News in brief
Results — Global energy major BP posted a 30% increase in second quarter profits to US$ 7.27 billion (EUR 5.75 billion), with revenue up 24% to US$ 73.46 billion.
Replacement cost profit, which excludes the impact of changing energy prices on inventories, rose 23% to US$ 6.12 billion. Second quarter gas production at BP fell however to 8,624 million cubic feet per day (mmcf/d), down 0.4% from the same period in 2005, with H1 gas output also 0.4% lower than 2005 at 8,668 mmcf/d.
UK gas output fell 20% year-on-year in Q2, to 911 mmcf/d, with H1 UK gas production 11% lower year-on-year, at 1,053 mmcf/d. Across the rest of Europe, BP’s gas production also fell: 22% in Q2 ’06 compared with Q2 ’05 and 23% in H1 ’06, compared year-on-year.
The average price realised from gas sold at the NBP in Q2 was 34.55 p/th, up from 30.15 p/th in the same period 2005. The H1 gas NBP price rose from 34.02 p/th in 2005 to 52.70 p/th this year.
At Henry Hub in the US, BP received an average price of 7.9 $/mmbtu for gas in H1 ‘06, up from 6.51 $/mmbtu in the first half of 2005.
In a statement, Lord Browne, BP’s c.e.o., said: “UK gas prices (NBP day-ahead) fell in the second quarter to average 34.6 pence per therm, compared to 70 pence per therm in the first quarter, but 15% higher than in the second quarter of 2005. However, European long-term contract prices, which are indexed to oil prices, increased by more over the same period.”
“As a result, UK spot prices traded at a discount to European contract prices in the second quarter 2006, compared to a small premium during the second quarter of 2005. The Rough storage facility has re-opened and inventories are expected to reach normal levels by October, but concerns over winter supply have led the NBP futures to exceed 80 pence per therm.”
Results — Spain’s Enagás lifted profits to EUR 111.3 million in the second quarter of 2006, the Spanish gas transporter reports. This was an increase of 10.6% year-on-year, matching market expectations.
EBITDA rose 11.5% to EUR 272.8 million, while net corporate debt was, at the close of the first quarter, EUR 1,507.8 million, down 3.8% quarter-on-quarter.
Demand for gas transported in the system during the first quarter reached 204,001 GWh, up 7.2% year-on-year. Enagás transported 80.5% of this total, or 164,221 GWh, as it owns most of the gas infrastructure in the country. The gas-to-power sector saw the sharpest demand rise, accounting for 32.5% of consumption, compared with 26.5% in the same period of 2005. Enagás said that 31 CCGTs were operational and five were running trials in the first quarter of 2006, compared with only 25 in the first quarter of 2005.
Enagás’ investments into new gas infrastructure reached EUR 170.3 million between January and June. Emission capacity was lifted at all three of Enagás’ LNG terminals: Huelva capacity was increased from 1,050,000 m3/h to 1,200,00 m3/h, Cartagena capacity was increased from 900,000 m3/h to 1,200,000 m3/h and Barcelona capacity was increased from 1,500,000 m3/h to 1,650,000 m3/h.
Enagás also approved additional projects for EUR 419.1 million, including the construction of a seventh and eighth storage tank at the LNG terminal in Barcelona, a gas pipeline between Lemona and Haro and a connection between Lorca and the Almeria-Chinchilla pipeline.
Results — Net profits at Italy’s gas network operator Snam fell by 14.6% to EUR 240 million in the first half of 2006, the company reports. It said the fall was due to regulatory changes starting on 1st October 2005. The new regime limited Snam’s return to 6.7% of revenues, from the previous 7.9%.
In the first quarter this year, Snam blamed a 13.6% drop in profits primarily on an increase in average financial debt affected by the payment of the Extraordinary Dividend in November 2005.
The amount of gas used in Italy actually rose in the first half, with 46.52 billion cubic metres (Gm3) injected onto the grid, up 3.9%, on increased power generation demand. The amount of LNG regassified by Snam (via its subsidiary GNL Italia which runs Panigaglia) was up 18.3% to 1.81 Gm3.
Snam’s total revenues were down 2.3% to EUR 904 million, EUR 866 million of which came from transport.
2006 capital expenditure will be in line with the previous year Snam said in a statement, with the focus on import connections with North Africa and Russia. This figure rose more than six-fold in 2005 to EUR 685 million.
Snam forecasts Italian demand to grow on average by 2% over the next four years (2006-2009).
Results — Norsk Hydro, Norwegian energy and metals conglomerate posted a year-on-year increase in operating profits of 30% to NOK 14.64 billion (EUR 1.84 billion) during the second quarter of 2006.
The results were driven by high realised oil and gas prices, alongside higher aluminum prices, but were “offset by lower than expected oil and production,” said Hydro c.e.o. Eivind Reiten in a statement.
Oil and gas production averaged 537,000 barrels of oil equivalents per day (boe/d) during the second quarter, roughly in line with the production levels in the same period in 2005, but down 73,000 boed on first quarter figures.
Last month, Hydro downgraded its 2006 production target figures by 30, boe/d to 585,000 boe/d. Approximately half the drop in expected production, 15,000 boe/d, will occur on the Norwegian Continental Shelf (NCS), with the biggest shortfall in production from the NCS coming from the 11 billion cubic metre (Gm3) Kristin field. Hydro realised an average oil price of US$ 67.9 per barrel in the second quarter of 2006, which is 36% above the price received in the same period in 2005, and 12% above the figure received in the first quarter of 2006.
In the gas market, the company realised NOK 1.79 per standard cubic metre (Sm3) in the second quarter, up 37% on the same period in 2005, but down 17% on the price realised in the first quarter of 2006, mainly due to lower spot prices, according to Hydro.
Results — UK-based E&P company BG Group has posted a 53% increase in second quarter operating profits. Despite almost tripling the operating profits from its LNG business for H1, analysts believed this performance to be disappointing, as these activities produced less operating profit than expected, at £34 million for Q2 and £172 million for the first half. Total operating profit for the first half climbed 75% year-on-year to £1.7 billion.
The Q2 results also included a prior period tax charge of £76 million relating to the increase in North Sea taxation, BG said. Including this charge, net profits for Q2 came in at £325 million (EUR 476 million), up 18%, with H1 earnings after prior period taxation up 63%, year-on-year, at £888 million.
Revenue rose 55% in Q2 to £1.75 billion, while H1 revenue was up 67%, year-on-year, at £3.73 billion.
Total production at BG climbed 25% to 55.6 million barrels of oil equivalent (mmboe) in Q2 ’06, from 44.6 mmboe in the same period of 2005. Gas output jumped 35.7% in Q2 to 42.7 mmboe, up from 31.7 mmboe in Q2 ’05.
The average realised UK gas price rose to 26.20 p/th from 22.98 p/th in the second quarter of 2005, with the H1 realised gas price up 39.7% to 32.96 p/th from the same period in 2005. The group’s average H1 international gas price rose 26.4% to 17.71 p/th, up from 14.01 p/th in H1 ’05.
Competition — The head of Germany’s federal network agency, Matthias Kurth, this month publicly offered his support to Dutch utility Nuon’s attempt to branch out in Germany’s end-user gas market, namely in Berlin and Hamburg.
“I call on network operators to cooperate efficiently and proactively with this alternative supplier’s request,” Kurth said, adding the authorities would “referee disputes” if no agreement could be reached. Kurth hoped this would encourage other new entrants to follow suit, and offer customers a choice of suppliers in other regions in Germany.
The move follows an announcement by Nuon’s head of German operations in Hamburg and Berlin, Thomas Mecke, earlier this month. In the press conference, Mecke, said Nuon would initially offer a twelve-month fixed price gas supply contract to customers in Hamburg and Berlin.
Distribution — Germany’s biggest Stadtwerke group, MVV Energie, and Energieversorgung Offenbach (EVO) will establish a joint network operations company on 1st October, MVV said. The new company will be based in Mannheim and will be owned 70/30 by MVV and EVO respectively. The new subsidiary will bundle the power, gas, water and heating networks of the two companies, but will not have any impact on the ownership of the grids.
“Together we bring enough horsepower to take over a leading role in the Rhein-Main-Neckar-Region,” MVV board member, Werner Dub, said in a statement. By bundling their activities, the two companies hope to achieve cost reductions through the cooperative venture, amid increasing domestic competition.
The announcement marks the reaction of the two companies to unbundling laws within the framework of EU energy market liberalisation, which require a legal separation of network activities from sales and production. In addition, the companies pointed to the push by the state regulators for lower network access charges.
Imports — German gas import prices increased by 41.8% year-on-year in June, according to Germany’s federal statistical office, Destatis. Month-on-month, gas import prices nudged up slightly by 0.5%. The price of crude oil rose 24.7% year-on-year in June, while mineral oil products climbed 23.9% for the same period.
CCGT - Spain’s Iberdrola has bought 70% of Korinthos Power from its parent Motor Oil (Hellas) Corinth Refineries (MOH), and will use this to cooperate in the tender to develop CCGTs in southern Greece.
According to a statement from MOH, Korinthos Power, now a 70/30 joint venture between the two, has all the necessary permits to take part in these tenders, called by DESMIE, the state-owned transmission system operator.
One tender for a 400 MW CCGT at Aliveri was launched in May, and tenders for another two plants with a combined capacity of 900-1,000 MW are expected, one by the end of 2006 and another by 2007. The tender is open to domestic and international companies, but in addition to Iberdrola, Edison and Enel are also rumoured to be interested in teaming up with local companies that already hold the relevant production and installation licences.
The Greek market is monopolised by PPC, which generates 95% of country’s electricity, and around 45% of its 12.2 GW of installed capacity is lignite-fired. Greece is keen to diversify away from lignite with its high CO2 emissions – PPC’s 2005 operating profit declined 26% year-on-year due to rising fuel costs and the cost of CO2 emissions allowances. In addition, CCGTs can be built faster than other forms of generation such as nuclear, and operate with higher efficiency.
Costis Stamboulis, Chairman & Executive Director of Institute of Energy for SE Europe, told EGM that more capacity was needed to meet demand during Peak periods, with another 400 MW facility needed every year for the next three or four years.
Hub - Italian wholesale company Enoi has begun providing market-making services for the Italian PSV (Punto di Scambio Virtuale) hub. The company has invited around 20 Italian companies to access a webpage showing both bids and offers to trade with Enoi.
“We are in an experimental period to see if there is some liquidity in the market,” a source at Enoi said. “We are not a big company so the volumes are small at the moment and we cannot give tight spreads.”
The volumes posted are typically 30 MWh at the moment. Periods bid and offered so far are Day-ahead, Weekend, Month-ahead, 16-31st August, September, October and Summer ’07. Enoi is not currently offering winter gas, an understandable position given the expected scarcity of supply in Italy this winter.
The numbers are not yet publicly available.
The move has been welcomed by Italian shippers, as progress towards transparency on the spot market. However, several pointed out that this would not necessarily improve liquidity as volumes are small and bid-offer spreads quite wide. “It’s a good thing but the real problem in Italy is that there isn’t enough gas available to trade,” one supplier said.
Italian incumbent ENI still controls all import routes and does not trade on the spot market.
CCGT — Dutch energy group Nuon has chosen Eemshaven in the Dutch province of Groningen as the location for its new 1,200 MW power plant
“Eemshaven is a superb, spacious location with a modern sea port, good infrastructure and excellent facilities for connection to the high-voltage grid,” Øystein Løseth, a member of Nuon’s management board, said in a statement. “In addition, the minister of transport, public works and water management, Karla Peijs, has stated her intention to have the channel leading to Eemshaven deepened after a number of statutory conditions have been met. This means that deep-drafted vessels carrying fuel would be able to enter the port, an essential factor in ensuring the continuity of the new power plant,” he continued.
The company said it had also obtained a licence from Royal Dutch Shell to use the latter’s state-of-the-art coal gasification technology.
The utility said the technology was also very well suited to co-firing biomass, citing its power plant in Buggenum in the Dutch province of Limburg. As well as coal and biomass, Nuon said it wanted to use gas in the new power plant, in order to be able to react flexibly to new developments in the fuel market.
Nuon expects the necessary permits for the Eemshaven location to be issued in the spring of 2007 and said it would make a definitive investment decision in mid-2007, with first production of electricity scheduled for 2011. The utility estimates its development costs for the plant will exceed EUR 20 million, with the total cost estimated at more than EUR 1 billion.
CCGT — French power incumbent EDF has joined forces with Dutch utility Delta to build an 870 MW combined cycle gas turbine (CCGT) in the province of Zeeland, in the Netherlands.
Under the terms of the agreement, EDF and Delta will co-finance and co-operate the plant, which is set to be operational in 2009, the French incumbent said. The output will also be equally split between the two.
Discussion between the two companies will continue over coming months, during which the final details and conditions of the project will be hammered out. The project is still subject to approval by the respective boards of directors.
Delta is the fourth largest Dutch utility and “the first to be able to start on the construction of a large, new power plant since energy deregulation in 1998,” EDF said.
This is the French incumbent’s first move into the Dutch generation sector. In the Netherlands, EDF currently holds stakes in the Dutch energy exchange APX as well as in energy service provider Dalkia (34%).
According to a Delta spokeswoman, the CCGT will be built in Zeeland’s industrial region of Sloe, near the Scheldt river. The facility would secure high-calorific gas supplies via Delta’s connection to the Belgian port of Zeebrugge. “We are not sure who exactly the customers will be, but we know there is demand, so it could be some combination of local industrial demand as well as demand from further afield,” the spokeswoman said.
E&P — Norway’s Statoil has unveiled new seabed compression technology that will boost flows from its Åsgard field by 25%, though not until 2012.
Gas production from Åsgard is expected to increase by 25% when this technology is employed, i.e. approximately 30 to 40 billion cubic metres (Gm3). Installation of the compressor on the seabed is scheduled for 2012/2013. Qualification of the seabed technology will take place towards 2012.
“Gas compression may be relevant both for the Troll field in the North Sea and Snøhvit in the Barents Sea,” Knut Nordstad, senior adviser at Statoil’s research centre, said in a statement.
Lest it be forgotten that the Norwegians are strongly tipped to join the vast Shtokman field development project, the company adds: “Seabed compression at Åsgard will give Statoil useful experience for future projects… If Statoil becomes a partner on the Shtokman field in the Russian part of the Barents Sea, experience associated with new seabed technology will be useful.” Gazprom is expected to announce its chosen partners for Shtokman in August.
Statoil is operator for Åsgard, with a 25% interest. The other licensees are Petoro (35.5%), Hydro (9.6%), Eni (14.9%), Total (7.65%) and ExxonMobil (7.35%). The field has reserves of 27.5 Gm3.
E&P — Polish oil and gas company PGNiG has signed a letter of intent with the largest Polish oil and petrochemicals company, PKN Orlen, regarding cooperation in exploration and production (E&P) PGNiG said. The two groups are set to cooperate both domestically and abroad, mainly in the area of the Caspian Sea (Azerbaidjan and Kazakhstan), the Middle East and North Africa. PGNIG told EGM that its affiliates are currently involved in exploration in Libya, Kazakhstan, Ukraine, Algeria and India.
The two companies also said they were intending to discuss possibilities regarding the increased sale of compressed natural gas as an automotive fuel (CNG), as well as for cooperation regarding LNG imports to Poland. PGNiG is presently conducting a feasibility study for a 5 billion cubic metres (Gm3) per year LNG port. Polish gas consumption is 13.5 Gm3 per year, of which 4.5 Gm3 comes from domestic production. The rest is imported mostly from Russia, but also from Central Asia, Norway and Germany.
Orlen is the largest consumer of natural gas in Poland, taking an annual 1.2 Gm3 per year, representing 17% of annual gas use by Polish industry.
Competition — Spanish incumbent Gas Natural’s grip on the liberalised gas market is loosening, according to a report published by regulator CNE. During the first quarter of 2006, power companies and international players held more than half of the gas in the market, the report showed.
Gas Natural is still by far the biggest, single player, accounting for 47.0% of gas sales in the liberalised market.
Iberdrola ranks second with 14.4%, overtaking third-ranking power supplier Union Fenosa with 12.8%. Iberdrola is currently entering the household market for the first time, developing gas infrastructure in the Madrid region and in the south of the country.
The country’s biggest power supplier, Endesa, only stood for 6.3%. Gas supplier Naturgas Energia took fourth place with 4.2% of sales in the liberalised market, followed by international majors Shell and BP with 4.1% and 3.6% each. Cepsa and BBE hold a liberalised market share of 2.9% each, with French gas incumbent GDF accounting for the remaining 1.7%, the report said.
In terms of customers, Gas Natural’s market share jumps to 69.6%, with Endesa in the second spot with 10.3%.
In the first quarter of 2006, 79.6% of gas demand was covered by the liberalised market. The consumption in the regulated market rose due to the seasonality of household demand. In terms of customers, 35.4% were buying in the liberalised market, up from 34.1% at the end of 2005. Almost all industrial users are sourcing energy in the liberalised market (98.0%).
E&P — British BP and Danish Maersk Oil North Sea UK have launched the first stage of a new development project to produce gas from the Harding area in the North Sea, BP has confirmed. The two companies have now approved Front End Engineering and Design (FEED) work for the Harding area gas project, hoping to start exploiting untapped gas resources in the field.
The project would link a new gas processing platform to the existing Harding platform, which currently only produces oil. This platform could then process and export gas at rates up to 400 million standard cubic feet (mmscf), or 11.336 million m3, of gas per day, BP said. An export pipeline would also link the new gas platform to the existing Brae gas transmission pipeline into St Fergus and an under-water tie-back of the high pressure high temperature Devenick gas field.
The FEED work, costed at £8.4 million, is expected to last until year-end. A final decision on the project is expected then. If it receives the go-ahead, the earliest date for first gas would be in late 2009.
BP operates the existing Harding field, and holds a 70% stake in it, with Danish energy group Maersk Oil North Sea UK Ltd owning the remaining 30%.
Competition — Italian power incumbent Enel has been granted a UK gas shippers’ licence by British energy regulator Ofgem, the regulator says. Enel has previously said it looked at the UK primarily as a trading opportunity, but was not available to comment further on its UK ambitions at the time of going to press.
Enel traded around one billion cubic metres (Gm3) of gas on the wholesale market in 2005. The company buys around 13 Gm3 of gas a year. It sells about 5 Gm3 to final customers and uses around 7 Gm3 in its own power plants.
The Italian and UK gas markets are not directly linked and the Italian wholesale trading market (PSV) is still very immature and illiquid, largely taking price direction from oil-linked formulae. But there is an indirect link, via some suppliers buying gas for Italy on the Dutch TTF hub, which is closely correlated to the NBP from 2007. EGM also understands that some deals have already been done legging in the PSV against the NBP.
Interconnector — After years of the Belgian gas network operator complaining about UK gas quality restrictions, it apparently still hasn’t provided adequate data to the British regulator about the “materiality of gas quality as an issue.” Ofgem this month published a sharp, open, letter it has written to Belgium’s Fluxys, asking why the network operator has not yet provided the information it requested.
Ofgem says it still hasn’t received real proof that the blending of gas at either end of the Interconnector could lead to increased deliveries to the UK. Nevertheless, it has asked National Grid to undertake an assessment of the options for gas treatment at Bacton with the full study to be published shortly.
Ofgem says in its letter: “It is unfortunate that you have still not provided any of the data we have requested although you have now had almost three months to do so.”
“The most efficient solution is one which will allow the market to determine the best provider of treatment services for their gas. This could be from services provided at Bacton, Zeebrugge or at the interconnector itself.”
E&P — CH4 Energy is to begin gas production from its Chiswick field in the southern North Sea in January next year, the company said. The gas will be shipped to the Netherlands and sold at the TTF.
Chiswick will produce 1.6 million cubic metres per day (Mm3/day) initially from the high cal field, though after the second well is drilled in June 2007, production is expected to exceed 2.0 Mm3/day.
“Production of 3.0 Mm3 would be good,” CH4’s managing director, Mark Routh, told EGM.
CH4 Limited owns 100% of block 49/4a and has agreed terms to export the Chiswick gas through the K13 extension and WGT pipelines to the Den Helder terminal in the Netherlands. The gas may end up in the UK through the BBL pipeline, scheduled to flow to Britain in December this year.
In July 2003, CH4 bought a 25% stake in the ETS gas pipeline, which runs from the Trent & Tyne fields in the southern North Sea to the Bacton gas terminal. It also bought a 37.5% operating interest in the Markham field in May 2004.
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