Infrastructural and Environmental Implications of an LNG Import Terminal Ban for the US Pacific Coast Up To

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1 Infrastructural and Environmental Implications of an LNG Import Terminal Ban for the US Pacific Coast Up To 1 Ruud Egging a, Franziska Holz b and Daniel Huppmann b a Department of Civil and Environmental Engineering, University of Maryland, College Park, Maryland 20742, USA, regging-at-umd.edu b DIW Berlin, Mohrenstr. 58, Berlin, Germany Presented at the 28 th USAEE/IAEE North American Conference, New Orleans, USA, December 2008 Abstract In this paper we analyze the consequences of an LNG Import Terminal Ban for the US Pacific Coast along with potential developments of the world natural gas market until. We use the World Gas Model (WGM), a dynamic, strategic representation of world natural gas production, trade, and consumption between and. In particular, we present a Base Case for a business-as-usual scenario based on forecasts of the world natural gas markets. We then analyze the impact of an LNG terminal ban for the US Pacific Coast, focussing on the North American gas market, but addressing global consequences as well. Our results show modest changes in world-wide production, consumption, and average prices, and investments in pipelines and LNG terminals are somewhat affected. A result of interest is a significant geographical redistribution of LNG trade flows taking place, smoothing out the overall impact of the local ban on LNG import terminals. Infrastructural implications are mainly limited to the Pacific Coast of North America and environmental consequences of gas trade flow redirections are relatively modest. although still significant when measures in absolute terms. Keywords: natural gas trade, World Gas Model, mixed complementary problem, infrastructure investments, California, LNG regasification, NIMBY 1 This paper is based upon work supported by the National Science Foundation Grant DMS for co-author one. 1

2 1 Introduction The world natural gas market is in turmoil. On one side, high prices and the increasingly tight environmental constraints have diluted the perspectives of natural gas to become the transition energy source on the way to a low-carbon world (e.g. hydrogen economy). Thus, a large part of gas-fired power plants forecasted around the turn of the decade have been shelved because they turned out to be economically unviable (Stern, 2007). But on the other side, natural gas still spurs various concerns about future reliable supplies, industry concentration, and supply security (Stern, 2007; Victor, Jaffe and Hayes, 2006). It comes as no surprise to see diverging forecasts for natural gas supply, demand and prices even for the short-term future. Thus, the official forecast for natural gas demand in Europe, based on the Primes model, has been significantly reduced (European Commission, 2007). Along these lines, the forecasts from the POLES model seem to be overoptimistic (European Commission, 2006). The Energy Information Agency has also corrected its figures for US natural gas demand downwards (Energy Information Agency, 2007). In this paper, we provide a discussion about the perspective of the world natural gas market until. In particular, we define and analyze a base case which builds on business-as-usual assumptions based on forecasts of the world energy markets. We then analyze a policy case, Pretty Coast, bannin investments in LNG import infrastructure at the US West Coast. The remainder of this paper is organized as follows: the next section introduces the World Gas Model (WGM) that has been used for the analysis presented in this paper. Section three presents the Base Case that provides us with a benchmark to which in section four the Pretty Coast results will be compared. The last section will draw conclusions and provide some directions for future research. 2

3 2 Model and Data 2.1 The World Gas Model The World Gas Model (WGM) is a multi-period equilibrium model of the global natural gas market covering the next three decades. It includes more than 80 countries and over 98% of global natural gas production and consumption (in ). WGM allows for endogenous investment in pipelines and storage as well as expansion of regasification and liquefaction capacities and considers demand growth, production capacity expansions and price and production costs increases over time. Taking into account the game-theoretic aspects of the natural gas market, the model includes market power à la Nash-Cournot for some players participating in natural gas trade (i.e. traders and regasifiers). See Egging et al. (2008) for a detailed description of the model. Players in the model include producers (P), traders (T), liquefiers (L), regasifiers (R), storage operators (S), marketers (M) and consumers in three sectors (residential/commercial (CR), industrial (CI), and power generation (CP)). See Figure 1 for an illustration of the typical trade relations represented in WGM. S M CR CP CI Country A P T L M CR CP CI Country B P T R S M CR CP CI Country C Figure 1: Illustration of typical gas supply chains in WGM The consumers are present via their aggregate inverse demand function. All other players are modelled via their respective profit maximization problems under some player-specific operational or technical constraints. There is usually one producer and one trader per country; only the US, Canada, and Russia are divided into several regions due to their geographic scope and importance in the world market. Pipelines, liquefiers and regasifiers are included as of today, but the model also allows for completely new pipelines and LNG capacities based on profit maximizing decisions of players in the model. While the role of producers, liquefiers, regasifiers and storage is intuitive, the traders are more specific: they act as the marketing arm of one or more producer(s) for trading via the pipeline grid. Depending on their 3

4 origin and point of operation, traders may have market power; this means that they are in a position to withhold supplies in a respective market and thereby increase prices and maximize their profits. WGM takes into account LNG contracts known as of today. Contracts are are phased out based on their end dates. Regasifiers, being the interface of the LNG supply chain with the downstream market, are modelled as Nash-Cournot players vis-à-vis the storage operators and marketers. Storage operators act as arbitrageurs between the low demand and the high and peak demand seasons in the model. Pipeline operators are agents that assign pipeline capacity to traders. The minimum transport costs are set by a regulated tariff; an endogenously determined congestion fee ensures that the scarce pipeline capacities are allocated optimally. The base year of the WGM is ; investment projects already under construction at the time of writing have been included in the and future capacities. Model runs include the period until 2040 in five year intervals, but results are only reported up to. 2.2 Data and calibration The model has been calibrated to projections of the future energy markets, namely PRIMES forecasts for Europe (European Commission, 2007) and POLES forecasts for the rest of the world (European Commission, 2006). These sources are used to determine the (exogenous) production capacities and the reference consumption quantities and prices of the demand function. POLES projections reflect a worldwide increase in natural gas production and consumption of 70% in relative to. Generally, demand stagnates or even declines in some countries in the projections after. The calibrated worldwide base case consumption (production) 2 in is 2368 (2435), and 3757 (3905) bcm 3 in, and an average wholesale price of $375 per 1000 m³. An average yearly price increase of 3%, in accordance with POLES projections, is used. For infrastructure capacities, project and company information from various sources (e.g., Oil and Gas Journal, GSE database at has been employed. This information was used to include existing additional capacities since and also considered when assessing the maximum allowable capacity expansions per period for the base case. 2 WGM model accounts for losses in liquefaction, regasification, storage and pipelines. Consumption in WGM is corrected for own consumption in the energy sector, IEA: 3 bcm: billion cubic meter. bcm/y: bcm per year, which can also be written as: bcma, bcm per annum 4

5 3 Base Case Results The base case (BC) follows business as usual assumptions as described in the previous section 2.2. Figure 2 shows a steady increase of world wide natural gas production and consumption over the whole forecasting period up to a level of about 3,900 bcm/y in. Figure 2: World consumption and production and world average wholesale price; in bcm/y and $/kcm LNG trade grows until and then plateaus around 525 bcm/y. By approximately 15% of total natural gas production is traded as LNG. The share of natural gas consumed domestically in production countries drops from 60% to close to 50% of total consumption by the end of the time horizon, while the share of natural gas exported by pipeline remains relatively stable (30%). Figure 3 shows global trade flows in. The Middle East, Russia and the Caspian region split their sales between Europe and Asia, and small volumes of LNG are exported to North America. Total consumption in Europe in amounts to 667 bcm/y; of which 27 bcm/y are LNG imports, (4% of total consumption), and 200 bcm/y are produced within Europe. The lion s share of consumption, however, is imported from Russia and the Caspian region. Figure 3: Natural gas flows in by region; in bcm/y, base case 5

6 In the base case, Asia consumes almost 850 bcm/y in. Looking at the country level reveals a very differentiated picture: while Japan and Taiwan continue to rely to a large extent on LNG imports, China and India each produce half of their consumption domestically and import another 40% by pipeline from Russia, Burma, the Caspian region and the Middle East. LNG imports fulfill only a minor part of domestic demand. North America produces about 60% of its consumption regionally with the remaining 40% satisfied by LNG imports. Figure 4: Base case liquefaction and regasification capacities (bcm/y) Investments in liquefaction and regasification capacities are presented in Figure 4. While liquefaction capacities almost triple, from 242 to 652 bcm/y, regasification capacities roughly double from 491 to 945 bcm/y. Ample spare capacities remain allowing to address seasonal demand fluctuations. Investment is strongest at the beginning of the time horizon, with another boost in ; after that, investments decrease due to the assumption of demand stagnation in many developed markets the long run. After having outlined the Base Case results in this section, the next section will present an extensive analysis of the Pretty Coast case. Some more Base Case results will be presented later in that section, for ease of comparison. 6

7 4 Pretty Coast In this section, we present the Pretty Coast case () results. Since US domestic natural gas production is expected to decline in the near-term, the country with the largest consumption worldwide will be increasingly dependent on imports. These can only partially be satisfied by deliveries from Canada; hence, LNG regasification capacities are expected to grow. However, due to a wide-spread NIMBY (notin-my-backyard) attitude among citizens in western states, especially California 4, gas companies are planning to invest in LNG import facilities in neighboring countries and re-export regasified gas to US markets by pipeline. As in the base case 42 bcm/y of regasification capacity is built on the US Pacific coast, disallowing re-gasification capacity to come into existence potentially leaves a significant supply gap. What alternatives remain to bring natural gas into the Western US markets? Beside infrastructural effects, what are other possible consequences of legislation prohibiting the construction of any LNG import facility at the Pacific coast of the US? West Rockies Midwest East Alaska Gulf Figure 5: USA Regions in WGM 4.1 Data and assumptions In the implementation of the Pretty Coast () scenario the following input parameters have been changed relative to the Base Case (BC): maximum re-gasification capacity expansions in US West have all been set to zero, in Canada West and Mexico Pacific the maximum capacities have been set to higher values than in the base case. See Table 1 below for details. (Different values are highlighted in yellow.) 4 In WGM US is split in six regions (See Figure 5.) Region US West consist of California, Washington and Oregon. 7

8 Table 1: Assumptions for Regasification Capacities and Maximum Expansions in both cases (bcm/y) Region Case Initial Maximum expansions 2008 Canada East Both Canada West BC Mexico Atlantic Both Mexico Pacific BC USA East Both USA Gulf Both USA West BC To facilitated re-exportation of regasified imported LNG from Canada and Mexico into the US, the allowed pipeline expansions were set to higher levels in case. Table 2 below provides details. Table 2: Assumptions for Current Pipeline Capacities and Maximum Expansions From To Case Initial (bcm) Maximum expansions (mcm/d) 2008 Canada West US West BC Mexico US West BC Alaska US West BC All other input parameters, such as production capacities and reference consumption values and prices, were the same in both cases. 4.2 Results LNG Trade and Re-gasification Capacities The total North American re-gasification capacity in the Base Case in is 328 bcma, about sixfold the capacity of the base year. Figure 6 below shows the breakdown of re-gasification capacity by North American region, for both the Base Case and the Pretty Coast case. At the right side of the figure we see the numbers for the US West Coast. In the BC total regasification capacity amounts to 43 bcma, up from zero in the base year. In the case, by assumption, the US West Coast capacity in remains zero, so 43 less than the BC capacity. To partially close the supply gap, we see in the Figure that Mexico adds more regasification capacity early on in the time horizon (+22 bcm/y in, another +2 bcm/y in ) and Canada West adds some LNG import capacity (+3 bcm/yin ); USA Gulf adds significant capacity in the last year of the time horizon. 5 The total North American capacity adds up to 319 bcm/y, only 9 less than the Base Case. In other words: 80% of the not at the US West Coast added capacity, is added in other American regions. 5 Note that US East in all years, and US Gulf in all years except add already maximum capacity in the base case and can therefore not add additional capacity in these years. 8

9 Regasification capacity (bcm/y) Base Case Pretty Coast Canada East Canada Wast Mexico USA East USA Gulf USA West Figure 6: Total regional regasification capacity over the time horizon Since North America as a whole has lower re-gasification capacity, we would expect the total world-wide LNG exports to be lower too. Figure 7 below confirms this hypothesis. It turns out that, starting, at an aggregate level all world regions (except for Norway, which supplies contractual levels only) export slightly lower amounts. 225 Total LNG exports by region 200 LNG exports (bcma) Base Case Pretty Coast Africa South America Middle East Asia Pacific Russia Norway Figure 7: Development of global LNG supplies 9

10 What Figure 7 does not show, is that globally many LNG trade flows are redirected. The following figure, Figure 8, shows the LNG exports to North America. LNG exports to North America L N G e x p o r ts to N o r th A m e r ic a (b c m a ) Base Case Pretty Coast Africa South America Middle East Asia Pacific Russia Norway Figure 8: Development of LNG supplies to North America over the time horizon Figure 8 shows that in the base case, over time Africa develops to be the main supplier of LNG to North America (supplying 154 bcm in, about half of total North American LNG imports). South America (83 bcm, 26%) and the Middle East (45 bcm, 14%) provide significant volumes. The remaining 35 bcm (11%) originates from the Asian-Pacific region. In the Pretty Coast scenario it is the Asian-Pacific region that sees its LNG exports to North America dwindle, to 2 bcm/y, less than 1% of total supplies. African and South American countries also deliver (slightly) less to North America. It is the Middle Eastern region that sees a big rise in its exports to North America (+22 bcm in ), thereby supplying almost ¼ of North American LNG imports. We see that the Middle East takes on a geographical swing-supplier role, and the global redirection of LNG trade flows smoothes out the impact of fewer imports at the Pacific Coast of North America, and more imports at the Atlantic Coast. An issue of consideration is that in the model there are no limitations in bi-lateral LNG trades and all players take part in an international spot-market. Bi-lateral trade issues could make the market less flexible and would possibly result in stronger effects. 10

11 4.3 Results Pipeline Trade and Capacities Table 3 below shows how the pipeline imports in North American regions are affected. We see that mainly region US West, and to a lesser extent, neighboring region US Rockies are affected. However all importing regions have somewhat lower pipeline imports in later years, as more flows would be directed to the Western states. Table 3: Regional pipeline imports in North America (bcm/y) Region Case Canada BC East Mexico BC USA East BC USA Gulf BC USA BC Midwest USA BC Rockies USA West BC What Table 3 also shows is that Canada East from on does not import pipeline gas anymore. Instead it imports LNG (see Figure 6) and Canada West exports to US regions only. Figure 9 shows the development of aggregate Canadian and Mexican pipeline exports over time in both cases. In the BC Canadian supplies to the US peak in and than steadily decline. Mexico starts as a net importer in BC, but over time develops into a net exporter of gas to the US, albeit for very modest amounts. Net pipeline exports to US (bcm/y) Base Case 80 Pretty Coast Canada West Mexico Figure 9: Development of Canadian and Mexican pipeline supplies to the USA 11

12 In the Pretty Coast case there are several observations to be made. First of all due to Alaskan supplies becoming available earlier, Canada supplies less gas to the US in and. When the Alaskan supplies plateau, Canadian exports in and beyond are higher in the than in the BC. For Mexican supplies we see that the impact of the Alaskan supplies in means that it stays a net importer of US gas for one more period, but in later year starts (re)exporting natural gas via pipeline to the US, while importing large volumes of LNG (See previous Figure 6). Eventually both Canada and Mexico would export more to the USA in case of a Pacific Coast terminal ban. 4.4 Results Wholesale Prices Figure 10 shows the percent difference in prices in the vs. the BC. Generally prices would be lower in, due to Alaskan supplies being available earlier. Only Alaskan prices would be significantly higher - although still lower in absolute value than in the rest of North America - since the higher output levels induce higher marginal production costs and therefore higher delivered prices. Whereas the Rockies and Pacific Coast initially see the biggest price decreases due to their relative proximity to Alaska - in the long run these regions prices are 4-5% higher in the Pretty Coast scenario. Development of relative wholesale price (% vs BC) 8% 6% 4% 2% 0% -2% -4% -6% -8% Canada East Canada West Mexico USA East USA Gulf USA Alaska USA Midwest USA Rockies USA West Average Figure 10: Development of difference in wholesale prices Pretty Coast vs. Base Case 4.5 Results Consumer Surplus So the LNG terminal ban at the West Coast impacts US consumers country wide. How does the combined price and volume effect work out? Table 4 shows indicative consumer surplus results. Initially in the, consumer surplus in US West in would be $2bln higher due to earlier availability of cheap Alaskan supplies, however in later years the effect is a negative $2bln, 5% lower than in the BC. Other regions in the US would also suffer in the 12

13 long-run from a complete LNG re-gasification terminal ban. Yearly consumer surplus for the US as a whole would be about $5bln lower in, but even over $10bln in. 6 Table 4: Indicative consumer surplus changes ($bln/y) Region Data US West Consumer Surplus BC USA total Difference relative to BC Consumer Surplus BC Difference relative to BC Results Environmental Impact The LNG terminal ban also has environmental consequences. Longer transport routes generally result in higher transport costs and losses (due to own use by compressors in pipelines). The transport costs are included in the wholesale prices, but for example the carbon dioxide emissions are not accounted for in WGM. The following provides an indicative assessment of the environmental impact. The carbon dioxide emissions when burning natural gas 7 amount to roughly: 500,000 ton CO 2 /bcm of natural gas. Methane leakages in transport and other factors also add to the negative environmental impact, and the Global Warming Potential of methane, the main compound of natural gas, is actually a factor 21 higher than that of CO 2 hence our numbers are merely a conservative estimate. Assuming a 0.22% loss rate per 100 kilometer 8, and taking an intra-regional transport distance of 1000 km, about 2% of gas is lost in transport. Table 5: Indicative change in CO2 emissions due to pipeline transport Year difference in pipeline flow (bcm) % /BC indicative loss (bcm) CO 2 emissions (ton) 31 10% , % , % , % ,000 To assess the impact of carbon dioxide emissions of changes in LNG trade, we cannot limit ourselves to the North American LNG imports. We should take account of the global redistribution of LNG trade flows resulting from the US West Coast terminal ban. One would expect that the trade flow redistribution results in longer transport routes which in turn induce higher losses in LNG shipments. 6 The extra Gulf region capacity in in the lightens the burden by allowing extra supplies. 7 gives the value: kg/ft 3. Conversion factor:p m 3 /ft 3. 8 European TPA Tariff Comparison 2003 V3, P

14 However due to lower total traded volumes this is not the case. In the the aggregate worldwide LNG exports in are about 8 bcm lower (BC: bcm/y, : bcm/y.) This 8 bcm in lower LNG production accounts for more than 1.5 bcm lower losses in LNG processing and transport, resulting from the high loss factors in liquefaction (12%) and regasification (1.5%). The 1.5 bcm lower losses in LNG would outweigh the higher losses in pipeline transport. So there are lower losses, but given the lower LNG volumes this is not a fair comparison. What would be a fair comparison? Maybe if we can look at the volume-weighted average transport distance in the two cases. In the BC, the total transported LNG volume amounts to bcm, the aggregate distance-weighted volume is: 2,648 (10 3 bcm sea mile), and the resulting average distance over which LNG is transported is 5,068 sea mile. In the, these numbers are: 2648, and 4,967. As it turns out, the average distance over which LNG is transported, is actually 2% lower in the in, than the BC. There can be various reasons for this, ranging from our assumption that in the Mexico has more room for regasification expansion, to (results not shown) LNG exporters supplying more to other, and nearby regions when supplies to the US decrease. About 520 bcm is on average transported over 100 sea miles less. Shipping loss rates are 0.3%/1000 sea miles. 520*0.1*0.3%=0.15 bcm/y. When we compare this value with the pipeline loss difference in of 0.7 bcm, we see a remaining difference of about 0.5 bcm/y, or 250,000 ton in higher CO 2 emissions in the Pretty Coast case. Assuming that a household uses 5000 m 3 /y natural gas, these numbers are in the order of magnitude of the gas use of 100,000 households in a year. 5 Conclusions and Future Directions This paper presents and analyzes scenario results for a ban on LNG regasification terminals on the US Pacific Coast. It is interesting to see that gas prices might actually be lower in the short run due to this ban, if it would induce earlier development of Alaskan supplies. In the long run prices would be somewhat higher compared to the base case, and several billion dollars per years might be lost in consumer surplus. The impact of Alaskan supplies being depleted earlier has not been addressed in this study, but earlier depletion would not contribute to the long-term security of supply of natural gas for the North American markets and possible induce higher prices in the long run. Infrastructural consequences of the terminal ban would be that other countries, Canada and Mexico, and other parts of the USA, such as the Gulf region or the Eastern states, would need to invest in more LNG import capacity to import enough gas to the US. More interstate pipeline capacity might be necessary to bring the gas to the Western States, and the longer transport routes will induce higher costs and higher carbon dioxide emissions, with a negative impact for end-users and the environment. Generally the impact of a terminal ban measured as a percentage of prices, volumes or consumer surplus, is rather modest. This is an illustration for how in a globalizing competitive gas market consequences smooth out over the globe. However measured in absolute terms, billions of dollars are spent extra by consumers, and are lost in consumer surplus; and the induced extra transport losses add up 14

15 to the yearly volume of natural gas used by 100,000 households. These are significant amounts and consequences, which policy makers should consider when deciding about permits for LNG terminals in their home states. For future research, there are many more scenarios worth investigating: what would happen, for instance, if demand decreased significantly, due to a worldwide CO 2 emission trading scheme or a rebound of coal if carbon capture and sequestration proves to be economically viable. Currently, the formation of GasPEC, a cartel similar to OPEC in oil markets, is also discussed broadly. Egging et al. (2008) provides a first insight in the global impact of such collusion among gas producing countries. Another line of research is in addressing the high uncertainty of gas consumption projections and other relevant parameters, e.g. by allowing the incorporation of stochastic scenarios in WGM. This is work in progress, as is the development of time-effective solution methods for large-scale mixed complementarity problems. 6 References BP (2008): Statistical Review of World Energy. Egging, Ruud, Steven A. Gabriel, Franziska Holz, and Jifang Zhuang (2008): A Complementarity Model for the European Natural Gas Market. Energy Policy, Vol. 36, No. 7, pp Egging, Ruud, Franziska Holz, Christian von Hirschhausen, and Steven A. Gabriel (2008): Representing Gaspec with the World Gas Model. Paper submitted to the Energy Journal. Energy Information Administration (2007): International Energy Outlook. Energy Information Administration (2008): Country Energy Data and Analysis; European Commission (2006): World Energy Technology Outlook 2050 WETO-H 2. European Commission (2007): European Energy and Transport Trends to Update Stern, Jonathan (2007): The New Security Environment for European Gas: Worsening Geopolitics and Increasing Global Competition for LNG. CESSA Working Paper Nr. 14. Victor, David G., Amy M. Jaffe and Mark H. Hayes (2006): Natural Gas and Geopolitics: Introduction to the Study. In: Natural Gas and Geopolitics: From 1970 to Cambridge and New York, Cambridge University Press; pp