35. Energy and the Economy in North America

North America is blessed with abundant energy resources. In many ways, 2020 was a pivotal year. U.S. oil production peaked at 13 million barrels per day early in the year. However, momentum behind the unconventional oil and gas revolution (or shale gale) slowed after 15 years. Its remarkable success moderated global oil and gas prices, even as this favorable outcome exposed the shale industry’s business model that emphasized growth over profitability. Similarly, lower prices hurt high-cost oil sands production in Canada, while ample U.S. supply limited access for Canadian exports of oil and gas. Lower prices also harmed the prospect of reviving Mexico’s petroleum industry either by attracting foreign investment or through organic domestic growth.

Global oil prices plummeted in March 2020, even before the full impact of the COVID-19 pandemic was felt. Worldwide economic recovery accelerated considerably in 2021, given the unprecedently large fiscal and monetary stimuli applied to prevent economic collapse. Consequently, energy prices rose significantly, prompting calls for renewed oil and gas investment and increased exports, and relatively less emphasis on climate policy measures to restrict fossil fuel use. For all three countries in North America—the U.S., Canada, and Mexico—energy development and consumption play a crucial role in their economies.

The U.S. went through a number of transitions that enhanced the country’s energy security and slowly decreased its reliance on fossil fuels to meet energy needs. However, current trends for greenhouse gas (GHG) emissions suggest climate change mitigation targets will not be met.

The U.S. is a market economy designed to take advantage of its resource endowment and competitive advantages in technological innovation. These drivers led to the Shale Revolution. The increased production made the U.S. less dependent on energy imports, enabled a transition from coal to natural gas-fired electricity production, and opened the door for substantial U.S. oil and gas exports. Nonetheless, the low social acceptance of oil and gas infrastructure due to environmental and climate change concerns prevent producers from efficiently accessing domestic and international markets.

Simultaneously, the renewable energy (RE) industry experienced a production bonanza. The growing share of wind and solar energy is underpinned by popular policy support for non-emitting sources of energy, technological innovation, and stagnant electricity demand.

For the U.S. to significantly reduce GHG emissions, it will need to accelerate the transition toward a RE-based energy matrix through more favorable policies to meet the needs of its top energy consumers. This will likely involve energy storage solutions that economically and technically overcome intermittency challenges for solar and wind. Additionally, fuel efficiency trends, electric vehicle penetration rates, and the social acceptance of renewable energy (RE) mega projects will play a role in determining the pace of GHG emission reductions.

The U.S. is the world leader of oil and gas production. For instance, in 2018 the U.S. reached historic production levels for both oil and gas products with 11 million barrels per day (mmb/d) of crude oil (EIA 2019a) and around 930 billion cubic meters annually (bcma) of natural gas marketed production (EIA 2019b). This represents a 7 mmb/d production increase for crude oil in the 2008–2018 period (EIA 2019a), and an equally impressive total production increase for marketed natural gas in the U.S. of 332 bcma from 2008 to 2018 (EIA 2019b).

The production boom was fueled by decisive improvements in extraction techniques for unconventional resources combined with favorable investment and operating conditions. On the technology side, innovation around hydraulic fracturing, directional drilling, and information technology enabled the economic extraction of hydrocarbons from shale deposits (US CRS 2018). Moreover, it was the new technologies combined with private mineral rights ownership, availability of geological data, liberalized integrated markets, abundant risk capital, competitive oil and gas service providers, and interconnected infrastructure that made the extraction profitable and massive (CSIS 2019).

Indeed, data indicate shale formations accounted for 70% of natural dry gas production and 60% of crude oil production in December 2018 (EIA 2019c). Specifically, the shale plays in the Permian region—located in Western Texas and Eastern New Mexico—contributed the most to growth crude oil outputs (EIA 2019d), while the Utica and Marcellus U.S. shale formations in Appalachia accounted for 85% of incremental natural gas production from 2012 to 2015 (US CRS 2018).

The rise in output amid stagnant energy demand produced a state of energy abundance. Data from 2000 to 2018 indicate total annual primary energy consumption stagnated at roughly 100 quadrillion British Thermal Units (BTUs) (EIA 2019e; US CRS 2018). Increased energy efficiencies and a structural shift from a manufacture-driven to a service-led economy account for the 1.5% annual U.S. energy intensity decline from 1957 to 2017 (Saundry 2019).

Contrastingly, U.S. primary energy production increased by 23% in the 2000–2017 period (US CRS 2018) from about 70 quadrillion BTUs in 2000 to almost 90 and estimated at about 95 quadrillion BTUs for 2018 (EIA 2019e). The Shale Revolution enabled oil production to rise by 64% and natural gas production by 42% in that period (US CRS 2018), and as of 2018 energy produced from petroleum and gas products accounts for 36% and 31% of total energy consumed, respectively (EIA 2019e).

Oil and gas products play an important role in the energy demand of the U.S. transport, industrial, residential, and commercial sectors. In fact, petroleum products represent 92% of the 28.3 quadrillion BTUs the U.S. transport sector consumed in 2018 (EIA 2019e). Petroleum and natural gas products respectively provided the industrial sector with 34% and 40% of its energy demand; the residential sector with 8% and 43%; and the commercial sector with 9% and 39% (EIA 2019e). Natural gas also represented the largest source of electricity generation at 35% of total electricity in 2018. Residential and commercial consumers rely on electricity for 45% and 50% of their energy demand, respectively (EIA 2019e).

The Shale Revolution positioned the U.S. to meet domestic need for oil and gas and further integrate the North American oil and gas markets. On the one hand, the increased production of light sweet crude oil from shale deposits reduced the need for oil imports. The net import of crude oil and petroleum products was reduced by 6.5 mmb/d from the 2008–2012 period to the 2016–2018 period (Pirog 2019).¹ However, due to refining configurations—major refineries are optimized to process cheaper heavy crudes (Pirog 2019)—the U.S. is still importing large amounts of crude oil from nearby Canada and to a lesser extent Mexico.

At the same time, abundant natural gas production increased demand for natural gas products as prices declined, while significantly reducing imports to make the U.S. a net gas exporter. This trend is most apparent in the transition from coal to natural gas-based electricity generation. Hence, from 2000 to 2017 total natural gas demand grew by 16%, and by 2018 natural gas demand for electricity generation grew by 80% (US CRS 2018). Contrastingly, coal’s share of electricity production declined to 30.1% in 2017 from 52% in 2000 (US CRS 2018). The decline was reinforced by the proximity of shale gas production areas to consumers in the northeast U.S. and efficiency gains in combined cycle gas-based power plants (US CRS 2018). Despite the rise in demand, 2017 natural gas imports were 34% less than at 2007 peak levels (US CRS 2018).

The growing contributions of natural gas to the U.S. electricity sector exacerbated the nuclear sectors’ challenges. Nuclear energy represented about 20% of U.S. electricity generation for 30 years (Saundry 2019). Yet, the fleet of reactors is nearing retirement age. Permitting challenges for new reactors as well as more cost-competitive gas or renewable electricity will continue to reduce nuclear’s role in meeting future electricity demand.

Surplus oil and gas from shale made the U.S. an important exporter of both. For example, refined oil product exports increased from an average of 2.2 mmb/d in the 2008–2012 period to 5.1 mmb/d from 2016 through the first ten months of 2018 (Pirog 2019). Likewise, crude oil exports increased from an average of 45,000 b/d in the 2008–2012 period to 2.2 mmb/d in 2018 after the previous crude oil export ban was lifted starting in 2016 (Pirog 2019). LNG exports started in 2016 and natural gas exports totaled 102 bcma in 2018 (EIA 2019f). When more LNG export terminals come online in 2022, the EIA projects natural gas exports to rise to over 212 bcma by 2030 (EIA 2019g).

Nevertheless, oil and gas firms face market access issues due to insufficient transport infrastructure. U.S. pipeline networks did not keep pace with production increases, and existing nodes do not efficiently connect producers with domestic and international consumers. Public opposition to oil and gas projects prevents those transportation gaps from being filled effectively and expeditiously.

A major driver for the low social acceptance of oil and gas projects is the sector’s contribution to climate change through increased GHG emissions. In fact, current trends indicate the U.S. will not meet its Nationally Determined Contribution’s emissions targets, despite gradual decreases in emissions and energy intensity. The latest EPA GHG emissions inventory calculates U.S. emissions at 6456 Million Metric Tons (MMT) of CO2e for 2017. Although emissions have decreased by 1% every year since 2005, the 2017 emissions levels are 1.3% higher than in 1990 (EPA 2019).

The highest emitters are also the greatest consumers of energy. Thus, in 2017 the transport sector emitted 1866 MMT of CO2e or about 29% of the total; the power sector 1778 MMT of CO2e or 27.5% of the total; and industry 1436 MMT of CO2e or 22.2% of the total (EPA 2019). There are mixed trends in emissions across sectors, however. For example, emissions in the transport sector have been rising since 2012. In contrast, the power sector has experience declines in GHG emissions since 2005 and industry emissions declined by 14.8% since 1990 (EPA 2019).

The discrepancies in emission trends are partly explained by contrasting gains in energy efficiencies. In fact, 2015 data demonstrate vehicles use 7% more energy per mile traveled than in 2003—customer preferences for heavy vehicles and the U.S.’s vast territory explain the sector’s growing energy intensity (Benoit 2019). This trend contrasts with overall energy and emission intensity improvements in the U.S. For example, from 1957 to 2017 there was an annual average 1.5% decline in U.S. energy intensity due to improved efficiency in the manufacturing and electricity sectors, the offshoring of energy intensive activities, and a structural transition to a service-based economy (Saundry 2019).

If current trends continue, the Climate Action Tracker estimates the U.S. will not meet its 2020 GHG emission target of 6348 MMT of CO2e or its 2025 5760 MMT of CO2e target by 60–90 MMT of CO2e and by about 500–600 MMT of CO2e, respectively (Climate Action Tracker 2019).

Public pressure to reduce GHG emissions through non-emitting sources of energy further explains the decline in U.S. emissions as renewable energy sources increasingly meet more energy needs. The combination of favorable public policies, technological innovation, and large markets for electricity with declining demand rates enabled RE outputs to grow substantially and economically compete with hydrocarbons. The cases of the wind and solar industries underscore these trends.

In response to growing public pressure to decrease GHG emissions and concerns around climate change, federal and state policymakers established favorable investment regimes for wind and solar energy firms. At the federal level, tax incentives for investing in wind and solar energy assets that included accelerated depreciation benefits (US CRS 2018) were introduced through legislation like the Production Tax Credit for wind and the Investment Tax Credit for solar (Deloitte 2019). At the state level, policymakers introduced Renewable Portfolio Standards (RPS) that required minimum annual increments in the capacity installed of RE assets (Saundry 2019).

To date, these policies have had a substantial effect in the primary energy produced through RE sources. For instance, RE contributions to primary energy rose from 5.3% in 2001 to 11.3% in 2017—this trend was intensified in the electricity sector where RE generation grew from 9% to 17% (US CRS 2018). Non-hydroelectric sources drove the growth, with hydro’s contribution stagnating at 6–8% of the total. Thus, from 2001 to 2017 wind production grew from 7 to 254 MWh; utility scale solar from 0.6 to 53 MWh; and distributed solar from 129 MWh to 24,000 MWh (US CRS 2018). The success was so great that as of 2016 data wind and solar represent the largest component of new installed capacity added for electric generation since 2014 (US CRS 2018). The RPS play a vital role in this increment, accounting for about half of all non-hydro RE electricity deployed from 2000 to 2016 and for 21% of wind and 59% of large-scale utility solar in 2016 (Saundry 2019). Deloitte anticipates this trend to continue into the future with 96% of new net generation capacity to come from wind and solar energy sources in 2020—about 74 GW (Deloitte 2019).

The favorable investment environment and mass deployments also fueled innovations that resulted in major cost improvements for both wind and solar. From 2009 to 2017 the levelized cost of electricity (LCOE) for wind and solar photovoltaic dropped by 67% and 86%, respectively (Saundry 2019). More recent data indicate further reductions with 10% and 18% costs reductions, respectively, for the LCOE for onshore wind and utility scale solar just in the first half of 2019 (Deloitte 2019).

Stagnate demand for electricity also favored wind and solar energy industries, since even efficient gas-based electricity producers would face unfavorable economic conditions under current demand projections. Renewable energy can produce electricity profitably due to existing tax benefits and escalating efficiency improvements (US CRS 2018).

However, for the U.S. to significantly reduce its GHG emissions more policies are needed to reduce fossil fuel dependency of the transport, electricity, and industrial sectors. To reduce emissions in the transport sector, greater fuel efficiency standards will likely need to be combined with programs that enable the penetration of electric vehicles, such as additional charging infrastructure in urban centers. Current investment patterns may leave 88 of the country’s 100 most populous metropolitan areas with less than 50% of the assets needed to meet the charging demand for their regions in 2025 (Nicholas et al. 2019).

Another key factor includes diversifying the electricity sector away from gas and coal to ensure electric vehicles run on non-emitting electricity. This will require technical and economical solutions to the intermittent generation of wind and solar electricity. Potential solutions include energy storage—levelized cost of storage (LCOS) has declined substantially in past years (Deloitte 2019)—where lithium ion batteries are used to store competitively priced wind and/or solar electricity and then discharged to meet demand. These solutions already exist in the form of energy storage assets that discharge electricity for 4 hours during peak time. A recent study by the National Renewable Energy Lab (NREL) indicates these solutions could help mitigate the differences in peak versus baseload demand (Denholm et al. 2019) making the grid more reliable.

As one of the world’s large oil and gas producers, Canada holds substantial proven reserves, and the sector is an important contributor to as well as enabler of economic growth. Canada also illustrates the socioeconomic contradictions in a democratic country that relies on the export of hydrocarbons to grow as well as oil and gas to meet domestic energy demand, while remaining committed to achieving ambitious greenhouse gas (GHG) emission reductions due to public and international pressure.

On the one hand, oil and gas investors seek to develop Canada’s vast resource potential to profitably meet domestic, U.S. and Asian energy demands. On the other hand, parts of civil society and some provincial governments block those investments to prevent Canada from moving further away from its GHG emissions target. In the middle, the Federal Government struggles to reconcile these contrasting views in a policy framework that secures growth and reduces GHG emissions to levels that would effectively mitigate climate change.

Furthermore, due to inadequate transport infrastructure, Canadian hydrocarbon producers have insufficient access to U.S. and Asian markets despite growing output. This is a challenge for crude oil producers who want to export to the U.S. and for gas producers seeking export markets in Asia to off-set decreasing U.S. demand for imports. Adding to these challenges is that developing Canada’s oil sands—the source of output growth—is a high-cost and carbon-intensive process. As future fossil fuel demand growth concentrates in Asia, transportation costs will likely prevent Canadian producers from receiving sufficiently high prices to justify increased investments.

As a country that produced an average of 4.3 mmb/d of crude oil and 167 billion cubic meters annually (bcma) of dry natural gas in 2018, Canada has a robust production base (EIA 2019h). The country’s 170 billion barrels of crude oil in established reserves (National Energy Board 2018), 2 trillion cubic meters in proved natural gas reserves, and a refining capacity of 2 mmb/d mean Canada could maintain current output levels for many years (EIA 2019h).

In 2018 Canada exported an average of 3.6 mmb/d of crude oil (Canada Energy Regulator 2019) and 80 bcma of natural gas (Natural Resources Canada 2019a). The sales are highly concentrated with over 96% of Canadian crude oil and gas exports going to the U.S. in 2018 (EIA 2019h) due to logistical links and geographic proximity. These sales valued at US $119 billion are Canada’s largest source of export revenues (Cleland and Gattinger 2019). Likewise, the oil and gas sector is responsible for employing over 60,000 people nation-wide, over US $36 billion in capital expenditures, and contributing a yearly average of US $14.8 billion to the Federal and provincial governments through indirect and direct taxes as well as land sales from 2014 to 2018 (Natural Resources Canada 2019b). The employment, investment, and revenue benefits are concentrated in Western Canada’s production centers—Alberta and Saskatchewan (Cleland and Gattinger 2019).

Furthermore, the oil and gas sector plays a key role in fueling Canada’s energy intensive economy. Fossil fuels enable Canadians to stay warm and operate in the country’s cold temperatures and connect its dispersed population across Canada’s vast territory (Cleland and Gattinger 2019). For instance, 9% of electricity in Canada is produced using natural gas (Natural Resources Canada 2019b). This share is expected to rise while coal-based electricity—accounting for 9% of the total—decreases as power plants in Alberta, Saskatchewan, and Nova Scotia close or are retrofitted to function on natural gas (Environment and Climate Change Canada 2017). Similarly, 96% of the Canadian transport sector runs on fossil fuels consuming 1.1 mmb/d of oil products and 73,000 barrels of oil equivalent per day of gas in 2016 (Inter-American Development Bank 2019). While the dependency is lower, natural gas products accounted for 34% and 45% of industrial and commercial energy use, respectively, in 2016 (Inter-American Development Bank 2019). Overall, according to the Institut de l’énergie Trottier the energy industry contributes US $188 billion to GDP, representing 9.9% of the total (Langlois-Bertrand et al. 2018).

Canada’s oil and gas pipeline network is insufficient to transport surplus supplies to U.S. and Asian markets. While crude oil production increased in Western Canada by 9.8% and by 8% in the first half of 2018 alone, export capacity stagnated at 2016 levels (National Energy Board 2018). This has led to peak levels of crude oil inventories and price discounts between Western Canada Select (WCS)—Canada’s leading commercial heavy crude oil benchmark (Oil and Sands Magazine 2017)—and Western Texas Intermediate (WTI)—North America’s leading crude oil benchmark. In fact, Alberta’s processed oil inventories are double historic levels (Canada Institute 2019) and WCS-WTI price discounts were above US $21 in 2018 (National Energy Board 2018). Price discounts are normal for heavy crudes like WCS that incur transport costs to reach U.S. refineries. However, previous discounts for WCS varied between US $10 and $15 (National Energy Board 2018). The economic losses to Canadian firms intensified despite rising demand for heavy crude oil imports in the U.S. Gulf region as Venezuelan exports declined from 2014 to 2018 due to sociopolitical unrest and were finally prohibited by U.S. sanctions in 2019 (Eaton 2019).

Additionally, natural gas producers face the dual challenge of declining import demand in the U.S., while export infrastructure does not yet exist to meet rising demand for gas products in Asia. U.S. demand for natural gas imports peaked in 2007 at 131 bcma, and by 2018 declined to 82 bcma as the Shale Revolution greatly increased U.S. domestic output, enabling U.S. producers in the Appalachians to meet East Coast demand (EIA 2019f). Equally important, the absence of a liquefied natural gas (LNG) export facility in Canada means natural gas exporters lack the infrastructure to sell to the world’s largest LNG importers: China, Japan, and South Korea (EIA 2019i).

To address these challenges investors planned projects to expand the existing oil and gas pipeline infrastructure. Key proposed projects include new pipelines like Keystone XL and Northern Gateway, expansions of existing assets such as the Clipper and the Trans Mountain pipelines, and new LNG terminals near Kitimat, British Columbia.

Nonetheless, many of these projects have been suspended due to low social acceptance and legal challenges rooted in environmental concerns. A contributor to project opposition is that Canada is unlikely to meet the GHG emission commitments of its Nationally Determined Contribution under the Paris Accords due to growing emissions from the transport and oil and gas sectors.

Concerns around higher GHG emissions contributed to public opposition and legal challenges against the Keystone XL (Swift 2019), Northern Gateway (Mackay and Lemiski 2019), Trans Mountain (Mackay and Lemiski 2019), and Clipper (Williams 2017) projects. Considering Canada’s latest report to the United Nations Framework Convention on Climate Change (UNFCCC) estimates emissions at 722 megatons of CO₂ equivalent (MtCO2e) (Environment and Climate Change Canada 2017) and policies to achieve the 513 MtCO2e 2030 target have yet to be announced or implemented (Environment and Climate Change Canada 2017), concerns seem justified. In fact, the report shows increased energy consumption in the transport and oil and gas sectors more than off-set emission reductions in the electricity sector (Environment and Climate Change Canada 2017). Moreover, as of 2015 these two sectors account for 50% of Canada’s emissions (Environment and Climate Change Canada 2017). Greater demand for internal combustion engine vehicles and oil and natural gas products led to higher GHG emissions. Although transport sector emissions are leveling out, oil and gas production gains will likely further increase emissions, since Canada’s oil sands require energy and CO₂ intensive extraction mechanisms (EIA 2015).

While blocking specific oil and gas projects may limit GHG emissions, ad hoc opposition fails to address the systemic challenges of having an economy traditionally designed to respond and benefit from domestic and international demand for oil and gas products. Additionally, ad-hoc opposition reinforces concerns that the multi-billion economic contributions of the oil and gas sector will not be off-set economically to enable a transition toward less GHG emissions. For instance, achieving 50% GHG reductions from 2005 levels by 2050 could require cutting oil and gas exports by 50% and thus losing half of those export revenues as well (Cleland and Gattinger 2019). This is a concern not only for oil and gas investors but also for provincial governments who depend on these sectors to maintain their economies and workforces employed. If these legitimate issues are not addressed, provinces like Alberta and Saskatchewan will continue to challenge the Federal Government’s cornerstone project to reduce emissions: the Pan-Canadian Framework on Climate Change (Cleland and Gattinger 2019).

Additional complicating factors are the environmental, social, and technical challenges of energy alternatives to oil and gas products. While most Canadians favor renewable energy alternatives such as hydro, projects continue to face opposition due to their potential impacts to wildlife (Cleland and Gattinger 2019). Moreover, although wind and solar projects have traditionally lower environmental impacts than hydro projects, effectively replacing demand for oil and gas products will require investing in massive assets that can produce the energy equivalent of millions of barrels of oil per day to fuel electric cars and meet the needs of industrial and commercial end-users. As a case in point, the Trottier report estimates that 30–50% GHG reductions from 2005 emission levels will require a total yearly electricity output of over 800 terawatt-hours by 2030 of hydro alone (Langlois-Bertrand et al. 2018). These mega projects will unquestionably have significant environmental impacts. Similarly, expanding the electric infrastructure in Canada’s vast and sparsely populated territories will remain a major challenge for investors but would play an important role in facilitating electric vehicle market penetration.

Overall, Canada’s future economic success will depend on its ability to effectively address these tensions within the existing political system. Likewise, external intervening variables like the international demand for Canadian oil and gas products will be key in determining the costs of more aggressive climate change measures.

The case of Mexico illustrates how policies to address pressing energy security needs can also undermine existing programs to reduce GHG emissions. Investments to increase Mexico’s energy supply have not kept pace with the rise in energy consumption leading to substantial import dependencies. Ineffective institutions in the hydrocarbon sector as well as rising crime, violence, and low social acceptance for mega projects are the main causes. To address these challenges the government instituted market-oriented reforms that resulted in significant upstream and RE investments.

However, the reforms will likely reinforce GHG emission growth rates underpinned by higher emissions in Mexico’s energy, transport, and heavy industries. Moreover, unlike Canada, Mexico has yet to report the aggregate effect of its GHG emission reduction policies, which makes measuring progress and correcting course to meet emission reduction targets in 2030 difficult. Until more pressing problems like energy insecurity are addressed, the government will likely face limited domestic pressures to reinvigorate actions to mitigate the causes of climate change.

For over a decade Mexico’s energy demand has outgrown its declining domestic production. The latest National Energy Balance indicates that from 2007 to 2017 energy production in Mexico declined on average by 3.3% annually, with 2017 experiencing the largest year-over-year decline calculated at 8.9%—energy production totaled 7000 petajoules (PJ) (Secretaria de Energia 2018). Meanwhile energy demand rose considerably, reaching 9200 PJ in 2017, from around 8000 PJ in 2007 (Secretaria de Energia 2018). This trend was reinforced in 2017, with a year-on-year increase in total energy demand of 1.2%. The overall growth is underpinned by Mexico’s growing energy per-capita consumption which increased at an annual rate of 0.2% from 2007 to 2017 (Secretaria de Energia 2018). The increment is driven by growing demand in the transport and electricity sectors.

The imbalance between domestic energy demand and production has made Mexico increasingly dependent on energy imports. For example, in 2017 consumption was 31.6% higher than total energy production forcing Mexico to import 4400 PJ of energy (Secretaria de Energia 2018) to meet 47.8% of its energy demand (Secretaria de Energia 2018).

The country’s highly hydrocarbon-centric demand and declining domestic production drive the import dependency. Hydrocarbons accounted for 84.8% of total primary energy consumed in 2017. Natural gas products accounted for 46.8% of the total—a large proportion compared to the U.S. and Canada—and oil products for 38% (Secretaria de Energia 2018). Yet, despite its importance to domestic energy needs crude oil production fell from the 2004 peak of 3.4 mmb/d in 2004 to less than 2 mmb/d in 2017 (Wood 2018), with a production decrease of 8.9% from 2016 to 2017; similarly, natural gas production fell by 14.7% from 2016 to 2017 (Secretaria de Energia 2018). Accordingly, imports are concentrated into these two energy sources with oil accounting for roughly 25% of total imports and natural gas for about 50% of the total (Secretaria de Energia 2018).

The main consumers of oil and gas products are the transport and industrial sectors, followed by the residential, commercial, and public sectors. Of their total sector energy consumption, oil represents 90% for transport consumers, gas and electricity 66% for industrial consumers, and 66% as well for residential, commercial, and public consumers (Secretaria de Energia 2018).

Most imports—about 85% (Secretaria de Energia 2018)—come from the U.S., due to geographic proximity to refining centers and pipeline infrastructure. A comparative disadvantage in refining capacities—due to technology and logistics—partly explains Mexico’s dependence on hydrocarbon imports from the U.S. (EIA 2017). In fact, Mexico mostly produces heavy crude oil that is best suited for U.S. refineries in the Gulf of Mexico (Secretaria de Energia 2018).

Nonetheless, the monopoly on the oil and gas sector by Petroleos Mexicanos (PEMEX), the national oil company, played a greater role in creating Mexico’s current oil and gas scarcity. Specifically, PEMEX had insufficient capital to invest in production due to government interference and excessive government take. During the decline PEMEX had full monopoly over oil production, but operated at a loss because the government imposed unsustainable dues and it also controlled its access to external sources of financing. For example, from 1999 to 2008 PEMEX reported net income losses since the government’s take exceeded the operational surplus: transfers to the government accounted for 63% of revenue, creating a 6% net income loss after accounting for operating costs (Balza and Espinasa 2015). The dues did not vary with the oil price and PEMEX was forced to go into debt to finance investments into prospective and exiting ventures.

However, in 2006 PEMEX’s access to foreign capital markets was restricted to curtail the company’s growing debt (Balza and Espinasa 2015). The restriction led PEMEX to severely cut investments into efforts to expand production in existing fields and into exploration ventures (Balza and Espinasa 2015; Wood 2018). The production decline at the Cantarell field, from 2.4 mmb/d of crude oil in 2004 to 228,000 in 2015 (Balza and Espinasa 2015), due to insufficient investments is a case in point (EIA 2017).

Additionally, Mexico’s unfavorable operating environment further exacerbated the country’s deteriorating oil and gas production. On the one hand, rising criminality has led to substantial oil theft through attacks on transport trucks or illegal taps on the pipeline system (Montero Vieira 2016). These robberies have been increasing in past years: from 102 in 2004 to 4219 in 2014—data suggest extractions in 2014 were equivalent to 7.5 million barrels of oil, further aggravating energy scarcity (Montero Vieira 2016). At the same time, the rising insecurity and low social acceptance of mega projects like oil and gas increase the operating costs for companies like PEMEX, as more resources are needed to protect personnel and assets and to address community concerns.

The government introduced market reforms in 2013 to the hydrocarbon and electricity sectors to increase investments and also to reduce inefficiencies in the energy sector and dependency on fossil fuels through increased renewable energy production. The primary tenets of the reforms were to end the monopoly of state-owned companies on production of oil, gas, and electricity; to allow foreign and private investments into both sectors; and to create auctions where the most cost-competitive bids get the right to develop a deposit or generate electricity (Wood 2018).

The results for both sectors were quite positive. In the oil and gas sector as of January 2019 and after three official rounds of public tenders, 107 contracts with 73 companies were signed to explore and develop resources; the government already received $1 billion in direct rents; and a discovery of 1 billion barrels of oil was made in the Zama field near Tabasco (Lynch 2019). These contracts could lead to 400,000 b/d in production increases for crude oil with $6 billion of additional rents for the government and operated at costs below PEMEX’s historical performance (Lynch 2019). Mexico’s substantial shale potential—sixth in the world in gas and eighth in oil (EY 2019)—suggests that the country could benefit significantly from additional investments.

In the electricity sector, the auctions for long-term contracts of power production resulted in allocations of 4867 MW to solar and 2121 MW to wind producers (Wood 2018). In fact, the third round was so competitive that average prices of solar and wind energy were below the costs of combined cycle gas power production after accounting for carbon taxes (Wood 2018). These renewable energy assets will help decrease Mexico’s reliance on hydrocarbons for its consumers.

While these reforms may indeed improve Mexico’s energy security, GHG emissions will likely increase and move Mexico further away from its Nationally Determined Contribution’s emission targets. Mexico’s latest report (Semarnat 2018) to the United Nations Framework Convention on Climate Change (UNFCCC) indicates that GHG emissions grew annually at a 1.8% rate since 1990 and were estimated at around 670 MtCO2e for 2015 (Semarnat 2018). The greatest contributors are the same large energy consumers: the transport, energy, and construction/manufacturing sectors. These consumer groups account for 24.5%, 25.9%, and 9.1% of total emissions, respectively (Semarnat 2018). In fact, growth in emissions in the energy production sector, underpinned by gas production due to rising consumer demand for energy, drove the sector’s 117% growth in GHG emissions from 8500 gigagrams of CO2e in 1990 to 85,000 in 2015 (Semarnat 2018).

The reforms will likely accelerate the GHG emission growth trend as more oil and gas is produced, economic growth intensifies, and the Mexican population consumes more energy with higher incomes. The report to the UNFCCC suggests that although the economy is getting less CO₂ intensive (Semarnat 2018), the average citizen in 2015 is emitting 18% more CO₂ than in 1990 (Semarnat 2018). For instance, economic development could accelerate the acquisition of cars for personal use in Mexico and increase GHG emissions from the transport sector—the sector already experienced an 83% increase in emissions from 1990 to 2015 (Semarnat 2018). Indeed, institutions like the Climate Action Tracker estimate that under current conditions Mexico will miss its 2030 GHG emission target of 755 MtCO2e by around 50–90 MtCO2e (Climate Action Tracker 2019).

Moreover, although Mexico developed early on a robust institutional base and ambitious GHG emissions reduction targets (Semarnat 2018), detailed plans to measure aggregate progress toward those targets have yet to follow. For example, while the overall CO2e reductions of some policies are identified as 72 MtCO2e (Semarnat 2018), and the report to the UNFCCC outlines the potential mitigation effects of policies in key sectors like transport and oil and gas (Semarnat 2018), no clear reduction path toward the 2030 target is outlined. A first step in the right direction would be to aggregate the GHG mitigation effects of all measures like Canada did, to identify progress, and to plan according to correct shortcomings.

Overall, as public pressure demands more immediate solutions to Mexico’s pressing energy security challenges and ongoing violence crisis, the government will have reduced bandwidth to devote sufficient resources to address climate change. Compounding the challenge is the country’s single-term president which reduces policy continuity as a new administration steps into office. Strong public support for a domestically managed oil and gas sector also represents barriers to more market-oriented reforms that may also undermine efforts to reduce GHG emissions, as investments are directed to hydrocarbons and not renewable energy sources.

After the COVID-19 pandemic, economic recovery will dominate politics and policymaking for all three countries in the medium term. Given their resource endowment, energy development will continue to play an important, if diminished, role in the U.S., Canada, and Mexico. Increased sensitivity to climate concerns and public pressure will lead to increased mandates for reducing GHGs at the federal and state/provincial levels in the U.S. and Canada. Extreme weather conditions, leading to more damaging hurricanes, flooding, sea-level rise, and drought-related forest and brush fires, heighten public concerns in the U.S. In Mexico, economic growth and expanding energy access will continue to take higher priority.

Although the shale boom may be over, along with so-called American “energy dominance,” the ability of this resource to surge or reduce production within a short period of time as compared to conventional production will help stabilize global oil and gas prices. Actual and potential U.S. oil and gas exports will also lead to the convergence of prices in the main consuming markets of Europe, East Asia, and North America.

The U.S. will continue to invest heavily in basic research and development and technological innovation in more cost-effective, environmentally, and climate friendly energy production and energy use, with the added impetus of competition against China to be the leader in these fields. Unlike in Europe, the commercial application of new energy technology, particularly disruptive technology, will be driven more by capital markets than by government mandates and subsidies or by incumbent energy companies whose business will be negatively impacted.

Much will depend on political developments in the U.S. and interaction among federal, state, and local authorities as they address rising public concerns over the effects of climate change and other challenges related to fossil fuel use. Government will concentrate on setting the rules of the game in American energy transition and avoid selecting technologies or funding their deployment. The private sector and investors will bear the business and financial risks of energy transition.

The advent of the Biden administration has marked the return of the U.S. to global climate negotiations and greater cooperation and coordination with international partners. There may also be opportunities to optimize new energy development by further integration of North American energy markets among the three countries with additional infrastructure connections. Whether the U.S. will take a leadership role in international energy cooperation, as it did for the 2016 Paris Climate Accords and in the preceding decades since the Arab Oil Embargo of 1973, will depend on evolving politics. Nevertheless, the policy case is clear even as U.S. relative weight in global affairs declines and the need for global cooperation to address the climate challenge, energy transition, and associated trade distortions becomes more acute. The politics will have to catch up.