sources of energy by 2022, which could reduce demand for low-calorific gas by another 4–5 bcm/y. GasTerra also has a target of negotiating the gradual phase-out of its long-term L-cal gas export contracts. In line with these developments, it is expected that Dutch natural gas production will fall by almost three-quarters through the forecast period to a level of 10 bcm/y.

Other Europe

Natural gas production in the United Kingdom recovered between 2013 and 2017, increasing at a rate of 3% per year. This was reversed in 2018, with gas output decreasing by 3% to just below 41 bcm. It is expected that domestic gas production will continue to decline at a rate of 3.7% through the forecast period, as decreasing output from depleting fields will not be entirely compensated by the additional output from new fields. This includes the Culzean field, which is expected to begin commercial 0perations in 2019, with plateau production due to be reached in 2020/21. According to Maersk Oil, the field could by then meet almost 5% of total UK gas demand (4 bcm/y) (BBC, 2017). In September 2018 Total announced a major discovery on the Glendronach prospect near the Shetland Islands, with gas reserves estimated to amount to 28 bcm. First gas production is expected in 2020 (Rystad, 2018). In January 2019 Total and CNOOC made a discovery in the Glengorm prospect, with estimated reserves of almost 38 bcm (Platts, 2019).

In Denmark, the Tyra field will be temporarily shut down from 19 September 2019 to July 2022 (Energinet, 2019).The field accounts for approximately 90% of domestic Danish natural gas production, with an output of 3.65 bcm in 2018. The redevelopment of the field will allow its lifespan to be extended by at least 25 years (OffshoreTechnology, 2019). During the shutdown, Danish gas imports are expected to increase to meet both domestic consumption and exports to Sweden.

Romanian natural gas production is expected to grow at a rate of 1% through the forecast period. However, this does not include the development of the offshore Neptun block, which has an estimated natural gas reserve base between 42 bcm and 84 bcm. An FID was expected in the last quarter of 2018; however, ExxonMobil and OMV Petrom decided to postpone given the regulatory changes in the Romania energy sector. Under a new law, companies producing in the Romanian offshore would need to sell at least 50% of their yearly output in Romania, considerably reducing potential revenues from exports (Reuters, 2018c).

Central and South America

This forecast expects an average annual increase in natural gas production in Central and South America of 1.1%, with additional production of 11 bcm/y to 2024 (Figure 2.26).

The growth is mainly led by Argentina, representing over 80% of the growth, with Brazil as the second-largest source of growth. Other regional production is expected to slightly decrease over the forecast period, mainly due to production decline in Colombia and Bolivia.

and 2017. The government started to scale back production incentives from 2018, adjusting its previous flat price to USD 7/MBtu in 2018 and then reducing it to USD 6/MBtu in 2021, still higher than the USD 4/MBtu market price.

In 2018 the International Monetary Fund set as a condition of its USD 57 billion line of credit bailout the reduction of subsidies and a balanced budget for 2019. The first measure enacted by the government was to raise utility rates to reduce subsidies to end users. In January 2019 the Energy Secretary Lopetegui announced that the production price incentives would be capped at the volumes declared in the original production plans as presented by the companies when they applied to the production subsidy scheme (Clarin, 2019). These modifications to both the production incentives and end-user gas subsidies could impact growth in domestic production. According to the state budget of 2019, the government has ARS 28.7 billion (USD 0.74 billion)8 set aside for the Gas Plan to guarantee a price of USD 7/MBtu. Considering a price of USD 3.90/MBtu in the Neuquén Basin as of early 2019, the budget could only subsidise an annual equivalent of 6.3 bcm (whereas the Fortin de Piedra development has already surpassed an annual equivalent of 5.8 bcm) (Rio Negro, 2018).

Domestic gas producers are achieving better market prices. While the price increased by 50% from USD 3.2/MBtu in 2013 to USD 4.80/MBtu in 2017, subsidies have decreased (they fell from representing 41% of the total price in 2013 to 27% in 2017). According to the government, the price is expected to reach USD 4.19/MBtu in 2018 and USD 4.32/MBtu in 2019 (Figure 2.27).

Figure 2.27 Domestic natural gas prices and share of subsidy in producer income, Argentina, 2012–19

Note: Data for 2018 are estimated and forecast for 2019.

Source: The Dialogue (2019), Energy in Argentina, Investment Opportunities for the International Community, www.thedialogue.org/wp-content/uploads/2019/03/2019-03-13-IAD-Energy-in-Argentina-Investment-Opportunities-for-the- International-Community.pdf.

Subsidies are being reduced, while domestic gas producers are achieving higher prices.

This forecast expects annual average growth of 3.5% to 2024, although development of the Vaca Muerta field remains partially uncertain due to operational bottlenecks, such as the lack of nearby sand resources needed for hydraulic fracturing (currently delivered from Entre Rios, 1 600 km away), rail development to ensure access to the production areas, and gas storage (due to the highly seasonal demand). There is also a need for better midstream infrastructure to connect production with natural gas demand centres. Argentina is already working on those bottlenecks; for example, in March 2019 the Energy Secretary announced plans for a new 22 mcm/d (8 bcm/y) pipeline from Vaca Muerta to Buenos Aires (Pipeline News, 2019).

Brazil

In 2018 Brazilian gross natural gas production increased by 1.8%, reaching almost 41 bcm. However, due to an increase of 27% in gas reinjected, or an additional 2.8 bcm, available natural gas decreased by almost 9% to 22 bcm in 2018 – after having reached a peak of almost 24 bcm in 2017.

Available natural gas represented 53% of gross production in 2018, reinjection 31%, losses and vented or flared gas 3% and own use gas 12% (Figure 2.28). The strong share of reinjection is due to the preponderance of associated gas produced from offshore oil fields. Offshore net production represented 80% of total available natural gas.

Figure 2.28 Natural gas production, Brazil, 2010–18

Source: ANP (2019), Dados Estadisticos [Statistical Data] (database), www.anp.gov.br/dados-estatisticos.

Brazil’s gross production increased by 1.8% in 2018, while available natural gas decreased by 8.8% due to higher reinjection in oil fields.

According to Petrobras’ Business and Management Plan 2019–2023 (Petrobras, 2018), deepwater operations will be prioritised by investing USD 68.8 billion to 2023 in exploration and production (56% pre-salt and 44% post-salt) and USD 3.7 billion in natural gas offloading, processing and transport to shore. Despite the expected expansion of oil and gas production in pre-salt fields in the medium term, this forecasts estimates annual average growth of 1.7%, as a significant proportion of the additional gas produced in the pre-salt fields will be reinjected to stimulate oil production.