|Title:||Japan energy supply mix by source as a percentage of total for 2009|
|Source:||Pipeline & Gas Journal|
Start of full article - but without data
Energy Supply Mix of Japan, 2009.
Energy source Percentage of total
Oil XX Coal XX Nuclear XX Gas XX Renewables X
This article explores the feasibility of exporting shale gas--in the form of LNG--from the U.S. to Japan and Korea considering the breakeven gas prices and the liquefaction and transportation costs versus prevailing spot and long-term contract prices of LNG in Japan. Potential risks also are discussed.
Japan has limited energy resources and its energy self-sufficiency, even after inclusion of nuclear power, barely amounts to XX%. This is the main reason why Japan is heavily dependent on imported energy to maintain its economic growth. Following the oil shocks of the 'XXs and 'XXs, Japan gradually veered away from initial oil dependence of almost XX% to reach current levels of XX% in terms of primary energy supply.
While making this transition, importing natural gas from neighboring countries would have been the perfect solution except that there were no nearby sources--barring Russia to be tapped. In the 'XXs and 'XXs, given the cold war conditions and Sakhalin yet to be developed, Japan obviously tilted toward importing LNG from faraway countries. Japan's energy supply mix for 2009 is presented in Table X. LNG imports constituted almost XX% of the total gas supply.
Today, Japan is the largest global LNG importer. Japan's LNG import was X.XX Tcf (XX.X million metric tons) in 2009. It is expected to reach X.XX Tcf in 2016 and X Tcf in XXXX. Despite a declining population (resulting in an aging work force) in Japan and meteoritic rise in LNG consumption in merging economies, Japan's share of LNG import will still be XX% of the Pacific market and XX% of the world market by 2015. In fact, there is a distinct possibility that due to the disasters at the Fukushima I Nuclear power plant, Japan will opt for increasing its LNG import. This presents a unique opportunity for gas producers to sell more LNG to Japan.
Japan's LNG Import Sources
Japan imports most of its LNG from a select group of countries in Asia, Australia and Africa. Table X shows Japan's import by country in 2009.
As can be noted from Table X, Indonesia, Malaysia and Australia each supply close to XX% of Japan's LNG imports. Japan is intent on diversifying the sources of LNG imports to get better control on LNG prices and attain reliability of supply in case of adverse weather/geopolitical events in any particular region of the globe.
Japan would obviously seek reliable suppliers with which it has had a long relationship who have enough spare capacity and stable political situation. Energy price and the necessity of upfront investments will be the other variables taken into consideration.
The main contenders to supply LNG to Japan are Qatar, Australia, Malaysia and Russia. Out of these, Russia's contribution would definitely increase from X.X% to a higher percentage when the Sakhalin-II LNG plant reaches its peak production (Mitsui and Mitsubishi together have a XX.X% share in Sakhalin-II and intend to supply Japan with an extra of XXX,XXX metric tons in the near future). In reality, reliability of Russian supply will always remain a big question.
Malaysia could be an eager exporter, but it already supplies almost XX% of Japan's requirement. Therefore, Japan might think of exploring other markets. Australia's case is similar to that of Malaysia. In the case of Qatar, all the parameters appear to be satisfied except for the concern regarding long-term political stability in the Persian Gulf region. It makes sense, therefore, for Japan to review the possibility of importing U.S. natural gas. In fact, officials from TEPCO Trading Corp. and Chubu Electric Power Co. have already shown interest in importing LNG from U.S. producers.
At this stage it is worthwhile to consider several factors that would govern the feasibility of exporting U.S. LNG to Japan and other Far East countries. Some of these factors discussed in this study are: X) U.S. natural gas spare capacity, X) U.S. liquefaction facilities and their locations, X) benefits of LNG export to the U.S. economy, X) financial feasibility of U.S. LNG export, X) mutual trust factor in dealing with Asian clients, X) LNG project finance, and X) possible impacts of regulatory changes on hydraulic fracturing and other risks for U.S. LNG development.
U.S. Spare Capacity
At first, U.S. natural gas spare capacity needs to be discussed. Daily consumption in the U.S. is approximately XX.X Bcf/d while the "technically recoverable" gas resource total is estimated at X,XXX Tcf of which XXX Tcf is attributed to shale gas. If these results are combined with the Department of Energy's latest determination of proved gas reserves, the U.S. has enough natural gas for the next hundred years. It should be noted that spare capacity, in a capitalistic system, does not necessarily mean domestic production minus domestic consumption. In an open market, a commodity will chase the highest price quoted for it globally.
A review finds that none of the large basins responsible for boosting U.S. natural gas production is close to the West Coast. Nor is there a facility on the West Coast for gas liquefaction. Geographically, the Gulf of Mexico is the next coast line closest to the Far East. Eagle Ford, Barnett, Woodford, Haynesville and Fayetteville shale gas basins are all located in states bordering the Gulf Coast.
Forecast gas production from Eagle Ford shale, which is closest to the Gulf Coast, is provided in Table X. Figure X shows the predicted growth curves in some of the other prominent shale basins. These basins are easily accessible to both the liquefaction facilities proposed on the Gulf of Mexico coast. A rapidly rising production trend is evident from these forecast data, which indicates that sufficient quantities of LNG could be exported if a reasonable net margin is assured to the producers.
[FIGURE X OMITTED]
Let us examine the facilities through which natural gas could be sent to Japan and Korea. As discussed above, several prolific shale gas producing basins are close to the U.S. Gulf coast and therefore it would make sense to examine existing/proposed LNG terminals on the Gulf Coast and associated liquefaction capacities.
Freeport LNG and Macquarie Energy have planned to jointly develop four liquefaction trains each with a capacity of XXX MMcf/d at Freeport LNG's existing LNG import terminal on Quintana Island, XX miles south of Houston. Following government approval, the start-up is expected in early 2015. Macquarie is contributing toward the development costs of the project. The project is planned to draw shale gas from the Barnett, Haynesville, Eagle Ford and Marcellus basins.
Cheniere Energy's Sabine Pass liquefaction project is being designed to permit up to four modular LNG trains--each with an average processing capacity of XXX MMcf/d. The initial project phase is anticipated to include two modular trains with the capacity to process on average X.X Bcf/d of pipeline-quality natural gas. Subject to regulatory approvals and long-term customer contracts, LNG export is expected to commence as early as 2015. Time and cost required to develop the project is anticipated to be materially lessened by Sabine Pass LNG's existing large acreage and infrastructure.
These proposed export terminals will be located in one of the largest gas-producing regions in the world, near two large natural gas trading hubs--the Houston Ship Channel and Katy--with access to the extensive U.S. pipeline network. Moreover, with the opening of the Panama Canal to LNG ships in 2014, cargoes being exported out of Freeport/Cheniere will have a much shorter and quicker access to the Far East, prime area for LNG demand.
Benefits Of LNG Exports
It is worthwhile to review the expected direct and indirect benefits of LNG export. Fully built out, the Freeport LNG liquefaction project will require more than $X billion of direct investment and will create more than X,XXX construction jobs over a two- to three-year construction period. Altos Management Partners has predicted that the incremental natural gas exploration and production required to supply this project would create XX,XXX-XX,XXX jobs and spur companies to spend $X.X billion a year on salaries, as well as exploration and production.
In terms of direct benefits of the Sabine Pass Liquefaction project, the craft labor payrolls alone during Stage X and X constructions are expected to be $XXX million and $XXX million, respectively, with total wages amounting to $X billion over a six-year period. On completion, approximately XXX-XXX full-time positions will be required to maintain and operate the project. Indirect benefits will include effects of increased gas production resulting from the ability to export domestic supplies and generation of even more economic activity as businesses and workers spend money. Indirect benefits will most probably be somewhat higher than those estimated for the Freeport LNG project as capacity of the Sabine Pass project is almost XX% higher.
LNG Export Economics
A preliminary review of the economics of U.S. LNG export is warranted. Such a review will scrutinize the conventional thinking that the disconnect between crude-linked LNG and North American gas is the driver which encourages U.S. producers to push for LNG exports. Toward that end, some calculations can be made to establish the cost of supplying LNG to Japan and Korea.
Table X shows the break-even prices of shale gas for four major shale gas basins. Now, at a minimum, by adding cost of transportation to a gas liquefaction facility, liquefaction cost, shipping cost, and storage and regasification cost, one can calculate the cost of natural gas at the point of unloading in Japan/Korea:
X. Delivery cost to liquefaction facility: Based on a typical maximum system-wide base rate for firm and interruptible transportation service of $X.XX/MMBtu plus a X% fuel and lost and unaccounted for (LAUF) gas charge, the total variable cost per unit for transportation from processing plant to a liquefaction facility XXX miles away can be estimated at $X.XX/MMBtu.
X. Liquefaction cost: Some authors see a generic liquefaction cost of U.S.$X.XX/ MMBtu. In 2010, Cheniere Energy said it would charge between $X.XX-X.XX/MMBtu for liquefaction, although according to Pan EurAsian, an adviser to the LNG industry, it appears to be $X too high. ICF calculated liquefaction cost at $X.XX/Mcf for a LNG plant in Russian Far East. For the present study, an average of the Cheniere fees, $X.XX/MMBtu, has been considered.
X. LNG Shipping cost: According to Brito and Hartley (2007), the unit costs of LNG shipping have been reduced by XX% during 1997-2007. Based on the market developments in the last few years, LNG shipping costs could further stabilize due to several reasons: (a) availability of a large number of L.NG carriers, (b) new technology which allows for reliquefying boil-off gas and thereby offers more cargo to buyers, and (c) development of new generation of LNG carriers which will increase cargo capacity. Some authors see an LNG shipping rate of U.S.$X.XX/MMBtu while Others considers a minimum shipping cost of $X.XX/ MMBtu. Another indicates a shipping cost of U.S.$X.XX/Mcf from Russian Far East to the North American West Coast, which has been used in calculations here.
X. Storage and Regasification cost: One author suggests regasification could add U.S.$X.XX/MMBtu to the price of imported LNG while another points to a regasification cost of $X.XX/Mcf. A minimum storage and regasification cost of $X.XX/MMBtu is considered in another piece of literature.
If the cost of transporting the gas to a liquefaction facility, liquefaction cost, LNG shipping cost and storage and regasification cost are added to an average break-even cost of U.S.$X (Table X), the cost of natural gas post-regasification at a Japanese/Korean LNG facility will be ~$X.XX/MMBtu. This value is somewhat higher than PFC Energy's estimate of $X.XX/MMBtu (it includes a storage and regasification cost of $X.XX/MMBtu added by this author) for Western Canada natural gas delivered through Kitimat to Japan. The PFC estimate suggests a netback for the producer-owners of Kitimat of $X.XX-X.XX/ MMBtu based on Japan Crude Cocktail (JCC) indexation and $XX-XX/bbl crude oil.
At this point, a review of JCC prices in the near future is warranted. Japan imports most of its crude oil from the countries around the Persian Gulf. Oman crude oil futures at the Dubai Mercantile Exchange range between $XXX.XX and $XX.XX/bbl during the period August 2011 to December 2016 (this futures contract is used as a benchmark for Saudi Arabia, Iran, Iraq, the UAE, Qatar and Kuwait crude sold in the Asia-Pacific market). NYMEX WTI futures range from a minimum of $XX.XX to a maximum of $XXX.XX between August 2011 and December 2019. Brent oil is trading almost $XX above WTI and is expected to do so for the next several years. Given such expectations for future crude oil prices, the $X.XX/MMBtu cost of LNG FOB Japan post-regasification as calculated above should provide any LNG exporter a significant net margin. A slide from a Sempra LNG presentation (Figure X) shows the Pacific Basin Premium, caused by oil-index pricing, as a percentage of JCC.
[FIGURE X OMITTED]
Examples of recently signed LNG contracts clearly indicate that at break-even prices of natural gas shown in Table X, there will be sufficient margin for U.S. producers to supply LNG to Japan/Korea/China. In fact, Japanese import prices averaged $X.XX per million Btu last year, more than double the average $X.XX per million Btu available to producers in Western Canada, according to data compiled by Bloomberg. In February 2011, China's CNOOC was in the market for one tanker for March delivery and was bidding around $XX/MMBtu. In mid-Feb 2011, Darwin LNG awarded seven cargoes loading from late March through June for up to $X.XX/MMBtu on a FOB basis. Platts Japan/Korea Marker (JKM), the benchmark daily assessment of the spot price for cargoes of LNG delivered ex-ship into Japan or Korea, for April 2011 was $XX.XX/MMBtu.
Discussions made above are based on LNG prices being linked to JCC indexation. But what if LNG prices are delinked from JCC? According to Daniel Muthman of E.ON Ruhrgas, most LNG long-term contracts are now priced at dollar-per-MMBtu rate that is XX-XX% of the dollar-per-barrel oil price. There are rumors Australia's Gorgon project and ExxonMobil-led Papua New Guinea project sold their planned output under long-term contracts indexed to oil at XX-XX%.
Mutual Trust Factor
Japan and other Asian nations have been known to place a great deal of importance on mutual trust developed over a long period of time. In this context, it could be pointed out that while Conoco/Marathon's Kenai LNG plant in Alaska is scheduled to close soon, it has supplied LNG to Japan since 1969. Therefore, U.S. companies such as ConocoPhillips and Marathon have established a long-term relationship with Japan. The Kenai LNG plant is closing down due to a lack of long-term natural gas availability.
As part of this study, potential sources of project financing need to be considered because LNG projects are extremely expensive. LNG project developers should consider an assortment of capital sources to reduce their overall weighted cost of capital. Funding sources include equity capital markets, long-term debt, ECA (Export Credit Agency)/multi-lateral, commercial bank loans, equipment financiers, government funding and trade players.
Greenfield LNG development is often structured close to XX% debt and XX% equity. Commercial banks and ECAs carry the debt load. For example, Qatar Gas II upstream and Liquefaction Trains I & II were structured at XX% debt and XX% equity. Four senior debt tranches: a commercial bank facility comprised of XX banks ($X.X billion), Islamic financing ($XXX million), two export credit agency facilities--the U.S. Export-Import Bank ($XXX million and its Italian counterpart Servizi Assicurativi del Commercio Estero ($XXX million and ExxonMobil Sponsor loan ($X.X billion as mirror facilities) were assembled.
The Freeport liquefaction project in the U.S. Gulf Coast will require more than $X billion of direct investment and plans to liquefy and export X.X Bcf/d of natural gas from Port Freeport on Quintana Island near Freeport, TX.
For the PNG LNG project in Papua New Guinea, operated by ExxonMobil, $X.X billion is planned to be funded from equity contributions from the partners. Out of the remainder $XX billion in project financing, $X.X billion will originate from export credit agencies, $X.XX billion from uncovered commitments from a syndicate of XX commercial banks, and $X.XX billion as co-lending from ExxonMobil.
Sometimes oil and gas firms may consider to "buy-in" at a later stage such as Total's $X billion deal for a XX% stake in Novatek which includes XX% of the Russian independent's Yamal LNG plant. Loans can also be availed from interested private equity firms.
To ensure smooth LNG supplies, Japan's policy has been to diversify the LNG supplier base and take shares in different LNG projects. To this end, Japanese government institutions have provided financing and incentives. In the past, Japanese financial support has taken various forms such as overseas investment loans, untied loans, import loans and direct loans. In certain cases Japan government has assisted through Overseas Government Cooperation Funds, credit guarantees from Japan National Oil Co., and investment and trade insurance from the Ministry of International Trade and Industry (MITI). For example, MITI has a X.X% stake in the ExxonMobil-led Papua New Guinea LNG project. Another example is Japan Bank for International Cooperation's (JBIC) loan agreement of $X billion with Woodside Petroleum Limited in Australia.