the eu versus gazprom...socar role pivotal in caspian gas options 14 upstream gas producers, in...

Energy Economist

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Issue 372 / October 2012

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The EU versus Gazprom 3The EU’s competition directorate has opened proceedings against Russian state gas company Gazprom on three suspected anti-competitive practices in Central and Eastern Europe. The investigation risks being interpreted as a politically motivated attack. Andrey Konoplyanik assesses DG competition’s claims, the motivations that lie behind them, and the Russian reaction to events.

Commodities: cycles and super cycles 7Much has been made of the concept of the commodity super cycle. Journalists have seized on the theory as evidence to support arguments that the end of the commodity price boom is not only here but that its timing was inevitable. Yet at best the concept of the super cycle is a work in progress; at worst, it is merely an attempt to see order in recent undulations in global economic development where perhaps none exist. Neil Ford

US coal in decline 11Once mighty, the US coal industry’s domestic market appears in terminal decline. New power generation capacity is made up almost entirely of natural gas plant or renewables. Old coal plant closures are being hastened by regulation. In the face of shale gas, coal no longer seems cheap. On a variety of fronts, coal has been left standing on the starting line, outpaced by innovation in other sectors of the energy world. Elisa Wood

Socar role pivotal in Caspian gas options 14Upstream gas producers, in particular Azerbaijan’s state company Socar, have emerged as the key players in the effort to bring Caspian gas to Europe via the Southern Corridor. The final stage of the route – to Italy or to Austria – has yet to be settled. Both could still have a future, but the TAP project’s willingness to cede equity to producers seems to be the model most in tune with events. John Roberts

Petrobras over-stretched 17Despite billions of barrels of sub-salt reserves, Brazil’s Petrobras is seeing oil production stagnate. Output from its mature fields is declining, while development of the sub-salt is hampered by delays. Petrobras is struggling to reconcile its role as an oil company with the demands made on it by broader economic priorities and the lead it is expected to take in Brazilian industrialization. Dom Phillips

Iran sanctions cut both ways 21EU and US sanctions on Iran are proving a double-edged sword by keeping oil prices high even as economic growth falters. However, there is little that the US and EU can do except hope that the sanctions work. A release of strategic stocks would risk exposing impotency as much as strength and undermine any residual notions of International Energy Agency independence. Ross McCracken

Wind speeds and profits 24Onshore wind power offers a tried and trusted technology for investors in renewable energy. However, as government support schemes are cut, the energy yield of turbines becomes ever more crucial to revenues. Average wind speeds are hard to predict and vary significantly from one year to the next. As energy yield is a function of the cube of wind speed, these variations have a big impact on profitability. Paul Whitehead

2 EnErgy Economist / issuE 372 / octobEr 2012

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ISSN:

Contents

Features

The EU versus Gazprom 3

Commodities: cycles and super cycles 7

US coal in decline 11

Socar role pivotal in Caspian gas options 14

Petrobras over-stretched 17

Iran sanctions cut both ways 21

Wind speeds and profits 24

Events/Letters

Forthcoming events and conferences 27

Letter from Johannesburg: See you in court 28

Letter from Venice: Competition and climate 29

Letter from Moscow: Policy u-turns 30

Letter from Washington: Trade disputes flourish 31

Letter from Brussels: Daily reporting 32

Market News Highlights

Iraq oil deal to see KRG volumes rise 33

Sentiment palls on CNOOC bid for Nexen 34

Libya targets oil production of 1.8 million b/d in 2013 35

Japan eyes quick uptake of HH linked LNG imports 37

Egypt promises state oil and gas divestments 39

US coal supply to outstrip domestic demand 40

CCS developer seeks guidance to advance technology 41

Nuclear industry hit by multiple shutdowns 42

European gas-fired electricity plant in doldrums 43

Japanese cabinet fails to endorse nuclear phase out 44

Paper mills defend manipulation charges 45

Data

EU carbon price dips on signs of intervention opposition 46

Crude drops abruptly 47

Editorial

Just as it appeared to be getting into its stride, with Chernobyl and Three Mile Island receding in the collective memory, the nuclear industry was shattered by the tragic Fukushima disaster in Japan. This disaster may now have claimed its latest victim, Japan’s nuclear industry.

A Japanese government policy unit has proposed that each reactor close after forty years and that no new reactors be built. Japan has the world’s third largest fleet of nuclear reactors. This suggests the last Japanese reactor would go out of service around 2040, although if the three reactors already under construction are completed, the country could retain some nuclear capacity until just after 2050.

Despite the commitment to renewables, it is likely to be coal and LNG that benefit most from this proposal, a prospect to warm the hearts of all those involved in the massive LNG projects being built off Australia, and perhaps in the next few years off east Africa. However, the timing of that benefit is some way off. In the short term, the new policy suggests the country’s offline reactors will resume service, reducing LNG and coal demand.

However, there is clearly much ambivalence. Japan’s cabinet failed formally to endorse the proposal.

In an important sense, it is an odd policy. Either nuclear reactors are safe or they are not. Justifying a middle ground in which they are safe enough to use for 40 years but no longer is hard to sustain. The fact is that a long-term phase out is, above all, a pragmatic policy.

On the financial side, the huge amount of sunk capital in these reactors will see some use, and Japan will be spared much of the burden of increased hydrocarbon imports. On the political front, a week let alone 40 years is a long time. Nuclear advocates, including those in the electricity industry, know that if popular feeling is currently not on their side, there is plenty of time for a policy reversal.

— Ross McCracken

Nuclear twilight?


analysis EuropE gas

The European Commission published September 4 a press-release entitled: Antitrust: Commission opens proceedings against Gazprom. The release said that the EU’s competition directorate would investigate Russia’s state-controlled gas supplier Gazprom with regard to three suspected anti-competitive practices in Central and Eastern Europe. It said: “First, Gazprom may have divided gas markets by hindering the free flow of gas across member states. Second, Gazprom may have prevented the diversification of supply of gas. Finally, Gazprom may have imposed unfair prices on its customers by linking the price of gas to oil prices.”

Under EU competition law, if Gazprom is found guilty, it could be fined up to 10% of its turnover in the European market. The annual value of Gazprom’s gas exported to the EU is about $60 billion, which means the fine could potentially amount to as much as $6 billion. There is no time limit set for such investigations, which can often take years. Their duration depends on the specific case and level of cooperation between the company and EU competition authorities.

When the Commission’s spokesman Antoine Colombani was asked in Brussels September 5 how the Russian authorities had reacted to the move, he said: “To clarify, this is an investigation which concerns Gazprom, which is a company active in the EU single market, which sells gas to the EU, and so we are looking at the behavior of this company. This does not concern Russia.” He also tried to take the spotlight off Lithuania, which first called for EU action against Gazprom last year. Colombani said the Commission decided to act not just because of Lithuania, but also owing to its own “monitoring” and due to information from “market players.”

Political responseThe Commission may claim the investigation has nothing to do with EU-Russia relations, but Gazprom and the Russian government say it does. Gazprom published September 5 a press-release that stated: “OAO Gazprom scrupulously abides by all the provisions of international law and national legislation in all of the countries where Gazprom Group conducts business.” In addition, “Gazprom Group’s activities on the EU market are in full conformity with legal standards applied by other natural gas producers and exporters, this includes price formation mechanisms.”

The company also made a point of particular significance; the press release said that Gazprom expects that in the course of the investigation “it will be taken into account

that OAO Gazprom, registered outside the jurisdiction of the EU, is a business entity empowered, according to the legislation of the Russian Federation, with special social functions and a status of a strategic organization, administered by the government.” This is a clear indication to the European Commission that in dealing with Gazprom, it is dealing with the Russian state.

Moscow reacted immediately in support of its major budgetary donor. Dmitry Peskov, a spokesman for Russian President Vladimir Putin, questioned the Commission’s move, saying “it’s not clear why this suddenly has become a subject for investigation. Why is there this assertion of a violation of the security of supplies?” Putin himself at the Asia-Pacific Economic Cooperation Summit in Vladivostok September 9, said that he regretted the Commission’s actions. He said, “United Europe would like to preserve its political influence, and that we should pay for this. This is not a constructive approach.”

More importantly, Putin signed September 11 Presidential Decree 1285 “On measures protecting Russian interests in Russian legal entities’ foreign economic activities”. This decree is a direct response to the Commission’s investigation. It stated that the Russian State should protect the interests of Russian strategic enterprises in their operations abroad. Gazprom is listed as a strategic enterprise in Presidential Decree 1009, signed in August 2004.

Decree 1285 deals with three main aspects of business: disclosure of information, the alteration of contracts, and the sale of assets. It states that strategic enterprises and their subsidiaries “should supply information on their activities upon request from the authorities and agencies of foreign countries, international organizations, … only subject to prior consent of a respective federal executive body authorized by the Russian Government.”

The same procedure shall apply if such enterprises make amendments to contracts and other documents concluded with foreign counterparts concerning their commercial (pricing) policy in foreign states, and/or sale of assets and/or entrepreneurial rights. The decree states that the authorized body must refuse to grant its consent to these actions if they could harm Russia’s economic interests. No definition of the country’s economic interests is provided. The government has been given one month to appoint the relevant federal executive bodies.

The EU versus GazpromThe EU’s competition directorate has opened proceedings against Russian state gas company Gazprom on three suspected anti-competitive practices in Central and Eastern Europe. The investigation risks being interpreted as a politically motivated attack. Andrey Konoplyanik assesses DG competition’s claims, the motivations that lie behind them, and the Russian reaction to events.


analysis EuropE gas

Also September 11, Sergey Kupriyanov, a spokesman for Gazprom, clarified at a press briefing that “now requests related to information disclosure, contract alterations and asset sales should be addressed to an authorized body, and if this is not in line with Russia’s economic interests, a request will be refused by the authorized body”. These statements and actions reflect both Moscow’s willingness to defend Gazprom, as well as the rising temperature of EU-Russian relations following the announcement of the EU investigation.

Gazprom in Central and Eastern EuropeThe European Commission’s press-release stated that “Gazprom may be abusing its dominant market position in upstream gas supply markets in Central and Eastern European member states”. Such a statement, the use of raids on Gazprom offices and the competition investigation create a perception of immediate guilt about which Gazprom can do little. The company does have a dominant position in CEE and, like any other business, seeks to maximize its profits.

However, this is a position that Gazprom has inherited. EU gas markets are dominated by ‘incumbents’, former monopolies that inherited their dominant positions when EU markets were liberalized. Gazprom finds itself in a similar position in CEE and is no less willing than its incumbent counterparts in the EU to give up the benefits of the monopoly position in which it finds itself.

Owing to the capital-intensive and long-lived nature of investments in natural gas supply and transmission, all companies live today with the results of decisions taken decades ago. Gazprom’s dominant position in CEE markets is the result of investment decisions taken within the completely different political and economic environment of the Cold War, when CEE was part of the Council for Mutual Economic Assistance (COMECON). Gazprom cannot be held responsible for this. No alternative supplies were developed for CEE under the planned Soviet economy, which is why all pipelines destined for the CEE are east-west oriented.

For almost 40 years until the end of the 1990s, the pricing of such monopoly supplies favored the COMECON states, even after the organization’s collapse at the end of the 1980s. Soviet (and later Russian) gas supplies to CEE were based on “cost plus” pricing, which resulted in lower gas price levels compared with “Net-Back Replacement Value” gas pricing with oil product indexation for Western Europe. Economic ties between the USSR and COMECON member states were based to a large extent on discounted oil and gas prices. These acted as the backbone of political ties within COMECON – discounted energy in exchange for political loyalty.

Only in 1998, ten years after the “velvet revolutions” in CEE states, and their move towards EU membership, was CEE import gas pricing transformed from cost plus to NBRV, in other words to “European formulas”. At the

time, the oil price was low, so the shift created no major negative results in CEE.

However, only when the situation in EU gas markets changed radically after 2009 did Gazprom become the target of EU attentions. Gazprom has stayed the same, while the external economic environment has changed. Economic crisis in the EU and the US shale gas revolution led to a surplus of gas in Europe and low spot prices in EU markets. Oil prices – and thus oil-indexed gas prices – remained high. This created a substantial gap between the prices provided by spot and long-term oil-linked contracts. Gazprom remains unchanged, but the market in which it is historically the dominant player has altered. It is the new market conditions that matter most today.

The chargesThe EU’s competition directorate claims that “Gazprom may have divided gas markets by hindering the free flow of gas across member states.” As mentioned, Gazprom has not divided CEE markets, they were divided by former Soviet central planning.

Today’s lack of ‘free flow’ between CEE markets is the result of a lack of internal EU infrastructure development (interconnectors, reverse flows, etc.). This, in turn, is the result of low investment stimuli for project financiers to invest in regulated infrastructure development within unbundled EU gas markets. Since 2003, the EU has imposed mandatory third-party access on infrastructure and nowadays de facto enforced spot/exchange pricing, which, inter alia, means that the rate of return on infrastructure developments is in the low-single digits with pay back periods in excess of 20 years.

However, DG competition most likely has existing infrastructure in its sights. In contrast to building new pipelines, which requires high levels of capital expenditure and long lead times, DG competition appears to want access to existing infrastructure. The utilization rate of EU gas infrastructure is estimated at about 70%. So the aim appears to be immediate access with no capital expenditure to infrastructure developed earlier on a project financing basis by other economic entities, regardless of both ownership rights and the contractual status of the infrastructure’s capacity. If this is the case, the EU is simply after a capex-free ride.

The competition directorate’s second claim is that Gazprom “may have prevented the diversification of supply of gas”. In 1911, Winston Churchill, then UK Navy Minister, famously proclaimed that energy security meant diversity of supplies. In today’s world this means for the consumer the diversification of supplies, in terms of conventional and unconventional gas, and in suppliers, both domestic and external. However, these are decisions for gas buyers and other gas suppliers, not Gazprom. Gazprom can’t prevent the development of alternatives to its own supplies, such as LNG, shale gas and alternative pipelines.


analysis EuropE gas

Moreover, as Gazprom deputy ceo Alexander Medvedev argues, Gazprom has been the initiator of competitive supplies to the EU market by breaking the monopoly power of Ruhrgas as sole importer of Russian gas to Germany and by establishing Wingas (a 50/50 joint venture with BASF) to provide alternative supplies. Even now, Gazprom has been actively improving the diversification of gas supplies to the EU by developing the North-South gas supply corridor, which is critically important for the CEE.

The combination of the Nord Stream, OPAL and Gazelle pipelines creates alternative routes for EU gas supplies. Supply from planned LNG terminals at Krk Island in Croatia and Swinoujscie in Poland to this North-South gas pipeline system are inevitable. This will add a new dimension to the corridor, which includes the diversification of supply sources beyond Russia.

In addition, Gazprom’s pricing policy unintentionally stimulates EU gas supply diversification, especially in CEE, where member states have the least competitive supply choices, compared with the older EU members. If alternative gas supplies emerge within the EU, for example shale gas, Gazprom’s oil-indexed gas would be the first victim.

Gazprom would already have lost more export volumes had it not been for “take-and/or-pay” (TOP) provisions and price review clauses in existing long-term contracts which prevent an immediate switch from contractual gas to spot gas. When the current LTGEC terms expire, Gazprom, as marginal-cost supplier to the EU, will definitely suffer most. But Gazprom’s refusal to ban TOP provisions cannot be considered a prevention of

diversification, since no unilateral decisions in bilateral contracts are allowed. This is why wholesale buyers of Gazprom’s gas started arbitration procedures.

What really prevents diversification is a lack of investment stimuli i.e. unattractive rates of return and long pay-back periods. Diversification needs adequate infrastructure to create choices both for consumers and producers. The Third EU Energy Package provides possibilities, but they need to be implemented (converted) into regulatory procedures incorporated into corresponding Network Codes. Russian and EU experts have been jointly developing such procedures both within informal EU-Russia expert consultations on Third Energy Package issues, and within the framework of the newly established Russia-EU Gas Advisory Council. Gazprom representatives have actively participated in both processes.

The third charge is that “Gazprom may have imposed unfair prices on its customers by linking the price of gas to oil prices”. Consumers and producers have different views of what constitutes a ‘fair’ price. Indeed, the meaning of a ‘fair’ price changes as markets evolve. However, no price should be considered “unfair”, if two commercial entities agreed on its value or on the mechanism of its calculation in a contract.

In the initial stage of gas market evolution, cost plus prices were used. These reflected costs plus an acceptable rate of return e.g. a minimum acceptable price for the producer. Consumers had no alternative supply choices. Cost plus is an “investment pricing” mechanism in non-competitive markets. It resulted in ‘fair price’ levels adequate for conditions of initial market development, and for political pricing as well.

In the next stage (intensive market development) indexation evolved on the NBRV principle, linking gas prices to the prices of alternative fuels at the point of end-use. This appeared in competitive markets where inter-fuel substitution and competition existed. NBRV pricing provides a maximum marketable price for the producer/supplier and an affordable, competitive, preferential price for consumers, which is lower than that of alternative fuels. Regular adaptation of NBRV prices (price reviews) helps to support its competitive level. Oil indexation is an “investment pricing” mechanism in competitive markets. It results in “fair price” levels adequate for conditions of intensive market development.

Contrary to both investment pricing mechanisms, spot pricing is a “trade pricing” mechanism. It is short-term pricing adequate for trade transactions, but not for project financing. Project financiers will never prefer spot pricing for developing new projects and will accept it only as a result of external pressure.

Oil indexation has been used in the EU since 1962. It emerged in the Netherlands and has been an integral part of the Groningen-type LTGEC. It took almost 50

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analysis EuropE gas

years for it to spread across Europe and beyond. In the 1960s, replacement fuels for gas were residual fuel oil (RFO) and light fuel oil (LFO). Nowadays, a broader spectrum of replacement fuels is available in the EU end-use energy mix.

For instance, in EU electricity generation, gas no longer competes with RFO, but with coal, nuclear and renewables. But oil indexation is still dominant in European LTGECs. According to the International Gas Union, its role had diminished from 80% in 2005 to two-thirds in 2009. According to DG competition’s Energy Sector Inquiry (2007), 90% of the LTGECs of three key EU gas exporters – Russia, Norway, and the Netherlands – referred to RFO plus LFO. Algeria, like Japan, indexed its gas to crude oil.

The evident and increasing gap between contractual and physical practice is why there is such heated debate about oil indexation. But that does not mean that the practice is “unfair”. The slow adaptation of oil indexation is inevitable, but not a full conversion to spot pricing throughout the EU. The preferable and most probable scenario for LTGEC pricing formulas in Continental Europe is to retain indexation, but to include greater elements of indexation to spot gas prices and other competing forms for electricity generation, such as nuclear, coal and renewables.

DG competition’s Energy Sector Inquiry (2007) demonstrated that there is a historical evolution in the structure of indexation from less to more liberalized regions in the EU. While the initial Groningen pricing formula presented 100% oil indexation (40% RFO/60% LFO), current contracts in Eastern Europe are based 95% on oil and in most of Western Europe 80%. In the UK, the proportion is only 30%. This suggests that the more competitive the market, the less the dependence on oil indexation.

CEE countries are at the back not the fore-front of this movement. However, the driver of evolutionary change should be objective market development trends, and the build-out of infrastructure that creates choices, not administrative pressures.

The role of politicsThe EU’s competition directorate has provided the right facts, but got both the reasoning behind them and, arguably, the target wrong. This mistaken logic could set in chain actions that damage rather than improve cooperation between Russia and the EU in the energy sphere.

Moreover, from a Russian perspective, there are other possible explanations for the timing of the EU’s move against Gazprom. The current economic crisis and its apparently approaching second wave is one reason. In these circumstances, the Commission wishes to support domestic energy companies, which are wholesale buyers of Russian gas and big EU taxpayers.

Gas oversupply has led to low retail prices, while contract wholesale purchasing prices stay high. TOP obligations forced EU gas companies to buy at high wholesale market rates, while regulatory measures oblige them to sell to end-users at low spot prices. This resulted in negative spark spreads and huge losses for these intermediaries, prompting the wave of arbitration procedures initiated by EU companies against Gazprom. Nothing personal, just business – on both sides.

However, the EU’s competition probe could be interpreted as a means of casting Gazprom in a negative light, and thus an attempt to influence neutral and independent court decisions in favor of buyers. This interpretation is especially seductive, if one takes into consideration that the Commission has opened its investigation on the basis of information from “market players”, as Colombani said.

Gazprom may well be the wrong target. The business of reselling Russian gas to EU end-users by wholesale EU intermediaries, which have grown to the level of ‘national champions’, has began to slip. The EU’s Third Energy Package opens the way to bypass these national champions by developing new streamlined gas value chains between producers and end-users.

The role of such dominant intermediaries, historically justified by the political split of Europe, may no longer be appropriate in the new architecture of the internal EU gas market. The dominance of EU incumbents has for long been a source of irritation for EU competition policy, yet the charges against Gazprom appear to be an attempt to support them by artificially worsening the business conditions of their foreign-based competitors and/or collaborators.

Another purely political explanation for the Commission’s behavior might be to switch the public’s attention from internal crisis to an ‘external enemy’. Unfortunately, the Russia-Ukraine gas crises between 2006-2009 have already prepared the ground for Gazprom to be demonized.

There is a clear sense that the EU is using its competition policy in a less than even-handed way. The aim is to declare oil indexation and TOP conditions unfair, not because they necessarily are, but because the economic environment has changed to make such a decision highly advantageous to EU gas companies. However, increasing competition in the EU gas market would be a better means of forcing Gazprom to adapt to a more open market rather than administrative attack, which will be interpreted as politically motivated rather than an objective matter of competition law.

Andrey Konoplyanik is a professor at the Gubkin State Oil and Gas University in Moscow and, amongst other posts, has formerly been a consultant to the board of Gazprombank and deputy minster for fuel and energy. Further information about the author can be found at www.konoplyanik.ru


analysis intErnational EnErgy

Much has been made of the concept of the commodity super cycle. Journalists have seized on the theory as evidence to support arguments that the end of the commodity price boom is not only here but that its timing was inevitable. Yet at best the concept of the super cycle is a work in progress; at worst, it is merely an attempt to see order in recent undulations in global economic development where perhaps none exist. Neil Ford

Commodities: cycles and super cycles

Although there were earlier attempts to postulate the theory, the concept of the commodity super cycle really emerged through the work of various economists and economic historians in the 1960s and 1970s. Writing in 1979, historian Walt Whitman Rostow provided this description of the pattern: “The lags involved in responding to a relative rise in food or raw material prices, and the fact that the response often required the development of whole new regions, led to an overshooting of world requirements and a period of relative surplus. A relative fall in the prices of food and raw materials then followed … until expanding world requirements caught up with the excess capacity.”

This seems entirely plausible as far as it goes. However, what is far more doubtful are attempts to stipulate the length of any long-term economic cycle, with the expectation that it will be replicated in the future. Rostow identified a roughly 50-year super cycle, with upswings over the years 1790-1815, 1848-1873 and 1896-1920; and downswings during the intervening periods of 1815-1848, 1873-1896, and 1920-1936. The reason why most economists restrict their analyses to the past 200 years is that GDP generally mirrored population size prior to the Industrial Revolution, but is now more closely tied to productivity.

More recent attempts to assess long-term trends in commodity prices have been able to make great use of vast amounts of data. In their February 2012

article, Super-cycles of commodity prices since the mid-nineteenth century, Bilge Erten and Jose Antonio Ocampo identify four super cycles over the period 1865-2009, ranging in duration from 30 to 40 years. Writing for the United Nations Department of Economic and Social Affairs, they conclude that non-oil price super cycles follow global GDP and are therefore demand led, but oil price super cycles are driven by supply. Erten and Ocampo identify two main differences between super cycles and short term fluctuations: the longer timescale and the wider range of commodities involved.

There are certainly some clear examples of extended periods of economic growth and high commodity prices. The period 1842-97 saw the industrialisation of North America and Western Europe on the back of coal and iron, particularly in the form of railways and steamships. Another stemmed from a combination of post-war recovery in Europe and the emergence of Japan as a global economic power in the 1950s and 1960s. The 1970s commodity boom lasted about ten years, while prices were also high over the period 2001-11.

Indeed, the first decade of the new millennium saw an historic commodity price boom, when the price of energy and metals more than doubled over the period 2003-08 in real terms. From oil and gas to copper and iron ore, demand for hard commodities soared. Although the price of food commodities increased by just 75% over that period, this reversed a general downward trend in food prices since the Green Revolution entered the mainstream in the 1970s.

The commodities boom of the past decade has had momentum of its own. Oil and mining companies have generated bumper profits from high commodity prices and have been able to reinvest their income in new exploration and production. Muscular economic growth in China and India has inflated prices even during a period of rising output.

The potential existence of super cycles and their duration is important to the energy sector for several reasons. Firstly, investors in energy and mining projects sanction new developments based on anticipated demand. The consumption of commodities and energy is clearly linked, so how super cycles operate is therefore of utmost importance in long-term planning, particularly as hydrocarbon fields and mines take so long to proceed

-0.5-0.4-0.3-0.2-0.10.00.10.20.30.4

1875 1900 1925 1950 1975 2000

4.8

5.0

5.2

5.4

4.0

4.2

4.4

4.6

Real Price Trend

Real non-oil commodity price components, total index, 1865-2010 (log scales)

Non Trend Super Cycle

Source: Erten and Ocampo, DESA Working Paper No, 110



from planning to profit. Secondly, commodity dependent exporters need to plan for both upswings and downswings in demand. Help in determining their timing is therefore useful.

Finally, attempts to understand super cycles can improve long-term analysis of supply and demand. Super cycles are an attempt to measure and predict the complex interplay of social, political, economic and demographic factors that determine the scale of demand and, to a lesser extent, supply. Commodity suppliers already seek to forecast very long-term demand through wide-ranging analysis. Oil major Shell, for example, uses its long-standing scenarios to forecast energy demand around the world up to 2050 and even beyond.

Not inevitableHowever, the biggest criticism of any deterministic theory of the commodity super cycle is that there is a big difference between describing the pattern of past economic development and predicting future trends. Patterns can always be found in long-term data, as even random distribution creates clusters. History is full of trends, but there is nothing inevitable about the commodity super cycle, just as there is nothing inevitable about the socialisation of the means of production or any other materialist interpretation of history.

First and foremost, there is great doubt about the length of the cycle. Ruchir Sharma, the head of emerging markets at Morgan Stanley Investment Management explains: “The 200-year history of commodity prices shows a repeated trend of two decades of price declines, followed by one decade of price gains.” Simon Kuznets, winner of the Nobel Economics Prize, identified the Kuznets Cycle, whereby rapid infrastructural investment pushes up demand for commodities on a 20-year cycle. He still has many supporters today. Many identify the BRIC nations of Brazil, Russia, India and China as being in the middle of a Kuznets cycle, as their infrastructural spending is increasing by an average of about 10% a year.

Others offer different figures. HSBC calculates the post-millennium boom at just seven years. Erten and Ocampo seem to offer a fairer assessment, calculating that super cycles can last anything from 20 to 75 years, with the upswing comprising roughly half of that period. It should also be noted that the theory of the commodity super cycle has its roots in the experience of Western Europe and North America over the past 200 years. This does not mean that it is universally applicable.

Also what happens when there are no economies left to emerge? Are further technological step increases required to begin the process again? Upswings tend to occur when technological innovations – or at least their popularisation – cluster. Even with regard to the more general theory of super cycles, a handful of economic

cycles over a two hundred year period are too small a data set on which to base a theory. On balance, Gary Becker of the American Economic Association seemed right when he said of super cycles in 1988: “We will need another 200 years of data to determine whether they do exist or are just a statistical figment of an overactive imagination.”

Moreover, too little analysis of super cycles seems to take supply-side factors into account, as resource depletion can also drive up prices. On the opposite side of the equation, new technology can bring new supplies on stream. For instance, North American gas prices have fallen as a result of the rapid development of unconventional gas production. Supply can also be affected by production costs. Oil production costs on new fields are generally much higher than in the past because so much new production capacity lies in deepwater, ultra deepwater or unconventional fields. At the same time, the cost of the metals used in constructing oil rigs, pipelines, tankers, LNG liquefaction trains and LNG carriers drives up oil and gas production costs.

Focus on ChinaThe big question is where the world economy is at present in terms of the demand cycle of upturns and downturns. The recent boom was fuelled by rapid growth in China and to a lesser extent India, and as during all cycles it was derailed by a slowdown in global economic growth, in this case resulting from problems in more mature economies. In a recent note, Barclays Capital argued: “In what appears an all too familiar repeat of recent history, the macro-economic factors that have contributed most toward commodity price weakness over the past two years – European sovereign debt worries and fears of a hard landing in China – have returned to haunt markets.”

Other observers agree. Sharma of Morgan Stanley says: “China’s growth is downshifting to a lower plain, its very commodity intensive phase of growth is coming to an end…This to me marks a big decade of increase in commodity prices coming to an end. I

-1.2

-0.8

-0.4

0.0

0.4

0.8

1.2

1.5

2.0

2.5

3.0

3.5

4.0

4.5

1875 1900 1925 1950 1975 2000

Real Price Trend

Real crude oil price components (log scales)

Non Trend Super Cycle

Source: Erten and Ocampo, DESA Working Paper No, 110



suspect that we’re headed now for two decades down as far as commodity prices are concerned. This is the sunset of the big commodities super cycle.” Edward Morse, the global head of commodities research at Citigroup, wrote in a report in April: “China’s increasingly differentiated impact across commodities is providing abundant evidence that the coordinated commodity super cycle of the last decade may be coming to an end.”

Such conclusions are based on faltering confidence in the mining sector and lower raw materials prices. The Dow Jones-UBS Commodity Index has fallen 25% since last April. If Indian and Chinese annual economic growth falls below 5%, then the knock-on effects could be huge, particularly if North America, Japan and the EU remain in the doldrums. Countries that have ridden the wave of the economies boom will suffer, led by Brazil, Russia and even Australia. Those countries in the industrialised world that have prospered while China and India remained relentlessly upbeat will also pay the price, possibly dragging their domestic economies back into recession.

Yet such an eventuality is not guaranteed. It is only one possible outcome and it is still too soon to call time on the commodities boom. Some organisations, including the World Bank, believe that the upswing ended in 2008, but this was probably not the case. Demand and prices recovered sufficiently after 2008 to indicate that the world economy may not be in the decline phase of the cycle, even if industrialised economies continue to struggle.

Annual economic growth in China has averaged 10% over the past 30 years and every partial slowdown during that period has prompted analysts to suggest too hastily that it was inevitable that the Chinese boom would run out of steam. Erten and Ocampo argue that: “the remarkable strength and length of this upswing in commodity prices reflect the extraordinary resilience of growth performance” of major developing countries.

In fact, most analysts tie their predictions to the fate of China. Nik Stanojevic, a mining analyst at wealth management firm Brewin Dolphin, said: “The jury is out on whether the commodities super cycle has reached its peak. It’s certainly a possibility. It remains to be seen how growth pans out in China and what will happen to the rate of Chinese urbanisation and industrialisation in coming years.”

The short-term direction of different commodity prices may differ as a result of the relative slowdown in China. The country consumes 11% of global oil supply, but 40% of copper production. Beijing has steadily reduced its forecast for this year’s economic growth to 7.5% on the back of disappointing economic data. India now expects 6%.

Both figures are still high by historic standards, but the trend is certainly down. The Chinese boom saw about 220 million people migrate from rural areas to the cities, creating a manufacturing sector workforce that required homes and other infrastructure. Such mass migration could be replicated in China over the next decade, but there are simply not enough people

Descriptive statistics of long-term trends in real commodity prices

Non-oil Commodity Prices (Total Index) 1865-1885 1885-1994 1994-2010

Annual compound growth rate 0.10% -0.60% 0.50%Cumulative growth rate 1.40% -47.20% 8.30%Duration (years) 20 109 16

Metal Prices 1865-1881 1881-1974 1974-2010


Total Agriculture Prices 1865-1893 1893-1998 1998-2010

Annual compound growth rate 0.10% -0.60% 0.40%Cumulative growth rate 1.70% -49.20% 4.50%Duration (years) 28 105 12Tropical Agriculture Prices 1865-1888 1888-2002 2002-2010Annual compound growth rate 0.70% -1.00% 0.30%Cumulative growth rate 16.30% -67.20% 2.50%Duration (years) 23 114 8

Non-tropical Agriculture Prices 1889-1932 1932-1994 1994-2010


Crude Oil Prices 1875-1925 1925-1962 1962-2010


Source: UN Department of Economic and Social Affairs, 2012



left in rural regions to sustain that pace of urban immigration in the long term. In particular, there are not enough young, mobile people.

The shape of a commodity price cycle can be influenced by how governments and central banks deal with recessions. The current strategy of easing money supply reduces confidence in paper money, but increases confidence in raw materials. Much will depend on how Beijing responds to the slowdown. With foreign exchange reserves of $3 billion, it has the financial muscle to fund job creating infrastructural projects in order to maintain social cohesion.

This is more important in China than in most other major economies because of tensions between different groups in hastily developed urban areas and also the lack of approved political outlets for socio-economic discontent. Beijing has often demonstrated its willingness to pursue Keynesian style investment programs. Erten and Ocampo conclude that “Global output accelerations play a major role in driving commodity price hikes over the medium run. Therefore, the ongoing commodity price boom could last only if China and other major developing countries are capable of de-linking from the long period of slow growth expected in the developed countries.”

Beyond ChinaHowever, China is still just part of the picture. Despite the impact of the global financial crisis of 2008-09 on growth and economic confidence in the industrialised world, the global economy continues to grow ahead of population growth. Growth is strong in China, India, much of sub-Saharan Africa, most of Southeast Asia and parts of Latin America. It seems entirely possible that a sustained period of high demand for raw materials could result from current economic and demographic change.

Put simply, the world’s population is forecast to grow from 7 billion last year to 9 billion by 2050 and even more importantly, average living standards and consumption are expected to grow rapidly over that period in Africa, Asia and Latin America. It is also worth pointing out that 7.5% growth this year represents a larger increase in total GDP than a 10% increase in the

size of a much smaller Chinese economy ten or even five years ago. Depending on where that growth is registered, it will still consume huge amounts of copper, iron ore and oil.

A moderate slowdown in China could be balanced out elsewhere. Strong growth in sub-Saharan Africa could compensate for a fall of perhaps 3% of Chinese annual economic growth. There are currently roughly as many Africans as Chinese and there are likely to be twice as many by 2050. Much of the strong economic growth recorded in sub-Saharan Africa over the past ten years has resulted from high commodity prices. This not only boosted income but encouraged the development of reserves that had previously been untapped, often because of the lack of transport infrastructure.

Higher prices and improved political and economic security have encouraged investment in commodities from Congolese iron ore to Mozambican coal. The big question is whether economic growth in Africa will translate into much greater infrastructural expenditure. The pace of road, rail, airport, port and residential construction suggests that this could indeed be the case.

Most commodity prices have fallen from their peak of 2008. Oil was trading at about $110 a barrel towards end-September, down from a peak of $147/b in 2008. Whether the peak has well and truly been passed or the period 2008-12 turns out to be a blip in an upswing remains to be seen.

Yet the important point is that the outcome will be determined by multiple factors affecting the health of the global economy: by a settlement to the eurozone crisis; the extent to which the Chinese economic boom slows; the uncertain recovery in the US economy; the endurance of Indian economic growth; and the extent to which Africa continues its long-awaited renaissance. It will not be determined by any pre-ordained, economic pattern. Economics is not the predictive science that many would like it to be. The results of the past cannot be replicated in a controlled experiment and cycles can only be judged historically.

Crude oil prices

1892-1947 1947-1973 1973-1998 1998-ongoing

Peak year 1920 1958 1980 2008Percent rise in prices during upswing 402.80% 27.40% 363.20% 466.50%Percent fall in prices during downswing -65.20% -23.10% -69.90% -Length of the cycle (years) 55 26 25 -Upswing 28 11 7 10Downswing 27 15 18 -Mean (of the full cycle) 36.9 24.8 53.2 91.2Standard deviation 3.9 0.7 8.5 16.4Coefficient of variation 27.9 7.5 42 47.4Skewedness 0 -0.3 0.8 0.3Kurtosis 3 2.2 2.4 1.9

Source: UN Department of Economic and Social Affairs, 2012


analysis unitEd statEs coal

Once mighty, the US coal industry’s domestic market appears in terminal decline. New power generation capacity is made up almost entirely of natural gas plant or renewables. Old coal plant closures are being hastened by regulation. In the face of shale gas, coal no longer seems cheap. On a variety of fronts, coal has been left standing on the starting line, outpaced by innovation in other sectors of the energy world. Elisa Wood

US coal in decline

As coal fuels fewer and fewer power plants in the US, it ignites more and more political controversy. US use – or growing disuse – of the resource has become a rallying cry in the presidential race. Republican challenger Mitt Romney is painting President Barack Obama as the scourge of the industry and himself as its white knight. During an August rally in the key state of Ohio, with hard-hat coal miners standing behind him, Romney accused Obama of “waging war on coal” and trying to bankrupt coal-fired power plants. “We have 250 years of coal, why in the heck wouldn’t we use it?” he said.

Obama certainly appears to have cooled toward conventional coal since his days as a US senator representing the coal state of Illinois. Now, when the pro-renewables president focuses on coal at all, he mostly pushes for ‘clean coal’ and warns that Romney would gut government efforts to develop Carbon Capture and Storage technology. As a result, while the coal industry backed Obama in the last election, it is at best silent and at worse opposing him this time round. The United Mine Workers, which endorsed his candidacy in 2008, has taken no position on the race so far. At the same time, pro-coal groups have organized in opposition to Obama in West Virginia, a state second only to Wyoming in coal production.

However, coal’s future depends on more than what is decided in Washington. No one disputes that the market is playing a role, especially with coal’s chief competitor, natural gas achieving record low prices this year. As Michael Morris, former AEP president, CEO and chairman, told the New York Times: “The math screams at you to do gas.” Morris made the statement in reference to AEP’s plan to retire the 1,097 MW Big Sandy coal plant in Kentucky

and convert it to natural gas. The company later withdrew the decision, but still plans to retire coal-fired plants with combined capacity of 4,600 MW.

This is bad news for the US coal industry, which counts on the electricity generation sector for its survival. Power plants use about 90% of the coal mined in the US. But the generation industry has not been kind of late. First, little new coal-fired generation capacity is being built. Instead, the US is developing mostly natural gas-fired power plant and renewables. Or, in some areas of the country, planners are concentrating on increased energy efficiency and demand management as a means of avoiding major new investments in infrastructure.

Second, remaining coal plants are dispatched less and less on the grid because they cannot compete against natural gas-fired generation. The power sector is expected to use only 829 million short tons of coal this year, well below the annual average of 1 billion short tons from 2003 through 2008, according to the US Energy Information Administration.

During first-half 2012, the US added 165 power plants in 33 states, totaling 8,098 MW, fueled predominantly by natural gas and renewable energy. Poignantly, the gas-fired plants were added in states that customarily burn mostly coal, with the exception of Idaho, which uses large amounts of hydropower. Only one new coal project was completed in the same period, the 800 MW plant at the Prairie State Energy Campus in Illinois, according to EIA data. “The only thing coal had going for it was that it was cheaper, and now it turns out it’s not cheaper,” said Andrew Holland, senior fellow for energy and climate at the American Security Project.

Not only are few new coal plants being added, but older plants are being retired more quickly than envisioned just a few years ago. The EIA expects 2012 to be a record year with 9 GW of plant closures. Long term, the federal agency projects that coal-fired power plants totaling 49 GW will retire through 2020 – one-sixth of US coal capacity – with the biggest impact over the next five years, as 27 GW of plant closes.

In late 2011, coal fell to less than 40% of the US power portfolio, a situation not seen since 1978. If EIA projections prove accurate, coal will not reclaim its 45% share of the US generation mix, set in 2010. In fact, EIA foresees its share falling as low as 38% over the next 25 years.

Electric capacity additions by half-year (MW)

14000

12000

10000

8000

6000

Solar

Other Renewables

Wind

Petroleum, Other

Natural Gas

Coal4000

2000

Jan-Jun2010

Jul-Dec2010

Jan-Jun2011

Jan-Jun2012

Jul-Dec2011

0

Source: EIA



Decline driversAll this suggests that US coal is an industry in serious decline, at least in terms of its once robust domestic market. Obama’s detractors – as well as many industry analysts – fault pending federal water and fly ash rules, uncertainty over the recently court-vacated Cross State Air Pollution Rule and most significantly, the Mercury and Air Toxics Standards, or MATS, which cap generator emissions rates beginning in 2015.

“There are two overshadowing drivers that are really having impact on the outlook as far as coal retirements are concerned,” said Rob Patrylak, managing director at Black & Veatch, a Kansas based engineering, consulting and construction firm: “Those are low gas prices and the EPA [Environmental Protection Agency] regulations. From an EPA regulation perspective, the one that is having the most impact from our analysis is the MATS.”

MATS is onerous because it requires coal plants to install equipment, rather than pay emissions costs, he said. The economics often favor retirement over a large investment in new plant equipment, especially for older, smaller and less efficient units, according to Patrylak. Most US coal-fired plants were built before 1980.

The EIA also describes MATS and other environmental regulations as factors driving retirements. The federal agency assumes in its projections that coal plants will have either Flue Gas Desulfurization or Direct Sorbent Injection installed by 2015 to comply with environmental rules. Half of US coal plants already have FGD systems, according to the EIA. “Particularly in the case of older, smaller units that are not used heavily, owners may conclude it is more cost efficient to retire plants rather than make additional investments,” the EIA said in a report published in late July.

Energy insiders dispute which plays the larger role in coal’s decline – environmental restrictions or market forces. Susan Tierney, managing principle of The Analysis Group and former assistant secretary at the US Department of Energy, says that broader trends began bringing down coal before the EPA’s new air pollution rules.

“While sometimes these decisions are complex, they essentially can resemble the basic choices that

households face, for example, when they have to decide whether making one more repair on an old car is worth it: often, making the repair is more expensive and risky than the decision to trade in that car and buy a new one with better mileage and other features that the old car lacks. These plant retirement decisions thus turn on these economic fundamentals,” she argued in her recent paper: Why Coal Plants Retire: Power Market Fundamentals as of 2012

She points out that record low natural gas prices have reduced wholesale electricity prices by more than 50% on average since 2008. At the same time, coal prices have remained relatively high, supported by expanding export markets. As a result, coal-fired plants have suffered, especially those that are old and less efficient. Some were already idle much of the time before utilities announced their retirements, she said.

Bradford Radimer, director of risk control at NRG Energy, echoed her sentiments. “Remember that a number of these plants have not been operating that well or that much,” he said during a recent webinar, ‘Energy Risk & the End of Coal?’, hosted by The Energy Collective. “There are a lot of other reasons, other than EPA regulations that these are closing. Many had become uneconomic already, but had just kept going through some power pool special provisions to make sure capacity is available.”

Others say it is near impossible to untangle whether economics or environmental policy are the chief cause of coal’s decline, since the two are closely intertwined. “I don’t think it is all one or the other. But the economics are really what is driving it. And the economics fit the Obama administration’s agenda,” said Richard Soultanian, president of NUS Consulting, a New Jersey-based energy management firm. “The Obama administration has been favorably disposed to using more natural gas.”

Consumption fallsOthers factors are playing into coal’s decline, such as the dampening of energy consumption in the US. Energy use continues to grow, but at a very slow pace, the result of a moribund economy, lower population growth, and increased use of energy efficiency. As a result, coal finds little or no incremental demand from energy consumption growth.

Reported coal generator retirements

Existing coal capacity Historical Planned (year-end 2011) 2009 2010 2011 2012 2013 2014 2015

Total net summer capacity (MW) 317,469 529 1,528 2,517 8,890 2,098 4,715 9,865Number of units 1,387 12 35 31 57 14 34 61Average net summer capacity (MW) 228 44 44 81 156 150 139 162Average tested heat rate (Btu/kWh) 11,281 12,200 12,879 10,714 10,897 13,922 11,067 10,659Average age at retirement N/A 50 54 62 56 55 57 57

Source: EIA



It’s a trend that is likely to continue for some time. The EIA does not see the US returning to pre-recession energy growth in the next two decades. Instead, growth is expected to hover at a modest 0.3% annually. To give a sense of the role energy efficiency is playing in that decline, the EIA points out that while the population will grow 25% over the next two decades, commercial floor space 27% and households 28%, energy use is expected to expand by only 9%.

Long-term trends aside, coal took an immediate hit this year because of mild weather that led to low seasonal electricity demand. In fact, March was the warmest on record. The weather contributed to a 6.6% drop in residential electricity sales in first-half 2012, compared with the same time period last year. In all, EIA expects residential electricity sales for the year to be 3.5% lower than last year.

Not only did power demand fall, but natural gas pricing competed fiercely with coal this summer, dipping to ten-year lows. As a result, more coal was backed out, and more natural gas called upon to serve the meager demand. “The very low cost of gas is making the scrubbing of these units uneconomical. It is even causing some once unthinkable dispatch changes. Super critical scrub coal plants are at times no longer being dispatched, which was just unthinkable three or four years ago,” said Daniel Krueger, partner and managing director at consultants Accenture.

In all, coal generation declined 29 billion kWh from the previous year, while natural gas generation increased 27 billion kWh during the same time period, according to the EIA. “It was the first summer where natural gas production of electricity equaled that of coal,” said Mark Gabriel, senior vice president/executive director of Strategy at Black & Veatch.

Environmental activism also appears to play a role in coal’s demise, although industry insiders tend to see it as subservient to the greater forces of abundant and inexpensive natural gas, decreased demand and environmental regulations. The Sierra Club has been one of the most aggressive opponents and takes credit for circumventing over 150 coal plant proposals in the US and leading 110 plants toward retirement.

Overtaken by innovationNRG’s Radimer sees another reason for the US movement away from coal – innovation. “The EIA sited four reasons for the plants closing; modest growth in electric consumption, low gas prices, combined cycle plants and aging coal-fired plants,” he said. “The common thread and the root cause behind this is really innovation, and I mean that in the broadest sense of both market and technology innovation.”

He pointed to the decrease in electric demand due to energy efficiency as one example: “Technology has made energy consumers use less energy at the same level of

comfort and service as they had before. We are using less energy to accomplish the same things we did before.” The same holds true for low gas prices, he said. “Why do we have low gas prices? Again it is innovation – innovation in new drilling technology. This has released a lot more energy than they ever thought existed.”

Coal itself has so far struggled in the race to innovate and make itself a more environmentally acceptable source of electricity generation. However, carbon cap and trade may not be off the table in the US, despite Washington’s rejection of the idea, says Larry Goldenhersh, CEO of Enviance, a California-based environmental data management company. A cap and trade program has been operating in the US Northeast for several years. California is about to begin a mandatory program as well, with the first auction scheduled for November.

By some estimates, California will raise $1 billion in allowance revenue the first year and as much as $14 billion by 2014, according to Goldenhersh. Should that happen, it is bound to capture the attention of the federal government, as it casts about for ways to overcome its deficit, he said. “It doesn’t matter who wins in November. I think you are going to have a very strong movement to impose cap and trade [nationally] by the time of the next election in 2016,” he said. Cap-and-trade schemes might provide a financial incentive towards greater innovation.

Janet Gellici, CEO of the American Coal Council, is optimistic about the eventual technical mastery of CCS, and possible new markets for carbon use. The oil industry is in search of CO2 for enhanced oil recovery. Stripping it off coal plants and selling it to oil facilities provides a business use for CO2. Suddenly, an economic impetus emerges to speed development of carbon capture, she said. “We need to reframe the conversation around CO2 as a valuable commodity,” she argues. “It is an attractive business opportunity for utilities.”

The coal industry could also benefit from increased US exports, as well as niche uses domestically. For

High Ref. Low

Projected retirements of coal-fired generators through 2020 (GW)

70

60

50

40

30

Rest of US

Southeast

Mid-Atlantic &Ohio River Valley

20

10

High Ref. Low0

Source: EIA

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Economic growthcases

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analysis unitEd statEs coal / caspian gas

example, coal plants are compatible with the growing and energy-hungry data center industry: “They are looking for power that can be supplied on a very reliable basis. They are not willing to bet on wind and solar,” Gellici said.

Natural gas prices offer another unknown in that they may not rock along the bottom for ever. NUS Consulting’s Soultanian sees certain states holding on more tightly to their coal-fired plants if natural gas prices rise. But he added, “unless your forecast is that the economic recovery will hockey stick and pick up in an aggressive manner, it is hard to see, with the amount of supply out there, that gas prices will move too quickly. At least for the intermediate time, people have confidence that prices will stay reasonable.”

Certainly, many factors are feeding into coal’s predicament. The sound and fury emanating from the presidential race might not match either candidates’ real ability to determine the industry’s fate. Indeed,

the American Coal Council’s Gellici says that while politics plays a role, it may be less influential than often believed. “It is not that any one person or party will change everything. There is a tendency to think that the world will return to normal with a change in administration – whatever normal is.”

Upstream gas producers, in particular Azerbaijan’s state company Socar, have emerged as the key players in the effort to bring Caspian gas to Europe via the Southern Corridor. The final stage of the route – to Italy or to Austria – has yet to be settled. Both could still have a future, but the TAP project’s willingness to cede equity to producers seems to be the model most in tune with events. John Roberts

Socar role pivotal in Caspian gas options

The story of the Southern Corridor is full of surprises. A year ago, three consortia submitted bids to carry Caspian gas to European markets: one group aimed to implement the Nabucco project, which would take the gas to the central European hub at Baumgarten in Austria; another favoured an interconnection system between Turkey, Greece and Italy (ITGI), while a third wanted to construct a Trans Adriatic Pipeline (TAP) that would connect Greece to Italy, but via Albania.

The three groups dutifully submitted their bids by October 1, 2011 and waited for the developers of the €20 billion ($25.9 billion), 16 Bcm-a-year second phase of Azerbaijan’s giant Shah Deniz gas field – commonly dubbed SD2 – to make their choice. They expected a firm answer sometime in early 2012.

Instead, they found themselves having to analyse within weeks the impact of a development that completely changed the dynamics of developing gas pipelines in Europe’s Southern Corridor. The development was the announcement on October 25, 2011 that Socar, the State Oil Company of Azerbaijan, a shareholder in Shah Deniz and a company deeply engaged in assessing prospective export markets for the consortium as a whole, was contemplating construction of its own pipeline across Turkey.

Events moved rapidly; within a month Socar President Rovnag Abdullayev had given the project a name: the Trans-Anatolian Pipeline (TANAP). This gave the Shah Deniz partners, and the Azerbaijani government, an alternative to both the all-the-way project that was Nabucco and reliance on an expansion of the existing trans-Turkish system operated by Turkey’s state pipeline company, Botas.

Officially, both TANAP and an expanded Botas system were to remain prospective choices for transit across Turkey until a decision between them was made in mid-2012. Unofficially, it soon became clear that TANAP was making all the running.

On June 26, President Ilham Aliyev of Azerbaijan and Prime Minister Recep Tayyip Erdogan of Turkey formally signed a binding Inter-Governmental Agreement on TANAP, while Turkish Energy Minister Taner Yildiz and Socar’s Abdullayev signed a Host Country Agreement concerning Turkey’s responsibilities for the project. A third agreement, between Socar and Botas, covered organizational and technical issues.

TANAP changed everything. It sidelined Botas, which would have just a 10% stake in the line. It ensured that it would be the upstream developers of the gas who

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Net generation by select fuel types

Source: EIA

(billion kWh)

Coal Natural Gas Nuclear Hydro


analysis caspian gas

would be responsible for developing more than half the infrastructure required to carry their gas to market.

And it usurped Nabucco, forcing its developers, if they wished to remain in contention, to come up with a much reduced option, dubbed Nabucco West, which would run for around 1,300 kilometers from Turkey’s western border with Bulgaria to Baumgarten, instead of 3,000 km from Turkey’s eastern border with Georgia, as envisaged in the original ‘classic’ Nabucco.

Socar leadIt also marked the arrival of Socar as a power that could use Azerbaijan’s new found oil and gas wealth to run its own export projects overseas. Azerbaijan’s accumulation of riches epitomised the dramatic change in thinking on the part of the producers in the years between the start of planning for SD2 exports in 2006 and the long-delayed point at which it was finally ready to call for supposedly final bids for export pipeline contracts in 2011.

At the start of this period, BP and its partners in developing Shah Deniz were still trying to keep costs down, opting to work with others prepared to raise the funds required to build the necessary export pipelines. They would then simply choose whichever offered the best combination of access to markets and tariff rates for actual shipment to those markets.

But, in 2006, Azerbaijan started to earn major oil revenues, owing to the commencement of exports via the Baku-Tbilisi-Ceyhan pipeline in June of that year. In the period immediately following, the key issue for all concerned was to recoup some of the vast expenditures that the international companies

in general, and BP in particular, had incurred in developing the giant ACG oilfield complex and the nearby Shah Deniz gasfield.

Six years later the situation is very different. Azerbaijan has cash in hand. As of July 1, the State Oil Fund of Azerbaijan was sitting on some $32.67 billion in accumulated oil revenues.

Moreover, it is not just Socar that is interested in taking a stake in export pipelines. From early on Socar said that although it had reached agreement for the Azerbaijani side to hold an 80% stake in TANAP with Turkish companies holding the remaining 20% (split evenly between Botas and Turkish Petroleum), it was prepared to relinquish up to 29% to other Shah Deniz partners.

BP, Total and Statoil have all expressed their intention to take up this offer. BP’s Turkey manager, Bud Fackrell, declared in a story reported by the Azeri Trend News Agency August 17: “The TANAP project is of interest for the entire region, and therefore we support it. BP received Socar’s offer to purchase part of its share. We intend to purchase a stake in this project.”

This is not by any means the only example of the upstream producers’ determination to take a stake in the current generation of pipeline projects. They already operate the South Caucasus Pipeline, which delivers Shah Deniz gas from Baku to the Georgia-Turkey border and which they plan to expand to meet the requirements for SD2 exports. In addition, August 9, three Shah Deniz Consortium members – BP, Total and Socar – signed an agreement with the existing shareholders in the TAP project – Switzerland’s EGL, Norway’s Statoil and Germany’s E.ON Ruhrgas – to help fund TAP development.

RUSSIA

UKRAINE

TURKMENISTAN

TURKEY

SYRIA

SLO.

SLOVAKIA

SERB.

ROMANIA

POLAND

MOLD.

MAC.

ITALY

GERMANY

IRAQ IRAN

HUNGARY

GREECE

GEORGIA

CZECH REP.

CYPRUS

CRO.

BUL.

BOS.

BELARUS

AZERB.

AUSTRIA

ARMENIA

AL.

KAZAKHSTAN

CaspianSea

Mediterranean Sea

Black Sea

4a4b

4c

5 1

1

1

7

8

1

6

2

2

3

Petrovsk

Odessa

Constanza

Brody

Baumgarten LanzhotLanzhot

Waidhaus

SamsunBourgas

Istanbul

Ankara

Dzhugba

Otranto

Brindisi

Tarvisio

Ceyhan

Tbilisi

Atyrau

Aktau

Baku

Sangachal

Tehran

Erzurum

Korpedzhe

Kort-Kui

TurkmenbashiKomotini

Stara Zagora

Nabucco1Nabucco XL2

Russian artery (simpli�ed)

Existing pipelines

Proposed pipelines

Trans Adriatic Pipeline5

ITGI (subsea line to Italy)4a

ITGI (DESFA link line) 4b

ITGI (Greece-Bulgaria Interconnector)4c

Arab Gas Pipeline6

South Caucasus Pipeline3 Ionian Adriatic Pipeline 8Trans-Anatolia Pipeline 7

South Stream pipeline route options

Southern Corridor gas pipeline projects

Source: Platts


analysis caspian gas

This wasn’t because TAP was suffering a shortage of cash; its backers have some of the deepest pockets in the current pipeline contest. But both TAP and Nabucco have quite understandably argued that if the Shah Deniz consortium wants both of them to remain as options for a year or so – the consortium has said it does not intend to make up its mind until the middle of next year – then they should not have to pick up all of the tab for remaining in business when one of them might eventually lose out.

However, a more important element of the August 9 agreement was that it gave Shah Deniz shareholders an option to take a 50% stake in TAP. Thus, as one TAP official told Platts recently, “the SD three (BP, Socar and Total) will have the option of taking up to 50% of the stake – so that would give the SD Four – (BP, Socar and Total plus Statoil) roughly two-thirds of TAP.”

Merchant model weaknessThis might be considered sufficient to settle the matter as to whether TAP will be chosen over Nabucco West, its last apparent rival to carry Caspian gas to Europe. But in fact the Shah Deniz consortium is discussing a similar arrangement with the developers of Nabucco. The problem is that Nabucco’s proponents have a very different goal to that of TAP.

TAP remains in essence a straightforward would-be purchaser of gas, which it plans to market along the TAP route itself and in Italy, Switzerland and markets north of the Alps. It does not particularly care who owns or operates the infrastructure so long as it gets the supplies it wants at a price that ensures it can operate successfully. Nabucco is a different creature altogether. It remains a merchant pipeline, a venture in which the project developers really do want to own and operate the system, making their money on the tariff charges for throughput.

So while there is no doubt that the Shah Deniz consortium members are willing to take major stakes in the Nabucco International Pipeline Company should the Nabucco West option be chosen, it is far from clear that Nabucco’s current shareholders – Botas, Austria’s OMV , Hungary’s Natural Gas Transmission Company (part of the MOL Group), Romania’s Transgaz; Bulgaria’s Bulgargaz, and Germany’s RWE – would be willing to offer them as much as a 50% share.

One or both?The issue has a bearing on what could yet prove to be the next great surprise in this long running saga: the nature of the choice to be made between TAP and Nabucco West. All too often, the question of how Caspian gas will reach Europe has been viewed as a race between rival pipeline promoters.

First it was the original ‘classic’ Nabucco concept for a line from the Turkish-Georgian border to Baumgarten against a much smaller proposal for an interconnector between Greece and Italy that could be plugged into a Turkey-Greece Interconnector. Then it became an

apparent contest between ITGI, TAP and Nabucco. Now it is viewed as a fight between TAP and Nabucco West.

But there are two possible outcomes that run counter to this view. The first is simply that while TAP is clearly favoured by many of the western commercial partners in Shah Deniz, its landfall, Italy, is not necessarily the destination of choice for Socar itself. Socar may only have a 10% stake in Shah Deniz, but it is Socar’s money and drive that is fuelling the TANAP pipeline.

There is a school of thought in Socar that argues that it really is important to get gas to the heart of Europe and the idea of going to Italy, first adopted by Statoil and then, apparently, by BP and Total, is misplaced.

This view within Socar questions what kind of infrastructure Italy can provide to ensure that gas going into the country can also be conveyed beyond Italy. Moreover, it asks what kind of competition would Azerbaijani gas face in the Italian market in an age of increasing LNG supplies? Better by far, this school concludes, to use a pipeline to carry gas inland, rather than to coastal Mediterranean destinations.

That would appear to favour Nabucco West. However, if Socar can develop TANAP, why not take a similar position on the onward extension to Baumgarten, and persuade its partners in the Shah Deniz consortium to go along with it? Now that Socar is a wealthy company that can afford to construct a major pipeline, it could take over the original Nabucco dream and construct a pipeline to deliver Azerbaijani gas to the heart of Europe; a pipeline, unlike Nabucco, largely financed by the producer of that gas.

It is far from clear whether this school of thought represents a dominant viewpoint within Socar and much will obviously depend on the progress that Socar makes in lining up prospective customers. After all, the choice of pipeline is only one element in the great Shah Deniz export issue; the other is actual gas sales.

However, there is an additional possibility. Proponents of the various pipeline projects, particularly when their case appeared threatened by a rival scheme, would commonly stress that they viewed their own project as opening the way for other projects to follow. It should not be assumed, they said, that they were necessarily seeking exclusive carriage rights for all Azerbaijani gas to Europe.

The focus on an either/or solution could be wrong and a more appropriate way of looking at the complex process is the eventual attainment of a ‘both/and’ solution. Right now, it really does look as if TAP is in pole position to deliver Azerbaijani gas to major European customers beyond Turkey. But it remains more than likely that an initial award to TAP next year might well be followed, or even accompanied, by a commitment to develop a system to carry gas to Baumgarten as well. The question would then be whether such an award would go to Nabucco West or to Socar.


analysis brazil oil

Despite billions of barrels of sub-salt reserves, Brazil’s Petrobras is seeing oil production stagnate. Output from its mature fields is declining, while development of the sub-salt is hampered by delays. Petrobras is struggling to reconcile its role as an oil company with the demands made on it by broader economic priorities and the lead it is expected to take in Brazilian industrialization.

Petrobras over-stretched

Brazil’s state oil company Petrobras should be in prime form. It has 15.71 billion barrels of oil equivalent in proven reserves and another 15.8 billion boe in potentially recoverable reserves, much in the relatively recently discovered vast sub-salt fields off the country’s Atlantic Coast. The company, which expects to make $236.5 billion in investments from 2012-2016, also sits on a large and rapidly growing domestic market, which could reach 3.38 million b/d by 2020. And while ostensibly a private company, the Brazilian government is effectively Petrobras’ principle shareholder, giving it unique access to policy and politicians.

Yet Petrobras posted a R$1.35 ($665 million) loss in second-quarter 2012, compared with a R$10.9 billion profit in the same period of 2011, its first loss for 13 years. Production at 2.554 million boe/d in July is falling instead of rising, compared with the 2.567 million boe/d recorded in July 2011. Moreover, the company’s 2012-16 business plan cut 700,000 boe/d of expected output growth, compared with the 2011-2015 plan, leaving its 2016 production target at 5.7 million boe/d. Petrobras also revealed in June that it intended to divest itself of $14.8 billion in assets. Clearly not all is well at the company so long lauded as the poster child of National Oil Companies.

State interferenceBrazil’s local content rules, regulation of domestic fuel prices and refinery construction plans indicate that as a state oil company Petrobras serves a higher purpose than just its shareholders. It is a central tool in the government’s industrialization policy. It is expected to generate both jobs and profits. This duel role is

traditionally the bane of NOCs, starved of investment capital as their coffers are raided by government for other policy purposes.

However, Petrobras has historically managed this balancing act well, retaining a critical distance from government in its everyday operations and investment decisions. Yet critics increasingly blame government interference for its current malaise. “Society is seeing that the government is finishing Petrobras off. It is destroying Petrobras,” said Adriano Pires, founder and director of Rio de Janeiro consultancy Centro Brasileiro de Infraestrutura.

Others argue that Petrobras shareholders understand both the pros and cons of investing in a company that is effectively state controlled. “This is the onus of the bonus,” said Jean-Paul Prates, director of energy think tank Centro de Estrategias em Recursos Naturais e Energia (CERNE). As a former energy secretary for Rio Grande do Norte state, where CERNE is based, Prates understands the company’s political dimension. “Nowhere in the world do you have a company with state participation that is free to do what it wants,” he said.

There are, in fact, some signs of change. In February, Maria das Gracas Silva Foster took over as Petrobras CEO from Jose Gabrielli. It rapidly became apparent that Graca Foster, as Petrobras’s former director of Gas and Energy is known, would make changes to make the company more efficient, and less politically driven.

Foster began by altering her executive management team. Jose Formigli was made director of exploration and production, replacing Guilherme Estrella, and Jose Cosenza took over the supply department from Paulo Costa. These changes were received positively in that they were seen as ‘technical’ rather than ‘political’ choices. In Pires opinion, this undid what he describes as the “very big politicization” that took place under the Lula presidency from 2002-2008.

But there are doubts as to how much Foster can achieve. Foster’s own appointment was seen as technical rather than political, but she is no stranger to politics and is a close friend of Brazilian president Dilma Rousseff. Nevertheless, her focus is on the business. “She’s very savvy, she knows how Petrobras works from the top down, and she’s trying to put it back together,” according to David Fleischer, a professor of political science at the University of Brasilia.

First-half financials ($ million)

Source: Petrobras

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6000

9000

12000

15000

International

Distribution

Biofuels

Gas & Power

Re�ning, transporta

tion

and marketing

Exploration and

Production

First-half 2012First-half 2011


analysis brazil oil

Yet there is no question that Petrobras works within wider policy constraints. At her inauguration ceremony in Rio, alongside Rousseff, Foster promised continuity: “Always with the focus on the discipline of capital, on meeting goals and deadlines, without neglecting security and environmental aspects,” she said. Rousseff said Petrobras was in good hands, but also emphasized the company’s importance for Brazil. “It has become a company even more popularly identified with our people. Its growth coincided with the growth of Brazil, and with the recuperation of the self-esteem of our people,” she said.

Import lossesPetrobras’ second-quarter loss was not simply the result of one-off factors, but a reflection of structural problems that are tied in with the government’s broader economic policies. Petrobras lacks sufficient refining capacity to meet domestic demand and has to buy refined products at international prices. The government fixes fuel prices to control inflation. This means Petrobras’ sells its imports at a loss, and, as elsewhere in the developing world, holding domestic fuel prices artificially low stimulates demand making worse the dependency on imports.

Petrobras’ profits were badly hit this year because of loss-making gasoline and diesel imports. The loss on this account in the second quarter has been reported by local media as R$9.968 billion. In the first quarter, these losses amounted to R$7.1 billion.

Foster has repeatedly argued that domestic fuel prices need to be more reflective of international prices. Domestic gasoline and diesel prices did rise in June, by 7.8% and 3.9% respectively, but analysts said it was not enough. According to Emerson Leite, an oil industry analyst at Credit Suisse in Sao Paulo: “for the good of the company, price parity is a must.”

The other option is to increase refining capacity to minimize the requirement for refined oil product imports. Petrobras has 12 refineries with capacity of 2 million b/d and is trying to increase this capacity.

However, the build out of new refineries is proving slow and subject to political interference. The Abreu e Lima refinery is being built in the traditionally poor state of Pernambuco at Recife. The area is undergoing something of a boom, partly because of World Cup infrastructure works – it is one of the host cities for the 2014 tournament – and partly because of the expansion of the EAS shipyard and the Petrobras refinery project. Politically, the benefits to the ruling Workers Party in the north east, the heartlands of its support, are huge.

However, the refinery is running massively over schedule and budget. In 2008, Petrobras said it would cost $4.05 billion and be ready in 2010. In August, supply director Jose Cosenza said the cost had ballooned to $17 billion, with initial operations likely to start up in 2014 and reach full capacity of 230,000 b/d only in 2015, five years behind schedule.

Petrobras has also been unable to finalize its project partnership with PDVSA, the Venezuelan state oil company. PDVSA has repeatedly failed to provide the financial guarantees needed to participate in the refinery, although Cosenza said in August that he believes PDVSA will eventually do so.

Other refinery projects are also delayed. The huge Premium I project near Sao Luis in Maranhao state in the north east will have 600,000 b/d capacity and is expected to be complete in 2017/2018. However, the project is still in the company’s ‘evaluation stage’, although 70% of its earthworks have been completed, according to Cosenza.

Outside the economic benefits to the poorest state in Brazil, it is not clear why Petrobras chose this site for a refinery. Sao Luis is a three-hour flight from Rio de Janeiro, where the oil industry is based. The principle fields are all off Rio de Janeiro and Espirito Santo states. The big urban population centers are all in the south east of Brazil.

The Premium II refinery project in Ceara, with planned capacity of 300,000 b/d, is also not scheduled for completion until 2017/2018. Again, Ceara in Brazil’s north east is a long way from Brazil’s oil fields and demand centers. Nor does work appear to have actually begun, owing in part to the presence of indigenous peoples on the site and issues over their potential relocation.

The completion of refineries like Abreu e Lima, and the 165,000 b/d Comperj project near Rio, will eventually cut Petrobras’s need for imports. The company currently imports 70-80,000 b/d of gasoline and 150-160,000 b/d of diesel. “In 2014, we are talking about importing 280,000 b/d of diesel,” Cosenza said. “In 2015/16, around 100,000 b/d.” Gasoline imports would fall to 90,000 b/d in the same period, he said.

For Jean-Paul Prates, the refineries issue is the biggest problem that Petrobras faces. “This is a very worrying situation. Petrobras is importing gasoline

Petrobras' imports and exports of crude oil and oil products (million b/d)

First-half First-half Change 2011 2012 (million b/d)

Crude oil imports 376 349 -27Oil products imports 326 395 69Total crude oil 702 744 42 and products importsCrude oil exports 447 424 -23Oil products exports 221 210 -11Total exports of crude oil 668 634 -34 and productsNet imports of crude oil and products 34 110 76

Source: Petrobras


analysis brazil oil

and looking for refinery solutions,” he said. “If there was one strategy critical for Brazil, it is this. Investments are crucial. The process is late.”

An aggravating factor has been the recent poor performance of the ethanol sector. Poor harvests have led to lower output and rising prices, making gasoline more competitive for Brazil’s fleet of flex-fuel vehicles. However, the sector is showing some signs of recovery. Consumption of hydrous ethanol rose 11.6% in August compared with June, but was still 12% down on August 2011, according to Brazilian distributors association Sindicom.

Graca Foster told Brazil’s Senate in September that she hopes ethanol production will return to previous levels helping to ease the pressure on Petrobras’s fuel supplies. “There is no reason it shouldn’t return in two or three years,” she said. Petrobras has $2.5 billion in biofuels investments in its 2012-2016 business plan and is moving forward with plans for second generation ethanol, which it hopes will be commercially available by 2015.

Local contentA second structural drag on Petrobras’ operations are the country’s local content rules. Development of Brazil’s vast sub-salt reserves is moving slowly because of delays in the delivery of rigs, platforms and other equipment. The government’s local content policy sets minimum targets of up to 65% for equipment and supplies. However, the Brazilian shipbuilding industry currently lacks the capacity to build all the rigs, ships and platforms Petrobras needs. As a result, Petrobras is now thought unlikely to increase production significantly before 2015.

In September, after repeated delays, Petrobras said it had finalized the contracts for a total of 26 rigs to be built in Brazil with local content levels of 55%-65%. 21 of these are contracted through the company Sete Brasil, in which Petrobras holds 10% equity, while a further five have been contracted through rig contractor Ocean Rig.

Sete Brasil already had a contract for seven rigs with the Estaleiro Atlantico Sul shipyard in Pernambuco, in Brazil’s north east. The total capex for all 28 rigs Sete Brasil will build is $27 billion. However, EAS has suffered extensive delays on Petrobras contracts. The problems it faces are emblematic of the issues created by the government’s local content policy.

In May, the yard finally launched the Joao Candido, a transport ship ordered by Petrobras transport arm Transpetro, 20-months behind schedule. Transpetro said it would fine the yard an undisclosed sum for the delay. Foster too has publicly criticized the yard for delays.

In March, Korean shipbuilder Samsung unexpectedly pulled out of its 6% holding in EAS. The yard’s new CEO, Otoniel Silva Reis, gave a frank interview to Brazilian

business daily Valor in August, in which he said the yard needed to improve training and production processes. Japanese company IHI Marine entered in May as the yard’s technical consultant. “My commitment is to neutralize cash-flow and make the shipyard productive,” Reis told Valor.

Despite the problems it causes, Graca Foster has repeatedly defended the local content policy. “The concept is very good, it is difficult to position against it. It is seen well by the country,” said Credit Suisse’s Leite. “It has its merits, but the way it is put is creating important bottlenecks for the growth of production.” The result is delays. “Local content makes things more expensive, and makes them take longer. This has the impact that we are seeing.”

Graca Foster defended the policy in June, when she presented Petrobras’s new business plan. She admitted the company was experiencing delays in the delivery of drilling rigs, but said this was not simply the result of local content rules. She argued that shipyards internationally were behind schedule in rig construction.

Foster also used a national radio interview to defend the local content policy in more detail. The average figure was around 60% for local content, from both federal government and Petrobras, said Foster. In terms of gas pipeline construction, Petrobras has achieved local content levels of 90%. “The orientation of the federal government and Petrobras is that we make everything in Brazil that can be constructed in Brazil,” Foster said.

However, there are signs that Petrobras may be prepared to soften its position. A 2011 tender for six flexible Pipe Laying Support Vessels on five-year charters saw little take-up: only one is being built in Brazil, by the Malaysian company SapuraCrest at the yard OSX are building in Rio, the other five will be built abroad.

In September, Petrobras opened up the tender for future PLSVs to foreign shipyards, a decision seen as an important concession on local content.”Boats of this size would have been built in Brazil by the same shipyards that are committed to the construction of our FPSOs and rigs. If we had maintained the demand for construction in Brazil, there would have been

E&P spending breakdown ($ billion)

Source: Petrobras

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Pre-salt

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analysis brazil oil

competition between these boats and the FPSOs and rigs,” said Petrobras. “In this case, the requirement for construction in Brazil was flexibilized.”

Over-stretchIn the excitement generated by the discovery of Brazil’s giant sub-salt fields, it appears that the country’s traditional producing assets have lacked attention. According to a Credit Suisse report last year, production from the Campos Basin, which accounts for 77% of Petrobras’ domestic oil and gas production, was declining by 13-16%. “Notably increasing pre-salt drilling rig demand means that less is left for new and tie-back wells in Campos,” the report said.

Some fields, such as Marlim, Albacora, and Albacora Leste, were showing a production decline of as much as 20% a year, much higher than Petrobras’ guidance of 7-10%, the Credit Suisse report said. “Fields that have been producing for a long time suddenly start producing a lot of water,” explained Leite. “This is happening at a moment when the company is directing a lot of resources to the sub-salt.”

Petrobras has recognized the imbalance in resource allocation. In July, the company unveiled a $5.6 billion operational efficiency program for 31 of its oldest platforms in one area of the Campos Basin. The PROEF scheme aims to restore operational efficiency levels that had fallen to 71% by end-2011 to 90% by 2016, the company said.

The scheme has “the objective of recuperating our historic levels of operational efficiency,” said Solange Guedes, executive manager of E&P engineering and production. Initiatives involve modernizing rigs, exchanging submarine systems, and getting suspended works moving again. “We are going to do more with more intensity,” said Guedes.

The area covered by PROEF accounts for about 25% of Petrobras’ domestic production. Guedes said that problems were first identified in 2009 and resources allocated. “We found now that they weren’t sufficient. That is why it is being intensified,” she said.

“You take resources from an asset that is producing to put on one that is yet to start producing,” said Leite,

who welcomed the efficiency program. “Without doubt, it’s very important … I understand that maybe they were lacking resources. Today these resources are a little more available.” Jean-Paul Prates echoes this view. “There wasn’t negligence … the sub-salt really demanded a big initial attention from Petrobras. Now it is the time to cope with both things.” He added: “There is going to be an improvement.”

Sub-salt positionHowever, changes to licensing rules to enhance Petrobras’ position in the country’s vast sub-salt plays threatens to stretch the company’s resources even further. Currently oil fields in Brazil operate on a concession model, with companies paying royalties of 5-10% to the government. In 2010, a new model was introduced for new sub-salt bidding rounds, in which companies will also pay the government a share of oil. It is called the ‘partilha’ – the profit-share, or distribution.

Under this, Petrobras will operate all new sub-salt concessions and retain 30% equity. This worries some in the industry who believe the company will be overstretched. “I think this concentrates too much the role of developing all these resources in one company,” said Leite. “This is going to limit the development of the sub-salt. Petrobras is not unlimited.”

At present, the question is academic: the last bidding rounds in Brazil took place in 2008, on the old concession model. Future rounds have been held up by the slow progress of a government bill on oil royalties, which is currently stuck in the Chamber of Deputies. The oil-producing states of Rio de Janeiro and Espirito Santo want to continue receiving a bigger share of royalties, the rest of the Brazilian federation wants a more equal share. A vote may be held before year’s end.

“When the government changed the regulatory mark, it created an enormous problem. It created a federal war, between producing states and municipalities and non-producing states and municipalities,” said Adriano Pires. “It has to be resolved to have another bidding round.” Pires argues that while no bidding on new oil concessions takes place, Brazil is losing investment. “By not having bidding for four years, Brazil has lost at least, in signing bonuses, without talking about new investments, without talking about new jobs, around $1 billion a year,” he said.

However, Petrobras may in fact welcome the respite provided by the political impasse, as it has enough on its plate already. Development of its sub-salt fields is being hampered by equipment delays, while it is simultaneously fighting a rearguard action against decline in its traditional producing areas. Given also the delays to refinery construction and its impact on the company’s financial performance, Petrobras appears to have some difficult years ahead.

2012-2016 Business Plan ($ billion)

Segments Investments %

E&P 141.8 60Downstream (RTC) 65.5 27.7Gas & Energy 13.8 5.8Petrochemical 5 2.1Distribution 3.6 1.5Biofuels 3.8 1.6Corporate 3 1.3Total 236.5 100

Source: Petrobras


analysis intErnational oil

EU and US sanctions on Iran are proving a double-edged sword by keeping oil prices high even as economic growth falters. However, there is little that the US and EU can do except hope that the sanctions work. A release of strategic stocks would risk exposing impotency as much as strength and undermine any residual notions of International Energy Agency independence. Ross McCracken

Iran sanctions cut both ways

While commitments made by the European Central Bank in September have provided some reassurance for the euro area, the currency zone and other European economies appear to be heading into recession, putting a drag on growth in export-dependent non-OECD economies. At the same time, the G7 has been talking about the release of strategic oil stocks as a means of mitigating the adverse economic impact of high oil prices on net oil importers. If oil prices remain high they curb economic growth, and threaten to worsen an already poor economic outlook. The release of strategic stocks might reduce oil prices and thus benefit the global economy.

In an interim assessment of the outlook for world growth provided in September, the OECD said that the global economy had weakened since Spring. The root cause is the persistent crisis in the euro area, which is affecting external economies in both the OECD and non-OECD. The OECD said that G20 GDP slowed to 0.6% in the second quarter, from 0.7% in the first, the third consecutive quarter of slowing growth in the G20 area.

The OECD says that weakness in the euro area’s periphery is spilling over into the core. According to the OECD’s forward looking indicators, the loss of economic momentum at the G7 level may persist into the latter half of the year. The US is an exception, but US growth is threatened by extreme fiscal tightening in 2013. Recognizing the weakness of the US recovery, the US Federal Reserve announced in September a huge open-ended bond-buying program aimed at boosting growth.

The OECD estimates that annualized quarter-on-quarter growth for the three largest euro area economies combined – Germany, France and Italy – contracted by 0.3% in second-quarter 2012 and will fall further by 1.0% and 0.7% in the third and fourth quarters, respectively, as Germany enters recession. The UK is also expected to continue contracting in the third quarter.

Moreover, the OECD highlights two significant risks to this already pessimistic outlook. Further intensification of euro area instability could have significant spill over effects for global demand, while “failure in the United States to avoid the ‘fiscal cliff’ could derail an already weak recovery.” Oil prices have also rebounded despite the economic outlook and remain sensitive to supply disruptions and geopolitical risks. The OECD’s data shows a sharp rebound in food prices, but a clear and pronounced downward trend in other non-oil commodities, such as metals, minerals and agricultural raw materials.

The OECD bases its analysis on forward looking indicators, noting a particular weakening of business confidence in the manufacturing sector, consistent with waning indicators of global trade, such as export orders. It also notes weakening levels of consumer confidence, particularly in the euro area, and sharply contracting levels of lending to households. It says that global output and trade slowed in the first half of the year and that Chinese exports into the euro area “are being hard hit.”

Such a prognosis suggests that oil demand forecasts for 2012 and 2013 may be scaled back, particularly if weakness in the G7 economies feeds through into reduced export-led growth in developing economies, as it appears to be doing based on the OECD indicators.

Chinese oil demand growth has already slowed over the course of this year. According to China’s National Bureau of Statistics and General Administration of Customs data, China’s apparent oil demand grew by only 1.66% in the January to July period to average 9.41 million b/d, up from 9.26 million b/d for the same period in 2011. Apparent oil demand does not take into account changes in stock levels, and is based on refinery throughput and net imported oil products. The year-on-year rate of demand growth has clearly slowed from the second half of last year. By comparison, based on BP Statistical Review of World Energy data, Chinese oil consumption grew by 5.5% in 2011 and 12.7% in 2010.

30

20

10

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0

65

60

55

45

40

35

30201020082006200420022000

50

World goods and services trade and GlobalManufacturing New Export Orders Index

Source: OECD, Markit Economics Limited

1 Values greater than 50 signify an increase in new export orders.

World goods and services trade, annualised q-o-q change (%)

PMI, Global Manufacturing New Export Orders Index1

(%) (Index)



At the Asia-Pacific Economic Cooperation Summit, held in September, China’s President Hu Jintao said that the economy continued to experience downward pressure in the second half of the year. GDP growth was 7.8% in first-half 2012, compared with 9.3% over the whole of 2011.

Analysts expect the Chinese government to enact further stimulus measures to support economic growth. Beijing has already lowered banks’ reserve requirements and reduced interest rates to stimulate lending, but trade and output data for July remain depressed. Beijing-based energy consultancy 3E said in a recent report that consumption of oil products has been depressed by weakening economic growth and that gasoil has been most heavily affected, largely owing to slowing operations from heavy industries.

Oil pricesDespite the deteriorating economic outlook, crude oil prices rallied in early September, creating an aggravating factor weighing on the world economy. International crude oil market Dated Brent averaged $113.37/barrel over August, up from an average of $102.59/b in July and $94.84/b in June. In mid-September, the marker traded over $117/b before a sharp drop to $108.41 September 19 and a partial recovery to $111.18 September 21.

As ever, multiple factors are at play in the oil market, notably a variety of supply interruptions such as the loss of Sudanese barrels to the market and the sharp drop in North Sea output as a result of maintenance, particularly to Forties, the largest crude stream that can be traded against the Dated Brent benchmark.

However, the main factor would appear to be US and EU sanctions on Iranian crude exports and the threat of their loss, or a substantial part thereof, to world markets. According to secondary sources, Iranian crude oil production has fallen from 3.52 million b/d in January to 2.75 million b/d in August. Exports of crude oil are thought to have fallen even further; some estimates suggest Iran has been unable to place 1 million b/d of exports.

However, OPEC production as a whole has not fallen. In January total OPEC output was 30.87 million b/d.

It had risen to 31.75 million b/d by May, even as Iranian production started to fall, and in August it was 31.54 million b/d. Iran may in August have been producing 770,000 b/d less than it was in January, but OPEC as a whole was producing 880,000 b/d more.

The two main boosts to OPEC supply have been in Libya and Iraq. The former by August was producing 450,000 b/d more than at the beginning of the year, while Iraqi production has leapt 400,000 b/d over the same period. Nigerian output is also 220,000 b/d up on the start of the year, while Saudi Arabian production in August was 200,000 higher than in January. Kuwait has added 150,000 b/d and the UAE 60,000 b/d.

According to the International Energy Agency, non-OPEC supply dropped from 53.4 million b/d in first-quarter 2012 to 52.9 million b/d in the third quarter. This implies that the loss of Iranian barrels has been more than compensated for by OPEC, but the market has lost supply overall as a result of the combination of the sanctions on Iran and non-OPEC supply disruptions.

Add to this the geopolitical risks of sanctions against Iran, its ongoing nuclear program, and the possibility, even if small, of an Israeli strike against Iran nuclear facilities, and the general level of threat to both further losses of Iranian output and/or the Strait of Hormuz have been enough to push oil prices back up to levels where policy makers are considering a release from the strategic reserves of IEA countries.

Supply crisis?Even if Iranian exports have indeed been hard hit, there is no physical shortage of crude oil on the market, bringing into question the legitimacy of a release of strategic reserves and its proximity to the US presidential elections. According to the IEA’s document on emergency releases of oil stocks, such action is designed “to mitigate the negative impacts of sudden oil supply shortages by making additional oil supplies available.” It adds, “although supply shortages may bring about rising prices, prices are not a trigger for a collective response action . . . the goal of the response action is to offset an actual physical shortage, not react to price movements.”

GDP growth in the G7 economies (annualized quarter-on-quarter growth in %)

2011 2012 Q2 2011 Q3 2011 Q4 2011 Q1 2012 Q2 2012 Q3 2012 Q4 2012

United States 1.8 2.3 2.5 1.3 4.1 2 1.7 2 2.4Japan -0.8 2.2 -1.9 7.4 0.3 5.5 1.4 -2.3 03 largest Euro countries 2 -0.2 1.2 0.8 -1 0.1 -0.3 -1 -0.7Germany 3.1 0.8 1.8 1.5 -0.6 2 1.1 -0.5 -0.8France 1.7 0.1 0.2 1.1 0 0.1 -0.2 -0.4 0.2Italy 0.5 -2.4 1.4 -0.9 -2.9 -3.3 -2.9 -2.9 -1.4UK 0.8 -0.7 -0.4 2.4 -1.4 -1.3 -1.8 -0.7 0.2Canada 2.4 1.9 -1 4.5 1.9 1.8 1.8 1.3 1.9G7 1.4 1.4 1.1 2.3 1.7 1.8 0.9 0.3 1.1

Source: OECD interim assessment, September 6, 2012



The IEA has taken emergency release actions three times: in response to the 1991 Gulf War in which there was a supply loss of some 4.3 million b/d; in response to hurricanes Katrina and Rita, in which the supply loss was 1.5 million b/d; and in June 2011, in response to the loss of Libyan crude exports as a result of civil war in Libya, which removed 1.6 million b/d from the market. The first two releases reflected a response to an actual physical shortage of oil globally in the first case and specifically in the US in the second. No-one was actually suffering from a shortage of oil at the time of the third release, which led to suggestions that the target was oil prices, a departure from both past and stated IEA policy.

G7 finance ministers made an unusual statement in late August that urged oil producing countries to increase output, saying “We stand ready to call upon the International Energy Agency to take appropriate action to ensure that the market is fully and timely supplied.” Their argument was that high prices were undermining economic growth.

Sanctions impactThe primary reason for higher oil prices are the sanctions on Iran. It was clear from the start that this was a risk. The idea was mooted that Iran would be forced to sell its crude at a discount and in this way supply would be unaffected, but Iranian oil revenues would fall, putting pressure on Tehran without increasing oil prices. However, this was just a theory – one used to reduce fears of higher oil prices and garner support for tougher sanctions.

Now that the theory has been proved wanting, policy markers are considering a strategic release of stocks, despite it clearly being contrary to the IEA’s own charter. There is also the problem that a release of strategic stocks is a temporary measure. The more stocks are released, the weaker the weapon becomes because stock levels fall. Using the weapon risks exposing its impotency. And, at some point, stocks have to be replenished. In contrast, sanctions are unlikely to be lifted unless there is major progress regarding Iran’s nuclear program, which so far looks unlikely.

The use of strategic stocks would thus represent a defeat of sorts for the US and the EU as it would indicate that they had misjudged the double-edged nature of oil sanctions. It would also further undermine the independence of the IEA. Briefing around the possibility of a release seems almost entirely political, aimed at both the US presidential elections and, external to the US, to put pressure on Saudi Arabia to keep its output high in order to compensate for the loss of Iranian exports.

Sanctions rarely work quickly, but they do appear to be having an impact on terms of lost revenues. Iran’s currency is reported to have sunk to a new record low against the dollar, with the central bank

saying it was trying to manage the plunge amid an “economic war with the world.” Iranian President Mahmoud Ahmadinejad has admitted on state television that Western sanctions were causing “problems” in exporting oil and international financial transactions. High oil prices are for Iran only a small consolation as the rise in price is small in comparison with the apparent loss of export sales.

Yet the cost of sanctions to the west is also large because a rise in the price of oil affects all oil, regardless of origin, even if the impact is widely distributed. If the sanctions have been responsible for a $10/b increase in oil prices that represents a transference of millions of dollars from net oil importers to oil exporters on a daily basis before the wider economic impact of slower growth is taken into account.

This creates a serious dilemma for oil importing countries, notably the EU and the US, the architects of the current sanctions regime. By targeting a key exporter of such a crucial internationally-priced commodity, on which their economies depend, the possibility of a phyrric victory was always high. Although a release of strategic stocks remains a possibility, if oil prices rise further, it is not a permanent solution. The real means of ratcheting up pressure on Iran lies outside both the EU and the US in the oil fields of Saudi Arabia.

Iranian and OPEC crude oil output

(million b/d)

18

22

26

30

34

Aug-12Jul-12Jun-12May-12Apr-12Mar-12Feb-12Jan-12

IranOPEC w/o Iran

Source: Platts

60

30

40

50

20

10

-10

-20

-30

-40

0

2012201120102000

Year-on-year growth (%)

Source: CEIC

China’s exports by destination

North AmericaEuro zoneEast, SE and Austral Asia


analysis EuropEan powEr

Onshore wind power offers a tried and trusted technology for investors in renewable energy. However, as government support schemes are cut, the energy yield of turbines becomes ever more crucial to revenues. Average wind speeds are hard to predict and vary significantly from one year to the next. As energy yield is a function of the cube of wind speed, these variations have a big impact on profitability. Paul Whitehead

Wind speeds and profits

The United Kingdom has been one of the fastest growing markets for wind power in the world in recent years and enjoys some of Europe’s windiest conditions. However, it is also famous for the unpredictability of its weather, and, in 2010, wind speeds were substantially lower than had been forecast. Wind speeds are a critical component of modeling expected returns for a wind farm and the low speeds of 2010 will have caused a significant deviation between projected and actual returns.

Unlike conventional thermal power stations, wind power is almost entirely about upfront risk. Almost all project costs are capital costs. The wind turbines alone account for about 64% of the total cost of wind energy, according to the latest figures from the UK wind and marine energy association RenewableUK. Civil works involved in erecting turbines account for another 13%, while electrical infrastructure and grid connection account for 8% and 6%, respectively, of the total. Project management, installation insurance, legal fees and bank costs make up most of the rest.

Operational and maintenance costs once the project is up and running are minimal by comparison, at least for onshore installations, because the ‘fuel’ – the wind itself – is free. Revenues do not start to come in until the capital costs, and thus most of the entire project cost, have been sunk. So investors need to do their homework before investing to make as certain as possible that a project will deliver a reasonable return even if the policy environment turns hostile.

Fortunately for investors, the capital cost of wind energy is falling as turbines get cheaper (and bigger) and installation becomes standardized. However, revenues

are also under pressure from a number of factors, such as lower wholesale electricity prices, owing to weak demand in Europe, or, as in the US, competition from cheap gas-backed power generation.

Moreover, in many jurisdictions, revenues from wind power are falling as government support mechanisms, like feed-in tariffs or renewable energy credit schemes, are cut in favor of less mature, emerging technologies. For example, the UK recently announced a 10% cut in support for onshore wind over the next five years (though the level of support remains more generous than expected). Italy is capping support for wind and other renewables, while US project developers face constant uncertainty over the renewal of production tax credits.

Energy yieldPrices and support schemes are just two factors impacting revenue. How much power a particular wind farm generates is also critical and depends on numerous factors. First there is the size of the turbines. Larger and taller installations should, in theory, generate more, because they have bigger blades and wind currents are stronger at greater heights.

Second there is availability – the ability of wind turbines to generate electricity when there is sufficient wind available. Major turbine manufacturers like GE of the US and Denmark’s Vestas say their modern onshore turbines have an availability of over 98% or more, meaning they are available to generate power 98% of the time when wind conditions are right.

Third, is the issue of siting and the arrangement of the turbines. Sites that are more exposed are typically windier than shaded sites. And the way the turbines are arranged affect the aerodynamics of the winds around the blades. Turbines that are not optimally sited can be arranged in ways that allow the “wake” generated by one turbine to interfere aerodynamically with neighboring turbines.

Finally, there is the wind resource itself. Wind speeds are usually assessed and compiled by local meteorological stations by taking measurements with anemometers – three cups attached to a vertical axis the rotation of which indicates wind speed. Wind data compiled in this way for at least a year can be used to calculate mean annual wind speed and wind direction. These can be used by developers to identify the best potential sites for wind farms.

0

2000

4000

6000

8000

10000

12000

201120092007200520032001

Source: EWEA

Annual EU wind installations (MW)

OffshoreOnshore



According to RenewableUK, wind turbines start operating at speeds of around 4-5 meters per second, or around 10 miles per hour, and reach their maximum power at around 15 m/s (33 mph). But at very high wind speeds – gale or hurricane force winds of over 25 m/s or in excess of 50 mph – wind turbines shut down as a safety precaution.

Developers need site-specific data and must typically gather their own wind data from a prospective site over a period of months or even years. But even with this data there are no guarantees that wind speeds will be consistent from one year to the next, or indeed from one decade to the next. As with most investments, past performance is no guarantee of future returns.

Exponential speedWind speed is crucial to performance because the “windiness” of a particular site is a function of the cube of the wind speed. That means that as wind speeds double, the energy potential of the wind increases eightfold. Similarly, if wind speeds halve, the energy content of the wind that can be harnessed falls eightfold. So, just a small reduction in actual average windspeeds compared with expected wind speeds can make a big difference to projected output and thus revenue.

“In practice, turbines at a site where the wind speed averages eight meters per second will produce around 80% more electricity than those where the average wind speed is six meters per second,” says RenewableUK. A slight drop in wind speeds over a sustained period can have a drastic impact on the output of a wind farm, and therefore on its profitability.

The UK provides a useful case study, because together with neighboring Ireland, it boasts Europe’s highest average wind speed. It is also home to four of Europe’s largest onshore wind farms and has some of the EU’s biggest centers of power demand, in London and southeast England, and the major cities of central and northern England. These conditions, combined with a favorable policy framework, have led to rapid deployment of wind power installations in recent years.

According to European Wind Energy Association figures, the UK installed 962 MW of additional wind capacity in 2010, taking the country’s total installed

wind power capacity to 5,204 MW. In 2011, a further 1,293 MW was installed – the biggest increase in any EU country after Germany.

The expansion in capacity prompted UK grid operator National Grid to trial a new wind forecasting system in 2011. The system seeks to prepare accurate wind speed forecasts for 34 locations across the UK based on the speed of the wind, the size and height of turbines and other weather conditions based on predictions from multiple forecasts. The forecasts are updated four times a day. This helps the grid operator anticipate short-term variations in wind output and plan more accurately how much power will be needed to compensate for wind’s intermittency.

However, wind farm developers need to make much longer-term assumptions about average wind speeds. Historical data provides a guide of sorts. Some national governments or wind associations provide databases that model wind speeds based on historic data at different locations. The UK Department of Energy and Climate Change hosts such a windspeed database, but warns that it is no longer updating it and much of the data it contains could date from the 1980s or even the 1970s. The weather has been far from consistent in the intervening years.

According to data compiled by the European Environment Agency and published in 2009 a model that seeks to predict wind speeds can be fairly accurate for speeds under 5 m/s, but becomes less accurate for speeds over 5 m/s, especially for larger sites. However, wind speeds for larger sites usually prove better than expected. The analysis compares

Source: EWEA

EU member state market shares for new wind capacity installed in 2011

Poland (5%)

Germany (22%)

UK (13%)

Spain (11%)

Italy (10%)

France (9%)

Others (19%)

Greece (3%)

Portugal (4%)

Sweden (8%)

Romania (5%)

Predicted and observed wind speed statistics across four geographical regions of Europe

Annual mean wind speed (m/s) Coefficient of Standard error Observed Predicted Error (m/s) determination of predictionRegion Mean σ Mean ∑ Mean σ r2 (for y = x) (m/s)

Denmark, Germany and Netherlands 4.46 1.495 4.573 1.336 0.114 0.798 0.636 0.812Finland, Norway and Sweden 3.832 1.881 3.839 1.878 0.007 1.450 0.999 1.455France, Portugal and Spain 3.825 1.437 3.637 1.307 -0.189 1.309 N/A 1.329Austria and Switzerland 2.538 1.594 2.081 0.995 -0.456 1.451 N/A 1.534

Source: European Environment Agency, technical report No. 6/2009



forecast wind speeds from the model with actual data from wind observation stations in 2001.

During the planning and financing stage of a wind farm, developers carry out a risk assessment, including detailed financial modeling of the impact of variation in wind speeds. They carry out an energy yield prediction based on turbine size, historical wind data from the site and other relevant factors. The outcome is called a P50, meaning that the probability of reaching a lower or higher output is 50:50.

“The P50 energy prediction is the best central estimate of the future production of the wind farm. You have a 50% probability (chance) that the future production will be more or less than this value,” RenewableUK explained.

Similarly for longer-term projections, developers and financiers often use a “P90” projection, which predicts wind speeds at a value at which there is a 90% chance of exceeding them, or just a 10% chance of falling below, according to RenewableUK. As a result, P90 values will always suggest energy production that is lower than P50 because there is a higher chance of it being exceeded.

“The P90 is often presented for the future 10 year average annual production and the future 1 year annual production. The 10-year P90 will be higher and a more “stable” value as mean wind speed variability from year to year is smoothed out over a 10 year period. The 1 year P90 will be a lower value and more volatile as the annual mean wind speed variability is not smoothed out,” said RenewableUK.

Using this assessment, UK wind speeds in 2011 were roughly in line with developer expectations, but in 2010 they were significantly lower than both P50 and P90 values. “The UK underperformed P50 wind speeds by 11% in 2010, and was only at P50 in 2011,” James Knight of investment bank Augusta Capital said at a recent renewable energy conference in London. “The 2010 under performance led to a 30% reduction in power,” he said, citing this “wind risk” as one of the key challenges facing wind farm developers today, after policy risk.

RenewableUK said developers have to accept the rough with the smooth; there will be bad wind years as well as good. Over the longer term these should even out: “In reality the UK 2010 wind speed produced energy output figures from wind farms below the 1 year P90, which is obviously not great for the owners, however that should not be a surprise. In theory, once in every 10 years the energy output will be below the 1 year P90. 2010 was more severe as it was close to a P99 case, but this can still statistically happen.”

Wind speed modeling, like long-term weather forecasting, is unlikely ever to be an exact science, making output inherently uncertain. Current models can both under and overestimate wind speeds and the impact on electricity output is large because the energy yield is a function of the cube of the wind speed. This means that wind farm developers’ actual revenues could vary markedly from projections, while the sector as a whole is likely to provide large variations in power output from year to year.

r2 here refers to the proportion of the variability in the predictions that can be explained by comparing regression with observations, in this case in the regression line y = x. If we have an r2 value of 0.4 then we can say that the variability of the prediction values around the line y = x is 1–0.4 times the original variance. Alternatively, the r2 allows the line y = x to explain 40 % of the original variability, leaving 60 % residual variability. Ideally, the GIS methodology would perfectly predict the wind speed at meteorological stations, in which case the line y = x would explain all the original variability. The r2 value is an indicator of how well the model �ts the data, where r2 = 1.0 indicates that the model accounts for all the variability with the variables speci�ed in the model.

Source: EEA; AEAT, 2008

Relationship between observed and predicted 2001 mean daily wind speeds for all European meteorological stations

14

12

10

8

6

4

2

00 2 4 8 10 12 14

Meteorological stations y = x

(Predicted)

(Observed)

6


The Gas ForumOctober 2London, UKwww.gasforum.co.uk

Global Clean Energy ForumOctober 2-3Barcelona, Spainwww.ihtcleanenergy.com

KAZENERGY Eurasian ForumOctober 2-3Astana, Kazakhstanwww.kioge.com

World Independent Oil Companies CongressOctober 2-4London, UKwww.terrapinn.com/conference/independent-oil-congress

The European Gas Policy Forum 2012October 3Brussels, Belgiumwww.gaspolicy.eu

POWER-GEN AsiaOctober 3-5Bangkok, Thailandwww.powergenasia.com

Renewable Energy World AsiaOctober 3-5Bangkok, Thailandhttp://www.renewableenergyworld-asia.com/index.html

Gas-to-Liquids 2012October 4-5London, UKwww.smi-online.co.uk/events

KIOGE 2012October 6-8Astana, Kazakhstanwww.kioge.com

Mauritanides 2012, Mining, Oil & Gas Conference and ExpoOctober 8-11Nouakchott, Mauritaniawww.mauritanides2012.com

The Role of Deep Geothermal – will the UK feel the heat?October 15London, UKwww.egs-energy.com/media/engineered-geothermal-energy-symposium-2012.html

11th Energy Investment and Regulation ConferenceOctober 15-16, 2012Izmir, Turkeywww.erranet.org

Appalachian Gas, 5th AnnualOctober 15-16Pittsburgh, USAwww.platts.com

Ghana Oil and Gas Summit 2012October 15-16Accra, Ghanawww.okl-events.com

Turkish International Renewable Energy CongressOctober 15-18Istanbul, Turkeywww.greenpowerconferences.com

2nd Annual LNG Technology Global SummitOctober 17-18Doha, Qatarwww.fleminggulf.com/conferenceview/

Asia Shale Gas SummitOctober 20-21Shanghai, Chinawww.shalegaschinasummit.com

International Conference on Solar Energy for MENA region-INCOSOL 2012October 22-23Amman, Jordanwww.incosol2012.ressol-medbuild.eu

World Energy ForumOctober 22-24Dubai, UAEwww.worldenergyforum2012.org/

Asia Smart Grid 2012October 22-24Singapore, Singaporewww.asiasmartgrid.com.sg/en/Home/

Natural Gas Fleet Vehicles North American Congress 2012October 23-24Houston, USAwww.natural-gas-fleet-vehicle-congress.com/

Africa ElectricityOctober 23-25Johannesburg, South Africawww.africaelectricity.com

Global Energy 2012October 29-31Geneva, Switzerlandwww.globalenergygeneva.com

Africa Oil WeekOctober 29-November 2Cape Town, South Africawww.petro21.com/events

Advanced Energy 2012October 30-31New York, USAwww.aertc.org/conference2012/index.htm

Shale Gas World ArgentinaOctober 30-November 1Buenos Aries, Argentinawww.terrapinn.com/2012/shale-gas-argentina/

International Off-Grid Renewable Energy ConferenceNovember 1-2Accra, Ghanawww.ruralelec.org

USAEE/IAEE North American ConferenceNovember 4-7Austin, USAwww.usaee.org

Global Refining Strategies Summit 2012November 5-7Houston, USAwww.globalrefiningsummit.com

3rd Unconventional Gas Asia SummitNovember 5-8Beijing, Chinawww.szwgroup.com/2012/unconventional/

World Clean Coal Week, China Focus 2012November 5-8Beijing, Chinawww.szwgroup.com/wccwchina2012/abo_gla.asp

POWER-GEN AfricaNovember 6-8Johannesburg, South Africawwwhttp://www.arc2012.com.au/.powergenafrica.com

Renewable Energy World AfricaNovember 6-8Johannesburg, South Africawww.renewableenergyworld.com

Australian Resources Conference 2012November 12-14Perth, Australiawww.arc2012.com.au

4th International Symposium on Energy from Biomass and WasteNovember 12-15Venice, Italywww.venicesymposium.it

European Autumn Gas ConferenceNovember 13-14Vienna, Austriawww.theeagc.com

Oil & MoneyNovember 13-14London, UKwww.oilandmoney.com

Oil and Gas Cyber SecurityNovember 14-15London, UKwww.smi-online.co.uk/2012cyber-security.asp

EvEnts

Forthcoming events and conferences


lEttErs lEttEr from JohannEsburg: sEptEmbEr 2012

LETTER FRoM JoHANNESBURG: SEPTEMBER 2012

See you in courtWhen the South African government lifted its 18-month long moratorium on shale gas exploration in September, many energy companies around the world must have raised a glass in celebration; only to then raise the telephone and call their lawyers. The realization was swift that the opponents of shale gas were unlikely to give up without a fight. The next stage in a process that may or may not lead to shale gas exploration in South Africa is likely to entail the preparation of court papers ahead of long and detailed argument in the High Court.

Almost as soon as the country’s shale gas potential came to light, the wealthy and litigious protestors of the Karoo Basin, the vast expanse of largely untouched land under which most of the shale gas lies, have threatened to fight shale gas exploration in court. Many of the people opposed to shale gas are those who live directly above it in small farming towns like Graaff-Reinet, a tiny dot in the heart of the Karoo.

Derek Light, an attorney for farmers and landowners around Graaf Reinet, is providing opponents with legal advice about applications for exploration licences. He is unhappy with what he describes as a hasty decision to lift the moratorium. “The task team could not have effectively performed its function in such a short a time. It should have performed a strategic environmental assessment in the broadest possible terms, which would have enabled them to make a well-informed decision that would be in the best interests of the people of this country,” says Light.

Wealthy author and photographer, Jonathon Deal, is also likely to prove a tough nut to crack for anyone wanting to explore for shale gas in the Karoo. Deal is the chairman of Treasure The Karoo Action Group -- the largest and highest profile opposition to fracking in South Africa. The group has a war chest of donations from rich supporters. Deal complains that South Africa’s first reaction was “let’s frack” instead of investigating ways of tapping into other energy sources. “There is natural gas offshore, in reservoirs which do not need to be fracked in order to remove it,” he says. “We plan to lodge an appeal if and when exploration licenses are issued.”

Anti-fracking protestors in the Karoo argue that the drilling and fluids used in the process will destroy their land, which is part of South Africa’s natural heritage, rendering it useless for farming and tourism -- two of the big money spinners in the region. The Karoo is home to South Africa’s prosperous mohair industry and scores of farms, producing everything from ostriches to sheep. At countless conferences across South Africa the protestors have provided reams of evidence suggesting fracking does not suit South Africa along with graphic portrayals of the damage caused to the land.

As a result, the first test case promises to be interesting. Although the judiciary in South Africa is fairly independent and swaddled within one of the most liberal constitutions on the planet, there is an air of so-called “national interest” around controversial issues like shale gas. Surely the government, despite its caution, will fight tooth and nail to open up the industry. Apart from an avalanche of foreign investment, the industry promises thousands of jobs, an end to energy shortages and a huge chunk of tax revenue.

The government report on fracking, upon which the cabinet based its decision to lift the moratorium, admits it doesn’t know how much shale gas is in the Karoo Basin. As the data is limited, the report, published in September, uses the estimate of 485 Tcf made by the US Energy Information Administration. The report makes what it describes as a moderately optimistic assumption that around 30 Tcf will be produced from the Karoo. Using a price of $4 per thousand cubic feet, the report predicts sales of R1 trillion ($121 billion) over the next 20 to 30 years.

It points out that a mere 1 Tcf was enough to launch Petro SA’s Gas-to-Liquids project in Mossel Bay, on the South African coast, which provides 5% of the country’s liquid fuels and has created at least 1,500 jobs. The report was very careful to avoid predicting how many jobs a shale gas industry could create directly, merely alluding to tens of thousands, as these numbers are always disputed.

Nevertheless, those against fracking have been cheered by intentions laid out in the report to toughen up the country’s mining regulations, before full fracking is allowed, to mitigate any negative impacts. “This will require a comprehensive review of the adequacy of the existing framework in order to identify any shortfalls or omissions and to ensure that it is sufficiently detailed and specific,” says the report.

The government also plans to appoint a committee to oversee what it calls the augmentation of the regulations. This tinkering with the regulations and controls is expected to take between six to 12 months. No time frame has been offered for the issue of licences.

Still, companies like oil major Shell are delighted with the decision to lift the moratorium. “The suggestions of the task team are in line with our exploration plans for the Karoo Basin,” says Bonang Mohale, the Shell South Africa Chairman. Shell intends to prepare an environmental, social and health assessment report ahead of exploration. It plans to drill six wells, if its first three-year exploration licence is granted.

But unless the anti-fracking protestors have a change of heart or run out of money, those views and explanations are likely to be tested across the floor of a courtroom. Lawyers and argument could still tie up the issue of fracking for many years to come.

— Chris Bishop


lEttErs lEttEr from vEnicE: sEptEmbEr 2012

LETTER FRoM VENICE: SEPTEMBER 2012

Competition and climateThe International Association of Energy Economics’ European Conference was held in Venice this year, a city uniquely placed to consider the issues of competition, climate change and security of supply -- the three most powerful themes in European energy policy today. Venice was built on the riches of a ruthless application of merchant trade (albeit primarily based on monopolies rather than free trade). At the same time, the city is still thought to be sinking into the Adriatic lagoon on which it was built. The rate of descent may have slowed, as water well drilling has been scaled back, but the low-lying city faces a new threat -- sea levels are rising up to meet it as a result of climate change.

The Venice conference addressed all the key issues, but it was notable that two of the three grand themes -- competition and climate change -- rarely met head on. The EU’s Emissions Trading System, the world’s principal attempt to create a market mechanism to address the cost of climate change mitigation measures, is firmly on the naughty step and likely to stay there for reasons of severe under performance. As a result, competition and climate change tend to exist in parallel universes: competition as part of the DNA of the treaties that underlie the EU; and environmental policy representing a Johnny-come-lately that has carved out a morally unchallengeable position in which the normal rules of the EU (state aid, competition policy, etc) are suspended. In this world of parallel universes, both competition and the suspension of competition are simultaneously correct.

Feel good factorThe moral high ground provided by renewable energy is good cover for all sorts of things. It is one of the more curious findings of economics that people are happier as a result of relative rather than absolute wealth. In other words, they don’t mind so much being poor so long as they are not quite as poor as the people in the next street. Europe might be said to be in this state with regard to climate change and renewable energy sources. It isn’t doing enough, but it is doing more than any other region of the world, and this is sufficient to generate a feeling of well being.

The EU, or rather a few of its member states, have led the way in the deployment of wind farms, photovoltaic solar power and biogas. The European Commission hopes to extend this lead with offshore wind networks, wave and tidal power. The environmental targets the EU has adopted are the most ambitious in the world. It has taken a stand on climate change and encouraged others to follow.

Even at a time of protracted fiscal crisis, which for many EU member states threatens a long-term cycle of high-debt and low growth, the European Commission’s environmental goals appear unbending. This is achievable because the ‘green economy’ has been sold as both a necessary and desirable state in terms of climate change mitigation and as a means of economic stimulation and job creation. It is an attempt, although imperfect, to marry and deliver both economic growth and sustainability, largely through the energy sector.

However, the strains are beginning to show. While the IAEE delegates considered the varied challenges posed by the integration of renewables into existing grids, a different voice could be heard from the gas-to-power utilities, one which said “help, we’re hurting.” And they are. Subsidized renewables output is reducing their share of the wholesale market at a time when demand is particularly weak. Moreover, continental European gas prices are largely linked to oil, a commodity from which the rest of the electricity market is increasingly detached, and oil prices are high.

Gas-to-power generators cannot politically challenge the moral imperative of renewables deployment (for which read subsidization). As a result, they have to fight on the only other available front -- the gas-to-oil link.

In this endeavor, the Commission is willing to help. In September, the European Commission’s competition directorate opened an investigation into Russian gas supplier Gazprom that included a charge that the company’s use of oil-linked gas contracts may be anti-competitive. Competition policy is the Commission’s big gun. It carries with it real sanctions and can achieve more in real terms than decades of policy making. It is now being deployed in defense of European gas buyers against an external gas supplier. If successful, it will make it less necessary to address the other part of the problem -- that gas is suffering because of the favors bestowed upon renewables.

Competition policy is being used to address one side of the problem where the EU will benefit from competition, but is being ignored where competition is less advantageous. Gazprom, and other external gas suppliers, know it too. Even if the oil indexation question is resolved, natural gas in the EU will struggle because EU energy policy is increasingly split between competitive and non-competitive sectors, one driven by the EU’s long-standing economic ideology and the other by its environmental ideology.

It would be easy to say that, one day, this contradiction will have to be resolved, but that’s not necessarily the case. The EU has struggled for decades to create competitive power and gas markets in a sector where natural monopolies and barriers to market entry meant that the creation of a textbook ‘perfect’ market was always going to be difficult, if not impossible. How much simpler it might be to displace it with something altogether different, not through genuine competition but by loading the dice so heavily that the outcome is never in any doubt.

— Ross McCracken


lEttErs lEttEr from moscow: sEptEmbEr 2012

LETTER FRoM MoSCoW: SEPTEMBER 2012

Policy u-turnsGazprom appears to have a won the latest battle over a proposed increase in the Mineral Extraction Tax for natural gas, with the authorities managing to make two contradictory decisions on the issue in just one week in September. First the finance ministry published a new formula for the MET for gas, which linked the tax to growth in regulated domestic prices, with increases phased in from 2013-15. The proposal envisaged a significant jump in tax revenue at the expense of both Gazprom and independent producers.

However, two days later, the same document on the ministry’s website offered another scheme, this time featuring absolute figures rather than a formula-based mechanism. It predicts much less growth in the tax take. This latest version foresees Rb176 billion ($5.62 billion) in additional payments to the federal budget in 2013-2015, compared with Rb355 billion under the initial scheme.

Although still set to pay more tax, the key winners from this second proposal are Gazprom and Russia’s biggest independent gas producer Novatek. These companies save about $6 billion and $1 billion, respectively, in MET payments, compared with the previous scheme, analysts calculated.

On the day of the second announcement, Gazprom and Novatek’s shares traded up against a falling market. “MinFin’s sudden lowering of its demands marks a victory for producers, and the range of possible negative outcomes has narrowed substantially,” analysts at Citi said, adding that “we see the risk around tax policy as rapidly fading for Russia’s gas producers.”

However, other analysts highlighted the government’s inconsistency and its impact on the sector. It can hardly be “supportive for improving the investment climate in the gas sector,” Alfa-Bank analysts said. Significantly, they did not rule out the possibility of further policy revisions. “Given the government’s lack of consistency to date, we do not adjust our TPs [target prices] yet, anticipating more noise on the subject,” Alfa-Bank said.

VTB Capital analysts also noted that the key concern is the reliability of the MET rates suggested for 2014-2015. “There is a risk that these rates, which are only to be approved in spring 2013, might be changed again,” they said, adding that there was also no clarity regarding gas MET policy after 2015.

They are right to be concerned. Finance Minister Anton Siluanov has not ruled out that the new MET approach, if adopted, may be changed again within two years. In 2014, the government is considering the introduction of flexible MET rates that would reflect the varying levels of difficulty of gas production at different fields. Siluanov said: “Some differentiated rates may be introduced already next year, at the very least in 2014.”

Gazprom’s CEO Alexei Miller is in favour, arguing that Gazprom would fail to produce over 35 Bcm a year of natural gas from new projects in 2014, if the differentiated rate is not introduced. In addition, Miller was quoted by local media as saying, the company “may see difficulties with taking final investment decisions as soon as 2013, in particular for the next stages of the Bovanenkovo field [in the north] and Chayanda [in East Siberia].”

Gazprom probably used the same argument -- the need to support its capital-intensive investment program for eastern regions -- in lobbying the government to moderate its initial proposal on higher taxes. Gazprom said in early September that it would intensify work in Russia’s eastern regions in order to enter markets in Asia-Pacific and reduce its dependence on Europe. This followed an announcement by the European Commission that it was initiating a competition investigation into the company’s practices in Central and Eastern Europe.

The theory seems plausible, given Gazprom’s earlier successes in its negotiations with the government over tax. After keeping the MET rate flat for five years, the government only decided to increase it from January 2011 in order to boost federal budget revenues and spread the tax burden across the oil and gas sectors more evenly. At present, the oil sector has a higher tax burden.

New Rosneftegaz roleThe MET gas decision is not the only budget-related u-turn the government has been considering. Rosneftegaz is a 100% state-owned holding entity that holds a 75.16% stake in Rosneft and a 10.74% stake in Gazprom, as well as stakes in other, smaller energy entities. The company has accumulated between $3-4 billion in capital via dividends paid by Rosneft and Gazprom, according to various estimates.

In May, President Vladimir Putin announced a new role for Rosneftegaz. It would invest in energy assets previously planned for sale to private investors. “Rosneftegaz buying shares in state-owned companies cannot be called privatization in the full sense of the word,” but if the energy holding buys into capital of some state-owned companies that will support their market value, Putin said in July.

However, the finance minister has now proposed a very different role -- budget donor. Siluanov wants the money to fulfill campaign promises made by Putin during the presidential election of late 2011/early 2012. Just before the discussions on the 2013 budget started, Putin made plain that he wanted these promises met and severely criticized the government for failing in this regard. The promises include higher salaries for state employees, development of Russia’s Far Eastern regions and higher defence spending.

— Nadia Rodova


lEttErs lEttEr from washington: sEptEmbEr 2012

LETTER FRoM WASHINGToN: SEPTEMBER 2012

Trade disputes flourishTrade tensions flared again between the US and China in September, with both countries filing World Trade Organization complaints against each other. The Obama administration challenged Chinese automobile subsidies, while China in return filed a formal complaint over tariffs the US has imposed on a number of products, including towers for wind turbines.

The clean energy sector has been at the center of many of the disputes between the two countries. In addition to wind towers, the US has imposed tariffs and duties on Chinese-made solar panels, charging that Chinese companies are being illegally subsidized under WTO rules, and are “dumping” their products in the US at below market cost. The US has also requested WTO arbitration over China’s export quotas on rare earth metals, which are vital components in several clean-energy applications.

In each case, China has said it is following WTO regulations and has warned that any “restrictive measures” against its products would hurt the US economy. China in August said six renewable energy projects in the US are illegally subsidized and violate WTO rules for “distorting normal international trade.” The country is also investigating whether US manufacturers of polysilicon, a key material used to make solar panels, are selling their product below cost.

Under the WTO dispute resolution process, the two sides will enter “consultations,” or negotiations, for 60 days. If no resolution is reached, the country that filed the complaint is allowed to request adjudication by a panel.

However, anti-dumping duties can be imposed in the meantime. In the wind tower case, the US Commerce Department in July announced a preliminary decision to impose anti-dumping duties of between 20.85% to 72.69%, on top of tariffs imposed by the agency in May of 13.7% to 26% for what the US has called China’s illegal subsidization of its manufacturers.

The decision was prompted by a complaint brought by several US wind tower manufacturers. Alan Price, an attorney for the manufacturers, said he is confident the US will not reverse its decision to impose the penalties. “At the end of the day, it’s not going to have any significant impact on the investigation,” he said.

Political posturingAlan Tonelson, an economist and trade expert at the US Business and Industry Council, a Washington research organization, said the US has instigated these trade tensions, and called the Obama administration’s actions “largely posturing.” He said the US has been losing the clean energy manufacturing race because it has yet to establish any credible national energy policies.

“There’s no doubt in my mind that the Obama administration -- and this even goes back into the Bush years -- that the United States does not have a coherent strategy for creating a world-class alternative energy industry in this country in such a way that it would reduce our dependence on fossil fuels, but also manufacture and develop the products and the entire infrastructure in such a way that value is added to the US economy,” he said.

He said the tough trade talk on China plays well for Obama on the campaign trail, as the president seeks to shore up support from key groups, such as manufacturing unions. “Constituencies can be pacified by these WTO filings,” Tonelson said.

Marc Ross, a spokesman for the US-China Business Council, which represents US companies doing business in China, said his organization would prefer the two sides to resolve their disputes through WTO adjudication, instead of unilaterally imposing tariffs. Although the trade dispute plays out in headlines and sabre-rattling declarations from both countries, he said that behind the scenes, the US and China have engaged in several negotiations and that most foreign policy experts do not see the trade issues as a major stumbling block between the two countries.

“Certainly, China is easily used as a populist tool,” Ross said. “Both sides are trying to out-do each other. But there’s more and more dialogue happening daily. Obama has met with President Hu 12 times. [Secretary of State] Hillary Clinton was just there, and Defense Secretary Leon Panetta was in Beijing [last] week. There’s a lot more engagement, a lot more talking happening.”

Meanwhile, on the campaign trail, Obama officials denied that politics had any role in the WTO filings, saying they are trying to establish a global level playing field for US manufacturers. White House Deputy Press Secretary Josh Earnest told reporters, after the administration filed its auto subsidy complaint, that the US has won every single case it has brought before the international trade board.

“If you take a look at the record of this administration’s success in advocating for American workers and American entrepreneurs before the WTO, it’s clear that this is a long and consistent part of the president’s record,” Earnest said. “The president isn’t focused on the politics; the president is focused on his responsibility to advocate for American workers. We have a strong record on this, and this is something that you can expect to hear the president talk about … over the course of the next 50 days.”

— Herman Wang


lEttErs lEttEr from brussEls: sEptEmbEr 2012

LETTER FRoM BRUSSELS: SEPTEMBER 2012

Daily reportingThe European Commission has suggested companies report standard wholesale gas and electricity transactions daily to EU energy regulatory agency ACER. The Commission is consulting on what should be in the detailed rules needed to implement the reporting requirements in the EU’s regulation on energy market integrity and transparency, known as REMIT, which took effect last December.

REMIT is intended to prevent and prohibit market abuse in the EU’s wholesale gas and electricity markets. It covers trade in both physical energy and capacity as well as derivatives of these. It requires market participants to publish inside information and to report their trades to ACER for monitoring. The details of how this reporting will work in practice are to be set out in detailed implementing legislation being prepared by the Commission.

“Our view is that ACER should focus its market monitoring on those markets where the risk of market abuse is highest and the cost of market abuse to market participants and consumers greatest,” the Commission said. “Market abuse is most likely where standard contracts are used and there is easy access to trading platforms. Consequently, ACER should focus its resources on ensuring that it has access to standard transactions,” it added.

The Commission suggests that all standard trades using organized market places, brokers or trade matching facilities should be reported. It also suggests that where there is a central counterparty it should have sole responsibility for reporting a trade, and where there is no central counterparty, both parties should remain responsible for reporting the trade.

These views are similar to ACER’s, set out in its own consultation paper issued June 21. ACER was to submit its formal recommendations to the Commission by September 30. ACER suggested, for example, using the financial markets as the model for reporting standardized energy trades, which means reporting “as quickly as possible and no later than the close of the following working day.” Non-standard trades could be reported less frequently, for example, within a month, it said. ACER also proposed that it defines the list of contracts to be reported, saying this should exclude balancing market trades except for markets where balancing is mandatory for most market participants. And that it develops a standard product taxonomy that all market participants would have to use to categorize their reported trades.

These ideas are in line with the recommendations made by consultants hired by the Commission. The consultants made other similar recommendations to those made by ACER, including that ACER define a standard commodity transaction as one that can be transformed into a generic REMIT standard reporting format. They also recommended that ACER set up a list of which transactions are fully reportable. “The...list would include [transactions on] all widely used organized market places, brokers or trade matching facilities and would be subject to periodic update,” the Commission said.

The consultants also recommended that initially -- for around two years -- all non-standard, transactions should be subject to less frequent and less detailed reporting. “Our initial view is that this is a suitable approach towards the specification of the contracts and transactions to be reported,” the Commission said. The consultants said that the national regulatory authorities it surveyed indicated that daily reporting for standard trades was enough for their monitoring purposes, and that any exemptions to this “should be justified and clearly defined.” The regulators added that real-time reporting should not be excluded “if this proves to be the most cost-efficient way of reporting.”

The regulators told the consultants that they want all contracts with delivery dates after December 28, 2011 -- the date REMIT entered into force -- reported as soon as the reporting mechanism is in place. They also want companies and/or third parties to report all trades concluded after that date, both standard and bilateral non-standardized. In addition, the Commission is seeking feedback on its suggestion that the definition of wholesale gas products extends to LNG and storage, including landing and storage capacity. That would mean companies would have to report their LNG and storage transactions.

REMIT also requires companies to publish fundamental market data. For electricity, the Commission is defining such data in detail in draft EU guidelines that it hopes to make binding early next year, subject to approval by national governments. But it says there is nothing equivalent in place or planned for gas, and asks for feedback on what fundamental gas data is missing and how it should be accessed. Transparency in gas pipeline data is set to increase though, under new EU rules, which entered into force late August. These require gas grid operators to publish extensive pipeline data on a central EU website from October 2013. Previously they were only required to publish data on their own websites.

The Commission’s REMIT consultation closes December 7, and sources say it wants to present a formal proposal for the detailed implementing legislation in early 2013. The proposal has to be approved by an EU technical committee of national government officials and pass a three-month scrutiny by the European Parliament and EU Council before the Commission can adopt it into law. That means the earliest the new requirements could be in place is early 2014.

— Siobhan Hall


Country-by-country breakdown of oPEC production (million b/d)

Country August July June May April March February January

Algeria 1.210 1.220 1.230 1.230 1.230 1.270 1.270 1.270Angola 1.750 1.650 1.730 1.750 1.770 1.700 1.800 1.710Ecuador 0.490 0.490 0.490 0.490 0.490 0.490 0.490 0.490Iran 2.750 2.900 3.100 3.250 3.280 3.400 3.500 3.520Iraq 3.100 3.050 2.970 2.980 3.000 2.850 2.680 2.700Kuwait 2.800 2.800 2.750 2.750 2.700 2.670 2.670 2.650Libya 1.450 1.450 1.480 1.450 1.400 1.350 1.250 1.000Nigeria 2.280 2.200 2.180 2.180 2.200 2.100 2.100 2.060Qatar 0.790 0.790 0.790 0.790 0.790 0.820 0.820 0.820Saudi Arabia 10.000 10.000 10.100 10.000 9.950 9.900 9.850 9.800UAE 2.620 2.600 2.600 2.580 2.600 2.540 2.540 2.560Venezuela* 2.300 2.300 2.300 2.300 2.300 2.300 2.300 2.290Total 31.540 31.450 31.720 31.750 31.710 31.390 31.270 30.870

*Some survey participants revised their estimates of Venezuelan production following the International Energy Agency’s re-evaluation of its Venezuelan supply methodology in June. This resulted in the Venezuelan estimate of the Platts survey rising to 2.35 million b/d in June from 2.23 million b/d in May.

Source: Platts

markEt nEws oil

A tentative deal between Baghdad and the KRG has raised hopes that a long-awaited federal Iraqi oil and gas law may soon be passed. Ali Salhi, the Kirkuk Governing Council’s chairman for oil and economic development, said in September he was “very hopeful” that a new round of meetings between central government, parliamentary opposition and KRG representatives would generate a new draft of the long-delayed law that all sides could support. He added that he expected the new law would extend legal protection to the terms of dozens of contracts the KRG has signed with foreign producers, but which Baghdad considers illegal.

KRG Minister of Natural Resources Ashti Hawrami told reporters that the agreement would ensure that payments due oil companies working in the KRG and crude oil volumes from the KRG would both in future be specifically incorporated into the federal budget, thus providing a stable environment for corporate investment in the KRG and growing revenues for Iraq as a whole. Hawrami was speaking at the STEAM energy conference in Istanbul. Neither Baghdad nor the KRG have announced the terms of the deal, and oil producers operating in the region have yet to be notified of the details.

Hawrami said the Kurdistan region of Iraq will produce some 200,000 b/d of oil in the last quarter of 2012 and remains on track to produce 1 million b/d in 2015. He said he expected the KRG to produce in excess of 250,000 b/d of crude in 2013. Speaking to reporters afterward, he added that more detailed figures for production levels between now and 2015 would be included in the KRG’s presentations to the federal budget being prepared by Baghdad.

Hawrami said that new discoveries were eventually expected to lead to the KRG producing some 2 million b/d. He gave no timeframe for this, but asserted that oil and gas drilling programs had so far yielded a 70% success rate.

KRG oil is to be exported to Turkey via a new pipeline to be built from Kumala to the Turkish border, Hawrami said. He told reporters that at present the KRG has a connection with the Kirkuk-Ceyhan line via Kumala in the KRG, but that it could not take all of the oil the KRG expects to produce in 2015. A new 1 million b/d pipeline would be built within the KRG from Kumala to the Turkish border, where it would connect to the Kirkuk-Ceyhan line, he added. Subsequently, a new line designed to carry heavy oil from the Iraqi Turkish border to Ceyhan would be built by the KRG’s Turkish partners, Hawrami said.

As for gas, Hawrami told the conference the first part of a new connection to carry gas from the Taq Taq field to Dohuk was under construction, and that from Dohuk it would be easy to extend it across the border into Turkey. A KRG official subsequently added that the line to Dohuk would be completed within six months.

Hawrami commented: “We already have commitments to supply gas to one power plant in Turkey. We are hopeful that will happen within two years.” He was referring to a power plant project being developed by Turkey’s Siyah Kalem company, which aims to take gas from the KRG and then send the electricity generated back across the border to serve Mosul and other northern Iraqi towns and cities.

Hawrami told reporters that the KRG’s gas strategy remained unchanged, that it aimed first to produce gas for Kurdish domestic use; then to ease the power shortages in Kirkuk, Mosul and other adjoining regions of Iraq. Once those were taken care of any surplus gas could meet the needs of Turkey, and then Europe.

Gas analyst Gokhan Yardim, a former senior official with Turkey’s state pipeline company Botas, told the conference that Turkey was already planning the construction of a 366 km (227-mile), 40-inch line to bring some 10 Bcm/year of gas from northern Iraq to Turkey.

Iraq oil deal to see KRG volumes rise

Market News


markEt nEws oil

Canadian independent Nexen has cleared the first major hurdle in the way of its takeover by state-owned Chinese oil company CNOOC, gaining strong shareholder backing September 20. The final verdict now lies with regulators and governments in Canada and the US.

However, the deal has started to raise concerns, suggesting there is at least a possibility the deal could go the same way as CNNOC’s failed attempt to take over US oil company Unocal in 2005, which was thwarted by US political opposition.

In Canada, the $15.1 billion takeover was endorsed by 99% of Nexen’s common shareholders and 87% of preferred shareholders, placing the transaction in the public domain at a time when unease is building within the Conservative federal government. The deal is currently before Industry Canada’s foreign investment review agency, which has an initial deadline of October 12, with the option to add another 30 days, to deliver its recommendations to the federal cabinet.

Despite his declared goal of welcoming foreign investment to finance an estimated C$650 billion ($665 billion) needed to grow Canada’s oil sands and shale deposits over the next decade and turning Canada into an “energy superpower,” Prime Minister Stephen Harper has wavered recently on giving outright backing to the deal. With a rift developing in his own ranks, Harper has broadened the regulatory review beyond the usual requirement for proof of a “net economic benefit” to Canada, insisting that China must show its state-run enterprises can be trusted to operate by the same rules as Canadian companies.

He surprised observers in late August by telling reporters that public opinion and assurances of economic reciprocity between Canada and China will be important issues in the government’s final decision. “This is a significant transaction with significant implications for the Canadian economy, both today and in the long term, and I think those considerations need scrutiny and they need some clear long-term policy direction,” Harper said.

In Canada, a Sun News-Abacus poll of 1,208 participants released before the shareholder vote had 69% of respondents urging government to reject the deal, up 12 points from a similar poll in August, while 8% said they backed the takeover. Minister of State for Finance Ted Menzies said September 19 he had “heard many concerns, varying concerns, concerns about the resource industry, concerns about a foreign company investing in Canada,” noting that residents in the oil-dominant province of Alberta are divided over the deal.

Rob Anders, a government Member of Parliament from a Calgary constituency and a frequent critic of China’s human rights record, said September 19 he is concerned about “any acquisition of Canadian hard assets by a foreign state and I have even greater concerns when it comes to China … There is also the issue of intellectual property. Alberta has a somewhat

difficult (oil sands and shale) resource basin that has inspired innovations we should market abroad rather than sell to China,” he said.

Industry Minister Christian Paradis said outside the House of Commons that the “transaction will be scrutinized very closely” after the opposition New Democratic Party demanded a public review of the takeover. “But it is not the intention of this government to put the oil industry out of business,” he said.

Liberal Party deputy leader Ralph Goodale said Ottawa should be working on a policy for foreign takeovers, especially after the Harper administration blocked an attempted C$39 billion hostile takeover in 2010 of Saskatchewan fertilizer company Potash Corp., by the Anglo-Australian mining giant BHP Billiton. “If Nexen is purchased, then what’s next? Is it Talisman, is it Cenovus, is it Encana?” he said. “Where do these dominoes begin to fall and where do they stop?”

The pressure is building on the Canadian government to decide how far it will go in allowing the sale of oil and natural gas assets to foreign state-owned enterprises. In addition to CNOOC and Nexen, the investment review agency is also examining the proposed C$6 billion buyout of Progress Energy Resources by Malaysia’s Petronas. Other oil sands deals for minority stakes have involved companies from China, Japan, South Korea and Taiwan. Kuwait Petroleum has indicated that it is on the verge of a joint-venture with Athabasca Oil Corp.

Nexen interim CEO Kevin Reinhart told shareholders September 20 in a webcast from Calgary that CNOOC has strengthened its case by promising to continue investing in and fully developing Nexen assets, retaining all Nexen employees, establishing a base in Calgary for all CNOOC assets in North and Central America and keeping a listing on the Toronto Stock Exchange. “This transaction will in no way close the book on Nexen or our way of doing business,” he said.

The deal is also before the US Committee on Foreign Investment in the US because 10% of Nexen’s assets are in the Gulf of Mexico, including a 20% stake in the Shell-operated Appomattox discovery. In an August letter, Democratic Senator Charles Schumer of New York urged the US Treasury Secretary Timothy Geithner, who is chairman of the committee, to use the review as leverage to solve long-standing trade and investment issues with China.

A UK government spokesman told Platts that CNOOC would also have to pass an assessment to be able to operate in the UK North Sea. EU competition authority approval may also have to be sought.

In the US, Robert Hormats, undersecretary for economic growth, energy and the environment, said the Obama administration welcomes Chinese investment in North American energy as long is does not raise national security concerns. “We’re certainly eager to have more Chinese investment,” Hormats told an event in Washington on the implications of Asia’s rising oil and gas demand. He added that Chinese companies would be more welcome if they weren’t stated owned or were in the process of being privatized.

Sentiment palls on CNooC bid for Nexen


markEt nEws oil

Libya is currently producing an average 1.6 million b/d of crude oil and expects to increase output by 30,000-40,000 b/d by early 2013 once repairs to one of the pipelines in eastern Libya are completed, according to National Oil Company Chairman Nuri Berruein. He told reporters on the sidelines of the CWC Libya Summit in September that Libya was targeting production of 1.8 million b/d next year.

We have held back production from some oil fields in order to preserve wellhead integrity so that we do not cause any damage,” Berruein said, adding that a pipeline being built in partnership with Wintershall of Germany would be completed “in record time,” allowing oil production to resume at higher levels from three or four fields in the Sirte Basin that are currently being held back.

NOC and Wintershall agreed in June to replace a corroded pipeline that links a cluster of fields in the eastern Sirte province, the first major infrastructure project to be undertaken since the end of the rebellion that ousted Moammar Qadhafi in October last year. When completed, export capacity is expected to rise by 100,000 b/d.

Foreign oil companies shut down production and evacuated staff from Libya at the start of the anti-Qadhafi rebellion in early 2011, leading to a total shutdown of production in the OPEC member state. Libya was producing an estimated 1.6-1.7 million b/d before the crisis and has been able to restore capacity to its previous levels relatively quickly since the end of the civil war.

Berruein said the target was to produce 1.8 million b/d by 2013 and reiterated the target of 2 million b/d by 2015, which Oil Minister Abdulrahman Benyezza told the conference earlier remained the target under an existing five-year plan. Oil exports are averaging 1.1-1.2 million b/d, slightly below earlier estimates, as all Libyan refineries have resumed full operations. The 220,000 b/d Ras Lanuf refinery, which resumed normal operations early in September, is operating at 180,000 b/d, Berruein said.

Gas production is still at around two-thirds pre-crisis volumes because of technical problems with some subsea wells that still need to be brought back on-stream, he said, adding that he expected gas exports to Italy to be restored to their previous level by the end of the year.

Having restored oil production to pre-crisis levels, Libya is now looking ahead to a stepped-up exploration campaign in an effort to boost both its oil and gas reserves, expanding and upgrading its oil refineries as well as developing its shale gas reserves, NOC executives told the conference. Berruein said the foreign oil companies that were awarded exploration acreage in 2006 and 2007 are due to resume their activities in early 2013.

He said BP, which won one a major exploration deal during the Qadhafi era, had committed to drilling five wells in deep offshore waters, hopefully before the end of 2014, assuming the right drillship is secured. Most of

the seismic surveys have been completed and companies that have made discoveries offshore will have to return to Libya to assess them, he added.

Total’s managing director in Tripoli, Bernard Avignon, told Platts on the sidelines of the conference that the French major, with partners Wintershall and Libya’s NOC, plans to begin offshore exploration in October. Algeria’s state-owned oil and gas company Sonatrach has lifted the force majeure on its Libyan operations and expects to begin drilling the first of three discovery wells this year, according to the company’s representative in Libya, Ali Abuogela.

Libya has held four licensing rounds since December 2004, following the lifting of US and UN Security Council sanctions that had held back Libya’s oil and gas sectors for several years. Berruein said the first round resulted in the addition of 784 million barrels of recoverable oil and 5.3 Tcf of recoverable natural gas. The second round in 2005 resulted in 23 areas being awarded, of which five are still active. This resulted in 12 oil discoveries and one gas discovery with the addition of 198 million barrels of recoverable oil reserves and 213 Bcf of recoverable gas.

Eight of the 10 areas awarded in a third bidding round in 2006 are still active and the companies are expected to resume operations in early 2013. That round resulted in three oil discoveries and one gas find, adding 18 million barrels of recoverable oil reserves but no gas, results which Berruein said had been disappointing. He was more hopeful about the fourth bidding round, which was held in 2007 and was mainly for gas exploration. Of the 12 contract areas offered, seven were awarded and six are still active. No wells have been drilled yet and Berruein said operations were also expected to resume in early 2013.

“Significant hydrocarbon resources are waiting to be developed,” Berruein said, but he added that there would be no further bidding rounds until a new government is in place. The exploration and production agreement known as EPSA IV is also being reviewed as part of a major critique of the last 10 years of exploration activity and EPSA models, he added.

Libya wants to raise its oil recovery rates from producing fields from a current average of 35% to 45% through the use of enhanced oil recovery techniques. The NOC also sees pushing recovery rates up by a further 10-15% as a future challenge, Berruein said.

Libya has made 58 discoveries since 2007, adding 3.2 billion barrels in place and 8.9 Tcf of natural gas. Assuming a recovery factor of 35%, this translates into 1 billion barrels of recoverable reserves for oil and 5.8 Tcf of recoverable gas, he said.

Future bidding rounds will have to be tweaked because Libya needs state of the art exploration for the less prospected areas and for the deep offshore. “We are not going to offer any concessions until a proper government is in place,” he said. “The results of the third round were disappointing but we are optimistic and expect some success from the fourth bid round.”

Libya targets oil production of 1.8 million b/d in 2013


markEt nEws oil / gas

The Russian government has decided to expand tax breaks for new oil fields in East Siberia to stimulate further development of the remote region, Russia’s energy minister Alexander Novak said in November. The government has decided to nearly halve export duty for crude produced from new fields in the region and extend tax holidays from the Mineral Extraction Tax (MET) until January 1, 2022, Novak was quoted as saying by Russia’s Prime news agency. The MET holidays were previously limited to 2017.

“The benefits would be granted to a certain volume of crude and the rate would be set at 45% of the price above $50/barrel. This would represent around a two-fold cut in the tax burden,” he said, speaking after a meeting held at a government residence outside of Moscow. The export duty reduction would be granted to fields with reserves estimated at over 10 million mt, which will be

depleted by no more than 5% as of January 1, 2013, Novak said, according to the report.

“The volume of crude which a company would be able to trade at the reduced export rate will be set [to a maximum internal revenue rate] of 16.3%,” Novak said. The fresh tax initiatives would make an additional 5.3 billion mt of oil economically viable to develop, translating into some 70-100 million mt/year of additional production, Novak said, according to the report. The additional crude oil output would bring into the federal budget around $300 billion, or around $15 billion/year by 2030, Novak added.

A spokesman with the energy ministry said that the ministry has also prepared a unified methodology to provide the tax benefits on a single basis rather than the current scheme to take decisions on a project-by-project case. The ministry hopes to offer the new tax benefits by first-quarter 2013.

Tax breaks for new East Siberian oil fields: report

French gas major GDF Suez has begun new price talks with Russian producer Gazprom, GDF’s executive vice president Jean-Marie Dauger said at an industry conference in Tokyo in September. It was announced earlier in the month that the French government would increase gas tariffs to households by 2% from October, 5 percentage points below the rise requested by GDF Suez. This was followed by a call from French Prime Minister Jean-Marc Ayrault for GDF Suez to renegotiate its long-term oil-indexed contracts with Norway, Russia and Algeria to lower prices to consumers.

The government’s domestic policy on gas prices puts France’s gas suppliers under great pressure to secure better prices from their own suppliers. Energy minister Delphine Batho warned ahead of the tariff increase that GDF Suez’s request for a 7% rise would not be met. Most of this was to cover catch up costs. In principle, changes to French gas tariffs, which dominate the household market, are based on a quarterly formula heavily linked to GDF Suez’ oil-indexed supply contracts.

France’s highest administrative court, the Council Of State, ruled that a price freeze, imposed by the previous government of Nicolas Sarkozy in fourth-quarter 2011, was illegal and customers would have to make up the difference in future bills. However, in July, the government’s 2% increase was well below that recommended by the energy regulator CRE, which has yet to express an opinion regarding the 2% rise sanctioned for October.

The impact on GDF Suez of the price freeze in fourth-quarter 2011 was €290 million ($380.5 million), equating to around €40 for each household on the regulated rates. Following the Council of State’s verdict, which infuriated unions, the government said it would ensure that the cost recovery took place over a long time period to reduce the impact on households.

France’s Socialist government, led by President Francois Hollande, is committed to keeping gas price

increases below inflation. Referring to the latest 2% rise from October, the energy and environment ministries said in a joint statement, “this decision aims to protect the purchasing power of the French people.” Batho said that in parallel with far-reaching reforms of gas and power tariffs, to be debated by parliament late in September, the government would also propose a more urgent change to the gas tariff formula. Without indicating how quickly this change would be put in place, the minister said the proposed reform would avoid the large price swings currently requested by GDF Suez on a quarterly basis.

While the current gas tariff formula remains in place, successive sub-inflation rises combined with continuing high oil prices will mean further losses for GDF Suez, increasing the company’s desire to renegotiate its long-term contracts with suppliers. Dauger, speaking at a conference in Japan, said GDF Suez was restarting price negotiations for the next three-year period with Gazprom.

In Europe, he said, “there is a big question: how to deal with the discrepancy between spot and long-term oil indexed prices. The spread between the two, which he put at $5/MMBtu, has become extremely large. It is sustainable for a short period, but it is now three years, and this hinders market development,” he said.

He told Platts that the 2009 review had led to a “substantial move” toward market prices, but “given the spread between spot and oil prices, it is time to do it again. It needs to be addressed.” The negotiation involves two parties and there is still a reluctance to move to 100% spot prices, even if the re-negotiation involves moving the base price in the oil indexation down closer to spot prices, he said.

While conceding that it would be simpler to move straight to spot prices rather than lowering the base price, Dauger said that what mattered was not so much the methodology as the end result. “What matters is the level of the price. Is my gas competitive?” he said.

Regulated French gas prices squeeze supplier negotiations


markEt nEws gas

Roughly 20% of Japan’s total LNG imports could be linked to US Henry Hub gas prices by around 2020 when the country could be importing up to 15 million mt/year of LNG from North America, Ken Koyama, managing director and chief economist at the Institute of Energy Economics, Japan, said in September. The IEEJ is an affiliate of the Ministry of Economy, Trade and Industry.

Speaking at the LNG Producer-Consumer Conference in Tokyo, Koyama said that a number of Japanese companies have accelerated their efforts to import LNG from North America not only to broaden their supply sources but also their pricing mechanisms.

Faced with rising LNG import costs, owing to oil price indexation, Koyama said Japanese buyers would explore other pricing mechanisms for existing LNG contracts and that importing LNG linked to Henry Hub gas prices from North America was a clear possibility. Koyama also said that one way to introduce Henry Hub gas prices could be through a weighted average of Japan Customs Cleared crude and Henry Hub gas prices.

Koyama’s comments follow an announcement by the Japanese government in late June that Japanese companies had secured the option to import up to 15 million mt/year of LNG from North America, which could start from as early as 2016, although formal contracts are yet to be finalized. Last year, Japan imported a record 78.5 million mt/year of LNG. The country’s LNG demand has soared since the March 2011 Fukushima nuclear disaster. Tokyo has been seeking additional supplies from major exporters such as Qatar, but Qatar has insisted on retaining oil-linked contracts for its LNG.

At the same time, Japan has been stepping up efforts to lower the cost of LNG imports after reporting its first annual trade deficit in 31 years in 2011. LNG imports from the Middle East, which are linked to crude oil prices, are far more expensive than natural gas from the US, where Henry Hub prices fell to 10-year lows earlier this year and are currently at a fraction of oil-linked LNG prices.

The US is unlikely to be the only new source of LNG. Five LNG projects to be developed on Canada’s West Coast could be in service between late 2014 and 2019, according to the country’s federal energy minister Joe Oliver, speaking at the same conference. “The relevance of Canada’s gas reserves in the total market is more than scale. It’s also geography. LNG tankers from Canada’s Pacific North West reach the Pacific Basin LNG market in as few as 11 days,” Oliver said. “This is faster than from the Middle East or Africa. LNG development in Canada’s West Coast is already attracting interest from Pacific nations including Japan, Korea and China,” he said.

Based on the projects proposed, Canada could have export capacity of 9 Bcf/d of natural gas, equivalent to 66 million mt/year of LNG, he said. He specifically mentioned the planned LNG Canada project – a joint venture between Shell, Korea Gas, Mitsubishi and PetroChina. The project was formally announced in May and would be sited at the British Columbia deepwater port at Kitimat.

Additional LNG export terminals and related pipeline infrastructure are being proposed for the Prince Rupert area also on the coast of the province of British Columbia, said Oliver referring to a recent announcement from Spectra Energy about developing a 4.2 Bcf/d natural gas pipeline and LNG export facilities in the port of Prince Rupert.

“A key strategic objective for Canada is to diversify its energy markets, particularly to the Asia-Pacific region where demand is increasing,” Oliver said, adding that Japan, as the world’s largest LNG importer, should have a particular interest in Canada, where “there are up to 1,300 Tcf , or 37 Tcm in natural gas resources, which will undoubtedly increase as we discover more shale gas and offshore resources ... For Canada, these LNG projects mean opportunities to expand and diversify our export markets. For Japan, they mean a safe reliable source of LNG for decades to come,” Oliver said.

Japan eyes quick uptake of Henry Hub linked LNG imports

Coastguard vessels from Japan and Taiwan dueled with water cannon September 24 after dozens of Taiwanese boats escorted by patrol ships sailed into waters around Japanese-controlled islands in the East China Sea. Japanese coastguard ships sprayed water at the fishing vessels, footage on national broadcaster NHK showed, with the Taiwanese patrol boats directing their own high-pressure hoses at the Japanese ships.

The large-scale breach of what Japan considers sovereign territory – one of the biggest since WWII – is the latest escalation in a row over ownership of the islands that pits Tokyo against Beijing and Taipei. The intrusion complicates an already volatile territorial dispute with China.

Adding to the tensions, China’s first aircraft carrier entered service September 24, marking an expansion of its blue-water fleet that will bolster its

military and diplomatic clout. Beijing says the carrier will mainly be used for training and development purposes, but military commentators say China is developing strike aircraft and support vessels which would help it become fully operational.

Taiwan said that officers aboard some of the patrol ships sent to the area were fully-armed elite coastguard personnel. Japanese Chief Cabinet Secretary Osamu Fujimura said Tokyo has complained to Taipei about the move, but that Tokyo was handling the situation as delicately as it could.

Eleven Chinese government ships entered waters around the Japanese-administered islands September 17. Japan had earlier announced that the state had bought the islands from its private owners, a move which sparked a series of anti-Japanese protests in Chinese cities.

East China Sea tensions rise


markEt nEws gas

Japan’s largest city gas utility Tokyo Gas is pinning its hopes on the US and Mozambique as a means of diversifying supply sources and price indexation for its LNG imports, according to a senior company official. He was speaking during an LNG Producer-Consumer Conference in Tokyo September 19, which the Ministry for Economy, Trade and Industry organized to debate the problems caused for Asian importers by linking gas prices to the price of crude oil.

Tokyo Gas now intends to import LNG at Henry Hub-linked gas prices from the US and is also considering buying LNG priced off the UK’s National Balancing Point from Mozambique as part of its efforts to lower its oil-indexed import costs, said Kunio Nohata, senior general manager of the utility’s gas resources department.

“If we only have the oil price linkage [for our LNG import contracts], we would only be able to lower the slope [of oil price linkage in contracts] slightly but not lower [the prices] drastically,” Nohata said. “This is why we need different benchmarks to make the breakthrough,” he said.

In the US, Tokyo Gas has teamed up with Sumitomo to import LNG from Dominion Resources proposed Cove Point LNG terminal in Maryland. Tokyo Gas and Sumitomo hope to conclude a gas liquefaction tolling agreement with Dominion by the end of this year, Nohata said, adding that the front-end engineering and design work on the project is nearing completion.

The Cove Point project anticipates the construction of a new LNG liquefaction plant at Dominion’s existing Cove Point LNG import terminal. Under the proposed agreement, the Japanese companies would take around 2.3 million mt/year of LNG for 20 years from the start-up of export operations at Cove Point, which is expected to have a capacity of 5 million mt/year.

Tokyo Gas is aiming to import around 1 million mt/year out of the proposed 2.3 million mt/year of LNG, and is in talks with prospective customers for marketing the remaining 1.3 million mt/year, Nohata said.

Dominion still requires approval from the US Department of Energy to export LNG to Japan or other nations that have not yet ratified a free trade agreement with Washington. The company also requires plant construction approvals. Should they be forthcoming and a final investment decision taken, start-up of the facility would be targeted for some time in 2017, according to Tokyo Gas and Sumitomo. Anadarko CEO Al Walker told the conference that the company expects its first two LNG trains, with a capacity of 5 million mt/year each, to come on stream in 2018.

Tokyo Gas is also considering importing more than 1 million mt/year of LNG at NBP gas prices from the Anadarko-led LNG project in Mozambique, Nohata said. Given the support from the Mozambique government for the project, Nohata said Japanese buyers could import 5 million mt/year of LNG or buy the total output from train one of Anadarko’s planned project. “If the timing of start-up works out, we may be able to form a Japanese buyer’s consortium,” Nohata said. “We are in talks with Mitsui and Anadarko with the hope of supporting the project by possibly becoming a foundation buyer.”

If Tokyo Gas bought 2 million mt/year of LNG at Henry Hub and NBP prices from the US and Mozambique, its LNG imports priced off the gas benchmarks could represent close to 20% of its requirements, according to Platts calculations. Tokyo Gas imported 11.47 million mt of LNG in the fiscal year ended March 31.

Tokyo gas seeks non-oil indexed gas

China started importing gas from Uzbekistan via pipeline in August, adding to the volumes it already receives from Turkmenistan, customs data released in September showed. China imported 1,441 mt equivalent (70,197 Mcf) of pipeline gas from Uzbekistan in August, valued at $687,095, according to the data. This would translate to a price of about $9.17/MMBtu, versus $10.22/MMBtu for Turkmen gas during the same month.

In June 2010, Tashkent and Beijing signed a framework agreement, under which state-owned oil and gas producer Uzbekneftegaz was to supply 10 Bcm/year of natural gas to the China National Petroleum Corp. The gas is sent via the Central Asia-China gas pipeline network, which starts in Turkmenistan and cuts through Uzbekistan and Kazakhstan before ending in China’s western Xinjiang province.

China’s total Turkmen gas imports in August stood at 1.28 million mt, or an average of 2 Bcf/day, up 52.7% year-on-year. This brings China’s total pipeline imports for the month to 2.02 Bcf/day, up 54.2% year-on-year. Separately, CNPC said in a report on its website on

Monday that China has received a cumulative 36 Bcm of gas from Turkmenistan since the pipeline started operating in 2010.

Meanwhile, China imported 1.09 million mt of LNG in August, up 3.5% from the same month last year, but down 18.3% from July. Australia was China’s top LNG supplier in August, sending 388,873 mt, up 20% year-on-year. Australia also supplied China with its cheapest LNG at $174/mt ($3.53/MMBtu).

China paid an average $563.65/mt ($10.84/MMBtu) for its August shipments, up 13.8% from the same month a year earlier. The most expensive import was a cargo from Russia at $1,063.23/mt ($20.45/MMBtu). The previous cargo China imported from Russia was in May, at a price of $982.57/mt ($18.90/MMBtu).

China’s total gas pipeline and LNG imports in August rose 126% year-on-year to 2.37 million mt or roughly 3.27 Bcm. Subtracting pipeline gas exports to Hong Kong totaling 118 million cu m and adding domestic natural gas output of 8.31 Bcm, apparent gas demand in August totaled 11.46 Bcm, an increase of 25.7% year-on-year.

China starts import of Uzbek gas


markEt nEws gas / coal

Egypt’s petroleum ministry is reviewing the country’s oil and gas assets with a view to allowing private-sector investment in numerous state-owned companies, it announced in September. A ministry statement said the preparatory study, which is expected to take three months, was aimed at creating a development plan for the oil and gas sector that would seek to maximize financial and economic return while improving management.

The proposed initial public offerings of currently state-owned oil company shares would be initiated “very soon”, petroleum minister Osama Kamal was quoted as saying. In the coming three months, the ministry will decide which companies and projects could benefit most

from private capital injection and the adoption of technology that the state cannot provide, he said. The oil ministry, through the Egypt General Petroleum Company, owns the country’s numerous local oil and gas producers, which operate in different license areas.

Kamal also said Egypt, which currently exports natural gas, would need to import gas from neighboring countries to further its industrial development. “If we want development, economic activity and high levels of growth, we have to import raw materials including energy,” he said. Gas imports would be preferable to importing diesel, owing to its lower cost on international markets, he said.

Egypt promises state oil and gas divestments

Queensland’s treasurer Tim Nicholls has brushed aside warnings of dire consequences for the Australian state’s coal industry and raised taxes on coal production in his 2012-13 budget, which he handed down to the Queensland parliament in September. Acting on a report from the Independent Commission of Audit headed by former Australian treasurer Peter Costello, Nicholls has increased the amount of royalty that producers must pay on coal that fetches more than A$100/mt ($103.50/mt) on the open market.

From October 1, Queensland producers will pay to the state government a royalty rate of 12.5% on coal valued between A$100/mt and A$150/mt. A higher rate of 15% will be paid by producers on coal with a marginal value of more than A$150/mt, according to Queensland Treasury budget papers.

Treasurer Nicholls said in his published budget speech that he was forced to act because the state government’s debt mountain was forecast to hit A$100 billion by 2018-19 without corrective action. “Queensland’s fiscal position and outlook is unsustainable and restoration must be an urgent priority for this term of government,” he said in his speech.

Michael Roche, chief executive of coal industry body the Queensland Resources Council told the 8th Coaltrans Australia conference in Brisbane in August, that some coal mines were at risk of closing if the Queensland treasurer increased coal royalty rates in his September 11 budget. “At current prices most thermal coal mines in this state are either running at a loss, or are struggling to stay afloat,” said Roche. “The costs of production in Queensland in Australia are far greater than any other coal-producing jurisdictions, causing significant movement up along the global cost curve,” he added.

Prior to the coal royalty rates increase, producers with open-cut mines in Queensland were facing an effective tax burden of 45%, and he predicted a royalty rate increase of the kind unveiled by the treasurer would push this effective rate to over 50%. The increased royalty rates are expected to raise A$200 million of additional tax revenue in the fiscal year to June 30, 2013, rising to A$474 million in the 2013-14 fiscal year

and A$483 million in the 2014-15 year, according to Treasury forecasts.

The increase has been criticised by BHP, which announced it would cease production at its Gregory coking coal mine in Queensland from October 10 due to lower prices and high production costs and would cut 300 jobs. BHP said it was “disappointed” with the rise, “especially an increase of this magnitude” given Queensland already had one of the world’s highest royalty regimes.

“We made it clear to the Queensland government that in the current environment any additional taxation will directly impact the profitability of our current operations and will affect business decisions on capital growth allocations in the state,” BHP said. The producer’s met coal business is currently under extensive review in response to a challenging external environment including rising costs, a high Australian dollar and falling commodity prices.

The Queensland Mining Council, whose members include BHP Billiton and Xstrata, said the royalty rise would see more job losses on top of the 900 already announced in first-half September. “For some existing high-cost coal mines, the royalty structure could be the final straw,” an official from QMC said.

As concessions for raising state coal royalties, the Queensland government has pledged to work with the coal industry to reduce regulatory costs, and to keep the new royalty regime for 10 years. “The government will also guarantee for a period of 10 years [to end of 2021-22 financial year] that coal royalties will not be increased again,” the government said.

The new three-tier structure for coal royalties in Queensland supersedes the state government’s current two tiers of coal royalty rates. This comprises a 7% rate on coal production valued from A$1-100/mt, and a 10% rate on production priced more than A$100/mt that was introduced by a previous Queensland treasurer, Andrew Fraser, in 2008. Treasurer Nicholls’ increase in coal royalty rates puts his government on a collision course with the federal administration, as state royalty payments can be offset against mining companies’ liabilities to the Australia-wide Minerals Resource Rent Tax.

Queensland ups tax take on coal


markEt nEws coal

Illinois Basin coal producers are planning for coal production expansions growing to 200 million short tons a year by 2016, but an industry consultant is looking at that potential growth skeptically. “Personally, I don’t think the demand is there,” John Hanou, president of Hanou Consulting, said at Platts 35th Annual Coal Marketing Days in September.

Hanou, who recently completed market studies on the prospects for both Powder River and Illinois Basin coals, told the Pittsburgh audience that projects are in place – primarily in Illinois – that could mean a potential 300 million st/year of Illinois Basin production by 2021. New Illinois Basin markets include a developing market for high-sulfur coal to power plants equipped with SO2 scrubbers, replacing more-expensive Central Appalachian tonnage, Hanou said. New power plants could take up to 18 million st/year. “But, planned production is exceeding domestic demand,” Hanou said.

Meanwhile, IB exports totaled about 6 million metric tons in 2011, with more than 10 million mt expected to be exported in 2012, and Powder River Basin exports totaled about 7 million mt in 2011, but future export levels from both basins are uncertain, he said. “The question is, will the market be there to support all of that planned production? My personal opinion is, it will not be there, at least in the next 10 years,” Hanou said.

“Basically, we’re looking at a 90 million to a 100 million ton expansion” in the IB, and when one considers announced 40 to 50 million st/year production expansions in Northern Appalachia and elsewhere, Hanou said his “gut feeling” is that the demand just isn’t there. In his presentation, Hanou noted three new power plants, completed since January 2009, creating a total of about 7.1 million st of new IB coal demand, and two plants under construction that will create a total of 5.5 million st/year of new demand. But this is against a backdrop of about 1,800 MW in coal plant retirements in the US by 2020.

By 2030, according to Hanou, nearly 49,500 MW of coal plant retirements are projected, amounting to 123.3 million st/year of coal consumption lost, with 56.1 million st/year of that loss in Powder River Basin coal burns.

In addition, scrubbed power plants aren’t switching to high-sulfur coal as fast as IB producers had planned, Hanou said. “I think the switches are going to happen, but the demand hasn’t developed as fast as the IB producers had wished,” he said.

In the midst of all these demand cutbacks, Murray Energy, Cline Group/Foresight Energy Partners and Alliance Resource Partners/White Oak Resources have capitalized 38.8 million st/year of new longwall production by 2015, with Foresight and White Oak planning a total of 34.5 million st/year of new longwall production between 2015 and 2018, Hanou’s presentation showed.

Meanwhile, planned “most likely” Powder River Basin production, his presentation indicated, could peak at 600 million st/year by 2021 before starting a decline between 2025 and 2030, to about 550 million st/year. He also noted PRB and IB spot coal price spikes every 2-1/2 years, correlated with natural gas price spikes. “I’m positive it will occur again when [domestic power plant] stockpiles get below normal,” Hanou said. “My prediction is at the end of 2013.”

As for production costs, Hanou said, “The future belongs to the low-cost producer,” which includes both PRB and IB. “CAPP production has peaked and will not recover going forward,” he said, but it will continue to serve “niche” markets, such as metallurgical, PCI and thermal. “Several US basins have the combined ability to replace the void left by CAPP,” and that includes IB, PRB, Colorado/Utah and NAPP’s Pittsburgh seam, Hanou said.

“Most of this production will be relatively low cost as a result of virgin reserves being accessed,” he said, and this includes PRB producers leasing federal- and state-owned coal reserves and IB reserves being mined that were previously neglected after demand for high-sulfur coal plummeted in the 1990s with implementation of the Clean Air Act amendments, until the recent resurgence in IB production due to demand from scrubbed power plants and export customers. But, Hanou warned, in addition to the new regime of environmental regulations, “Huge natural gas shale plays are taking [their] toll on coal.”

US coal supply to outstrip domestic demand

India’s largest miner state-run Coal India Limited is to award the contract for exploring its coal blocks in Mozambique within two weeks, a senior CIL official told Platts September 20. The company is in the process of scrutinizing the financial bids of the four firms, the official said. He declined to name the four but said they include both Indian and international firms.

In May this year, CIL invited expressions of interest for a selection of companies to undertake drilling activities in its two coal blocks in Mozambique. Eleven companies responded to the EOI. According to the official, CIL wants to start the drilling activities during the current fiscal year, which started April 1.

In 2009, the government of Mozambique allocated two coal blocks at the Moatize coal field in the Tete province, with total reserves of about 1 billion mt (of which 80% is thermal and 20% coking coal) to Coal India Africana Limitada. This is the first acquisition by CIL abroad on the basis of bilateral cooperation between the two governments. The mining of coal is likely at these two blocks before August 2014. The company expects to mine about 5 million mt/year from the two blocks.

CIL meets about 80% of the India’s coal requirement, but it has been falling short of targets due to factors like environment issues and land acquisition problems and other regulatory hurdles.

Coal India close to Mozambique decision


markEt nEws coal

Rather than a ban on the Environmental Protection Agency’s proposed carbon standard for new generation, industry needs guidance – particularly on liability matters related to carbon storage – and funding to speed Carbon Capture and Storage technology to commercial deployment, according to Robert Hilton, Alstom vice president for power technologies for government affairs. He made his comments after appearing before the US House Energy and Power Subcommittee in September.

“We need some guidance from EPA or Congress. We prefer from Congress,” he told reporters. “Congress can do something about the liability issue, I hope.” Congress could also help with financial incentives or other means to advance the technology, he said: “We need to obviously get funding to make this work – a mechanism to get funding.”

However, a bill before the subcommittee offered by West Virginia Republican Representative David McKinley, is not helpful in clearing a path for CCS development, Hilton said. The bill, which has nine cosponsors from both parties, requires that three of four designated federal officials report to Congress that CCS is “technologically and economically feasible” for fossil fuel-fired generation before EPA can finalize any rule imposing a carbon standard on a new or existing power plant.

Hilton said CCS is already “technologically feasible,” but he does not understand how “economically feasible” would be defined. “We need to understand under what circumstances would you go forward with CCS,” he said about the legislation.

The hearing came as the Republican-led House of Representatives prepared to consider a large package to “stop the war on coal” allegedly being waged by the Obama administration. The package, which included a ban on EPA regulation of greenhouse gases, passed 233-175 September 21, but is not seen as likely to progress any further.

Although no CCS technologies have been deployed for commercial scale demonstration, Alstom has done “validation scale demonstration” involving power plant fuel gas. “At this point we can say confidently that the basic technology works,” Hilton told the subcommittee. Full-scale operations for most of various CCS projects, if they continue, are unlikely before 2017, he said.

“Alstom believes that the technology will be commercial when the industry determines that both buyer and seller can enter in ordinary contractual relations that meet the needs of both parties – not when a regulation is announced,” Hilton said. “We know that carbon capture technology works. We need time and support to reach the point of commercial offerings.”

Other industry representatives testified in favor of the legislation, however, and said they feared electricity rates would jump up to 20% under various EPA regulations aimed at power plant pollution. “Given the obvious need for commercially available and cost-effective CCS in order to meet EPA’s proposed NSPS for coal plants, the bill … provide(s) much needed congressional direction …,” said Mark McCullough, American Electric Power’s executive vice president for generation.

CCS developer seeks guidance to advance technology

China’s National Development and Reform Commission has submitted a plan to reform the country’s coal pricing mechanism, according to state media reports. The plan advocates two to five-year coal supply contracts instead of the current annual contracts. The pricing of contract coal will be based on national benchmark prices.

Additionally, a new coal and electricity price linkage mechanism will be adopted, the report said. Under this, changes to electricity prices can be made for changes in thermal coal prices of up to 10%. If the price change exceeds 10%, the NDRC is entitled to impose counter measures in line with China’s Price Law. Formerly, the coal and electricity price linkage mechanism released in December 2004 specified that if thermal coal prices change by 5% or more, adjustments can be made to electricity prices.

Mao Xiaoling, an analyst with Beijing-based Dexin Yongming Consultation, said the reform scheme may prove unpopular with both coal miners and power generators. The former want to see a fully market-oriented coal pricing mechanism, while the latter prefer closer linkage between coal and electricity prices. Mao said that until electricity prices become market-oriented, China’s coal prices will not be fully market-oriented.

No output cutsIn a bid to boost coal mine safety, several provinces, including Jilin Province in northeastern China, Sichuan Province in southwestern China, and Shandong Province in eastern China, have recently issued notices to suspend coal production at smaller mines until end-October.

Chinese coal mines will undergo much stricter safety check-ups across the country prior to the CPC conference in October. The conference usually results in the suspension of production at small mines just in case of any safety mishaps, market sources noted.

However, big coal miners are not prepared to cut their output. At a seminar held by the State-owned Assets Supervision and Administration Commission in September, Zhou Dongzhou, board secretary of China National Coal Group, told local media that his company has no plans to cut output. Instead, China National Coal Group plans to raise coal output in 2012 by 5% year-on-year. The coal miner produced 85.90 million mt of coal in first-half 2012, up 1.29 million mt year-on-year.

Shenhua Group, another big coal miner in China, also plans to achieve a 4-5% year-on-year increase in coal output in 2012. In the first half, Shenhua Group mined 230 million mt of crude coal, up 29.68 million mt, or 15.2% year-on-year.

NDRC proposes new coal pricing mechanism


markEt nEws powEr

The nuclear industry was buffeted by a series of announcements of reactor shutdowns and potential phase-outs in September. It was announced that Spain’s Garona BWR would shut in July 2013, rather than in 2019 as had previously been expected. In Canada, the newly-elected government of Quebec said that state-owned Hydro-Quebec would not be allowed to invest in a life extension of the Gentilly-2 PHWR, which would have to close when its license expires at year-end. Then came the news that European utility Electrabel had found the same kind of flaws in the pressure vessel of Tihange-2 as were found in June and July in the vessel of Doel-3, made by the same manufacturer in 1974. The Belgian government issued a statement that the units would not restart by the end of this year.

Significant policy statements affecting nuclear were also made in two of the world’s three largest nuclear states. In Asia, a Japanese government policy panel proposed phasing out nuclear power altogether by the 2030s, but the cabinet declined to formally endorse the plan. In France, President Francois Hollande said he would follow through on a campaign pledge to shut the Fessenheim nuclear power plant at the end of 2016, more than four years before the end of its currently approved lifetime.

However, industry leaders have portrayed decisions after the Fukushima I accident last year to proceed with nuclear phase-outs in Germany, Switzerland and Belgium, and not start a nuclear program in Italy, as having relatively limited impact on nuclear’s role worldwide. At the annual symposium of the World Nuclear Association September 13-14, Areva Chairman/CEO Luc Oursel emphasized the positive, saying Hollande has “confirmed that nuclear power will remain an essential part” of French energy supply. Ricardo Perez, president and chief operating officer of Westinghouse, also took a positive outlook, saying that although “this is a difficult time for the nuclear industry,” there were still “65 nuclear power units under construction around the world.”

Luis Echavarri, director general of the OECD Nuclear Energy Agency, said it was a mistake to lump all the news together because each case was unique. At the International Atomic Energy Agency general conference in Vienna, Echavarri said the Japanese decision was to shut reactors by the “end of the 2030s,” which he said would more likely not occur before 2042. What happens in 20 years “is not a concern,” Echavarri said. “The main concern is what happens in the next five to 10 years.” The need for affordable power may well lead a future Japanese government to revise the phase-out decision, “based on concerns at that time,” he said. He judged as positive the decision to allow most licensed reactors in Japan to continue operation.

The French decision to close Fessenheim, Echavarri said, “looks like what they did with Superphenix many years ago,” a reference to a previous Socialist government’s decision in 1998 to decommission the 1,200 MW fast breeder reactor at Creys-Malville in

fulfilment of a political commitment to the Greens in its coalition. “I am not concerned about decisions that affect a certain individual plant based on a specific situation,” Echavarri said. “Hollande’s message is positive: France is going to continue relying on nuclear power for many decades,” Echavarri said, and even if nuclear’s share of French electricity supply declines to 50%, “that is still a very large nuclear program.”

Nevertheless, the IAEA’s 2012 projections of future nuclear generating capacity have dropped again, with a low scenario seeing 456 GW of nuclear capacity in 2030 compared with 546 GW in projections just two years ago. Holger Rogner, head of the IAEA’s Planning and Economic Studies Section, said that the financial crisis of 2007-2008 and the Fukushima accident in 2011 had contributed equally to a “lateral shift” outward in time in the agency’s annual projections of future nuclear capacity.

As of September 17, there were 435 power reactors in operation worldwide, totaling 370 GW net, Rogner said. That figure dropped during 2011, in particular because of the forced shutdown of eight nuclear power units in Germany. There are 64 units under construction, totaling 62 GW, Rogner said.

The post-Fukushima period stopped an “almost exponential” rise in the number of new reactor construction starts projected in previous years. There have been two construction starts so far in 2012, compared with 16 in 2010, he said. Rogner said that optimism about a nuclear renaissance had dominated projections of future capacity until 2010. Since then, there has been a “lateral shift” in projections for installed nuclear capacity in 2020, with the 2020 figures pushed out “about one decade” to 2030 since Fukushima, he said.

According to the IAEA , under a “low” nuclear scenario – corresponding to a conservative view of what might happen – nuclear power would provide only 10.4% of global electricity in 2030, down from a “low” projection in 2010 of 13.8%. Nuclear power provided about 12.3% of world electricity in 2011, Rogner said. In the IAEA’s high nuclear scenario, which assumes a set of more favorable circumstances, including international agreement on financial penalties for carbon emissions, installed nuclear capacity would grow to 740 GW by 2030 – a decrease from 803 GW projected for that year in 2010.

Nuclear’s share in total electricity would still increase by 2030, to 13.6%, under the high scenario, but that is well below the 16.6% share in 2030 that the 2010 scenario foresaw, he said. Nuclear power will experience “relative growth” by the 2030 mark, Rogner said, “but much less than what we expected in 2010.” The non-OECD Asia region is projected to have the highest growth under both low and the high scenarios. Rogner said the low scenario sees “Europe on its way out,” – meaning western Europe – and Russia and the former Soviet Union growing “a little.” China dominates the non-OECD Asia region’s plans and accounts for about 50% of the global increase, he said.

Nuclear industry hit by multiple shutdowns


markEt nEws powEr

Central plant development in West Europe remains in the doldrums, with talk of investment largely confined to speculation as to when additions might be needed. The answer for central west Europe is 2020/2022, according to German utilities E.ON and RWE. The UK is exempt from this ‘lost decade’ outlook because of looming coal and nuclear plant closures, but economic and regulatory uncertainties are restricting construction starts in the UK as much as anywhere else.

With German peak demand last year logged at 54.5 GW versus 77 GW of conventional power station capacity connected to the HV grid, Germany has a large surplus of central plant, despite last year’s nuclear closures. It is this near 30% capacity margin, plus renewables, plus import/export capacity, that in great part helped northwest Europe ride out last February’s freeze and have made discussions of a German capacity market or strategic reserve somewhat academic.

While central plant development is effectively frozen, a number of sizeable new power stations are nearing completion or have recently entered operation. These were planned and financed in more optimistic times, and face a tough initiation before capacity margins tighten, wholesale prices rise and capacity markets provide some support. As a result, impairment losses are being attributed to these out-of-the-money gas plants across west Europe.

Austria’s Verbund is just one utility to have been caught out, with gas-fired assets at home and in France weighing heavily on its balance sheet. In July, it took a €52 million ($67.5 million) impairment on its just-opened Mellach CCGT, following a €110 million write-down on the project in October 2011. These losses were related to the power station’s 15-year, 750 million cu m/yr oil-indexed gas supply contract and low wholesale prices, it said in June.

In France, Verbund’s equity interests in two CCGT plants, Poweo Pont-sur-Sambre Production SAS and Poweo Toul Production SAS, were reduced to zero in 2011 by losses or impairment charges. Furthermore, Pont-sur-Sambre CCGT was placed under a safeguard procedure in March 2012 in relation to its gas supply agreement with ENI. Verbund has been allowed to cancel its Pont-sur-Sambre gas contract and access cheaper spot gas, significantly improving the profitability of the plant. Meanwhile, it presses on with construction at Toul (413 MW), which is scheduled to be put into operation end-2012.

In Italy, Sorgenia (CIR, Verbund) 800 MW Aprilia CCGT went into operation in the second quarter. With total thermal capacity of 4,500 MW, Sorgenia’s goals are complete. Unfortunately, the near-term effect of this build-out has been a steep decline into loss for first-half 2012, owing to vanishing spark spreads. Italy has had its own renewables boom focused on solar PV, which has chased CCGTs out of the midday peak market.

Another utility with swathes of gas plant entering a moribund market is Nuon (Vattenfall) in the Netherlands. Its new Hemweg 9 power plant in Amsterdam was

connected to the Dutch grid in May 2012. Diemen 34, a combined heat and power plant, was expected on line in September. And its 1.3 GW Magnum CCGT in Eemshaven is to start supplying electricity in late 2012. All this at a time of record imports of cheap hydro and lignite power into the Netherlands because of the rising cost of national gas-fired power. From March to June this year, power production from gas fell to its lowest level since 2001.

The UK could be the first market to revive for gas plant, given scheduled closures of opted-out coal plant and ageing nuclear units. There is the prospect of a gas strategy from the government, as well as a new capacity market, seen as vital by independent generators if their projects are to have any hope of competing with those planned by the Big Six utilities.

The government is due to consult on the detailed design of a capacity market in 2013, having decided to implement a market-wide mechanism based on ensuring a required volume of capacity. The market is to involve estimates of the total volume of reliable capacity required a number of years ahead; contracting for the required volume from providers through a central auction process; and placing incentives on providers of capacity to ensure they are available when needed. Ministers are to decide when to run the first auction process based on future estimates of security of supply from the System Operator National Grid and possibly other technical experts, including regulator OFGEM.

One developer in favor of the proposed mechanism is InterGen. It already owns and operates 2.5 GW of gas-fired plant in the UK and has consent for a further 1.8 GW of carbon capture ready gas capacity that it wants to have online around 2015. However, without a capacity mechanism, “InterGen’s existing gas assets will struggle to be economic and our new UK plants will in all likelihood be unable to obtain finance to support their construction,” the company said.

Meanwhile, renewables continue to thrive. Green generation met 25% of gross electricity consumption in Germany in first-half 2012. Combined renewables output increased by 20% or 11.5 TWh to 67.9 TWh versus first-half 2011. Renewable energy output growth more than compensated for the 10.73 TWh or 18% drop in German nuclear output to 47.73 TWh for the period.

In the UK, completion of the 500 MW Greater Gabbard offshore wind farm in September has cemented the UK’s lead in this market. The three largest offshore wind farms in the world – Greater Gabbard, Walney and Thanet – are all in UK waters, soon to be overtaken by London Array (630 MW) and Gwynt y Mor (576 MW). Meanwhile, all 88 turbines at the 317 MW Sheringham Shoal wind farm in the Greater Wash are now installed, most delivering power. Total UK wind capacity is nearing 7 GW, with nearly 2 GW of this offshore.

European gas-fired electricity plant in doldrums


markEt nEws powEr

The Japanese Cabinet September 19 refused to formally endorse a nuclear phase-out policy adopted by a government panel five days earlier, in a twist that one senior Japanese industry official said was the result of pressure from both within and outside Japan. The “Innovative Energy/Environment Strategy” issued by the government’s Energy and Environment Council, September 14, would allow the restart of existing reactors and completion of those already licensed, but no new construction starts.

Japan would phase out nuclear power generation by the end of the 2030s, although the document gave neither a precise timetable nor other details of the shutdown plan. The EEC schedule left nuclear power as “an important power source” for Japan for the next two and half decades, with no numerical targets for nuclear capacity in any year until the end of the phase-out. The EEC advocates a policy of gradually replacing nuclear power with renewables.

However, instead of adopting the policy and its phase-out target, cabinet ministers are treating it as a “reference document,” Osamu Fujimura, chief Cabinet secretary, told a televised press conference September 19. The ministers also decided that the strategy would be “constantly reviewed and revised,” Fujimura said. Shunsuke Kondo, chairman of the Japan Atomic Energy Commission, said on the sidelines of the International Atomic Energy Agency general conference in Vienna that the Cabinet had said its energy policy would be “based on” the EEC document, but without a target date for phase-out and with more flexibility.

The EEC’s policy proposal has come under fire from nuclear power operators, business organization leaders and representatives of local governments around nuclear power plant sites. A senior Japanese nuclear official said privately that the government had received strong protests from abroad, notably the US, Japan’s most important partner in nuclear energy. The reactor technology used in Japan originally came from the US, and now the Japanese and US nuclear industries are interwoven through partnerships or ownership arrangements.

The Cabinet decision leaves Japan’s future nuclear policy unclear. In a statement on its website, the EEC said the government will order the Nuclear Regulation Authority, the country’s new regulatory organization that began life September 19, to “strictly” apply a new law that limits reactor operation to 40 calendar years, with a single 20-year renewal possible. No new nuclear power plant construction will be authorized, the EEC said.

The EEC policy preserves spent fuel reprocessing and the potential for using the fast reactor, Monju, to burn plutonium and minor actinides. It also leaves a definitive decision on nuclear power to future governments. Prime Minister Yoshihiko Noda said during the televised EEC meeting that “It would be irresponsible to determine a definitive policy [now] for the unforeseeable future.”

The EEC did consider other scenarios, in which nuclear power would have been phased out much earlier. Under the relatively vague formulation of its policy, if all reactors were allowed 40-year lifetimes, the final reactor closure would not happen until after 2040, according to Hideaki Matsui of the Japan Research Institute.

All 50 of Japan’s LWRs were shut in the wake of the March 11, 2011 severe accident at Tokyo Electric Power Co.’s Fukushima I station, which prompted the policy review. Only two units have been allowed to restart. The EEC policy was determined by Noda, Minister of Economy, Trade and Industry Yukio Edano, Nuclear Power Minister Goshi Hosono and National Policy Minister Motohisa Furukawa, who oversees the EEC.

Noda’s role in carrying out the policy may depend on upcoming elections. Noda promised the Liberal Democrats and other opposition parties before the Diet adjourned September 8 that he will “soon” call a lower house general election, probably in the fall. Should the pro-nuclear Liberal Democratic Party win a majority or a plurality of the vote, then LDP could scrap the whole EEC policy. The Japanese nuclear official said the proximity of elections may also explain why the Cabinet declined to set a detailed nuclear policy.

Under the proposed EEC policy, spent fuel reprocessing would continue for an unspecified period. The national government plans to set up a fuel cycle forum, or official panel, including representatives of Aomori prefecture and prefectures that consume power, the EEC said, without further details. The panel will discuss direct disposal of spent fuel, interim spent fuel storage and a final underground repository for waste, the EEC said. Aomori is the location of the commercial fuel cycle facilities of Japan Nuclear Fuel Ltd., and Fukui is home to the Monju prototype fast breeder at Tsuruga City.

Restart of existing reactors will be permitted. Only two of Japan’s 50 LWR units – Ohi-3 and 4 – are currently in operation. The remaining units have been shut for periodic inspections and have not been able to restart pending local and national government approval, which has required new safety checks since Fukushima.

Construction could proceed on three units under construction at the time of the Fukushima accident, according to Edano, who said the ministry of energy, transport and industry regards the construction licenses as still valid. The Electric Power Development Co.’s 1,383 MW BWR at Ohma in Aomori was 37.6% complete as of March 11, 2011. Chugoku EPC had completed 93.6% of its 1,373 MW Shimane-3 BWR by the end of April 2011, when it also suspended construction. Neither EPDC nor Chugoku EPC has announced whether or when it expects to complete the units. Tepco’s 1,385 MW Higashidori-1 BWR was 9.7% complete in March 2011, reflecting site civil engineering and construction of a port. Tepco has frozen the project.

Japanese cabinet fails to endorse nuclear phase out


markEt nEws powEr

Two paper mills and a consultant accused of manipulating demand response markets in the US state of New England have provided their arguments for why they did not violate any rules or regulations. Among other things, Rumford Paper said it was not being paid for phantom energy consumption reductions but that it was providing demand response just as it had before the New England program began

Enforcement staff at the Federal Energy Regulatory Commission in July accused Maine-based Lincoln Paper and Tissue and Rumford of manipulating ISO New England’s day-ahead load response program, or DALRP, in 2007 and 2008, by inflating their energy consumption when their load baselines were being measured and then repeatedly offering consumption reductions without any plan to actually decrease load as offered. Staff said that those alleged actions led to the companies being paid for “phantom load reductions.”

Essentially staff said that the paper mills turned down their on-site generation and used more power from the grid during the time that their baseline was established, but later resumed using the generation and decreased their consumption from the grid, which made it appear that they were providing demand response. The commission also accused Competitive Energy Services and CES employee Richard Silkman of coming up with the scheme and recommending it to Rumford.

It ordered the consultant, employee and paper mills to respond to the accusations and state why they should not be assigned a combined total of more than $26 million in civil penalties and be made to disgorge any resulting profits.

In its September 14 response, Rumford said enforcement staff failed to recognize that Rumford “did not change its behavior when it began participating” in ISO-NE’s program because Rumford was “already providing the type of demand response that the DALRP was designed to compensate.” The DALRP “was designed in such a way that existing and ongoing demand response

behavior qualified to receive the new DALRP subsidy,” Rumford said. ISO-NE and FERC could have “limited the subsidy payments to new and incremental demand response, but they structured (and approved) the program in a way that intentionally did not do so.”

“All that Rumford did was receive an ‘additional financial benefit’ for its ongoing demand response,” the paper mill said. “Thus, Rumford should not be found to have violated the commission’s anti-manipulation rule.” Staff should have differentiated “doing nothing” from “doing what you would have done otherwise,” which typically is referred to as “free riding,” economist and consultant Roy Shanker said in testimony attached to Rumford’s response.

Free riding “occurs in virtually every program where out-of-market incentives or subsidies are created for market participants to induce some desired form of behavior,” Shanker said. “The responsibility to address free riding lies with the program designer, and if appropriate, the party that approves the design,” he said. “It does not reside with the party responding to the available incentives.” Moreover, ISO-NE did a “very poor job” of addressing the free-rider problem in its DALRP, he said.

Lincoln said enforcement staff “finds an intent to manipulate the markets where there was no more than uncertainty and confusion and where Lincoln had to attempt to logically interpret a new day-ahead load response mechanism with minimal guidance, particularly for behind-the-meter generation.” “Without intent, there is no case against Lincoln,” th e company said. Moreover, “if the commission wants to adopt a policy where behind-the-meter generation is not treated as demand response, it should formally do so, not after the fact as part of this enforcement proceeding,” Lincoln said.

CES and Silkman, filing their answers jointly, said they “did not violate any rules relating to the day-ahead program, and they certainly did not engage in any scheme to manipulate the electricity market.”

Paper mills defend demand response manipulation charges

UK wind power generation set a series of record highs in September, hitting 4.131 GW at 0856 GMT September 14, contributing 11% to the UK generation mix, according to the country’s transmission system operator National Grid. Wind power output pushed briefly above 4 GW at around 2200 GMT September 13 for the first time, after reaching an average of 3.98 GW over the half hour between 2030 and 2100 GMT, breaking the record of 3.8 GW set May 13.

“Accurate long range forecasts made it possible to know a week ahead when high levels of wind output were expected. This gave a lot of opportunity for preparations to be made to remove as many restrictions to green energy as possible within the limits of running a secure GB transmission system,” a National Grid spokesman said.

Wind power lobby group RenewableUK said that the record was proof wind energy was providing an

increasing supply of clean electricity to the UK. RenewableUK chief executive Maria McCaffery added: “As our wind energy capacity increases, the need to import expensive fossil fuels starts to diminish. The transition to a low-carbon economy is well underway and harnessing this bountiful, free resource will help us to drive down energy bills for all users in the long term.”

Earlier in the week, wind generation touched highs of 3.36 GW, according to real-time data just before 1430 GMT September 11, causing gas-fired power to slump to 6.9 GW – its lowest mid-afternoon weekday level on record, according to Platts Powervision. Reduced dependence on gas-fired power over peak demand hours weighed on the price of day-ahead baseload power at market close September 13. On the OTC market, day-ahead baseload fell 4% day-on-day from £43.80/MWh ($71.04/MWh) to £42.20/MWh.

UK wind sets new record


Platts Co2 assessment monthly averages, September 1-25, 2012 (Eur/mt)

Delivery High - Low Midpoint

Dec-12 7.812 - 7.772 7.792Dec-13 8.199 - 8.159 8.179Dec-14 8.731 - 8.691 8.711

All prices are in euros per metric tonne of carbon dioxide equivalent as traded under the EU Emissions Trading Scheme.

Source: Platts European Power Daily

CO2 price trend (€/mt)


6

8

10

12

14

Sep-12Jul-12May-12Mar-12Jan-12Nov-11Sep-11

20122013

data co2 markEt

EU carbon dioxide allowances declined in September, in line with German Cal 2013 power prices, on jitters over the extent of possible opposition to the European Commission’s proposals to delay future carbon auction volumes. This followed December 2012 EU Allowances hitting a six-month peak of €8.37/mt ($10.83/mt) September 7, according to Platts assessments, taking support from bullish sentiment in the wider financial markets after the European Central Bank announced new economic stimulus measures for the euro area.

Any moves that could help avoid further economic turmoil in Europe tend to support carbon prices along with other commodities, as a strengthening economy would likely see increased industrial activity in the EU ETS-regulated sectors, driving up CO2 emissions and demand for allowances. However, prices fell back sharply from those early-month highs, slipping to €7.27/mt by September 24 amid signs that a number of EU member states may try to block the European Commission’s proposals to delay auction volumes of between 400 million and 1.2 billion EUAs in 2013-15.

The Commission has yet to specify the exact volume of EUAs to be delayed temporarily from the auctions, but several EU member states have already signaled opposition to such proposed market intervention. Officials from Poland, the Czech Republic and the Netherlands have already voiced opposition to the proposals, and the market is watching to see if enough no-votes can be gathered to form a blocking minority in the Council of Ministers, which must approve the Commission’s proposal.

In the EU’s weighted vote ballot system, a blocking minority would require 91 votes. Poland, the Czech Republic and Netherlands hold a combined 52 votes, leaving 39 more needed. Some market observers suggest other member states could also be sympathetic to the opposition cause, raising the prospect that the regulator’s efforts to bolster the carbon price could yet be derailed.

Registry upgradeThe Commission is to partially suspend the single EU emissions registry September 27, and fully suspend it the following day until October 2 to allow a software upgrade. The so-called Union Registry is the central database that tracks ownership of carbon allowances and emissions offset credits traded under the EU ETS.

The suspension of the registry will allow new software to be rolled out, allowing new functionalities that will enable auctions of regular allowances and aviation allowances in the 2013-20 period, a new trading account type and a “trusted account” list. “The trusted account list adds to the set of security measures available in the single registry. This measure prevents any transfer from a holding account to an account that is not trusted,” the Commission said in a statement in September.

EU carbon price dips on signs of intervention opposition

Co2 Market

“Registry users will continue to have access to their registry accounts but it will not be possible to propose transfers or modify personal details,” the Commission said, while the upgrade is ongoing, ahead of full suspension of the registry at 18:00 CEST September 28 until 08:00 CEST October 2, when operations will resume.

Among other benefits, the switch from individual national registries to the single Union Registry is intended to boost security around Europe’s carbon trading system, which became the victim of hacking attacks on several national registries and saw the theft of allowances in late 2010 and early 2011, forcing the Commission to temporarily suspend all 30 national registries. The new trading system under the single registry includes a 26-hour delay to allow checks to be carried out on most transactions in order to prevent unauthorized activity.

Only transfers made between a trading account and one of its trusted accounts will be exempt from the 26-hour delay, according to the Commission. The upcoming suspension of the single registry takes place over a weekend and only affects two business days – September 28 and October 1. The suspension would not be expected to significantly affect trading in the EU ETS, since the bulk of transactions are made on the forward or futures markets, where the bulk of contracts tend to go to delivery in December each year.


oil forecasts (million b/d)

Change in Change Total Change Call on non-OPEC in OPEC World Oil in OPEC supply NGLs Demand demand

September 2012 estimates for 2012

EIA 30.88 0.51 0.34 89.09 0.83IEA 30.30 0.40 0.40 89.80 0.90OPEC 29.90 0.70 0.40 88.70 0.80

September 2012 forecasts for 2013

EIA 30.97 1.24 0.19 90.10 1.01IEA 30.20 0.70 0.30 90.60 0.80OPEC 29.50 1.00 0.20 89.60 0.90

Sources: EIA, IAE, OPEC

0

500

1000

1500

2000

2500

3000

3500

4000

Aug-12Aug-10Aug-08Aug-06Aug-04Aug-02Aug-00Aug-98

International rig count (monthly average)

Source: Baker Hughes

Oil Gas

data markEt indicators

Physical crude marker Dated Brent dropped abruptly in September, taking its lead from futures markets. Having started the month at $115.33/barrel, Dated Brent moved up to $117.14/b September 14, but then lost $8.73/b over the next three days. It rebounded to $111.18/b September 21, but then fell sharply again to $108.87/b September 24.

In particular, futures markets saw a late day sell-off September 17, in which October crude on NYMEX lost $3.02/b in the space of a minute, while traded volume jumped to 12,604 lots from 2,314 lots. This prompted speculation that a ‘flash crash’ had occurred; a sudden sharp change in price driven by high frequency computerized trading rather than any real change in market conditions.

More broadly, concern over the impact of US and EU sanctions on Iranian crude supply gradually gave ground to renewed fears over the economic health of the euro area. While the announcement of bond buy-back schemes on both sides of the Atlantic buoyed economic hopes in the earlier part of the month, this optimism gradually evaporated and took a clear dive with the announcement September 24 that Germany’s business climate index had

Crude drops abruptly

Market Indicators

dropped to 101.4 points in September from 102.3 points in August, prompting concern that the euro area’s largest economy could be heading towards recession.

On the supply side, OPEC crude output rose by 90,000 b/d to 31.54 million b/d in August as increases from Angola, Iraq, Nigeria and the UAE outstripped decreases from Algeria and Iran, a Platts survey showed. Iranian output fell by 150,000 b/d to 2.75 million b/d as US and European sanctions continued to bite. Algerian volumes were estimated to have fallen by 10,000 b/d to 1.21 million b/d.

Angola accounted for 100,000 b/d of the 230,000 b/d rise, boosting output to 1.75 million b/d from 1.65 million b/d in July. Other smaller increases came from Nigeria, the UAE and Iraq, the latter as a result of expanded export capacity in the south of the country.

However, the International Energy Agency said global oil supply fell in August by 100,000 b/d overall as increases in OPEC output were undermined by unplanned non-OPEC outages. The IEA reduced marginally its forecasts for demand in 2012 and 2013, although the outright numbers were higher as a result of further baseline revisions to demand in 2011.

Dated Brent ($/b)

Source: Platts Global Alert

1-year average: 2-year average: 5-year average: 10-year average:

111.44 108.1591.02 69.61

80

90

100

110

120

130


NYMEX 3-2-1 Crackspread* ($/b)


1-year average:2-year average: 3-year average:

26.9924.4719.28

10

15

20

25

30

35

40


* A hypothectical re�ning margin used for trading purposes based on three barrels of crude making two barrels of gasoline and one barrel of distillate.



Platts forward curve for Dated Brent ($/b)

Source: Platts Forward Curve – Oil

September 24, 2012

95

100

105

110

Cal-15Cal-13Q4-13Q2-13Q4-12Feb-13Dec-12Oct-12

Market structure: Dtd Brent vs 1st Mo ($/b)


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3


Natural Gas month-ahead ($/MMBtu)

Source: Platts Gas Daily, European Gas Daily

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Zeebrugge Henry HubUK NBP

Coal ($/mt)

Based on energy values of CIF ARA 6,000 Kcal/kg, FOB Qinhuangdao 6,200 Kcal/kg, Nymex lookalike 6,668 Kcal/kg

Source: Platts Coal Trader, Coal Trader International

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ARA 90-day Qinhuangdao90-day

NYMEX lookalike1st month

Oil product comparisons: September 21, 2012 ($/b)


US

EUROPE

AS I A

FOB Rotterdam Barges Premium Gasoline 10 ppm 131.11Gasoil 0.1% 130.43Jet 134.40Fuel Oil 3.5% 99.88

CIF NY Unleaded 93 0.3% Barge 143.49No.2 Barge 131.81Jet Barge 134.86No.6 3.0% NY Spot cargo 99.88

FOB SingaporeGasoline 92 unleaded 120.65Gasoil Reg 0.5% sulfur 127.69Kerosene 129.10HSFO 180 CST 103.00

FOB Gulf Coast Unleaded 93 (waterborne) 144.65No.2 (waterborne) 130.87Jet 54 (waterborne) 133.14No.6 3.5% 101.25

WTI Cushing Front month: 92.69 Brent front month: 111.36 Dubai front month: 108.25



NWE next month generating cost comparisons, profit/loss ($/MWh)


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Coal Gas

NWE next quarter generating cost comparisons, profit/loss ($/MWh)


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Coal Gas

Cincinnati next month generating cost comparisons, profit/loss ($/MWh)

Source: Platts

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CoalGas

Atlanta next month generating cost comparisons, profit/loss ($/MWh)

Source: Platts

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30


CoalGas

UN I TED STATES

EUROPE

AS I A

NW Europe fuel oil 16.82NBP gas 9.68ARA coal 3.73

NY Harbor 1% S fuel oil 16.64Henry Hub gas 2.78NYMEX coal 2.45

Singapore fuel oil 17.89Japan JCC LNG 18.10Qinhuangdao coal 4.60

Japan JCC value shows latest available CIF price published by the Ministry of Finance, converted to US dollars per MMBtu. All other values re�ect Platts most recent one-month forward assessments for each product in each region, converted to US dollars per MMBtu.

Comparative power feedstocks: September 21, 2012 ($/MMBtu)

Source: Platts LNG Daily

NWE Note: Based on typical kg CO2/mmBtu rates of 101.5 for coal, 55 for natural gas; and on generating efficiencies of 49% for UK gas plant, 54% for western Europe gas plant, 34% for all coal plant. Benchmark coal priced at ARA. Details of methodology at www.platts.com. US Note: Based on typical heat rates of 9,800 Btu/kWh for coal generation and 7,800 Btu/kWh for natural gas generation; no NOx controls on coal stations resulting in 0.6 lb/mmBtu NOx; benchmark coals meeting specifications for NYMEX look-alike and CSX-Big Sandy/Kanawha Central Appalachian coals, barged to Cincinnati and railed to Atlanta, respectively. For details, see methodology at platts.com.



Gas price differential narrowsPlatts November LNG Japan Korea Marker was assessed at $13.10/MMBtu September 24, up slightly from $12.95/MMBtu at the start of the month, but down from a mid-September peak of $13.325/MMBtu September 17. Spot demand especially for early November deliveries – the start of North Asian utilities’ preparations for the peak winter demand season – remained low owing to high inventories and earlier term contracts providing sufficient replacement volumes. The lack of demand meant some unsold October cargoes could roll over to first-half November, putting a dampener on spot prices.

Winter is one of the two peak buying periods in North Asia, owing to rising winter heat requirements, especially for city gas utilities. However, most market players are predicting limited demand for this winter, a Tokyo-based trader said, although the weather can always surprise.

In Europe, day-ahead prices at the UK’s National Balancing Point rose to 62.30 p/th September 14, their highest level since the cold snap in February, despite record low levels of demand. However, September 17 saw prices on both the prompt and curve fall steadily on the back of optimism about higher flows ahead of the end of the Norwegian maintenance season, as well as falling oil prices.

Day-ahead gas contracts on the Dutch TTF trading hub hit a seven-month high of €26.15/MWh September 14 as market participants remained concerned over tight gas supply, but then fell for three consecutive days. The contract was valued at €25.55/MWh at the close September 19.

Low gas demand kept the price gains in check and the sharp movements on the prompt were not echoed on the curve. Fourth-quarter gas was pegged at €26.15/MWh September 19 after reaching a high of €26.75/MWh September 13. Further out, the winter 12 and calendar 13 gas contracts were pegged at €26.75/MWh and €26.70/MWh respectively at the close September 19, both falling below the €27.00/MWh price level for the first time since early August.

In the US, the NYMEX October gas contract settled 3.5 cents higher on the day at $2.797/MMBtu September 20 on supportive weather forecasts. Some sources added the consecutive losses on prior days had also opened up some buying opportunities and supported a slight rally.

The EIA reported US natural gas in storage rose 67 Bcf to 3.496 Tcf for the week that ended September 14. The net injection was within consensus expectations of a build between 64 Bcf and 68 Bcf. As a result, the 342 Bcf surplus to the year-earlier level fell to 320 Bcf, while the 284 Bcf surplus to the five-year average of 3.218 Tcf fell to 278 Bcf.

New England markets proved to be quite volatile, jumping more than $1 September 17 and then crumbling 60 cents the next day. Unseasonable weather and ongoing maintenance at the Cromwell compressor station in Connecticut – a major emerging constraint point on the Algonquin Gas Transmission system – prompted the intraday volatility.

Comparative power feedstock prices: US

($/MMBtu)

Values re�ect Platts most recent one-month forward assessments for each product in each region, converted to $/MMBtu.


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8

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16

20


Gulf Coast 3% S fuel oilHenry Hub natural gasNYMEX coal

Comparative power feedstock prices: Asia

($/MMBtu)

Japan JCC value shows latest available CIF price published by the Ministry of Finance, converted to $/MMBtu. All other values re�ect Platts most recent one-month forward assessments for each product in each region, converted to $/MMBtu.


4

8

12

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24


Singapore fuel oilJapan JCC LNGQinhuangdao coal

Values re�ect Platts most recent one-month forward assessments for each product in each region, converted to $/MMBtu.


Comparative power feedstock prices: NWE

($/MMBtu)

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NWE fuel oil NBP gas ARA coal

Coal price rise fadesEuropean-delivered CIF ARA thermal coal physical spot prices have settled back into their pre-Fenoco strike sub-$90/mt range amid little signs of utilities needing to restock to any great degree ahead of the winter season. Stocks at ARA discharge terminals remain comfortable despite a high rate of burn as coal remains a baseload fuel across most of Europe.


UK baseload month ahead (£/MWh)

Source: Platts European Power Alert

40

45

50

55


European baseload month ahead (€/MWh)


35

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45

50

55

60

65


Dutch SpanishGerman

Nord Pool system day ahead (€/MWh)


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US day ahead ($/MWh)

Source: Platts

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60

90

120

150


PJM WestInto Cinergy


Source: Platts

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Palo Verde Mid-C


Source: Platts

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300


ERCOT (Houston)

With CIF ARA spot prices trending down, market sources have warned of further possible downside, owing to Atlantic basin oversupply, with low-cost US producers still exporting material from East Coast ports, some spot Russian cargoes still available and Colombian supply lines almost back to full throttle.

In the financial coal derivatives market, the weak physical market has steepened the forward curve’s existing contango, with some utility hedging and locking in of strong dark spreads largely shielding back-end prices from similar falls. Fluctuations in the euro-dollar exchange rate continue to affect API2 prices. According to Platts data, the API2 (CIF ARA) prompt month-year-ahead spread has widened to over $9/mt, its highest since mid-June.

Richards Bay FOB spot prices have been volatile, falling to $83/mt in September and briefly opening the arbitrage to Europe, with some Capesize cargoes placed into ARA in early September. Since then prices have rebounded back above $85/mt, with speculation that Indian spot inquiries are growing as the country’s monsoon season ends.

Asia-Pacific spot coal demand is minimal, with buyers still holding back for offers to fall. Prompt prices of Newcastle higher-ash 5,500 kcal/kg NAR coal have stabilized at just above $73.50/mt FOB. Weakening prices of standard 6,000 kcal/kg NAR Newcastle coal have put pressure on the Asia-Pacific market, with physical spot cargoes heard traded at around $4/mt discounts to financial derivative prices recently.


BIOMASS POWER GENERATION CONFERENCE 2012

Inaugural

Financing the future of the fourth energy source

Visit www.platts.com/biomassconference for details of the event programme, speakers and more!

Hilton Paddington Hotel, London • 1st & 2nd October 2012

Platts Inaugural Biomass Power Generation conference will bring together those members of the Biopower community responsible for furthering the role of Biomass as the source of renewable power generation. The conference will assemble stakeholders from each stage of the value chain including fuel suppliers, major utilities, independent developers, regulators and leading associations to discuss how to achieve sustainability, scalability and financial security for the fourth energy source in Europe.

Key speakers include:

Supporting Organisations:

Dr Christian Rakos President, European Pellet Council

Dr Raphael Slade Re-search Fellow, Imperial College Centre for Energy Policy & Technology

Dr Hans Dieter Hermes Director of Business Development Biomass, Vattenfall

Sonia Medina Partner and COO, Africa Renewables

Marie Donnelly Director, DG Energy, European Commission

Thomas Dalsgaard Executive Vice President, DONG Energy Thermal Power

TM

To find out more information on the opportunities available, please contact: Joseph Ravenscroft: Tel: + 44 (0) 7825 230208 E: joseph_ravenscroft @platts.com

PLTSNEW

EXCLUSIVE SUBSCRIBER DISCOUNT AVAILABLE!!

Contact [email protected] for info

Sponsored by:

mailto:[email protected]

mailto:[email protected]

http://www.platts.com/biomassconference

The 2012’s ERRA Energy Investment & Regulation Conference strives to address the following broad issues:

SESSION I: ENERGY MARKET IN TURKEY: DEVELOPMENT, INVESTMENTS AND PERSPECTIVES

This session strives to provide a comprehensive introduction to the Turkish energy including presentationsby representatives of the Turkish government, national energy regulator, national privatization agency,international investors and financial institutions as well as significant international energy companieshaving investments in Turkey.

SESSION II: INFRASTRUCTURE DEVELOPMENT TO SUPPORT CROSS-BORDER TRADE

This session is to investigate the issue and the potential solutions from the perspective of Europe and the U.S.as well as from the perspective of a TSO. In addition, the session is to discuss how the regulator couldimprove/mitigate the investment risk of the infrastructure development.

SESSION III: REGULATORY TOOLS FOR SUSTAINABLEDEVELOPMENT OF THE ENERGY INDUSTRY

This session is to address the pros and cons of the electricityproduced from renewables as well as consequences of notharmonized renewable support schemes. The session is toreport on some practical results of energy efficiency programsand their regulatory implications as well as the influence ofthe shale oil and non-traditional fossil fuels on the economicsof renewables.

SESSION IV: REGIONAL MARKET CREATION

This session is to present the Central Eastern European case studyon day ahead market integration and the trilateral market coupling.The same session is to address the import of Azerbaijan gas toEurope: the Shah Deniz project, the regional market wholesaletendencies in the ERRA countries as well as the possibilities forcooperation between gas TSOs in system balancing.

WORKING LANGUAGES of the Conference:English, Turkish and Russian

Quick & Easy Ways to Register!

WEB: http://www.erranet.org/InvestmentConferences/2012 PHONE: +36 1 477 0456EMAIL: [email protected]

1 The Energy Regulators Regional Association (ERRA) isa voluntary organization with headquarters in Budapest,Hungary comprising of independent energy regulatorybodies primarily from the CIS, Central European andEurasian region, with affiliates from Africa, Asia theMiddle East and the U.S.A. For more details, please referto our official website here: www.erranet.org

REGISTER by September 14 and save EURO 100

organized by the Energy Regulators Regional Association (ERRA)1

and hosted by the Energy Market Regulatory Authority (EMRA) of Turkey

• ACER• Arkansas Public Service

Commission/NARUC • BP Turkey• CEER (Ofgem)• Deloitte Turkey• EBRD• ENEL• Energy Market Regulatory Authority of

Turkey• Energy Regulatory Office of Poland • ENTSO-E• ERRA• Fortum Corporation • Garanti Bank Turkey • Hungarian Natural Gas Transmission

Company • Iberdrola • International Finance Corporation • JSC INTER RAO UES, Russia • KEMA Consulting GmbH• Maryland Public Service

Commission/NARUC• Pierce Atwood LLP• Regional Centre for Energy Policy

Research• Romanian Energy Regulatory Authority• RWE Turkey Holding A.S.• State Energy and Water Regulators

Commission of Bulgaria• USAID • Verbund

CONFIRMED SPEAKERS represent the following leading organizations

SUPPORTED BY:

SPONSORED BY:

MEDIA PARTNERS:

ORGANIZED BY:

I.zmir Elektrik

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