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«IN THE NORTHWESTERN COAST OF MEXICO 7 in the Northwestern Coast of Mexico LNG Impact on Natural Gas on Both Sides of the U. S.-Mexico Border Sophie ...»

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Currently, there are no LNG facilities on the Pacific Coast of the U. S. The early PacIndonesia project that was supposed to deliver LNG from Indonesia to California in 1980 was cancelled for several reasons, one of which was powerful popular resistance. Thus, many of the new West Coast LNG proposals are based on deliveries into Baja California and transmission across the U. S.-Mexico border by pipeline (see next section). Three LNG import terminals are proposed for the California coast (one in Long Beach and two off the coast of Oxnard) and one close to Oregon (Table 2).

The projects in Baja California are getting serious scrutiny. Developers of these projects face a number of hurdles, ranging from funding for project investment to technological advances to development of appropriate policy and regulatory regimes and coordination for new transportation corridors.

Developments upstream appear to be the key point in the development of LNG. At the same time, there is strong public opposition to new pipeline projects that cross through states. The NIMBY (not in my back yard) position is still present and accentuated by the terrorist threat: citizen fear that liquefied natural gas ship could be targets. Terminals in Baja California would be of great interest for the state. It would increase the source of supplies and it would reduce risks of supply disruptions for this area. Nevertheless, concerned citFRONTERA NORTE, VOL. 18, NÚM. 36, JULIO-DICIEMBRE DE 2006

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izen in Vallejo and Tijuana have already rejected attempts to site LNG terminals in their neighborhood. There are also concerns regarding FERC certificate delays. In addition, necessary infrastructure enhancements downstream from LNG terminals will be needed which are likely to raise landowner and cost allocation issues. Will firms take the risk of building a large number of LNG terminals only for some of them to become uneconomic to run? LNG facilities still represent mayor capital investments. While developing new pipeline capacity in these markets is more and more difficult, the decline in delivered LNG costs makes LNG an attractive, cost competitive in these gas consuming markets. The question is until which point it will be attractive.

Price Analysis

The future of LNG imports in California depends on various elements. The firsts are natural gas prices and cost of the LNG value chain. Gas prices will have to be consistent and high enough to make LNG imports profitable to its producers. Shipping costs, which vary with distance, add to the cost of LNG.

Tankers must offload their cargo within a certain period of time, which means that imports form closed countries are preferable.

Thanks to technical innovations, costs along the LNG value chain have been significantly reduced over the past 20 years. All the technological improveMERITET-ROSELLÓN-ELIZALDE/LNG IN THE NORTHWESTERN COAST OF MEXICO 17 ments have allowed a decrease of around 30%, meaning that more and more projects are becoming economically viable.

In 2003, the cost of liquefaction, shipping and regasification pushed the cost of LNG up to between 2.75 and $4.00 per MMBtu. There are very large disparities in individual costs between projects, depending on the projects and countries involved.

Current prices are about 3.00 to $4.00 per MMBtu depending on the costs of natural gas liquefaction, transportation and regasification (Figure 5). Natural gas can be economically produced and delivered to the U. S. as LNG in a price range of about 3.00 to $4.00 per MMBtu (depending on shipping costs).

As the distance over which natural gas must be transported increases, LNG usage has economic advantages over pipelines. The total cost of LNG production has been quite streamlined and reduced thanks to competition and technological progress. According to the IELE, the LNG value chain “now incorporate technology improvements for cost reductions and economies of scale, as well as enhancements and protections for health, safety and the environment”.

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In the early 1990's, the Mexican government adopted a policy encouraging natural gas use thanks to its environmental qualities (clean combustion), its suitability for use in more efficient technologies such as combined cycle plants and the presence of relatively abundant gas sources. As a result, the program to replace fuel oil by natural gas in power plants, investment plans for building new combined cycle plants, and the environmental regulations that went into effect in 1998 for all industries, ensure a heavy demand for this hydrocarbon in Mexico over the next few years.

On the supply side, approximately 64 Tcf of natural gas resources remain in Mexico, 15 Tcf of which are proven reserves (Petróleos Mexicanos, 2004).

Producing 1.6 Tcf per year, Petróleos Mexicanos (Pemex-the National Oil Company) maintains a monopoly on domestic gas exploration and production and a strong market power in transport systems (National Gas Pipelines System, NGPS). Private companies have been allowed to participate in downstream projects since 1995.

Every year, the Mexican Secretary of Energy publishes a study that analyses the future of the natural gas market for the next ten years. The most recent version for the period 2004-2013 (Secretary of Energy, 2004a) considers six

scenarios that combine three demand cases and two supply cases, as follows:

E1. Base Demand–Average Supply (Reference case); E2. Base Demand– High Supply; E3. High Demand–Average Supply; E4. Low Demand–Average Supply; E5. High Demand–High Supply and E6. Low Demand–High Supply.

Table 3 presents the results of the reference scenario (E1). This picture forecasts an increase in gas demand from 5 309 MMcfd in 2003 to 9 303 MMcfd in 2013 (average annual growth of 5.8%). Power generation will be the most dynamic and biggest consumer sector and its participation in total demand would rise from 34% to 51% in 2013. However, national supply is expected to be unable to satisfy all consumption demands because Pemex's powerful budgetary constraints limit the adequate development of gas fields.

Imports would therefore increase from 983 MMcfd in 2003 to 3 784 MMcfd in 2013. These imports vary from 2 045 MMcfd under scenario E6 to 4 076


MMcfd under E3 in 2013 (Figure 6). LNG imports in 2013 are estimated to range from 555 MMcfd (E4 and E6) to 814 MMcfd (E1 and E2) (15-25% of total imports), in addition to imports coming by pipeline from the U. S.

Five LNG terminal projects have received approval to be built in Mexico from the Comisión Reguladora de Energía (CRE-the Mexican Energy Regulatory Commission). Four of them would be installed in Baja California, and one in Altamira, in the State of Tamaulipas (Table 4). However, one of them, scheduled to be developed by Marathon Oil Corp. (Gas Natural Baja California) has been called off in March 2004 after the State of Baja California seized land the company had planned to buy. Additionally, two proposals respectively in Manzanillo and Lázaro Cárdenas (central-Pacific area of the country) are under revision by the CRE. For LNG imports to 2013, Sener's study (2004a) only considers the Altamira LNG Project because the Altamira Terminal and the Federal Electricity Commission (CFE) have already signed a long-term supply contract. The other three proposals are still negotiating a supply contract.

Dependency on foreign supply will increase since the rate of imports/demand would reach 42% for E3 and 41% for the reference case in 2013. Showing another panorama, the E6 scenario considers exports to be 1 613 MMcfd and imports 2 045 MMcfd (Figure 6). These forecasts clearly underline the uncertainties as to whether the indigenous production can be sufficiently increased to satisfy rising demand and eventually export gas to the U. S.

Baja California: Gas Supply and Demand, Import Points and Gas Power Plants

The States of Baja California Sur, Sinaloa, Sonora and Baja California comprise the Northwest region, but natural gas is only supplied and commercialized in the two last ones. Gas consumption has rapidly increased in recent years from 5 MMcfd in 1993 to 250 MMcfd in 2003 (annual growth of 48%), which now represents about 5% of the national figures (Table 5). The power generation sector has mostly contributed to this evolution by rising from 7 MMcfd in 1999 to 233 MMcfd four years later (90% which is regional production).

As far as supply is concerned, all demand is satisfied by U. S. imports since there is neither production in the zone nor pipelines from the south of the country. These imports are carried by means of six transborder pipelines (Table 6).


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According to the Secretary of Energy's projections (Secretary of Energy, 2004a), gas demand in the zone will continue to grow at an annual rate of 10.7% to reach 693 MMcfd in 2013. The installation of 3 245 MW of gas fired, combined cycle power plants will be responsible for the increase. Almost 450 MMcfd of additional imported gas will thus be required from 2003 to 2013.

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It includes the Federal Electricity Commission (CFE) and independent power producers.

Source. The authors with data of Secretary of Energy, 2004a.

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The development of gas resources within North America will be a lengthy process that will require the discovery of new gas fields, and the more effiFRONTERA NORTE, VOL. 18, NÚM. 36, JULIO-DICIEMBRE DE 2006 ciently exploitation of already existing fields. The development of large new pipeline systems will be a natural consequence of this process; such a process will mature over many years. In the meantime, the timely construction of LNG infrastructure will be vital. LNG will thus have a very important role in the natural gas supply all over North America.

In 2004 LNG imports from the U. S. were 1.8 MMMcfd, and are expected to increase to around 7 MMMcfd by 2010. The increase of LNG imports is regarded as so important that by 2012 such imports will be higher than pipeline imports from Canada (Lajous, 2005). These calculations are carried out under the assumption of gas imports from Baja California that—in turn—originate from LNG imports into the Baja peninsula.

General natural gas price formation in the United States is very much linked to an interval whose boundaries are determined by low-sulfur heavy fuel oil and heating oil (Lajous, 2005). The price differential between these two liquid fuels has increased, which implies that the price interval for natural gas has widened, implying more uncertainty and price volatility. This is a crucial element to understand forward prices for the 2005 winter of around USD8 per MMBtu. In the longer run, marginal supply sources (such as LNG) establish a floor for the price of pipeline gas.

Price formation for LNG imports into the U. S. is basically determined by short run conditions. More specifically, LNG prices are linked to internal pipeline gas prices such as the ones in Henry Hub. The U. S. market is primarily characterized by non regulated gas-to-gas competition, as opposed to other gas regions in the world (e.g., Europe) where gas competes with oil and substitute fuels in a long-run framework. So, for example, the LNG price in Lake Charles, Louisiana (one of the most important LNG terminals), is highly correlated to the price at Henry Hub.3 Rising LNG imports are going to have an impact on natural prices in the area.

Most likely, LNG will have an impact on natural gas prices in California because it will be part of the energy mix: natural gas supply will increase, therefore prices should decrease. Its influence on price will be largely determined by how many suppliers will effectively compete and how quick they will be able to supply. However, LNG will not be able to set prices at its level of costs.

In 2004, the average import price of pipeline gas in the U. S. was USD5.81 per MMMBtu, while the importing price was USD5.82, and the one registered at Henry Hub was USD5.85 (Lajous, 2005).


It will remain a “price taker” and not become a “price maker”. To have an influence on natural prices, LNG should present costs below price levels and be able to reduce prices to its cost level. As described by Jensen (2004), many misunderstanding about LNG impacts are linked to the difference between “netback pricing” and “cost of services” pricing. LNG will moderate gas prices but is likely to retain its netback pricing. LNG suppliers operate with the idea that U. S. price levels will determine their netbacks (rathed than their costs determining U. S. price levels). Jensen emphasized that in the past, American the U. S. Congress recognized the difficulty of trying to apply cost-of-service regulation to individual producers with very different costs when their product was an exchangeable commodity in the marketplace. The same also applies to the possible development of LNG supplies in the U. S.

At the same time, LNG supplies in California could have an influence on basis differentials in the natural gas market in the U. S. The current price reference point used for trading is at Henry Hub. Prices at the end of pipeline networks are among the highest. Now the impact of LNG is also going to depend on transportation costs… The global price arbitrage system should evolve if LNG facilities are built in Baja California.

In Mexico, the LNG price contracts that CFE has agreed on, use internal U. S.

prices as a reference. While the LNG price in the Altamira project (in the northeast of Mexico) is linked to Henry Hub, the LNG price in Baja California is determined by the Southern California Border Average (Socal). In 2004, the price in Altamira was USD0.36 per MMBtu higher than the Baja California price. However, as Lajous (2005) argues, the arranged contract LNG prices seems odd. CFE agreed to pay the Henry Hub price plus USD0.17 in Altamira and Socal, minus USD0.03 in Ensenada. In the first case, there is no reason for paying a higher price than the Lake Charles one (which is very similar to the Henry Hub one), while in the second case, it appears to be too high.

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