted for the latter, and the U.S. — well, that’s still to be determined. It’s logical for oil and gas producers, refiners and others in carbon-intensive industries to wonder, what does it all mean for us? In today’s RBN blog, we look at Canada’s carbon tax (which it refers to as a “carbon price”), explain how it works, and examine its current and future impacts on oil sands producers, bitumen upgraders and refiners.

This is the third blog in our series on carbon dioxide (CO2) emissions, which dives into the complex arenas of oil refining and carbon regulations, and how they may increasingly impact the competitive playing field for refiners. In Part 1, we started off with a big-picture view of refineries and the CO2 they generate and emit, and provided a brief overview of the policy options governments have to “nudge” refineries to reduce their emissions. In Part 2, we took a deep dive into one of the policy options, cap-and-trade, by examining the EU’s Emissions Trading System (ETS). We also noted some of the shortcomings of that scheme and said its effectiveness in curbing emissions remains to be proven. Today, we will look at another policy tool governments can use: a carbon tax.

A carbon tax is just that: The government assesses a certain cost for every tonne (metric ton, 1,000 kg, or about 2,205 pounds) of CO2 that is emitted. Though in Canada, they don’t actually call it a tax — instead, it is referred to as the “carbon price.” So, what is the price of carbon? As shown in Figure 1, the carbon price started out at C$20/tonne in 2019 and increased each year by C$10 to C$50/tonne in 2022. The initial legislation only set the carbon price through 2022, but a follow-up law in 2020 increased the annual progression to C$15/tonne each year starting in 2023 until the carbon price reaches C$170/tonne in 2030. For reference, as of this writing, US$1 is equal to C$1.37, so C$170 is the equivalent of US$125.

In Canada, this carbon price is assessed in two separate ways: as a fuel charge and via the Output-Based Pricing System (OBPS). The fuel charge is assessed on 22 different types of fuel for sale in Canada — everything from gasoline to propane and even coal. The charge is calculated based on the CO2 that would be emitted from the fuel’s combustion and that year’s carbon price. (The fuel charges are increased annually every April Fools’ Day. No jokes, please.) For example, a liter of gasoline (just over one-quarter of a gallon) would emit approximately 2.2 kg of CO2 and — at 2023’s C$65/tonne carbon price — would be subject to a C$0.14 charge. (We did the math: The carbon price would add C$10.60 to the cost of a 20-gallon fill-up.)

Another feature of Canada’s carbon price is that it’s revenue neutral, which means the taxes collected throughout the year don’t all end up in Ottawa to help fund Canada’s governmental expenditures. Instead, a Climate Action Incentive (CAI) payment each quarter returns 90% of what was directly collected in each province back to households in that province. (The other 10% goes into funds to help finance energy transition investments.) The CAI payment is determined by household size and is said to return more money than collected to 80% of households.

The fuel charge impacts most everyday Canadians, but for power-generation and industrial emitters the carbon price is assessed through the OBPS. Basically, the OBPS sets a benchmark on each unit of production. If a facility such as a gas-fired power plant is under the limit, the excess credits can be sold or banked for future years. If a facility exceeds the benchmark, it must pay the carbon price to the government for the number of tonnes it exceeds the benchmark or purchase credits from other participants. The benchmark also declines by a set amount each year — in essence, ratcheting down the amount of CO2 a facility can emit without incurring a cost. The OBPS mainly targets industries that might be put at a competitive disadvantage internationally if they were assessed the full burden of the carbon price. As such, those facilities that fall under the OBPS are exempt from the fuel charge we discussed earlier. The OBPS structure basically allocates tax credits instead of allowances like the EU ETS does, as we discussed in Part 2. The OBPS is also structured to be revenue-neutral, with funds collected in each province being returned to the province to support decarbonization efforts.

Now here’s the twist: The Canadian carbon price is just a backstop! Prior to 2018, some provinces had carbon pricing schemes in place while others did not, or the schemes weren’t applied equally, and this backstop helps level the playing field across Canada so provinces that have carbon pricing schemes don’t lose industry to provinces without their own carbon pricing program.

As it turned out, most provinces decided to fall under the Canadian carbon pricing system fuel charge —only British Columbia and the Northwest Territories have their own provincial systems. (Quebec operates a cap-and-trade program that has been approved by Ottawa to charge a slightly lower carbon tax on fuels — with some controversy.) On the OBPS front, very few industries fall under the system administered by Canada. Only four provinces fall under the backstop: Manitoba, Prince Edward Island, Yukon, and Nunavut, which have no refineries and represent less than 10% of Canada’s GHG emissions and only 5% of Canada’s gross domestic product (GDP). As for the other provinces, Quebec has (as we said) a cap-and-trade program and the rest — including the heavily industrial provinces of Ontario and Alberta — have OBPS programs very similar to Canada’s. Later, we will focus on the Alberta OBPS since it is the provincial system with the most impact on Canadian oil and gas assets.

Before we do, let’s put Canada’s CO2 emissions into perspective. First off, they are significantly less than the U.S. and EU, which we covered in prior blogs. In 2021, the U.S. produced 6,280 million metric tons (MMT) of CO2e emissions (that is, CO2-equivalent) and the EU produced 3,460 MMT of CO2e emissions, while Canada produced only 670 MMT of CO2e emissions. Figure 2 breaks down the major categories of Canadian emissions by sector, with the largest being oil and gas (dark-blue layer), followed by transportation (yellow layer), heavy industry (blue layer), buildings (red layer), agriculture (light-blue layer), and electricity (purple layer). Agriculture and buildings both are greater contributors than electricity, which might seem counterintuitive as electricity generation is usually one of a country’s largest emitters, but Canada is blessed with lots of hydropower — and has a lot of nuclear power too. In fact, Canada gets only 16% of its electricity from fossil fuels.

Just over half of the carbon emissions in Canada are from the transportation sector and the oil and gas industries. Transportation-based emissions have increased from 20% in 1990 to 22%-23% in the last few years. Oil and gas emissions, on the other hand, have soared from 17% in 1990 to 28% in 2021. As you might expect, most of the growth in oil and gas emissions has come from the expansion of crude oil production in the oil sands regions of Alberta. Emissions from oil sands production (yellow layer in Figure 3 below) have skyrocketed from just under 3% of total Canadian emissions in 1990 to almost 13% in 2020, and from 15% to 45% of oil and gas production emissions.

Other sources have shifted too. In the early 1990s, for example, natural gas production and processing (gray layer) was the biggest source of oil and gas emissions, which plateaued between 2006 and 2011 before contracting over the last decade. Conventional oil production (blue layer) was the next-largest source in 1990, peaking in 2014 before also contracting. Refining and pipeline emissions (dark-blue and green layers, respectively) have both contracted a bit since 1990.

We can further break down oil sands emissions into mining, in-situ recovery, and upgrading. Mining and in-situ recovery are the two ways oil sands are produced from the ground — the approach used is dictated by the depth of the deposit, with deposits less than 250 feet deep being mined and deposits over 650 feet deep being produced by in-situ recovery techniques (cyclic steam stimulation and steam-assisted gravity drainage). Currently, Canada produces about 3.25 MMb/d of bitumen (the hydrocarbon extracted from oil sands), with in-situ recovery accounting for just over half of that total. However, as shown in Figure 4 below, in-situ recovery (red layer) contributes significantly more to total emissions than bitumen mining (gray layer). Because of the need to generate vast amounts of steam, the emissions intensity of in-situ production is about three times (3x) that of mining bitumen.

The other oil sands category is upgraders (green layer in Figure 4). Upgraders are used to convert bitumen to synthetic crude oil (SCO), a light sweet crude equivalent that is a blend of naphtha, distillate, and gasoil. (A reminder: Bitumen is a low-quality hydrocarbon that is nearly a solid at room temperature and can’t be pumped in pipelines. It must either be upgraded or diluted with condensate to create a pumpable crude.) Upgraders either remove carbon or add hydrogen to get a lighter product. (These are the same types of units which are found in more complex, profitable refineries that we discussed in Part 1.) SCO production has plateaued over the last decade at just over 1 MMb/d of crude, which means that about a third of total oil sands production is upgraded. Due to their cost and market demands, new upgraders aren’t likely soon.

With the understanding that upgraders are just a special type of refinery, it makes sense to include them in total Canadian refinery emissions. Refining and upgrading created about 4.5% of Canada’s emissions in 1990, increasing to just over 6% in 2021, producing just over 41 MMT CO2e emissions in 2021. There are currently 16 refineries and four upgraders operating in Canada. Two of the upgraders use carbon-capture technology to reduce their emissions by just over 1 MMT CO2 each annually. [Shell retrofitted the steam methane reformer (SMR) at its Scotford upgrader to capture CO2 that is then sequestered in a saline aquifer. A greenfield upgrader/refinery in Sturgeon, AB, which became fully operational in 2020, uses carbon capture on its gasifier, a hydrogen-production unit. These captured emissions are used for enhanced oil recovery (EOR).]

The vast majority of oil sands operations are in Alberta and a few refineries are also located within the province. For this reason, we will focus on Alberta’s version of the OBPS system, which is called the Technology Innovation and Emissions Reduction Regulation (TIER). We will use the basic ideas of this regulation to estimate the potential impact on oil sands operations and refineries. First off, oil sands operations have more aggressive benchmarks under TIER than other facilities. The benchmarks started at 90% of a facility’s emissions intensity in 2020, reduced by 1% a year until 2022, 2% a year from 2023 through 2028, and 4% a year starting in 2029 (refineries and other industrial facilities remain at 2% a year). Mining and upgraders, in turn, were bumped down to 83% in 2021 vs. 89% that year for other facilities and in-situ oil sands operations.

Figure 5 shows the estimated average value that refineries, mines, in-situ production, and upgraders have to pay per barrel processed or produced by year. While the impact may be relatively modest today, the cost will grow over time. Refineries will be impacted the least, facing added costs of about C$1/bbl by 2030, but in-situ producers and upgraders will have to pay about C$3.50/bbl that same year. Granted, these are just estimates. Some facilities will likely come in much lower or end the year with excess credits, while others will pay significantly more depending on what their emissions intensity is compared to the benchmark. Also, TIER has a cost-containment program if facilities do run into economic hardship from the carbon price — that could blunt the cost for the worst-impacted facilities.

It is way too early to make any major conclusions on the effectiveness of Canada’s carbon price system at reducing emissions, especially as it relates to refineries and oil sands. Pipeline constraints out of Alberta are likely much more impactful on profits than a tax that currently costs less than a Loonie a barrel. But in time the impact will be more pronounced and will be something to watch. Canada has many programs to support and provide funding for industry participants in retrofitting facilities to abate CO2 emissions. Those — combined with the carbon price — could lead to some interesting projects in the future.

For our final blog in this series, we will come back to the U.S. and highlight the California’s cap-and-trade system, the U.S. government’s 45Q tax credits, and how a price on carbon could impact U.S. refinery profit margins.

Note: The article was authored by Alex Hardman of Baker & O’Brien and published on RBN Energy’s Daily Energy Post on October 20, 2023.

“Over the Hills and Far Away” was written by Jimmy Page and Robert Plant and appears as the third song on side one of Led Zeppelin’s fifth studio album, Houses of the Holy. Page and Plant wrote the song at Bron-Yr-Aur, a small cottage they rented in the Welsh countryside after finishing a massive North American tour with Led Zeppelin in 1970. The tune was originally called “Many, Many Times.” The intro section is played by Page on acoustic guitars, utilizing Eastern-influenced pull-offs in the key of G that Page is fond of. The midsection of the song is led by the band and guitar-driven riffs, followed by a quiet outro featuring Page on guitar and pedal steel guitar. The song was released as the first single from the album in May 1973 and went to #51 on the Billboard Hot 100 Singles chart. Personnel on the record were: Robert Plant (vocals), Jimmy Page (guitars, pedal steel), John Paul Jones (bass, piano, organ, Mellotron, synthesizer), and John Bonham (drums).

Houses of the Holy was recorded between December 1971-August 1972 with The Rolling Stones Mobile Studio at Headley Grange and Stargroves, and at Island and Olympic studios in London, with Jimmy Page producing and Eddie Kramer engineering. The album was released in March 1973 and went to #1 on the Billboard 200 Albums chart. It has been certified 11x Platinum by the Recording Industry Association of America. Two singles were released from the LP.

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