A Review of Barriers to Full-Scale Deployment of Emissions-Reduction Technologies

     Innovative clean technologies are part of the solution to reducing greenhouse gas emissions in both Canada and Alberta, particularly in the latter’s petroleum industry. However, while governments and their agencies may provide policies and financial support, proponents of cleantech still face numerous barriers to full deployment and commercialization.  To navigate the innovation and funding process successfully, it’s crucial for proponents to know the factors that impact the effective commercialization of cleantech innovations. They must also understand the role policies play in either supporting or hindering favourable outcomes.  Start-ups require support that focuses on innovation with a strong commercial potential, while scale-ups need to rely on proven strengths if they want to obtain private sector support for growth. Granting agencies and governments have an important role in supporting innovation. More clearly demonstrating and communicating their due diligence around funding decisions justifies expenditure of public money. Moreover, their decisions can and should send a signal to private sector financiers whether a certain innovation represents a good investment. Due diligence equally works to signal financiers when a specific project does not merit investment.       Innovative clean technologies are part of the solution to reducing greenhouse gas emissions in both Canada and Alberta, particularly in the latter’s petroleum industry. However, while governments and their agencies may provide policies and financial support, proponents of cleantech still face numerous barriers to full deployment and commercialization.  To navigate the innovation and funding process successfully, it’s crucial for proponents to know the factors that impact the effective commercialization of cleantech innovations. They must also understand the role policies play in either supporting or hindering favourable outcomes.  Start-ups require support that focuses on innovation with a strong commercial potential, while scale-ups need to rely on proven strengths if they want to obtain private sector support for growth. Granting agencies and governments have an important role in supporting innovation. More clearly demonstrating and communicating their due diligence around funding decisions justifies expenditure of public money. Moreover, their decisions can and should send a signal to private sector financiers whether a certain innovation represents a good investment. Due diligence equally works to signal financiers when a specific project does not merit investment.    The need to find innovative solutions to reducing emissions may seem pressing, but the race should not be to the swiftest. De-risking for commercialization means that a proponent must firmly establish that the technology works, is economically feasible and can attain sufficient market penetration for a return on investment to the prospective financier, as well as provide socio-economic and environmental benefits.  Trying to simplify or speed up the stages of innovation and the funding process means proponents can be exposed to incompletely proven and riskier technologies, which can damage credibility with financiers. A balance must be struck between the financier’s wish to expedite the de-risking process and the need to avoid inadequate de-risking which can jeopardize the project and its funding at a later stage.  Distinctions must also be made between firm-level support, which allows a company more flexibility in pursuing or cancelling projects, and project-level supports, in which the funding is specifically targeted for use in the development of a particular innovation and has a defined end point.  Cleantech innovation in Alberta faces added hurdles associated with a post-2014 economic downturn that has reduced some firms’ cash flows and has made firms, as well as government, less inclined to support cleantech innovations. This situation makes it crucial for innovation proponents seeking funding to distinguish clearly between a proposed project’s economic and environmental benefits. A technology whose primary benefit is reducing emissions is susceptible to changes in emissions pricing or regulations, and thus is not an attractive candidate for investors. An innovation that primarily reduces costs but offers a secondary environmental benefit is a better investment because it is much less sensitive to policy changes.  Alberta innovators must make sure they emphasize the economic benefits, and do their due diligence and careful de-risking if they want to surmount the added obstacles. Cleantech innovation doesn’t have to become a casualty of the provincial economic environment if the proper steps in the innovative and fiscal processes are conscientiously followed

The Ground Rules for Effective OBAs: Principles for Addressing Carbon-Pricing Competitiveness Concerns through the Use of Output-Based Allocations

The federal government’s decision to impose a minimum national price on carbon emissions has the potential to make certain businesses in the country less competitive. Specifically, there are emissions-intensive and trade-exposed industries across Canada that compete against producers from other jurisdictions where governments do not put a price on carbon. For these industries, the obligation to pay a carbon price creates a competitive disadvantage. Specifically, these businesses will face higher costs and may encounter a loss of market share to international competitors from jurisdictions that lack the same emission-control measures. That not only hurts Canadian businesses, it could also negate any emissions reductions that carbon pricing in Canada achieves on a global scale. The federal government has opted to protect such emissions-intensive, tradeexposed businesses using subsidies called output-based allocations (OBAs). This is the same system that Alberta is introducing through its forthcoming Carbon Competiveness Regulation. It also shares certain similarities with cap-and-trade programs, such as those in Ontario and Quebec, which provide free allocations of emissions permits to certain firms. OBAs are a desirable complementary policy to a carbon price as they maintain the incentive for producers to invest in production methods and facilities that are less emissions intensive. So while producers are still, nevertheless, subsidized to offset the tax burden of the carbon price, they will, under an OBA system, see greater benefits the more they work to reduce their emissions intensity. Still, to function most effectively and most efficiently, an OBA policy should follow certain key principles. The most critical principle in the design of an OBA policy is ensuring that OBAs are allocated to facilities independent of their individual emission levels, and allocated equally (on a per unit basis) to facilities producing the same product. One of the major flaws with Alberta’s current Specified Gas Emitters Regulation (SGER) is that it does not follow this principle. Rather, subsidies under SGER are allocated based on a facility’s historical emissions intensity. As a result, more generous subsidies are given to those facilities that are “dirtier” (that is, those with higher emissions intensities) than to “cleaner” facilities with lower emission intensities. Secondly, it is important for a well-designed OBA policy to have transparent costs. Including a clear accounting of OBAs in government finance reports will ensure the public is fully aware of the revenues being directed to the subsidies. Thirdly, OBAs for different facilities are best allocated using a classification system based on the product being produced, and not using more conventional industry-classification codes. Commonly used conventional industry classifications—for example, conventional oil and natural gas extraction—group together facilities that produce distinct products and compete in different markets. Consequently, this classification will not recognize the various levels of emissions intensity and trade exposure within an industry. This will result in some facilities receiving more OBAs than they should and others receiving less than they should. Finally, a well-designed OBA system should seek to be as administratively efficient as possible with minimal implementation costs imposed on government and businesses. It is important to recognize that the federal carbon price and OBAs are a new policy and that many large emitting facilities have been making investment decisions based on a previous regulatory environment. Therefore, a compromise approach may be to initially provide an output subsidy based on a facility’s past emissions intensity (as Alberta has historically done under its SGER system) and then to transition gradually to the optimal OBA system over time

ENERGY & ENVIRONMENTAL POLICY TRENDS OUR PLANET IN 2040: COMPARING WORLD ENERGY OUTLOOKS

Comparing the predictions of the latest world energy reports gives insights into the world’s progress towards limiting greenhouse gas emissions and meeting the goals of the Paris Agreement. It gives an indication of just how close — or far — we might be from keeping global temperature increases below 2°C by 2100

Public-Interest Benefit Evaluation of Partial- Upgrading Technology

Approximately 60 per cent of Alberta’s oil sands production is non-upgraded bitumen which, after being mixed with a diluting agent (diluent) to allow transport, is exported. A popular view within Alberta — and particularly among Albertan politicians — is that a much larger share of oil sands bitumen should be upgraded in the province. However, without public subsidies or government underwriting, it is uneconomic to build and operate new facilities in Alberta to fully upgrade the bitumen into synthetic crude oil. But there are new partial upgrading technologies being developed that, subject to successful testing at a larger (commercial) pilot scale, can prove to be not only economic in Alberta, but also generate large social and economic benefits for the province. The advantages include a much smaller capital investment, a significant increase in the value of the product and market for the product and, even more importantly, a dramatic reduction in the need for large amounts of expensive diluent to transport the product to market. Indeed, the only diluent required will be that to move the bitumen from the production site to the partial upgrader and this can be continually recycled. The market for the synthetic crude oil produced by full upgrading is only getting tougher. Any Alberta bitumen fully upgraded here would compete closely with the rapidly expanding supply of light U.S. unconventional oil. Partial upgrading does not upgrade bitumen to a light crude, but to something resembling more of a medium or heavy crude, and at a lower cost per barrel than full upgrading. Unlike in the increasingly crowded light-crude market, the Alberta Royalty Review Advisory Panel recognized that currently there are gaps in several North American refineries that could be filled by this partially upgraded Alberta oil. A partial upgrader serving that less-competitive market not only appears to hold the potential for investors to make attractive returns in the long term, it would also provide important benefits to Alberta from a social perspective. Since partially upgraded crude can be shipped via pipeline without diluent (as bitumen requires), producing it in Alberta would free up pipeline capacity otherwise tied up by current volumes of diluted bitumen or dilbit (diluent typically represents about one-third of each barrel of dilbit). It also reduces the cost to shippers of paying tolls for diluent exported in the dilbit and recovering diluent at the U.S. pipeline terminal, where it is less valuable than if it were recovered in Alberta at the partial upgrader. The value of each barrel produced would also be higher, benefitting oil sands producers. Partial upgrading also seems to promise a lower emissions-intensity profile compared to other bitumen-processing technologies. Based on the model of a single 100,000-barrel-a-day partial upgrader, the value uplift could be $10 to$15 per bitumen barrel. Meanwhile, there could be an average annual increase to Alberta’s GDP of $505 million, and as many as 179,000 person-years of employment created (assuming a 40.5-year operating period). The increase in taxable earnings would increase provincial revenues by an average of$60 million a year, not including additional federal tax revenues. If successful, there would be many such partial upgraders with corresponding multiplication of these benefits. But there remains the critical task of proving partial upgrading technology at a higher scale than current testing. This might also depend on the province helping sustain investors through the “death-valley” between successful research and initial testing and demonstration of full commercial viability. The province has stepped into help technologies cross that “death valley” before. The promise of partial upgrading may well justify, as manager and steward of Alberta’s resources, helping bridge that valley again

The Potential for Canadian LNG Exports to Europe

Offering numerous ports with the shortest shipping distances to Europe from North America, Eastern Canada has the potential to be a player in the European liquefied natural gas (LNG) market. However, the slower-moving nature of proposed projects on Canada’s East Coast, combined with a glut of global LNG liquefaction capacity, means it will likely be difficult for Canadian projects to gain a foothold in the market in the near term. As just one player in the worldwide competitive market, Eastern Canada will face challenges keeping up with faster-moving and lower-cost entrants, particularly those on the U.S. Gulf and East Coasts. Geography, too, is a double-edged sword for proposed projects in Quebec and the Maritime provinces. While they offer the benefit of proximity to Europe, they are located significant distances from Canada’s major natural-gas-producing provinces of British Columbia and Alberta. Further, there are no direct natural gas pipelines connecting proposed projects to supply sources in either Western Canada or the Northeastern U.S. This places these projects at a significant disadvantage relative to projects on the U.S. Gulf Coast. The latter are located in a petrochemical hub, complete with major infrastructure connections to numerous sources of natural gas supply.Also working against Eastern Canadian LNG development is anti-pipeline and anti-fossil fuel sentiments across the country. These sentiments are slowing Canada’s regulatory process and have also contributed to the establishment of moratoriums on hydraulic fracturing in three Maritime provinces. This virtually rules out local supply sources of natural gas for export from Canada’s East Coast in the near term.None of this necessarily means, however, that Eastern Canada’s future in LNG exports is doomed. Reason for optimism remains and it centres on indications that European countries are looking to diversify their natural gas supply sources and are prioritizing geopolitically stable and environmentally responsible supplies.Canada is a world benchmark for that kind of stability, thus making it a dependable, reliable supplier unshaken by whichever way the geopolitical winds are blowing. The kind of stability Canada offers will be key to obtaining long-term LNG supply contracts and the financial capital accompanying them to build pipelines and LNG export facilities.In 2015 the NEB granted export licenses for six proposed LNG export facilities on Canada’s East Coast. Since then, one project was cancelled and the remaining five have repeatedly pushed back their timelines. This has left Canada in a limbo of sorts, but it can extricate itself. Market entry in the 2020s is within reach and aligns with a current opening in the European LNG contract market. Canada must move faster, however, if it is going to compete with the U.S., which currently has two operating LNG export facilities and an additional four under construction. The longer Canada’s process, the more likely that, for example, countries in Europe wanting to wean themselves off unstable Russia as a supplier, will turn to the U.S. rather than Canada.Windows of opportunity continually open and close for entrance to any LNG market. For Eastern Canada to compete in the European market it will need secure supplies of natural gas, and investment and long-term contracts to shore up the financing for building the necessary export infrastructure. For all those things to work in harmony, Canada must pick up the pace and deviate from the status quo or risk losing out entirely

An Overview of Global Liquefied Natural Gas Markets and Implications for Canada

Liquefied natural gas (LNG) is a small but growing share of the global natural gas market. Global consumption of natural gas rose by 2.4 per cent between 2005 and 2015. The majority (70 per cent) of consumption relies on indigenous production. Most of the rest comes from pipelines, with LNGsourced natural gas growing from seven to nine per cent of consumption between 2005 and 2015.Global LNG imports increased rapidly between 2005 and 2011, rising from 193 to 334 billion cubic metres annually. They have stayed relatively constant since, averaging 324 billion cubic metres annually. Europe and Asia and Oceania are the primary recipients of LNG imports, accounting for 90 per cent of global imports from 2005 to 2015.An increase in global LNG liquefaction terminals accompanied the rise in imports. From 2005 to 2015, the number of liquefaction terminals increased from 20 terminals in 13 countries to 38 terminals in 20 countries. Total global liquefaction capacity rose by almost 90 per cent, mostly in the Middle East.The growth in LNG is largely attributable to an increasing mismatch between areas of natural gas supply and demand. As of 2016, the world’s natural gas reserves were estimated at 194,782 billion cubic metres, with the Middle East and Russia and Eurasia having the largest shares, respectively.Despite having smaller reserves, the largest gas-producing region is North America, which accounted for 26 per cent of global production from 2005 to 2015. Production in North America – and specifically the United States – steadily increased over this period as a result of advances in horizontal drilling and hydraulic fracturing and a corresponding surge in shale gas.More so than other energy sources, the gaseous nature of natural gas has historically made it difficult to trade. This contributed to a rise in regional markets, with corresponding variation in prices. From 2010 to 2015 the LNG price in Asia was significantly higher than natural gas prices in Europe, which were in turn higher than prices in North America. These price differentials incited what was frequently referred to as the “LNG race,” with project proponents seeking to lock-in supply contracts and secure final investment decisions for new LNG liquefaction terminals.Although price differentials still remain, they have narrowed considerably since the start of the oil price crash in 2014. Lower prices, combined with a growing surplus of LNG liquefaction capacity, has led to a significant slowdown in the approval of new LNG liquefaction terminals in recent years.Looking ahead, however, another opportunity for LNG development lies on the horizon. Even if governments enact stringent measures to curb greenhouse gas emissions, natural gas production and consumption is expected to keep growing – the only fossil fuel to do so. Forecasts also suggest that the mismatch between areas of supply and demand will continue to become more pronounced.Production growth in the Middle East, Russia and Eurasia, North America and Africa is forecast to exceed growth in demand. Correspondingly, all three regions are anticipated to have a growing natural gas surplus through to 2040. In contrast, Europe and Asia and Oceania both currently have natural gas deficits that are also forecast to grow.New infrastructure will be critical to getting natural gas to consumers. While pipelines remain the cheaper option for transporting natural gas, Russia and Eurasia is the only major producing region with significant or planned pipeline access to external demand markets. As a result, it is expected that a second wave of new LNG capacity will be required by the mid-2020s.Having missed out on the first LNG race, this second development window offers the most promising opportunity for proposed Canadian export facilities to enter the global LNG market. With numerous proposals for new liquefaction terminals on standby around the globe, however, this next wave of LNG development will again be highly competitive. It is therefore important that Canadian firms and investors act now to manage investment risks and position themselves to proceed with proposed projects as soon as the next window opens. Moreover, Canadian governments have an important role in ensuring the stability of policy and regulatory environments underpinning Canada’s attractiveness as an investment destination

The Canadian Northern Corridor Community Engagement Program: Results and Lessons Learned

The Canadian Northern Corridor (CNC) Research Program is an investigation of the feasibility, desirability, and acceptability of infrastructure corridors in advancing integrated, long-term infrastructure planning and development in Canada. The Corridor Concept involves a series of multi-modal rights-of-way across mid- and northern Canada — connecting all three coasts and linked to existing corridors in southern Canada — for the efficient, timely and integrated development of trade, transportation, and communications infrastructure. Corridors are expected to make public and private infrastructure investments more attractive by reducing the uncertainty associated with project approval processes; sharing the costs associated with establishing and administering rights-of-way; decreasing negative environmental impacts; and moving to a more strategic, integrated and long-term approach to national infrastructure planning and development. A key outcome of corridor development is decreasing the existing infrastructure gap that persists between northern and southern Canadian regions and communities. The causes of this gap are complex and will require a diverse set of tools and solutions to resolve; the CNC is a useful conceptual tool to initiate discussions on northern infrastructure and to identify feasible and lasting solutions to address Canada’s infrastructure gap

Enabling Partial Upgrading in Alberta: A Review of the Regulatory Framework and Opportunities for Improvement

Alberta’s energy resources are market-constrained. The province has the opportunity to alleviate constraints by partially upgrading its crude bitumen before shipping to refinery: partial upgrading would create new markets for Alberta oil and free up pipeline capacity for all producers by reducing the volume of diluent in the system. The Government of Alberta has taken steps to take advantage of this opportunity through enactment of the Energy Diversification Act (2018) and subsequent launch of the Alberta Partial Upgrading Program to provide fiscal support to proponents of partial upgrading. In addition to financial risk, however, proponents face regulatory risk and there is the opportunity to facilitate the proliferation of partial upgrading at scale by ensuring an enabling regulatory environment. As a new approach to oil processing, partial upgrading may not fit neatly into existing rules and regulatory processes. There is the need for a comprehensive review of the regulatory framework and how it would apply to commercial-scale partial upgrading in order to understand where gaps exist and opportunities for improving regulatory certainty may lie. Here we show several gaps and sources of uncertainty in Alberta’s regulatory framework that may hinder proliferation of partial upgrading at scale. We find that partial upgrading would likely be treated as an oil sands processing plant but the lack of formal delineation between types of processing plants creates ambiguity and inefficiencies. Other gaps and sources of uncertainty are not unique to partial upgrading projects, but are of special importance to this group due to timing, the newness of the technology, and the shifting environmental regulation context in Alberta and Canada in general. Our analysis shows that numerous immediate opportunities exist to improve regulatory certainty for proponents

Nutrient indicators of agricultural impacts in the tributaries of a large lake

Lake Simcoe in Ontario, Canada, is a large lake surrounded by a mix of urban, agricultural, and less developed areas and is showing adverse effects from excess nutrient inputs, including low hypolimnetic oxygen concentrations. Knowledge of both the quantity and quality of nutrients and seston entering the lake is important because large reductions in phosphorus (P) loads have been proposed to help restore the lake and its coldwater fishery. We examined land use effects on P quality (i.e., bioavailability) and its relationship to seston in the tributaries of Lake Simcoe. Indicators of agricultural impacts were examined in 13 tributaries of Lake Simcoe, which were selected to represent a range of land use types. Bioavailability of P was assessed through analysis of different forms of P and stoichiometric indicators of nutrient status in seston. Nutrient sources were examined using the δ15N of seston. The percentage of cropland in the subwatershed had a strong relationship with P as reflected in higher soluble reactive P concentrations and lower indicators of P deficiency. Cropland land use effects were complicated; they contributed highly bioavailable P to a P deficient lake, and at the same time, contributed high seston loads causing turbidity, resulting in light deficiency. In the Lake Simcoe watershed, animal manure application on cropland could be a source of nutrients related to the δ15N variability and, correspondingly, bioavailable P. Management efforts should therefore include best management practices to reduce manure application to croplands and to prevent runoff from areas where manure is stored

The Canadian Northern Corridor Community Engagement Program: Results and Lessons Learned

The Canadian Northern Corridor (CNC) Research Program is an investigation of the feasibility, desirability, and acceptability of infrastructure corridors in advancing integrated, long-term infrastructure planning and development in Canada. The Corridor Concept involves a series of multi-modal rights-of-way across mid- and northern Canada — connecting all three coasts and linked to existing corridors in southern Canada — for the efficient, timely and integrated development of trade, transportation, and communications infrastructure. Corridors are expected to make public and private infrastructure investments more attractive by reducing the uncertainty associated with project approval processes; sharing the costs associated with establishing and administering rights-of-way; decreasing negative environmental impacts; and moving to a more strategic, integrated and long-term approach to national infrastructure planning and development. A key outcome of corridor development is decreasing the existing infrastructure gap that persists between northern and southern Canadian regions and communities. The causes of this gap are complex and will require a diverse set of tools and solutions to resolve; the CNC is a useful conceptual tool to initiate discussions on northern infrastructure and to identify feasible and lasting solutions to address Canada’s infrastructure gap