Global LNG faced a number of problems as 2013 began. All reflect industry's growing pains; none responds to easy solution.
As in recent years, industry supply and demand are struggling to find balance, as expected supply from some areas lags, other possible, unexpected supply has appeared on the horizon in the last 12-18 months, and some markets are behind announced schedules for installing regasification.
When 2013 began, the global LNG industry was capable of producing as much as 290 million tonnes/year (tpy) and regasifying about 625 million tpy, according to data compiled by Oil & Gas Journal.
These figures come close to those compiled for yearend 2012 by Groupe International des Importateurs de Gaz Natural Liquéfié (GIIGNL), Paris.
It determined total operating liquefaction capacity of 282 million tpy and total operating regasification capacity of about 660 million tpy.
The industry group's report for 2012, appearing in the last week of March this year, stated that 236.3 million tonnes moved in international trade last year, down by nearly 2% from more than 240 million tonnes of net LNG trade movements in 2011.
Liquefaction that opened last year included the 4.3-million-tpy first train of Pluto LNG on the Burrup Peninsula in Western Australia. Also, in North Africa, Sonatrach completed construction of the single 4.5-million-tpy train at Skikda to replace three trains lost in a 2004 fire (OGJ Online, Feb. 18, 2004). Formal commissioning was under way in first-quarter 2013.
Regasification completed by yearend 2012 included:
• Mexico: 3.8-million-tpy Manzanillo terminal on the Pacific Coast.
• Spain: 5.1-million-tpy El Musel terminal at the northern port city of Gijón on the Bay of Biscay. In an austerity move, however, the Spanish government decreed even before construction at the terminal had finished that it would be immediately mothballed (OGJ Online, Apr. 30, 2008).
• China: 3.5-million-tpy Zhejiang Ningbo and the 2.6-million-tpy expansion of the Fujian terminal.
• Japan: 0.9-million-tpy expansion at Mizshima and a 0.3-million-tpy terminal by Okinawa Electric at Okinawa.
• Indonesia: 1.5-million-tpy floating regasification and storage unit (FRSU) in Jakarta Bay.
Major issues
As 2012 drew to a close, OGJ polled a few leading LNG consultants on what they saw as leading issues facing industry.
• Prominent on the lists was the evolution of global LNG pricing, made more urgent by prospects of low-cost LNG being exported from North America.
UK-based Andy Flower wondered if industry will "continue to be dominated by long-term contracts" or will growth in short-term trading, boosted by destination-free supplies from the US, lead to "LNG and gas markets moving towards commoditization."
Jim Jensen of Jensen Associates, Weston, Mass., said that, by any "equilibrium commodity price" standards, Asian prices are "way out of line with the rest of the world."
He said some of that is due to the tight market created by Chinese growth and post-Fukushima Japanese demand (OGJ, Apr. 2, 2012, p. 128). Much of it is also attributable to the inflexibility of the traditional Asian oil-price-linked formula, known as Japan Customs Cleared (JCC), also called the "Japan Crude Cocktail."
"Clearly, the Japanese are trying to break open the rigidities of the traditional formula by introducing different indicators into the formula and by buying fob [free on board] in North America at Henry Hub prices." With such a large disparity between European and Asian prices, Jensen said, "someone may introduce arbitrage competition into the mix."
John Sheffield, of UK-based WIGLOX LNG Consultancy, told OGJ that when oil-indexed, long-term pricing hit $16-20/MMbtu, Japan and [South} Korea are challenging the traditional Southeast Asia pricing scheme, "seeking alternative hub-based pricing or a net back structure."
Evidence of such efforts he has found in the tactic adopted by several Japanese buyers in taking positions with developing North American LNG export projects.
And if Japan establishes LNG supplies with a different pricing structure, he wondered how this would affect the "very expensive Australian LNG developments," more about which below.
• Because of the current and potential size of Asian LNG demand, such discussions about global pricing tend to begin with and focus on Asia. But there are similar issues surrounding natural gas pricing in Europe.
LNG as a means of importing natural gas to the region began making inroads some years ago, especially when Western European countries realized how dependent they had become on pipeline supplies from Russia via a few countries comprising the former Soviet Union.
Jensen observed that European gas demand has fallen off sharply, due to some degree to the post-2008 recession, but at "current prices and a weak cap-and-trade system, gas is losing out to coal. What are the implications for European LNG demand?"
And, as Europe increasingly moves toward hub pricing, "how does an LNG seller price his product?"
Sheffield specifically saw UK gas supply in a crisis, "committed to close coal-fired power stations, in complete confusion over replacement of nuclear facilities, and [tied to] totally inadequate potential from renewables." The only way is gas, he said.
The UK faces "declining indigenous supplies [and] limited future potential supply increase from Norway." It will need to rely on LNG. "But what is the impact of competing with [Southeast Asia] for supplies?"
• Nearly all planning in the last 18-24 months among LNG professionals has taken place under the specter of whether and how much LNG will be exported from North America. Massive proved and probable natural gas reserves in shale developments there have prompted several groups to propose LNG export projects, mainly on the US Gulf Coast and Canada's West Coast. (OGJ, Aug. 6, 2012, p. 92; Dec. 3, 2012, p. 116; and Jan. 7, 2013, p. 94.)
Sheffield foresees unknown effects of exports from the US on Henry Hub pricing and wondered if the public might turn against the export of a "national asset and resource."
Some development seems inevitable, however, but "surely nothing like what is currently listed [by the US Energy Information Administration] as potential projects. If the likely export total by 2020 is around 45 million tpy, Henry Hub pricing may not be too drastic but seems "surely to climb to $4-6[/MMbtu]."
He noted that the opening of the Panama Canal expansion in 2014 will enable US supply to access Southeast Asia markets.
Flower cautioned that "market demand and the availability of finance rather than decisions by the US Department of Energy [DOE] on licenses for the export of LNG to non-Free Trade Agreement [FTA] countries are likely to be the main determinants of whether exports will be in the 40-60 million tpy range by the early 2020s."
The current obsession of buyers in Asia for Henry Hub-based LNG supplies may "delay development of LNG production in Australia, East Africa, [and] West Africa."
• The other supply question centers on development of massive natural gas reserves off East Africa. With little or no local market to absorb production, export as LNG was almost immediately floated as the logical step (OGJ, Apr. 2, 2012, p. 70 and p. 122).
Sheffield summarized some of the thorny problems involved in production from this region. "How quickly will the developments in Mozambique and Tanzania happen?
"Are the political and legal systems in the host countries robust enough for the potential volume of trading? How quickly can the markets in Southeast Asia absorb the new production?"
And he wondered how development off East Africa will affect the large Australian LNG projects under way and planned.
Jensen said that the large new and economic source of supply into the Pacific Basin could have a major impact on the region's Asian price structure; "How much is likely, when, and who will be the sellers?"
He noted that US projects "will be unique in that they are likely to be fob [contracts] with source [Henry Hub] rather than destination [JCC or European oil products] pricing. How will that affect international prices, particularly in Asia?"
• No consideration of questions facing international LNG trade can be complete without noting the roles of Asia and Oceania in the mix.
Will Asian demand come into its own as the principal demand driver of LNG supply? Will China and India be the largest portions of that demand?
Jensen told OGJ that China is a rapidly growing gas market, but can "it maintain its growth in the face of changing patterns of world trade?
"And how does it ultimately divide up its market among conventional domestic gas, shale and coalseam gas, pipeline supplies (particularly from Russia) and LNG?"
Russia's proposed pipeline link to China from West Siberia, he said, equals "half the LNG Qatar put on the market 2009-11."
An abundance of expensive, large LNG supply projects in Australia presents a flip side of the picture of Southeast Asia. Many have run into severe cost overruns caused by shortages of workers and materials, which have delayed them.
Flower said delays in start-up of the seven Australian projects now under construction will extend the currently tight global LNG market into the late 2010s.
What's happening, where
Space here sufficient to recap and update for 2012 is limited. What follows tries to hit some high points.
North America
LNG markets in Asia, Europe, and to some degree in Latin America are watching the debate in the US over allowing companies to export as LNG some or none of its shale-derived natural gas bounty.
That discussion received some badly needed quantification late last year. In December, under commission from the US DOE, NERA Consulting issued a report on the likely effect of US LNG exports on the US economy (OGJ Online, Dec. 17).
NERA analyzed several scenarios for global supply and demand and concluded that, under any of them, US LNG exports would not harm the US economy. The study further determined that Henry Hub prices would increase only modestly as a result of LNG exports.
Now industry and markets await decisions on several proposed projects, especially those requesting approval to export to countries with which the US does not have a Free Trade Agreement. Countries with an FTA encompass very few current LNG importers.
Sabine Pass LNG is the only export project in the US that has received approvals and begun construction. Cheniere Energy Inc., Houston, last month filed with the US Federal Energy Regulatory Commission (FERC) to add fifth and sixth trains to the project at Sabine Pass in Cameron Parish, La. The company already has filed with DOE for approvals for those trains to export to both FTA and non-FTA countries.
Trains 1 and 2, under construction and targeting start-up in 2016, will ship 7.7 million tpy, of which 4.2 million tpy is contracted to BG and 3.5 million tpy to Gas Natural Fenosa. If approved, Trains 3 and 4 will ship 8.3 million tpy by 2017 (OGJ Online, May 4, 2012).
Last year, Cheniere Energy awarded a $3.8 billion contract to a unit of Bechtel for engineering, procurement, and construction for Trains 4 and 5. At the time, costs for the two trains were estimated at $4.5-5 billion.
Customers for the two trains are BG (1.3 million tpy), Korea Gas (3.5 million tpy), and GAIL (India; 3.5 million tpy).
In January, Shell and Kinder Morgan's El Paso Pipeline Partners announced they will develop an LNG export project in two phases at the existing Elba Island LNG import terminal near Savannah, Ga.
The companies will modify El Paso's Elba Express Pipeline and the Elba Island LNG terminal to ship gas to the terminal, liquefy it, and export it. The single export train will be able to produce about 2.5 million tpy. Kinder Morgan will own 51%; Shell 49%. Shell has taken 100% of the liquefaction capacity.
The Elba Island terminal has already been approved by DOE to export up to 4 million tpy to FTA countries and filed last year for approval to export another 4 million tpy to non-FTA countries.
In September 2012, Freeport LNG Development applied to FERC to build and operate LNG export at its import terminal on Quintana Island, Tex.
Freeport wants to install three trains, each with 4.4 million tpy of capacity. The company has received approval from DOE to export 1.4 bcfd to FTA countries but awaits approval for an equal amount to non-FTA countries.
Also in September, Golden Pass LNG received approval from DOE for a $10-billion project to export 15.6 million tpy to FTA countries from its import terminal site near Port Arthur, Tex. It followed in November with an application for non-FTA countries.
The project is 70%-owned by Qatar Petroleum and 30%-owned by ExxonMobil. Start-up would follow 5 years after project approvals and final investment decision by the operator.
The $2 billion Golden Pass import terminal is owned by Qatar Petroleum (70%), ExxonMobil (17.6%), and ConocoPhillips (12.4%).
Earlier this year, Canada's National Energy Board (NEB) approved application by LNG Canada Development Inc. to export from LNG Canada's proposed plant near Kitimat, BC (OGJ Online, Feb. 5, 2013). The license authorizes the company to export 24 million tpy for 25 years. Start-up targets 2020.
LNG Canada is a joint venture of Shell Canada Ltd., Korea Gas Corp., Mitsubishi Corp., and PetroChina Co. Ltd.
In January, Chevron Canada Ltd. announced plans to buy 50% of Kitimat LNG and the proposed Pacific Trail Pipeline and 50% in 644,000 acres in the Horn River and Liard basins in BC. The sellers are EOG Resources Canada Inc., Encana Corp., and Apache Corp (OGJ, Jan. 7, 2013, p. 42).
The two-train Kitimat LNG project, targeting start-up in 2016, is in front-end engineering and design. Its NEB license allows export of 10 million tpy. The 290-mile PTP system will provide a direct connection between Spectra Energy Transmission's system and the Kitimat LNG terminal.
Last year, Canada's Ministry of Natural Resources approved a 20-year export license for BC LNG Export Cooperative. This action followed a similar approval by NEB in February (OGJ Online, Feb. 3, 2012).
The export plant will sit on the west bank of the Douglas Channel in the District of Kitimat. BC LNG intends to ship mainly to Asia.
The company is owned by LNG Partners LLC, Houston, and HN DC LNG LP, each with 50%. Natural gas would move to the Douglas Channel site via the existing Pacific Northern Gas Pipeline and possibly on the proposed Pacific Trail Pipeline.
The NEB license authorized BC LNG to export 1.8 million tpy for 20 years.
The NEB action follows the granting of another 20-year LNG export license in October 2011 to KM LNG Operating General Partnership. That project would be based at Bish Cove, near Kitimat (OGJ Online, Oct. 14, 2011).
Asia Pacific
A recent analysis of Asian LNG demand by Wood Mackenzie lays out a case for focusing more on the other countries of Southeast Asia, especially Indonesia, Thailand, Malaysia, and Singapore. "India, on the other hand, may disappoint," said WoodMac.
Combined Southeast Asian LNG markets, it said, will account for a third of overall Asian LNG demand growth by 2025, growing by 45 million tpy. India's LNG market, on the other hand, may grow more slowly than once thought, by only 20 million tpy within this timeframe (OGJ, Mar. 4, 2013, p. 46).
• China. In January, authorities for eastern Jiangsu Province approved China Petroleum & Chemical Corp. (Sinopec) to begin building a 3.0-million-tpy LNG receiving terminal in Lianyungang port, in eastern Jiangsu province. Approval from China's National Development and Reform Commission (NRDC) remained pending as 2013 began.
Late last year, China National Offshore Oil Corp. (CNOOC) commissioned its fourth LNG receiving terminal, in Ningbo, Zhejiang Province, capable of importing 3.5 million tpy.
In mid-2012, China's NRDC approved CNOOC's plans to build a second LNG terminal in the southern city of Shenzhen. The Diefu terminal will be able to receive 4 million tpy.
Supporting its operations will be four 160,000-cu m LNG tanks. CNOOC Gas and Power Group, a unit of CNOOC, holds 70% in Diefu; Shenzhen Energy Group 30%.
At yearend 2012, a start-up date had not been announced.
Early last year, CNOOC began building a floating LNG receiving and storage unit (FRSU) to be moored southeast of Nanjiang port in Tianjin harbor, Bohai Bay. First phase, to start up this year, is to include floating storage, port, gas pipelines, and onshore storage and will be able to handle 2.2 million tpy.
The second phase, due to start up in 2015, would add a 3.8-million-tpy onshore terminal and include four 160,000-cu-m tanks.
The entire project is owned by subsidiary CNOOC Gas & Power, Tianjin Port, and Tianjin Gas Group.
• India. The long-delayed LNG receiving terminal at Kochi was finally to be commissioned during first-quarter this year, owner and operator Petronet LNG said in late 2012. The 5-million-tpy terminal has been under planning and construction since 2007 and was originally scheduled to open in 2010.
Nagging supply problems from lack of pipeline capacity feeding the terminal will hold its initial operations to less than 1 million tpy for at least a year, said the company.
It is just these sorts of delays along with other wrangling among companies and governments that prompted Wood Mackenzie to caution suppliers against counting too much on Indian markets in the near to medium term.
In early January, GAIL (India) Ltd., Mumbai, commissioned the 5-million-tpy Dabhol LNG terminal at Ratnagiri, Maharashtra, about 210 miles south of Mumbai. Gazprom Marketing & Trading Singapore supplied the commissioning cargo aboard the 138,000-cu m LNG Pioneer.
The terminal will send out natural gas to the southern and western states of Maharashtra, Goa, Karnataka, and Tamil Nadu, reported GAIL. In the immediate future, it said sendout from the terminal will meet demand in Maharashtra through GAIL's Dabhol-Panvel pipeline connected to Maharashtra regional pipeline network.
The terminal is operated by RGPPL, a joint venture of GAIL and NTPC Ltd., India's largest power company.
The company also said it was in an advanced stage of commissioning the nearly 870-mile Dhabol-Bengaluru pipeline.
GAIL Chairman and Managing Director Shri BC Tripathi also said the new terminal would expand over 2-3 years first to 7.5 million tpy of capacity, then to 10 million tpy.
Commissioning of the Dabhol terminal along with GAIL's cross-country gas pipeline network will integrate the entire gas market of India from Bhatinda-Nangal in North to Kochi in the south, spanning a gas grid of more than 2,100 miles.
Until then, Dahej and Hazira were the only operating LNG terminals in India (OGJ Online, Jan. 22, 2013).
• Indonesia. Earlier this year, Inpex Masela Ltd. awarded competing contracts for front-end engineering and design (FEED) of its floating LNG plant for development of Abadi field off the Tanimbar Islands, Indonesia.
Stage 1 of the development of Abadi gas field envisions a single 2.5-million-tpy liquefaction unit as well as production capacity of 8,400 b/d of condensate
Inpex Masela (60% interest) will operate the project in partnership with Shell Upstream Overseas Services (I) Ltd. (30%) and PT EMP Energi Indonesia (10%).
The FEED was awarded to two groups: One led by engineering company JGC Corp./PT JGC Indonesia; the other by engineering and oil and gas contracting service company PT Saipem Indonesia/Saipem SA.
The first group consists of JGC Corp., PT JGC Indonesia, PT Technip Indonesia, PT Technip Engineering Indonesia, Technip France, and MODEC Inc. The second group consists of PT Saipem Indonesia, Saipem SA, PT Chiyoda International Indonesia, Chiyoda Corp., and PT Tripatra Engineering.
The announcement said that these groups will conduct the FEED in parallel under a design competition.
To keep to the project schedule and ensure consistency of engineering, it said, one of the groups will continue into the FLNG engineering, procurement, and construction (EPC) phase. The FLNG EPC contract will therefore be awarded to the group that "provides technical and commercial superiority" based on overall design for the floating plant (OGJ Online, Jan. 25, 2013).
Late last year, Indonesia's government approved a plan to expand the Tangguh LNG project operated by BP in far eastern West Papua province. Plans call for building a third train at Tangguh at an estimated cost of $12 billion.
The train would add 3.8 million tpy of liquefaction capacity at Tangguh and raise its total capacity to 11.4 million tpy.
BP Indonesia said the new train will sell 40% of production to such Indonesian buyers as state-owned electricity company PT Perusahaan Negara, and the rest to buyers in the Asian-Pacific region.
BP holds 37.16% in the project. Its partners include CNOOC Ltd. 13.90%, Nippon Oil Exploration (Berau) Ltd. 12.23%, and LNG Japan Corp. 7.35%.
Last year, Nusantara Regas, a joint venture between Indonesian state oil company Pertamina (60%) and gas utility Perusahaan Gas Negara (40%), started up the country's first FRSU, a 3-million-tpy unit in Jakarta Bay, West Java.
Nusantara Regas has a sales-and-purchase agreement with Total and Inpex that will supply 1.5 million tpy to the floating terminal over 2012-22. Total and Inpex plan to process gas from their Mahakam block in East Kalimantan at the nearby Bontang LNG plant and ship the LNG to the floating terminal.
• Malaysia. Last year, state-owned Petronas reached final investment decision (FID) on what would be the world's first floating LNG plant. If the 1.2-million-tpy platform comes online as scheduled in 2015, it would precede Shell's Prelude floating LNG vessel by a year.
Scheduled for 2016 delivery, the $11 billion Prelude vessel will be able to produce 3.6 million tpy of LNG in addition to 1.3 million tpy of condensate, and 400,000 tpy of LPG (OGJ Online, May 20, 2011).
The Malaysian FLNG unit will monetize gas from Kinawit field, off Sarawak, and will target domestic demand.
In November, Malaysia LNG Sdn. Bhd., a production unit of Petronas, awarded the Linde Group, Munich, a contract to build a midscale LNG plant within the Bintulu LNG production complex in Sarawak, East Malaysia.
Design production capacity for the plant will be 1,840 tonnes/day from boil-off feed gas from LNG storage and ship loading. The new plant is to go on stream at yearend 2014.
Linde's process will also enable Malaysia LNG to minimize flaring, said the company (OGJ Online, Nov. 28, 2012).
Australia
In Australia, its large LNG production projects continue apace yet several have announced cost overruns.
• Eastern Australia. In July last year, Reuters reported that Santos had raised its cost estimate for the two-train, 7.8-million-tpy Gladstone coalseam gas-to-LNG project by 15% to $18.5 billion (Aus.). The company said it needs to find more gas ahead of the project's planned 2015 start-up (OGJ Online, Jan. 19, 2011).
Gladstone is owned by Santos 30%; Malaysia's Petronas and France's Total 27.5% each; and Korea Gas Corp. 15%.
The global news service said at the time that Santos was the second of three CSG-based LNG projects to announce a cost increases.
The announcement followed one earlier in the year from BG Group that its two-train, 8.5-million-tpy Queensland Curtis Island LNG project faced a 36% cost increase due to regulatory costs, some changes to the project, and a stronger Australian dollar. Origin Energy's two-train, 9-million-tpy Australia Pacific LNG (APLNG) also faced cost increases.
Late last year, BG Group signed heads of agreement to sell interests in Queensland Curtis Island to CNOOC for $1.93 billion and the sale of LNG. The interests include a stake in upstream assets and in the first train of the project. The deal excludes any interest in the second LNG train, transmission pipeline, and common facilities.
The companies agreed BG will supply CNOOC with 5 million tpy from its global assets for 20 years beginning in 2015. In March 2010, BG signed an agreement to supply 3.6 million tpy of LNG to CNOOC.
The Chinese company will acquire a 40% equity interest in the first Queensland Curtis LNG train, in which it already holds 10%. It also will acquire a 20% equity interest in BG holdings in the Walloons Fairway region of the Surat basin, in which it now holds 5%. CNOOC also will acquire a 25% working interest in BG upstream assets in the Bowen basin of Queensland.
BG's QGC Pty Ltd. remains operator and majority owner of the LNG project (OGJ Online, Oct. 31, 2012).
In July last year, APLNG reached FID for a second train at the CSG-based LNG plant planned for Curtis Island, near Gladstone in Queensland. APLNG ownership consists of Origin Energy Ltd., ConocoPhillips, and Sinopec.
First LNG from Train 1 is on schedule for 2015, said the consortium. First LNG from Train 2 targets 2016 (OGJ Online, July 5, 2012).
• Western Australia. Last year, Woodside Petroleum Ltd.'s $15 billion (Aus.) Pluto LNG project on the Burrup Peninsula began operations. At full capacity, the single-train project will produce 4.3 million tpy.
Woodside has said a second train will follow but has yet to report new reserves to support it. It was planning to drill three wells last year in the Carnarvon basin and on the Exmouth Plateau. One of these, Banambu Deep-1, was to have spudded in permit WA-389-P at mid-year.
Banambu Deep-1 will be followed by Anake-1 in WA-269-P to the northeast of Pluto field.
In coverage of the opening of the Pluto LNG train, Reuters said the Pluto project came online a year behind schedule and $900 million (Aus.) over budget. The project is to contribute up to 21 million boe to Woodside's 2012 production and 37 million boe/year to Woodside's production in the long term, said the international news service.
Woodside owns 90% of the development and operates the project. Tokyo Gas and Kansai Electric Power each owns 5%.
In April 2011, Chevron Australia applied for environmental approval for a fourth LNG train for its Gorgon project on Barrow Island, saying it had found sufficient reserves to support the expansion (OGJ Online, May 4, 2011. An FID could be reached by yearend 2013 with construction starting in 2014.
In September, Chevron reported that Geryon field, discovered in 2001, and Chandon field, discovered in 2006, will supply the new 5.2-million-tpy LNG train, bringing Gorgon capacity to 20.8 million tpy.
Geryon and Chandon will supply about 11 tcf of low-CO2 high-deliverability gas to the project.
The fourth train work will include construction of a fourth LNG storage tank on Barrow and the laying of a third pipeline to feed the project (OGJ Online, Sept. 26, 2012).
In January this year, Japan's Inpex and Total SA reached FID for their $34 billion development of the Ichthys LNG project in northwest Australia. The two-train, 8.4-million-tpy project is based on an estimated 40 years' supply of gas and condensate reserves in the Browse basin.
The gas will move via pipeline more than 800 km (nearly 500 miles) to the LNG plant to be built at Blaydin Point near Darwin. Condensate will be sold via a floating production, storage, and offloading vessel at the field, which is off Western Australia.
CPC Corp. of Taiwan and Chubu Electric Power and Toho Gas, both of Japan, will buy 1.7 million tpy, 490,000 tpy, and 280,000 tpy, respectively, based on nonbinding agreements signed in June 2011. All supply agreements are for 15 years.
Ichthys field was discovered in 2000-01. Reserves are put at 12.8 tcf of gas and 527 million bbl of condensate. The project will come on stream at yearend 2016.
Partners in the project are Inpex 72.805%, Total 24%, Osaka Gas 1.2%, Tokyo Gas 1.575% and Toho Gas 0.42% (OGJ Online, Jan. 13, 2013).