by Vaclav Smil
Obviously, such a level of trade has required enormous pipeline infrastructure (USEIA [US Energy Information Administration], 2008; NEB, 2014a) and some thirty border crossings (Figure 5.1). Among the many tangible signs of the economic integration of Canada and the United States, this one is perhaps the least known and least appreciated by the public: unlike crude oil whose extraction from oil sands and increasingly common transportation by railcars (and more common accidents) attract plenty of public attention, the multibillion natural gas trade takes places quietly out of sight, the only common evidence of it being small signs indicating the routes of buried pipelines.
Figure 5.1 Canada–US natural gas pipeline crossings.
The first Canadian natural gas pipeline to the United States was built by the Westcoast Transmission Company (now operating as Spectra Energy); it began the construction of a 60 cm diameter pipeline from Taylor in northeastern BC to the BC–US border in 1955, and deliveries began in 1957 (CEPA [Canadian Energy Pipeline Association], 2014). In 1956 (after 6 years of planning and often contentious political, financing, and regulatory process), TransCanada Pipelines began its construction of a transcontinental line from Alberta–Saskatchewan border to Toronto (TransCanada, 2014). Alberta gas reached Winnipeg in 1957, and after the most difficult section through the rocks of the Canadian Shield, the construction was finished in October 1958. The line was extended to Montreal in 1976, and its length (3,500 km) was surpassed only by the Soviet line from Western Siberia. TransCanada Pipeline owns the most extensive network of natural gas pipelines in North America (13 major systems and nearly 60,000 km of trunk lines of which about 41,000 km are in Canada).
In 1981, Foothills Pipe Lines brought gas from Central Alberta to the US border, and in the Westcoast Energy operates a system that extends from parts of Yukon and Northwest Territories through Alberta and British Columbia where it joins the US trunk lines near Huntingdon and supplies gas to the US Northwest market (in recent years mostly between 20 and 30 Mm3/day). Spectra Energy owns nearly 5,700 km of pipelines that move the western gas east to Canadian and US markets, and it also owns the Maritimes and Northeast Pipeline that brings natural gas from Nova Scotia to the Eastern United States. Alliance Pipeline (about 3,700 km, completed in 2000) brings liquid-rich natural gas from northeastern British Columbia and northwestern Alberta to the US Midwest, specifically to a hub near Chicago, with recent deliveries clustered around 50 Mm3/day.
There is also a special pipeline (Kinder Morgan Cochin) that moved natural gas liquids from Fort Saskatchewan in Alberta to Windsor, Ontario, through seven US states, but in 2012, the company applied for the reversal of the line’s western leg from Illinois to Alberta in order to bring more condensate for bitumen blending in Alberta’s oil sands. In total, there are now 31 points for natural gas exports (and imports) along the US–Canada border: a single point in New Brunswick, 3 in Quebec, 10 in Ontario, 2 in Manitoba, 7 in Saskatchewan, 6 in Alberta, and 2 in British Columbia, with 5 of them (at crossings to Montana, Idaho, North Dakota, and Minnesota) accounting for 70% of all US pipeline imports.
Even as it had been importing more natural gas from Canada, the United States remained an exporter of gas to Mexico. After the first global oil price spike in 1973–1974, these exports were cut by nearly 90% (from about 400 Mm3 in 1973 to just 46 Mm3 by 1983), but afterward, their almost uninterrupted rise brought them to nearly 3 Gm3 in the year 2000 and to a record high of 18.6 Gm3 in 2013. And, concurrently, exports to Canada became even larger. There were always small seasonal gas shipments from the United States to Canada, running on the order of 2–3 Gm3, but this has changed with the sudden availability of American shale gas. In 2011, as Canadian gas exports fell by 5%, the US sales to Canada rose by 27% to more than 26 Gm3 and increased further to 27.5 Gm3 in 2012 when they equaled a third of the US gas imports. As a result, annual throughput of several Canadian pipelines (particularly of the TransCanada Mainline) has decreased (to as low as 43% of capacity at the Iroquois transit point in Ontario during the first 6 months of 2012), and that resulted in increased operating tolls for the remaining customers (NEB, 2014a).
But such expense is negligible compared to Canada’s decreased export earnings. During the 1990s, export prices were fairly steady (fluctuating mostly between $1.5 and 2.0/1000 cuft), but a subsequent rise brought them to the $6.83 in 2006 and 2007 and to the record level of $8.58 in 2008. Combined with the record level of shipments, this translated to earnings of about $25 billion in 2006 and 2007 and $30 billion in 2008. But the price was halved in 2009 ($4.14), and it was down to $2.79 in 2012 (adjusted for inflation the last time the natural gas price was that low was in the late 1990s). How much further will the Canadian export decline will depend on the progress of US shale gas extraction and its share exported as LNG.
Canada has more natural gas reserves ready to be developed: after a lengthy regulatory review, Canada’s National Energy Board approved the construction of the Mackenzie Valley Pipeline to bring the Beaufort Sea Arctic gas to Alberta and then to the United States, but its prospects remain poor because of the surge of the US shale gas extraction and Alaska gas pipeline that has already greatly reduced the decades-long dependence of the United States on rising Canadian gas imports. Total US natural gas imports were steady until 1986 (fluctuating narrowly around 28 Gm3), and then a nearly uninterrupted rise brought them to 130 Gm3 in 2007 (USEIA, 2014h). This peak was followed immediately by a fairly rapid decline: by 2013, the imports were 37% lower, a shift with an obvious impact on Canadian sales. With new US pipelines bringing gas from Marcellus shale to markets in the US Northeast and the Midwest, it is very unlikely that Canadian gas exports will return to their peak levels anytime soon, but it is also highly unlikely that they will be soon reduced to marginal levels.
In any case, the change has been pronounced. The United States became the net importer of natural gas in 1958 when it purchased almost 1% of its total consumption. Post-1985 combination of stagnating domestic production and increasing dependence on imports led to projections of massive LNG imports during the second decade of the twenty-first century. But immediately after the import share reached its historic peak in 2007 at 16.3%, the trends began to reverse with speculations about the future level of the US exports and the magnitude of ensuing earnings entirely displacing worries about the rising import dependence. Nothing illustrates this reversal better than the conversion of some of the US regasification facilities into liquefaction plants for exporting shale gas to Asia and Europe. I will take a closer, critical look at these speculations in the last segment of this chapter dealing with LNG and, once again, in the book’s last chapter when I will try to answer the question about how far the gas will go.
5.2 EURASIAN NETWORKS
America’s natural gas imports have been, primarily, the result of very high rates of per capita energy consumption that could not be entirely supplied by massive domestic production and had to be supplemented for decades by increasing shipments from Canada and, to a much lesser extent, by purchases of foreign LNG. In contrast, European natural gas imports have been a necessity, not an existential one but an unavoidable as long as the continent’s countries wanted to improve their standard of living while reducing the environmental impact of high energy consumption: rise of natural gas imports had its obverse in falling coal combustion, now the dominant source of primary energy in a single EU country (Poland).
Europe’s natural gas pipeline network has evolved largely in response to four major developments: discovery of Groningen gas, discovery of the North Sea gas, imports of Russian gas from Western Siberia, and increased imports of LNG from North Africa and the Middle East (Figure 5.2). Following chronologically the construction of all of the continent’s major pipelines and charting the emergence of Europe-wide natural gas networks (now connected to Western Siberia, Central Asia, and Algeria) would be tedious: instead, I will describe the major lines of the system, including its latest extensions, as well as so
me of the most notable plans for its further expansion.
Figure 5.2 European gas networks.
Europe, for decades considered devoid of any major hydrocarbon resources, was lucky as the discoveries of giant gas fields, first in the Netherlands and then in the North Sea, brought huge gas reserves within easy pipeline reach of the continent’s three largest economies. But it was not enough to satisfy the rising demand, and the continent has developed a rising dependence on the export of Soviet and, after 1991, Russian natural gas (Clingendael, 2009; Högselius, Kaijser, and Åberg, 2010; Smeenk, 2010). European natural gas grid began to develop during the late 1960, with the sales of Groningen gas to Belgium and Germany in 1966 and to France in 1967 and with the sales of Soviet gas from Ukrainian fields (discovered before WWII, Shebelinka being the largest one) to Czechoslovakia, also in 1967 (called, a year before the Soviet invasion of the country, Bratstvo, Brotherhood).
In 1968, Austria was the first country outside the Soviet block to get the Soviet gas via a short spur from Czechoslovakia; West Germany followed in 1973 (in that year, East Germany was also connected), Italy in 1974, and France in 1976. All of these deliveries used the same trunk line completed in 1967, and although its capacity rose from less than 7 Gm3 in 1973 to nearly 55 Gm3 by 1980 (Gazprom, 2014), it was obvious that a new line will have to be built to connect giant fields of West Siberia with Central and Western Europe. Construction of 4,451 km long line from Urengoy to Uzhgorod station on the Ukrainian–Slovak border began in 1982. Construction of this Cold War pipeline was opposed by the United States because of its concern about the increased Soviet political leverage (CIA, 1981)—but Germany provided financing, and together with other European countries (led by France and Italy) and Japan, it also supplied the required pipe, pipe-laying equipment, and gas turbines for compressor stations. The line was built in stages and completed according to schedule in 1984 (Figure 5.3).
Figure 5.3 Russian export pipelines.
Parallel lines were added during the late 1980s, and in 1994, construction began on a more northerly line from Yamal to Germany. Unlike all the previous lines crossing the Ukraine, this line goes via Smolensk and Minsk and transports the gas to Germany across Belarus and Poland. The 4,190 km Yamal line began to operate in 1997, but its full design capacity of 32.9 Gm3 was reached only in 2006. As already noted in the first chapter, yet another route to Germany was taken by the Nord Stream projects whose two parallel lines were laid between 2010 and 2012 on the floor of the Baltic Sea on their 1,224 km transit from Vyborg to Lubmin (Nord Stream, 2014; Figure 5.2).
The northernmost EU country to get the Russian gas is Finland, the southernmost one is Greece, but Russian gas also reaches Turkey: it got to Istanbul first via Ukraine, Moldova, Romania, and Bulgaria, but by 2003, a direct 1,213 km Blue Stream line was laid across the Black Sea from to Samsun on the northern Turkish coast and then to Ankara. By 2014, pipelines carrying the Russian gas westward had a capacity of 241 Gm3 (142 Gm3 via Ukraine, 38 Gm3 via Belarus, 6 Gm3 to Finland, and 55 Gm3 for the Nord Stream), and the Blue Stream was designed for 16 Gm3 (EEGA [East European Gas Analysis], 2014). Russian gas was sold to 23 European countries (spatially ranging from Greece to Finland and from Latvia to the United Kingdom) as well as to Turkey.
Actual gas deliveries to the EU countries, other European non-EU states, and Turkey rose from 130 Gm3 in 2000 to 154 Gm3 in 2005, stagnated before reaching a new record of about 161.5 Gm3 in 2013 or 30% of those countries’ consumption, with 16% of Europe’s total supply now passing through Ukraine. South Stream pipeline would bypass Ukraine and deliver gas directly across the Black Sea to the Balkans, supplying first Bulgaria, Serbia, and Hungary and then linking to the existing network in Italy, and it would add another 63 Gm3 of export capacity starting in 2016 (South Stream, 2014). In June 2014, the EU asked Bulgaria to stop work on South Stream as its construction conflicts with the Union’s rules on public procurement and liberalization of energy markets, and in December 2014, Russia officially scrapped the project and decided instead to build a new pipeline to Turkey.
Gazprom, the descendant of the Soviet natural gas ministry that now accounts for about 75% of Russia’s natural gas extraction, controls all Russian gas exports, but its long-held advantages—high profits and apparently unassailable dominance as the prime supplier of the EU needs—have been eroding due to high investment needed to keep up the output of its aging Siberian fields and bringing new fields on line (an effort requiring also new long pipeline or new LNG terminals), as well as due to the EU’s effort to diversify its sources and reduce its dependence on the Russian gas. But realities make rapid diversification of supplies impossible, while politics (domestic and foreign) and business ties preclude many clear national strategies.
Dependence on Russian natural gas ranges from absolute in the east to very important as far west as Germany and Italy. In 2013, five EU countries (Finland, Latvia, Estonia, Lithuania, and Bulgaria) got all of their natural gas consumption from Russia; the shares were more than 98% in Slovakia, 86% in the Czech Republic, 84% in Poland, close to 70% in Greece and Hungary, and 42% in Germany (BP [British Petroleum], 2014a). Moreover, Gazprom points out that the consumption of the Russian gas as the share of the EU total supply has actually risen (to 28.3% in 2013, after falling from 25.3% in 2000 to 22% in 2010), that the company is a more reliable supplier than the nearest alternatives (Algeria or Libya), and that it can cover best any rising seasonal swings in daily gas deliveries.
Most importantly, there is no other supplier positioned so well to cover the continent’s widening gap between extraction and demand that stood at about 300 Gm3 in 2013 but is expected to rise to 400 Gm3 by 2025 and to 45 Gm3 by 2035; it now imports nearly half of its gas, but by 2030, it may have to buy 75% of it. This high degree of interdependence—the EU’s high, and rising, dependence on imports and Russia’s natural advantage to supply them—leaves no room for sudden dramatic shifts. As Gazprom’s head of contract structuring and investment flows put it, EU–Russian gas trade is simply too deep and too comprehensive to fail (Komlev, 2014).
Moreover, Germany, the EU’s leading economy and the largest importer of Russian gas, has its strongly pro-Moscow lobby led by the former chancellor Gerhard Schröder, now the chairman of the board of the Nord Stream. And given the strong German exports to Russia, many large companies (Siemens, Daimler, BMW) as well as scores of Mittelstand exporters are eager not to upset the existing trade arrangements. Gazprom, whose stock value was cut by 75% between May and October 2008 and recovered only about 20% of that loss by summer 2014 (Gazprom, 2014), has responded to European diversification moves (small volumes of LNG are now coming from Trinidad and Tobago, Qatar, and Nigeria) by strategic pricing.
When taking the price it charges to Germany, its largest buyer ($380/1000 m3) as the standard, the United Kingdom gets about 15% discount but Switzerland has to pay 15% more, and Poland pays an almost extortionary price that is 40% higher (Eyl-Mazzega, 2013). On the other hand, as oil and gas exports account for 80–90% of Russia’s foreign trade with many EU countries and gas alone makes about 10% of all Russian exports, Gazprom will have to be more flexible in order to keep this revenue stream from gradually declining, and it will have to do more to lessen concerns about the reliability of its deliveries.
Suggestions for improving the EU’s bargaining power by applying competition law rigorously, by licensing (with conditions) all Russian gas imports, or by confronting Gazprom monopoly with a monopoly of a single central EU gas buyer are listed by Helm (2014) as a part of a credible European energy security plan, but their early adoption is unlikely. Even less likely is an early diversification of the EU’s energy supply away from natural gas: most of the member countries see nuclear power as unacceptably risky, increased coal combustion would destroy the commitment to lower carbon emissions, and wind and PV electricity supply only marginal shares of overall primary energy demand (Smil, 2014).
Pipelines crossin
g Ukraine were not the only lines built during the Soviet era that became international lines after the dissolution of the USSR. During the 1970s and 1980s, lines were built to bring natural gas from giant fields of Turkmenistan (Shatlyk, Bayram Ali, Kirpichli) and Uzbekistan (Urta-Bulak, Dengizkul, Kandym) to the European part of the USSR and then to Europe via the Soyuz line, with a branch going northeast just west of the Aral Sea to supply the industrial areas in the southern Ural region. In the south, the Turkmen gas is transported eastward to Kyrgyzstan, Tajikistan, and Southern Kazakhstan. The other line that is now international transports Azeri Caspian Sea gas from Baku to Russia as well as to Armenia and Georgia.
Two recent developments have brought a fundamental shift to Eurasian gas exports (Figure 5.4). In 2009, Turkmen natural gas began to flow to China via 1,833 km long pipeline (diameter of 1.067 m) starting at the Uzbekistan border and ending in Horgos in Xinjiang. The second parallel line was completed in 2010, and they also receive gas from fields in Uzbekistan (long-term contract for 10 Gm3) and Kazakhstan. Gradual increase of shipments should be the total volume of exported gas to 65 Gm3 by 2020 (Gurt, 2014). And in May 2014, Russia and China finally concluded a long-contemplated deal (originally involving the West Siberian gas) to sell Russian gas to China. East Siberian gas from Chayanda field (in Sakha, formerly Yakutia, with reserves of 2.4 Tm3, not yet in production) and Kovykta (west of the Lake Baikal, reserves of about 2 Tm3) will be the source, and the deliveries should start in 2018 (Itar-Tass, 2014a).
