THE CHANGING FUNDAMENTALS OF GLOBAL GAS MARKETS: … · ADNAN VATANSEVER: Good morning. (00:00:11)...

THE CHANGING FUNDAMENTALS OF

GLOBAL GAS MARKETS:

EUROPE AS THE BATTLEGROUND

TUESDAY, OCTOBER 12, 2010

WASHINGTON, D.C.

WELCOME/MODERATOR:

Adnan Vatansever

Senior Associate, Energy and Climate Program

Carnegie Endowment

SPEAKER:

Tony Melling

PANELISTS:

Branko Terzic

Executive Director, Deloitte Center for Energy Solutions

Deloitte Services LP

Vello A. Kuuskraa

President

Advanced Resources

Chris Goncalves

Vice President, Energy and Environment Practice

CRA

Hidehiro Nakagami

Deputy General Manager, New York Office

Tokyo Gas

Mikhail Korchemkin

Founder and Managing Director

East European Gas Analysis

Transcript by Federal News Service

Washington, D.C.

Transcript Not Checked Against Delivery

ADNAN VATANSEVER: Good morning. (00:00:11)

My name is Adnan Vatansever. I am a senior associate here at Carnegie’s Energy and Climate Program, and

it’s a great pleasure for me to welcome you all to this event. We are hoping that this will be part of a series of events that will be exploring the key questions that are affecting energy consumption and energy production, and I would like to mention a few things about the energy and climate program here.

David Burwell, who is the director of the program and also sitting over there – he’s been leading the efforts

in developing a very comprehensive program that is aiming to tackle the question about carbon emission reductions. And in this comprehensive approach, the goal is to tackle both the demand side and the supply side of the energy balance.

Some of the projects that we have been working on are about reducing energy consumption and about

energy efficiency. But we also believe that there are opportunities for carbon reduction by focusing on the fuel mix of individual countries; in particular, the fossil fuel mix of individual countries, and probably also on a much more ambitious global scale. And when it comes to the mix of fossil fuels, I guess then it becomes a question about the future of natural gas, as it’s known to be the cleanest fuel.

So I think that it is a very timely event, partly because natural gas markets have become dramatically

uncertain in the past couple of years. This has been partly because of the unconventional gas revolution that has spread in the U.S. and raises questions about how it will spread elsewhere.

It is also partly because of the glut that has been created by the global recession; but it is also partly because

of the changing dynamics in how natural gas is being priced, particularly in Europe these days. And this particular question is the focus of the report that we are launching today, “The Natural Gas Pricing and Its Future”. If you haven’t received the report, we should have quite a few copies outside.

(00:02:28)

We are fortunate to have Tony Melling, the author of the report. He’s going to be sharing his insights, his

main conclusions about how the price dynamics has been developing, and he argues that Europe is the battleground, and it raises quite interesting questions about the future of gas pricing elsewhere as well, particularly in Asia.

I’d like to say a few words about Anthony Melling, and I’m sure you have all of the speakers bios, but I’ll be

very brief. He’s an established authority on gas contracts. He has three decades of international gas contracting and market analysis experience with particular emphasis on the U.K. and continental Europe.

Tony gained early experience in British Gas Exploration and Production. In the mid-’90s as the U.K.

oversupply began to revolutionize the U.K. gas industry, he drafted an influential analysis of the situation that helped shape management’s response. Subsequently, he studied and analyzed contracting practices across the continent. His models were widely employed in the company’s planning. On leaving BG in 2000, Tony focused on European gas contracting practices, and as a consultant was active in several areas, including energy marketing, energy purchasing for large industrial plants and power generation, and LNG.


(00:03:49)

Before giving him the floor, I’d like to do two things in particular. First, I’d like to briefly summarize the

structure of today’s two panels, and then I would like to provide a very quick overview; probably in less than five minutes – an overview of the global gas markets. I think it might be helpful for those that are less familiar with gas, but also because it will set the background for Tony’s presentation.

So, regarding the structure of the event: In the first panel, Tony will be speaking about 25, maybe 30,

minutes, and then we’ll have time for a Q&A session. After that, we have about 10 minutes’ break, and during the second panel we are having five very distinguished discussants. Each of them will take one major question related to the natural gas markets, and particularly related to Tony’s report as a response.

One of the questions will be on power generation. Branko Terzic will focus on that. The other question

will be on the future of unconventional gas. Vello Kuuskraa, a leading authority in unconventional gas in the U.S., will focus on that. We’ll have Mikhail Korchemkin, who will explore how exporters are adapting to the changing natural gas market dynamics. And we’ll also have the importer’s perspective from Tokyo Gas, from Hidehiro Nakagami, and after a Q&A session, Chris Goncalves will provide an overview, and he has one very challenging question to address, which is, are the regional gas markets converging in some way, or are they likely to converge in any time in the near future.

(00:05:33)

Having said this, just a very quick overview of the global gas markets. And I would like to go over three

particular themes. The first is consumption of gas versus other fossil fuels. The second is the growing role of internationally traded gas, and the third is how gas is priced worldwide.

It’s interesting to look at this chart which shows how oil, coal, and gas consumption grew over the past 40

years. For those that are probably less familiar with gas, it’s interesting to see that even though it’s known to be the cleanest fuel, it actually trails behind oil and coal in terms of global consumption. If you would take China out of the picture, though, you have the chart on the right side, where you can see that gas consumption surpassed coal consumption about 20 years ago, and particularly during the past decade, it actually grew about four times faster than oil consumption and about again four times faster than coal consumption.

Where did the growth come from, particularly in the past decade? By 2008, for the eight years from 2000 –

from the year 2000 – the growth was about 600 BCM. Much of that came from Asia-Pacific, from Europe, CIS, and also the Middle East.

In each of these three regions, you have three leading countries. You have China, Russia and Iran. In each

of these countries, the growth in consumption was around 60 billion cubic meters per year. In 2009, growth continued in the Asia-Pacific region and the Middle East, whereas in all of the remaining regions, there was a contraction because of the recession.

(00:07:17)

Prospects for future growth: I will not go into many details here, but generally, the expectation is that the

growth will be around 42 percent according to IEA by 2030, and most of this will come from emerging markets and


the Middle East. I should also mention that there are some much more ambitious forecasts. For instance, PetroChina expects that the increase will be up to 300 billion cubic meters by 2020, which is almost twice more what IEA is predicting.

Regarding trades, I guess the main conclusion that we can draw for trade is that while gas consumption has

been growing by about 22 percent since 2000, trade has been growing three times faster. In the case of LNG, it’s been growing a little bit faster than that – than piped gas. So overall, now traded – internationally traded gas accounts for about 30 percent of globally consumed gas, whereas this share was as low as 22 percent only 10 years ago.

And the final point is about how gas is priced. And I guess this will be probably the most useful thing to do

in order to set the context for Tony’s presentation. I tried to draw a very brief summary here based on the International Gas Union’s methodology. They are distinguishing between gas that is produced and consumed domestically, and gas that is traded internationally, and they distinguish generally between three types of pricing. One is regulated, the other one is oil-index and the third type of pricing is spot market pricing.

(00:08:57)

In case of domestic production, most of the sales are basically on regulated basis. There is a significant

share for spot sales primarily because the U.S., U.K., and Australia are also big producers of gas, and they sell the bulk of the gas in their domestic market. In case of piped gas, piped imports, predominantly it is based on oil indexation. This is the case pretty much for almost all Russian gas with very few recent exceptions, and Algerian gas. This is predominantly the case for Norwegian imports in Europe, and also Dutch imports in Europe.

And the main exceptions here, where you see spot markets – this is about the cross-border trade in North

America, and also trade that involves the UK. And you also have a few other exceptions globally. For LNG imports, the share of oil indexation is even larger, and there are much fewer exceptions – primarily, again, in North America, a few exceptions in Europe, and also in Asia.

Well, thank you for the attention, and now I would like to give the floor to Tony. (Break.) (00:11:43)

MR. MELLING: Well, thank you very much, Adnan, for opening up the presentation. Natural gas pricing is not often a hotly debated topic. However, in Europe it has become exactly that.

There is a collision between two cultures about how natural gas should be priced, and the shock waves are impacting the whole world. The problem is that the price of gas purchased under European long-term contracts is linked to the price of oil. Starting around 2008, a new surge of natural gas sold under short-term contracts at commodity prices became available and changed the landscape dramatically.

Commodity-priced gas was at times selling for half the price of oil-index gas. The incumbents lost control

of the market and ended the year owing billions of dollars to the producers for committed volumes that they could


not take. In mid-2009, the situation was clearly not sustainable even for the next 12 months let alone the 30-year contract terms.

As a defensive measure, long-term contracts were hastily revised, and the shock waves spread also to Asia

where similar pricing principles apply. The total value of European oil-index natural gas contracts exceeded $2 trillion U.S., and the crisis impacted on the gas sales revenues essential to the governments of Russia and Algeria.

(00:13:19)

As a result, the issue was already reshaping relationships between E.U. sovereign governments and those of

the major gas suppliers. It is also influencing the development of major gas resources and even the planned direction of gas flows out of Russia. The issue is also reshaping the patterns of interfuel competition and gas consumption in Europe and across the world. The outcome has the potential to determine the role of gas as bridging fuel in the transition towards a low-carbon economy. It is, by any definition, a major issue.

The oil indexation story begins here. Shell and Exxon discovered the super giant Groningen field in 1959.

At 2,800 BCM, it was a super giant field. It wasn’t the first natural gas developed in Europe, but it was a massive quantity of cheap-to-develop gas at the epicenter of European energy demand. Commercially, Europe had seen nothing like it. The Groningen field alone had the ability to generate about 15 billion per year at today’s wholesale prices. Europe already had a gas industry, but this project was so large that it needed to attract customers away from other fuels.

(00:14:48)

(Inaudible) – Exxon formulated a marketing and pricing plan. Exxon proposed linking the price of gas in

each market segment to the end user’s alternative fuels and to discount in order to rapidly gain market share. The pricing principles were developed. Gas would be priced on the basis of its energy content as a percentage of recent oil prices, and the price would be updated every three months. The proposal was sold to the Dutch government and announced by the Dutch Minister of Economic Affairs in the now-famous Nota de Pous. This was the beginning of what became known as oil-indexed pricing in Europe.

Here’s the basic principle. Gas flows from the top downwards – from the producers to the end customers.

Pricing – oil index pricing – flows from the end users upwards. The starting point is what gas is worth at the burner tip. Now, a lot of calculations went into valuing what the gas was worth at the burner tip in relation to oil and other fuels. And this was turned into an art form in Germany and other continental countries. That was the starting point for pricing. By deducting the infrastructure terrace at each state, net back prices can be calculated at each point along the journey. The city gate, the gas company boundaries, national borders, and even the well head.

The alternative fuels selected were light fuel oil – commonly used for space heating, and heavy fuel oil –

widely used in industry. Coal was already falling out of favor, even back in 1962. Some end customers managed to negotiate a minority percentage of coal into their oil index formulae, but this was the exception rather than the rule. Notably, the system had no place for the price of fuel into power generation. Before 1988 in Europe, natural gas was considered too valuable a fuel to be squandered in power generation.

(00:17:17)


So how did the commercial structure actually perform? Well, I don’t think slides actually get much clearer than this. You can see that natural gas quickly displaced energy – quickly displaced other fuels. This is just the domestic sector in the Netherlands, but in other countries, in other sectors, you saw a similar pattern – maybe different rates of penetration of gas into the markets, but oil indexation was remarkably successful at what it wanted to do.

So as a result of this success, under the new pricing model, the gas industry boomed. New long-term

contracts were negotiated and fragmented gas industries across Europe became linked by national and international transmission systems. LNG volume arrived as early as the 1960s, firstly from Algeria, and then from across the world.

One exception in the story was the U.K., which, although one of the largest markets, was not yet connected

to continental Europe. Although oil index contracts were used, they differed in structure from those in continental Europe. This was the golden age of the European gas industry. Net back-pricing ensured expansion, stability, and profitability. Franchised gas companies harvested the markets, making huge profits. The last thing that they or their shareholders wanted was change. However, oil indexation had one serious flaw that was beginning to be exposed.

(00:18:56)

Gas was becoming abundant, but prices based on oil, did not reflect this. Everyone was happy, it seems,

except the customers who spoiled the party. A key driver for change was the large customers. They thought, in many cases correctly, that they were paying too much. The initial point of attack was not so much on the wholesale price of gas, but on the excessive margins between the border and the end customer. End users across Europe lobbied hard, even in Germany and Italy, but major changes first occurred in the U.K. And why?

Margaret Thatcher had been elected in 1983, and privatization fitted well with her missions to shrink the

state sector and encourage private enterprise, and the government needed money, too. British Gas was actually sold intact in 1986, but the government appointed a regulator with the mission to open the markets to competition, and eventually break up the incumbent gas company, which is did in 1996.

Moving on to the commoditization of gas in Europe: The unexpected consequence of liberalization was the

accelerated exploitation of discovered gas fields. New players emerged rapidly, and began by undercutting British Gas, and then each other. In 1994, the market was oversupplied, and prices fell dramatically. Increasing levels of over-the-counter trading quickly developed into published daily spot prices.

(00:20:45)

Then, in 1996, modifications to transportation pricing created the NBP hub. Thirty-four years after the

Nota de Pous, natural gas pricing reached its next stage of development, and gas in Europe became a commodity. By 1995, when British Gas was allowed to compete on price, it had a major financial problem. Market prices were much lower than their oil index prices. British Gas was forced to unbundle at this point, leaving the marketing arm to renegotiate contracts. In return for more favorable prices, Centrica paid billions of dollars in compensation to the gas producers. Some of the contracts renegotiated in the period from 1996 to 1999 remained at oil index prices, but most were revised to market prices.


Commodity markets could have remained confined to the U.K., but the gas industry lobbied government hard for a pipeline connection to Europe. In 1998, the U.K. became connected to Europe by the Interconnector pipeline, with a massive 20 BCM of capacity, which was much more than was actually required.

In 1998, the European incumbents were still harvesting the markets and making large profits. They feared

the Interconnector, but defenses were well prepared. Gas flows were constrained to specific routes, and the U.K. volumes – what gas there was available in the U.K. at the time – was actually sold to continental incumbents under royal index contracts of up to 15 years, and these were negotiated before the Interconnector actually began to flow.

At the time, nobody really expected to be a game-changer in continental Europe. Planning scenarios

indicated that the gas surplus in the U.K. would last perhaps until 2004, 2005, and after that the Interconnector flow was supposed to turn around.

(00:23:01)

The Interconnector was supposed to be an import pipeline to the U.K., but when spot gas volumes became

available too, into the continental Europe at low prices, the incumbents got greedy, started buying this spot gas at low prices. They were able to absorb the volumes into their purchase portfolios and resell the gas to customers at oil-index prices, much higher prices, making a lot of money. All they had to do was nominate lower takes on their long-term contracts. They could make hay while the sun shines and then return to business-as-usual around 2005. There was really nothing to worry about.

In parallel, they were using every trick in the book to limit the impact of E.U. legislation, effectively blocking

competition from the essential infrastructure such as pipelines, storage facilities, and distribution networks. Before we move on to the – before moving on to the legislation, I’d like to discuss the concept of the

middle ground. Rule number one for the oil-indexed incumbents was defend the middle ground at all costs; avoid oversupply. So what is the middle ground? Under the oil-index contracts, the volume commitment of the purchaser is typically to buy 85 percent of the annual contract quantity. The seller’s obligation is to supply a maximum of 110 to 115 percent of requested. Now these are typical numbers, not exact numbers for any particular contract. If the purchaser nominates less than the minimum bill quantity, he still has to pay for 85 percent of the volume, and this is called the take-or-pay clause.

Any gas that is paid for but not taken can be recovered in a later year. But if you don’t take the gas within a

limited period, you lose it altogether. And if you lose it, that’s about $300 million for every BCM of gas that you don’t take. So it’s a lot of money. It’s a big loss if you don’t manage to take it.

(00:25:24)

If the oil-index wholesalers in aggregate can stay within the middle ground, between the 85 and 115 percent,

they have the flexibility to absorb the impact of any market price gas that becomes available. Commodity market prices can be controlled by the oil-index purchases using the daily nomination’s flexibility.

If the market is undersupplied, then commodity prices will rise above oil-index prices, resulting in problems

for the market-prices purchases, but less of a problem for the oil-indexed players. However, when there is too much gas – and this is what we’re heading to – when there is too much gas, commodity prices fall. Oil-index suppliers lose


market share, and their problems can spiral out of control. Their only option is to go back to the suppliers and renegotiate prices or volumes – and/or volumes.

The next four slides illustrate the preconditions for the crisis that hit European markets in 2009. First thing

was legislation. But, in continental Europe, despite the lobbying from Industry, governments were generally not keen to see their flagship gas companies broken up. The E.U. clearly had a fight on its hands. And that fight was really about the ownership and control of the system. Competitors needed to get access to the gas system.

(00:26:58)

Well, E.U. legislation is a bit like a bike shed full of tools. You know there’s a tool in there to do the job,

but you can’t always remember where it is or how to use it. Fortunately, back in Brussels, somebody had taken the trouble to reread Article 86 of the Treaty Establishing the European Community which clearly stated that energy utilities were subject to the same competition rules as private companies. In 1988 the E.U. published its intention to create a single-energy market in Europe, and that meant competition.

Gas transit was a major issue. The E.U. won a small victory with the Gas Transit Directive in 1991, but

became aware that each battle painstakingly won simply took you to the next layer of resistance; and there were many layers of resistance available to the incumbents.

So back to the toolshed for a bigger tool – the one they picked out was the E.U. Gas Directive. Learning

lessons from the U.K., the E.U. laid out a timetable for the introduction of competition into gas markets. Unfortunately, negotiations weakened the power of the directive. This was a directive that you had to get the agreement of all the E.U. countries, for everyone, even those that opposed with it, had to agree it. And so, you had to have negotiations which considerably weakened the power and took the sting out of the third party access clauses.

So there was at that point to be no level playing field. However, the first directive was a very large foot in

the door. By the time it became effective, the E.U. was already targeting improved infrastructure access with a second directive agreed in 2003. At last the advantages of the incumbents could be eroded away, allowing new players access to gas supplies and customers. So all it needed was a bigger tool and 15 years of practice.

(00:29:10)

The 2009 crisis ran parallel to the negotiation of a much-improved third energy package, which becomes

effective in March 2011. Amongst the many articles of this package, it requires the unbundling of pipelines, storage facilities, and marketing operations. It also establishes a European regulatory body, which incidentally is already there.

The contagion of European Markets: As the Interconnector began to flow to Belgium, a spot-market price

began to develop at Zeebrugge First it was only trading across the flange between the players. Gas couldn’t actually get into Belgium. The Interconnector had been set up very cleverly so that no gas could actually enter Belgium. It could flow through Belgium to Germany, it could flow through Belgium to the Netherlands, but it couldn’t actually enter Belgium for the first couple of years.

As forecast, U.K. gas flows to Europe began to fall towards 2005. Then, they did the unexpected. Flows

actually began to increase. At first, Norwegian gas flows to the U.K. increased, and then new LNG terminals with a


capacity of 30 BCM per year were commissioned. The incumbents had underestimated the potential of short-term supplies from – (inaudible) – Norway, plus the broader LNG markets. And what effectively happened was the U.K. became a bridgehead for supplies into continental Europe via the U.K. This was effectively a surprise attack on the continental incumbents.

(00:31:07)

Throughout this period, second-tier players in Europe – that’s one layer below the large incumbent

wholesalers, and it also includes, you know, new players like electricity companies and, you know, oil companies that chose to enter the gas market. So you had a large number of these second-tier players, as we call them. They were mounting attacks on the oil index markets and learning fast. They were expanding outside of their historic market areas. In fact, players that were incumbents in some countries became second-tier players in other countries in preparation for the previously unthinkable – gas on gas competition.

From 2000 onwards, European gas demand forecasts were not materializing. They were inconsistent and

frequently revised downwards. Power-generation gas demand in particular was sluggish. Oil-index pricing had considerable risks for independent generators. Also, there was a lack of gas infrastructure liquidity and power structure liquidity, and a mismatch – quite a serious mismatch between gas and power market nominations procedures. In short, the potential for gas-fired power generation in Europe, which was already factored into demand forecast, remains unfulfilled.

Adding to the demand errors, European incumbents had overpurchased as a defensive strategy – to keep

competing gas out of the market and to convince regulatory authorities that competing supplies were not required. In other words, if you thought that regulatory authorities were looking at you and considering competition, you went out and bought more gas to convince the authorities that competition was not required. This was the game that they were playing as a defensive tactic. British Gas had tried that and come unstuck, and now the incumbents were trying that.

(00:33:38)

By 2008, 2009, the European supply position was commensurate with a market size of over 600 BCM a

year. In other words, the purchases – the gas purchases in aggregate could support a market size of 600 BCM. Yet, even in the overheated economy of 2008, European gas demand was just over 560 BCM, and most of the oil-index contracts were running close to their lower limits. Downward flexibility under the oil-index contracts amounted to only around 50 BCM a year. So the incumbents would find it impossible to retain the middle ground if the markets turned against them.

By 2009, we had what could be described as the perfect storm. Everything seemed to be pointing towards

2008 as a period when several trends would converge and create oversupply. Little did I suspect – (inaudible) – at the beginning of 2008, that two even more powerful forces would coincide with the existing trends to create the perfect storm.

Shale gas production in North America was increasing at unprecedented rates and displacing LNG imports,

and this could only be absorbed in Europe or Asia, and Asia wasn’t looking for more gas. Additionally, in mid-2008, gas commodity market prices plummeted as demand cratered to less than 530 BCM.


(00:35:16)

The – (inaudible) – second-tier players used the low prices as an opportunity to capture new customers in

continental Europe. As the sales of oil-index gas fell, the sales of commodity-priced gas actually increased. Result: Gazprom suffered export sales reduction, 14 percent, and a revenue fall of 39 percent in 2009. And Sonatrach of Algeria suffered the same problem. Customers bridged their contracts, missing their minimum bill commitments, in some cases by a wide margin, and they would need to pay under the take-all pay clauses. Would they do so?

Throughout 2009, the incumbent wholesalers became aware of the looming minimum bill problems. At

$300 million per BCM shortfall, wholesalers owed billions of dollars to Gazprom and Sonatrach. Under the Russian sales contracts to E.ON of Germany, press reports quoted a figure of $700 million owing to Gazprom.

Overall, minimum bill payments, payable by incumbent wholesalers, mostly Russia and Algeria, would have

amounted to somewhere in the order of $3 billion, payable due in October 2009. Now we know that some of these bills were paid, and other buyers were let off the hook. One of the problems here was that end customers had similar clauses in their contracts, and they didn’t have the cash liquidity to pay the wholesalers, and so the money couldn’t flow up the chain to the producers. So a lot of the times they were let off the hook, but with bills owing for the future.

The prospect of one year’s worth of payments may not have been too daunting, but the threat of prolonged

recession and more market-priced supplies was even more daunting. Some of these contracts still had 30 years to run. Clearly, the financial stakes for the producers are high, and for the wholesalers they were potentially crippling. And from this, you can understand why the incumbent wholesalers were reluctant to allow competition into their traditional market areas.

(00:37:52)

One thing is certain: The gas producers quickly got the message that the wholesalers’ contractual problems

were becoming the producers’ problems. The middle ground had been lost, and the market was now in oversupply. If nothing was done, oil indexation could disintegrate. Indeed, at this point, many commentators felt that oil indexation in Europe has already reached the end of the line.

But, the oil index fought back. What happened to release of pressure? Firstly, the suppliers – notably

Norway, and then Russia, made concessions on price, but more importantly on minimum bill volumes. Gazprom was at pains to point out that these changes were temporary, and come the end of oversupply, that they would resume business-as-usual, as there wouldn’t be enough market-priced gas to go around.

Since then, two significant drivers have also moved in favor of oil-price indexation. Firstly, demand is on a

rising trend. And secondly, long, cold winters enabled the incumbents to meet their downwardly revised minimum bills and even have some hedge room which the incumbents then used to purchase market-priced supplies.

(00:39:20)

Market-priced supplies could even have been higher. Production startups have been delayed. Terminal

outages have been high, and pipeline supplies have been curtailed for a variety of reasons. Some commentators have


suggested collusion between suppliers, or oligopoly behavior, or commercial restraint of production. I don’t really have an opinion on which of these is true, but could even be a combination of all three.

Oil indexation made adjustments to survive 2009, 2010. The lesson here is not to underestimate the

resilience of the oil-index contracts. Continental contracts had price renegotiations clauses which relieve the pressure on some buyers. This was something that British Gas did not have in its contract in 1996, but wished that it had.

So how long will oil indexation survive? These long-term oil-index contracts were designed for an era when

monopoly suppliers could pass costs through to their customers. Today the contracts are fundamentally incompatible with end user needs, or indeed, the E.U.’s vision of competitive single-gas market. In some countries, the battle for commodity markets is clearly being won. Elsewhere, the industry remains divided.

Then, in August 2010, the German Chancellor Angela Merkel spoke out in clear support of commodity

markets, and this was seen across Europe as a direction marker for the highly influential German gas industry. The Russians are the most vocal advocates of oil indexation. This is understandable in view of the fact that

it has been the price model underpinning almost the entire development of gas from export and much of the gas from revenue base since the 1970s. Algeria is strongly aligned with Russia, but less vocal. These two countries together supply more than one-third of Europe’s entire gas needs. The stakes are simply too large for the producers to walk away from oil-index contracts.

(00:41:49)

The defenders of oil indexation cling to the belief that the oversupply would disappear by 2015, and then

they can resume business as usual. This is very similar to the continental incumbents’ belief, in 2005 –that Interconnector supplies would disappear by 2005; and that didn’t happen.

We cannot turn the clock back. European legislation continues to improve – third-party access, liquidity,

and competition. And these are fundamentally incompatible with the oil-index culture. This leaves the following possibilities: Firstly, dramatic revolution – possibly resurgence of the oversupply

of 2009 causing urgent and revolutionary renegotiations. That’s just one possibility. Second possibility: A negotiated revolution where oil-index purchases jointly negotiate a switch from commodity market – switch to commodity market pricing with the key producers. And that will probably involve the payments of quite large sums of money. Third possibility is an evolutionary transition to market pricing.

(00:43:11)

New oil-index contracts are no longer being signed. To the European wholesalers today, you have a triple

risk. You have price, volume, and regulatory risks. And that set of risks is simply too large. When they signed these contracts, there was only really one risk, and that was volume risk. Now you’ve got three risks. So oil indexation, because people won’t sign new contracts, oil indexation could naturally just die a slow death.

Another possibility – and this one’s quite real, one that they’re worried about – is the next – (inaudible) – of

E.U. legislation. This depends on their ability – on the E.U.’s ability – to identify the next big tool and their


willingness to use it. However, the most likely agent for the next big change is a combination of the above. It was just such a combination that created the near-revolution in 2009. The next time it happens, liberalization and commodity markets will be further down the road, and the movement away from oil indexation may be easier.

Let me leave you with one final thought: If you were to ask the question in Europe, which is the most

important market price in Europe today, the answer would almost certainly be the NBP commodity market price rather than the German border price, which is the measure of the oil-index price. As in the U.K. of 1996, oil-index prices are still there, but they are becoming obsolete.

Thank you. MR. VATANSEVER: Thank you, Tony, very much. Thank you for the very informative presentation. I’d

like to open the panel for questions. Please identify yourself as well. (00:45:16)

Q: Roman Zytek – Middle East and Central Asia Department, International Monetary Fund. I look at

your road ahead; there is one bullet point that is missing to me here. We assume that oil prices will be so high as they are today 20, 24 times, 25 times higher than 1 million BTU in the United States forever, and therefore, the index cannot work. I think that’s implicit assumption. There should be another assumption – that oil will need to restore its competitiveness in the market, and the only way it can happen is when the price of oil falls. Is it possible? What do you think about this scenario?

MR. MELLING: The oil price falls, huh? I’m not really an oil-price forecaster. I think the biggest fear of

the oil-index buyers are the oil-index buyers becoming increasingly uncomfortable with their oil-index contracts. And their big worry is that oil prices go through the roof so gas could be plentiful and oil scarce, and they’re paying a price that’s linked to the oil index. You know, that’s a big threat and a big worry to them. Does that answer your question? I think – will they fall? – I don’t think so. But then, I’m not an oil forecaster.

Q: That’s a very interesting condition; however, I think the determinant is the fact that oil is predominantly

a transportation fuel, and there is not gas-to-oil competition in transportation. So as long as transportation demand is there, I don’t see the direct possibility of that fall. Until we find a substitute to oil for transportation, I don’t see that linkage being as tight as it could be. But it’s certainly possible. We’ve had, you know, within the last 20 years, oil at 15 a barrel where nobody thought it would be so.

(00:47:39)

Q: There is another interesting point I’d like you to comment. (Inaudible) – In the past 10 years, oil

reserves has added – it’s like we got another Saudi Arabia; and in terms of gas, in the same period we got another Russia. But the cost of this incremental addition is very different. In fact, what’s the most expensive oil? – Maybe produced $50 a barrel, but gas is – we’re talking about the range of $10 a barrel. So this is not a good reason to break the link.

MR. MELLING: Yes, I’ll very much agree with that, yes. Yes, I think, when you look at the world gas

reserves, you know, 60-odd years of gas reserves, 40-odd years of oil reserves, and you look at the – believe in the curve, you know, we’re further along the curve for oil than we are for gas. The two markets really are fundamentally


different, and why should you link, you know, gas to oil prices? In the early days you didn’t have anything else you could link them to, in the 1960s. It worked. It was a good system. Now, it’s sort of come to the end of its – the end of its useful life. And really, in my view, it should be replaced now by something else – by commodity markets.

Q: I just have a factual question, I guess, kind of related to what’s just been said. MR. VATANSEVER: Could you identify yourself– (00:49:23)

Q: (Inaudible) – with IHS Cambridge Energy Research Associates. In the United States many years ago

there was a de facto linkage between oil and gas prices, because there was so much substitutability of gas with oil in primarily the electric power sector. And it just worked out. There was, you know, a lot of boilers could switch – physically switch from gas to oil. That is no longer the case. Because of the lower gas prices most everything has already switched. But I think that’s the genesis for the oil-gas price linkage, at least in the United States. And my question just is, is that physical switching capability still present in the infrastructure in Europe?

MR. MELLING: Between oil and gas, very little. Very little, to be quite honest. I think there always is, if

you look at, you know, very long-term energy prices, there’s always a link between gas, oil, and coal. You know, they tend to go up together – look down a very long-term scale, and that always has been the case. I think the linkages on a shorter term – the linkages come and go, you know. They’re there one month, they’re not there the next month because conditions have changed slightly, particularly in power generation, for example. You know, coal plants switch on and off. So linkages come and go. Yes, there is a long-term linkage, but I think a lot more short-term dislinkage, if you like.

MR. VATANSEVER: Let’s take two questions, or two or three questions, and then you could probably

answer them we have five more minutes, MR. MELLING: Sure. (00:51:14)

Q: Robert Johnson from – (inaudible) – group. You mentioned Sonatrach and Gazprom as the incumbent

exporters, and their preference for maintaining oil indexation. We think the view of Cutter (ph) Star Petroleum is on the oil indexation question as a lower-cost producer, you know, how comfortable are they with – (inaudible) – to the shift towards more commodity-based pricing.

MR. VATANSEVER: Okay, let’s get another question as well. There was a hand there. Thane Gusterson? Q: Thane Gusterson, Cambridge Energy and Georgetown. The standard Russian answer, Alexander

Medvedev’s answer is, we’re perfectly happy to sell our LNG into North America at commodity prices because spot markets in North America are deep and liquid. Medvedev goes on to say the same is not true in Europe as yet, and consequently spot markets in Europe are subject to manipulation. That’s a risk for us as long-term planners.

My question to you is, at what point would you say that spot markets become sufficiently deep and liquid in

Europe to satisfy a reasonable investor in supply? Have the Norwegians, for example, given any indication as they


move gas into the U.K. that they can live with the depth and liquidity of the U.K.’s spot markets? At what point would Gazprom say, okay, we’re satisfied?

MR. MELLING: I like that question. MR. VATANSEVER: There was another question over there. Yes, go ahead, please. (00:52:56)

Q: Hi, Michael Ratner with Congressional Research Service. If we just assume that oil indexation goes

away, can you comment about how you see supply, demand, and prices reacting in this kind of medium term? MR. MELLING: Yes. Indexation goes away. Right. The first one was the – I think there are a number of

countries that say – less consistent with their messages than Russia and Algeria. You know, Algeria and Russia have been very firm with their messages. You know, Norway used to be very firm with its messages, and then they started selling, they knew that they needed to sell gas into the U.K. to expand their export sales, and so – and they became much more aligned to the E.U. single-competitive markets.

(00:53:59)

Qatar doesn’t have to comply to E.U. legislation so they can do what they like on pricing and reach arms-

length deals. They’re selling a lot of their gas on oil index, and some of it – increasing amounts – into spot markets. And so, you know, everyone thinks spot market prices are lower. I don’t think they necessarily take the view that spot market prices are always going to be lower. It’s a good thing to have, you know, a mixed portfolio – some oil-index sales, and some spot-market sales. I thi nk that’s probably what Qatar think.

Although, within a lot of these companies, you know, not just Qatar gas, but even, you know, E.ON of

Germany, and ENI (ph) of Italy, and Gazprom itself. You know, you do have a mixture of views and different camps. You know, within Gazprom, notably, there’s the Gazprom Marketing and Trading in London who sell gas at spot market prices – you know, buy and sell at spot market prices. So within a lot of companies there’s a mixture of views. The Gazrom and Sonatrach are the two firmest, I would say, on that one.

On the liquidity question, I think it’s a very good question, because it’s kind of a chicken-and-egg situation.

If Gazprom did start selling a lot of market-priced gas into European gas markets, then the liquidity would be very good. The fact that they don’t makes the liquidity bad. Liquidity, you know, it comes and goes, and there are companies out there that probably can control the liquidity quite easily, including Gazprom, and particularly Statoil is in the perfect position to be able to do it, and some people suspect them of doing it.

(00:55:53)

Having said that, you know, there’s a good churn rate at the NBP hub; less so in the European hubs. And

certainly most people feel that the NBP hub, you know, gives good liquid market price. But, you know, it’s never going to be perfect, and even oil markets – you know, subject to manipulation at times; or so it’s said. You know, what the churn rate is – well, you know – I mean, nowhere in Europe yet achieves churn rates as good as the Nymex markets. I don’t think you need them that high. And certainly most people feel the U.K. NBP is a liquid hub, and


most of the hubs in Europe tend to follow the NBP rather than – as much as setting their own prices. Does that answer the question?

Q: What is the trend, and what is then the response to the Norwegian – (inaudible) – sales more and more

on spot sales. MR. MELLING: Yeah, I think the trend has generally been upwards for liquidity in Europe, and

particularly in the last few years there’s more spot-market priced supplies have become available. Yeah, the liquidity has improved; not in Italy or Spain, but certainly in Northwest Europe. The Norwegian – yes, Norwegians are treading a fine line, if you like, between the demands of the Russians and the demands of the E.U. and the demands of their customers. It’s always a very fine line, you know. I saw Gazprom praising them for some statement that they’d made about their marketing of gas. So it is a fine line that they walk. They have to comply with E.U. competitive market legislation, so, yeah, they have to be careful what they do. They’ve had their offices raided by the E.U. before, and it will probably happen again, you know, if the E.U. suspects them of doing the least thing that’s untoward. So you know, it’s easy just to take a look at their position and say they can manipulate the market; it’s not quite that easy.

MR. VATANSEVER: There was a question on the oil-indexed gas prices (00:58:33)

MR. MELLING: Yes, if oil indexation goes away. How can I answer that? It’s a good question. Perhaps –

yeah – I said there are two cultures in Europe, you know, two different mindsets. You know, you have the mindset of the commodity markets, and that’s a very different mindset from the mindset of oil indexation.

The mindset of oil indexation is one where volumes and prices, flows of gas, are all very tightly controlled.

You don’t want anything to disrupt that control that you have over the market. You know, it’s a control situation. Commodity markets thrive on – well, commodity market brokers think they bring, you know, order and harmony and balance to chaotic markets, and oil-indexed players think that commodity markets bring chaos to ordered and balanced markets, if you like.

I think if you flipped over – flipped your mindset from the oil index to balanced flows, and if the German

gas industry tomorrow said, okay, what we need is just loads and loads of supplies, we need South Stream, Nabucco; we need a pipeline from Iran, and everywhere; what we need is just loads of gas – then prices will go down. That’s a different mindset. And if they ever adopt that mindset and get oversupply, then, you know, that will be good for the European consumers. As it is, you’ve got half of the industry that’s trying to constrain the flow of gas to Europe, and half that’s trying to bring more gas in, and it’s whoever wins that balance will control the prices, if you like.

Okay, does that answer the question? (01:00:46)

MR. VATANSEVER: Well, thank you very much, Tony. I would suggest that we have a short break, and I

am assuming that you may find the answers for some of your questions during the second panel, as we’ll have five presentations, and we’ll also have an additional Q&A session at the end of the presentations. Well, thank you very much again. Ten minutes’ break, please.


(Break.)

(00:00:17)

MR. VATANSEVER: I’d like to welcome you back. We’re starting a very interesting discussion. As I

mentioned, we have five discussants. Each of them is going to cover a very interesting theme related to gas markets

and also respond to the report that we have launched today. I will start with power generation and each time I will

be introducing the speakers separately.

(00:01:05)

Let me introduce the Honorable Branko Terzic, who is going to be talking about power generation and its

link to gas. He is the executive director of Deloitte’s Center for Energy Solutions and Regulatory Policy and also

policy leader in energy and resources for Deloitte Services. He is the current chairman of the United Nations

Economic Commission for Europe Ad Hoc Group of Experts on Cleaner Electricity Production. He is a current

member of National Coal Council.

Formerly Dr. Terzic was a commissioner at the Federal Energy Regulatory Commission and also Wisconsin

Public Services Commission. Dr. Terzic is a member of the planning committee for the Energy Colloquium,

executive council Energy Efficiency Forum and New America Foundation Energy Advisory Council. His columns

appear in Energy Metro Desk and European Energy Review. He is also a private counselor to Crown Prince

Alexander of Serbia.

(00:02:06)

BRANKO TERZIC: Thank you ladies and gentlemen. This is a formidable audience because I know quite

a number of you very well and you’re all more expert on the subject I am talking about than I am. So I am chastised

by that. Let me move ahead. Just to remind you that, at least for my career, I have been involved with two issues in

the 20th century, one issue in the 21st.

The 20th century issues have been securing adequate energy supply at reasonable cost and making that

available to consumers at reasonable cost. This is the public service commission model. This is the Federal Energy

Regulatory Commission model. This is how we brought electricity to the one-third of the world’s population. Only

a third of the world’s population has adequate electricity right now, a third has intermittent service and 1.7 billion to

2 billion people have no electricity today whatsoever. We’re talking here about natural gas for electricity use.

The 21st century finds us still with that issue of having to supply adequate energy at reasonable cost but with

the condition that we have a climate change issue; not a certainty, a high probability. You can choose your own

position on the political spectrum, whether you’re a total climate change skeptic or whether you believe, as the

international committee does, that there’s an 85 percent chance that our greenhouse gases are producing climate


change. Somewhere on that spectrum I’m reminding you that, those of you who are in the military, if something has

a 50-percent chance of occurring, we plan on it. I was only a captain and a general told me that recently. So I’m

going to believe him.

(00:04:06)

We are talking about natural gas for electricity. I want to point out that we can also talk about natural gas

for central station electricity, and as the former CEO of a gas company, I was always interested in having natural gas

at the distribution for combined heat and power, something that we do not have good technology for yet in this

country. Switzerland, other countries do have home units, natural gas single cylinder engines, fuel cells, something

that will convert natural gas to electricity with heat reclamation, the small CHP or larger CHP at the head.

We don’t talk much about that use of natural gas but it is one that’s out there that’s potential. I think we’re

lacking some good transportable, easily installable technology but in many parts of the world where there is a

distribution gas network available for that, we have it there as well. Of course, the third option is the natural gas

transportation whether at a compressor site, at a central station or at a home compressor. I just had a very

interesting conversation with a gentleman from the International Monetary Fund and in many parts of the world

natural gas for transportation may be another use out there that will change significantly on a country by country

basis the future of natural gas.

(00:05:28)

This is the U.S. energy balance. I use this in a lot of my presentations to remind audiences of where energy

goes. As I mentioned earlier, petroleum is predominately a transportation fuel. Natural gas has not displaced

petroleum there. Natural gas has a combination of industrial, residential, space heating and electric production. In

this country, electric production under natural gas will increase for a variety of reasons, including uncertainly over the

climate change bill, and over the certainty of the EPA’s ongoing regulations, particularly the ones already in law with

respect to fly ash and with respect to other chemicals, not CO2.

We already have – I have friends in the engineering profession. Their companies are being called and asked

to review existing coal boilers – big, old, fat existing coal boilers for conversion to natural gas, inefficient conversion

to natural gas in those boilers in order to meet fly ash and other requirements. So there’s already some of that going

on as well as the question of meeting need for new supply.

Now, in the U.S. two years ago, every one of the NRC regions was at or below its minimum reserve

requirement at 15 percent. The recession has saved us from blackouts. We had 35 percent reserve capacity in this

country in the 1980s, for example in ’85 when I was a state commissioner in Wisconsin. So the reserve capacity

issue, the issue of if demand picks up, if we come out of the recession, who’s going to be ordering what natural gas

turbines, quickly installed will meet it.


(00:07:21)

These are just some slides I included on projections for increased global natural gas demand. We’ll just skip

those and go right to Tony’s paper, excellent paper, and you can read these along with me here. The power

generation is not amenable, mostly for independent competitive generators running on gas combine cycle. Long-

term contracts may at time put you in a position where you’re selling at below – into an electricity market at low

price and being required to buy high priced gas with take or pay penalties, so that contracting.

However, if you are in a base load situation, and your gas units are base load, as we have here in the United

States, you might much more feasibly get along with a long-term contract. The demonstration is – there was a

question about Norway. The spot markets in northeastern Europe are supporting combined cycle gas turbine

development already and the superior characteristics from these spot markets works much better with the

competitive electricity markets and gas turbines bidding into competitive electricity markets.

I agree with Tony that long-term oil index will not disappear from gas markets, not in the foreseeable future.

But I like very much the Statoil-Poweo GSA which Tony writes about. It may represent the way forward. It will

allow gas producers to remain open to GSAs with the turbine developers, with the market developers. This will be a

question of how quickly Europe wants to move to gas. Clean air requirements, how well the carbon market works, a

lot of considerations going into this with respect to the European marketplace.

(00:09:29)

One of the things we didn’t talk about was the issue of pipelines. Tony mentioned that the electricity – the

gas directive and electricity directives in Europe both require third-party access – open third-party access. Europe

however does not have the equivalent of the Federal Energy Regulatory Commission. It has a weak committee-type

organization. I think Tony was talking about the organization that Lord John Mogg – Lord Mogg runs, the sort of

the committee of committees of state – of regulators.

They don’t have the authority of the FERC which dealt with the unbundling problem on natural gas in

order 636 where in this country natural gas pipelines were taken out of the gas sale business and put totally into the

gas supply business under straight fixed variable rate design, very important to give them the financial security and

the commodity was stripped away and they were forced into nondiscriminatory policies.

(00:10:30)

The difficulty that Europe has of course is their largest individual supplier of natural gas through pipelines

in Russia is still in a bundled mode and I think on the long run it will have to be negotiations with the Russian

government, with Gazprom to demonstrate to them that in the long run, possibly an American model of a separate

unbundled transportation with straight fixed variable rate design to protect the pipeline investment and then opening

up the commodity to the separate issue of how you price the commodity.


Now, I am talking as a former member of the Federal Energy Regulatory Commission, which

singlehandedly screwed up natural gas pricing in what was the greatest screw-up in energy pricing probably in the 20th

century, based on the Wisconsin v. Phillips decision in 1951 where the Supreme Court told the Federal Power

Commission that they had misread the 1930s Natural Gas Act and should have been regulating natural gas

commodity at the wellhead all along.

In response, the Federal Power Commission came up with a convoluted, a complex and unworkable

method, a series of methods of pricing natural gas, creating the unprecedented situation by the late 1970s in

interstate commerce of high natural gas prices and commodity shortages as a permanent thing, while in the intrastate

market, we had low prices and excess supply.

(00:11:59)

Of course, Congress came in and wisely stripped the Federal Energy regulatory Commission, the successor

of the Federal Power Commission, from setting the price of natural gas. Immediately a few months later, the

average price of natural gas in the country dropped from $3.50 to $2.50 between October of ‘85 and February of ‘86,

for example. In October of ‘85, I approved the purchase of $10 natural gas, ‘85 $10 MCF natural gas by the

Wisconsin gas company. That was all that was available at the market at that time.

So we have some good lessons to be learned about attempting to manipulate or work with gas prices. We

understand how markets work. We also understand here, I think, that with respect to electricity, the flexibility of

spot prices and hybrid prices may be spot for certain kinds of generators, long-term index prices possibly for the

base load generators may give the market.

(00:13:03)

There is a need for new firm capacity going forward. That will be very much dependent also on climate

change legislation and issues. The new capacity has to come from dispatchable sources. You cannot provide firm

capacity in the future from solar, wind or other. It’s not firm. New capacity has to come from dispatchable sources.

Energy can come later under that umbrella from renewables. Natural gas has the advantages for electricity

production in Europe and elsewhere of being available, deliverable, lower, half CO2 emissions and priced

competitively. The natural gas contract forums will have to meet the dynamic means of competition and generation

or they just won’t come. Thank you very much. (Applause.)

MR. VATANSEVER: Thank you, Branko, for a very informative presentation. Our next speaker is Vello

Kuuskraa. I’d like to invite him here. He is the president of Advanced Resources. He has over 40 years of

experience with unconventional gas. He is a member of the Potential Gas Committee and is the author of over 100


technical papers on energy resources. Recently, he authored a three-part series entitled “Gas Shale Transformation”,

published in the Oil and Gas Journal.

He and his firm assist domestic and international companies to identify opportunities for gas shale, coalbed

methane and tight gas sands place in the U.S. and worldwide. He currently serves on the board of directors of

Southwestern Energy Company and on the board of directors for Research Partnership to Secure Energy for

America. Mr. Kuuskraa is the 2001 recipient of Ellis Island Medal of Honor that recognizes individuals for

exceptional professional and patriotic contributions by America’s diverse cultural ancestry.

(00:15:06)

MR. KUUSKRAA: Thank you for that very warm introduction. I’m pleased to be here and if you look at

the title of my talk, Unconventional Gas: Is it an exportable North American revolution, I hope to kind of put some

background on that and then see whether this might be the source that creates a liquidity that Tony, you talked about

earlier in your talk.

Well, for the U.S., really it was gas shales that changed the outlook from what I call fears of impending

shortages, which we expected in the early part of the decade, to now expectations of plenty.

(00:16:10)

So just a few facts on that – instead of declining, natural gas production has increased during this past

decade. Unconventional gas provided 20 BCF a day and more than replaced declines in onshore and offshore

production. Gas shales provided the big bulk of that. Now, I can see, and it now provides over 60 percent of U.S.

natural gas production and it’s nowhere – when I first started talking about this, they were wondering if I was really a

reputable and time has caught up.

Just to put some picture on it, in fact, 10 years ago you had basically conventional and offshore gas, the big

boys. They were in decline and that led to a number of analysts saying, we’re in to basically diminishing returns or

we need to really build large LNG facilities. What they forgot to look at was unconventional gas, which basically

came to the rescue.

Just a quick picture, the tremendous growth in unconventional gas, particularly gas shales in the past three

or four years and starting with some of our big shale deposits and at the very top, if you see kind of like in the dark

purple, reddish is Haynesville, which you’ll end up being potentially that in the Marcellus. It’s the largest of them all.

(00:18:01)

So I want to use this as a way to address the same kind of questions that I think will need to be addressed in

Europe that we’ve begun to grapple with here in the U.S. We don’t have all the answers yet and clearly less for


Europe but this, I think, provides the fundamentals. The question first is how large is the resource base. Is it large

enough to enable it to become a major climate change solution, support from the U.S. exports of LNG? We’ve had

some steps towards that.

How much can be converted to productive capacity at affordable prices? What’s the role of technology? If

this is a technology play, this is what brought it about, how will that continue and can you do it in an environmentally

sound way?

Well, I want to put – we hear a lot about the climate benefit of natural gas and basically I want to say that

it’s a 70 percent solution. For really old, inefficient plants, it can be even higher than that. Half of it comes from the

lower carbon content. The rest of it comes from the higher efficiency of natural gas plants compared to coal plants.

So I just put that – combine those two, if you look at it pounds of carbon per kilowatt hour.

(00:19:31)

So let me kind of walk through for the U.S. the answers to some of these questions. I’ll turn to Europe in a

minute. It’s large. Gas shales are about half of our unconventional gas resource – tight gas, coalbed methane make

up the rest, and we still have a large undeveloped conventional gas resource base. It’s widely located. Most of the

activity has been along the East and Central parts of the U.S. We have shales in the West as well which are not quite

as economic to develop.

What really brought about the change? We’ve been developing gas shale – in fact the gas shales were the

first source of natural gas in Fredonia, developed over 100 years ago. But it was viewed as a small, high cost type of

resource and what really changed the game is that it is now the low cost part of the price supply curve for U.S. gas

and that’s really at the heart of the revolution itself. Policies, research and technology had a major effect. I don’t

want to lose this because this happened in the past. No one remembers what happened 20 or 30 years ago.

But it was basically a success story and this could be a model for Europe. The DOE helped build the

essential resource and science knowledge base. Without that, we would still be kind of punching holes in the blind.

The Gas Research Institute basically did the early demos. When we started it, everybody thought that we were out

of our minds.

(00:21:21)

Then there were tax credits and they weren’t so important for pushing you over the limit. It was really it

attracted capital and capital brought about other talents to the arena and basically it brought us to where we are.

However, I do want to point out that of this large resource base, still only a relatively modest portion is low cost.

The rest of it still is looking for continued advances in technology.

What changed the game is basically horizontal wells with multistage fracturing. I did some of the earliest

work on horizontal wells for the Department of Energy in 1980 for the shales of the Appalachian Basin and through


the Gas Research Institute began to develop the kind of feedback mechanisms that allowed you to apply basically

hydraulic fracturing in a science way rather than blindly in the dark.

Now, a very critical question both in the U.S. and particularly Europe is can these be developed in an

environmentally sound way. There’s going to be a harsher spotlight on this development and if the industry is going

to be successful, it has to adopt what I believe is called green natural gas development. A number of things go there.

(00:22:48)

I’ll just touch on three of them – reducing surface impacts, particularly as you begin to look in Europe and

its higher densities of population; capturing methane emissions so that you truly have a positive balance; and then,

assuring that the wells are safe and the hydraulic factures are safe in terms of drinking water and other effects.

Well, the first one is actually relatively easy to solve. Reducing land use impacts, you can do that with multi-

pad wells and multi-well pads. In fact, at Southwestern Energy, where I’m on the board, we find it’s cheaper to do

multiple wells from a single pad than doing it the old way. There’s nothing like good economics to drive good

environmental practices. Reducing methane emissions, there is an – EPA has an excellent program. Southwestern

Energy joined it. It was one of the – got an award for being the best new entrant a few years back.

The second thing is if you look at the bottom of that, Williams Company, who’s been one of the companies

involved for some time, they’ve captured – this is now data that’s a couple of years old – 24 BCF. It cost them $17

million to do that. They sold it for $159 million. It’s a good return. Again, economics drive you to good. In this

case, economics drive you to good environmental practices.

(00:24:23)

A third is, and the one that of course everybody is worried about, EPA has a study underway, legislation

being talked about. Basically doing your well impact correctly and basically that’s what it comes down to. If you do

it incorrectly, you can cause problems and have caused problems. You need – if you do it correctly, you basically

have steel casing and cement to protect groundwater.

You’re working 5,000 to 10,000 feet below the water table. There’s a lot of strata above you, one to two

miles of strata that will protect you. I talked about the ability to look at the fracture. Microseismic can tell you

where it’s going and those kind of dots that you see, this is a deep Haynesville well, you can see that the highest point

of basically disturbance, which would be a small fracture, is probably about 300 or 400 feet above the horizontal well

itself.

Finally, strong supporter of disclosure, it’s a personal view, not necessarily our company’s view, and

development of less environmentally impact chemicals. We’re actually developing certain sonics-type of approaches

to get rid of some of the bacteria sides.


(00:25:57)

Now, to Europe, okay? We took our first look at Europe and there are basically at that time three

prospective areas – Alum Shale, Sweden; the very important Silurian Shales of Poland, and the Mikulov Shales in

Austria. We’ve put a number of about 1,000 TCF in place, recoverable of 140. Just recently we’re doing a world

study of gas shales for the Energy Information Agency and we finished Poland. We’re currently putting a

recoverable – technically recoverable resource, not yet economic, of over 300 TCF just in Poland. It’s a large

resource.

But it’s a big but; the European gas shale geology is much more complex, lots of faults. Certain areas there

could be conduits for water and the way we like to do it is you’ve really got to look at the well site and every well

becomes a Ph.D. thesis. It might be a little overstated but not by a lot. We do believe the largest potential will be in

Poland. The geology is somewhat simpler. The resource quality appears to be higher and there are some exploration

wells underway.

The things we look for – is it silica rich, is it mature, high in total organic content. No longer the trapped

source, et cetera, of conventional gas and those appear to be favorable in Poland. However, lots of constraints still

and the constraints are particularly impressive. We need to know first of all what’s the size and quality of the

economic recoverable resource. If you’ve got $5 gas, it’s one game. If you’ve got $10 gas, it’s a very different game.

That fundamentally has not been established. We’re working on that. But we don’t have an answer yet.

(00:28:04)

You have to basically resolve the environmental consequences of hydraulic fracturing, water use and

disposal. They can be done. We have the technology to do it. We just need to make sure it’s done right.

Expanding the infrastructure, there are some efforts underway to do that. Right now there are severe constraints in

this.

The capital costs are going to be higher, at least two times those in North America, could be two-and-a-half

times. What we’ve seen, however, is over time, costs come down, wells get better. Just at our own company in a

period of about three-and-a-half years, we brought our cost down by almost threefold, part of that better wells, part

of that lower costs, then better certification approvals and a transparent regulatory process.

(00:28:57)

So let me conclude. The work we’ve done so far says we’re relatively confident the U.S. has plentiful

supplies. We now think particularly in Poland there are large supplies. The challenge is converting these resources

into economically competitive reserves. Important to do this in green development way, but if you do so, we think

there are considerable benefits.


In addition to working on the markets, basically we think it can provide a substitute for old, inefficient

power plants. It can increase energy security either for transportation or low emission power for electric cars and

importantly improve the economy from lower energy costs, more domestic jobs and an improved trade balance both

in the U.S. as well as in Europe. Thank you very much. (Applause.)

MR. VATANSEVER: Thank you, Vello. Thank you very much for a very insightful presentation. Our

next presenter is Mikhail Korchemkin. He is the founder and managing director of East European Gas Analysis, a

consulting company that specializes in cost benefit and financial analysis of natural gas projects in the former Soviet

Union. His previous experience includes performing numerous visibility studies for the USSR gas ministry, now

Gazprom. He has consulted numerous corporate and governmental clients in the U.S., Europe and Asia. The floor

is yours.

(00:30:46)

MIKHAIL KORCHEMKIN: Thank you. Yeah, thank you for giving me the opportunity to speak at this

meeting. I’d like to give a brief history of the competition, gas competition in Europe, and focus on Russia and

specifically on the most recent gas plan to 2030. Before I start, I’d like to show this interesting chart I picked up at

Reuters just a week ago. There’s nothing like global LNG market. The prices go different ways and differ by region

a lot. Most people see the right portion of the chart as part of a wave but Gazprom normally sees it as a trend.

Just a reminder that two years, the CEO of Gazprom made a forecast according to which today’s price of

gas in Europe should be $30 per MBTU; actually, Gazprom is selling now at $8. Anyway, this also shows that, no

surprise, it became reasonable to re-export LNG from Freeburg, Texas, to Japan, and maybe we’ll see soon exports

of LNG produced in the U.S., not just to re-export. Now, back to Europe, the history of competition in this decade

was a prominent and steady loss of Gazprom. Somehow in the ‘90s, Gazprom was gradually increasing its market

share.

(00:33:08)

This chart shows just a share of immediate suppliers in imports from outside of the European Union and

these are the numbers of OECD Europe, which is mostly the whole Europe plus Turkey with the exception of I

think it’s Bulgaria and Romania and minus the Baltic states. So it’s a very representative picture and the numbers of

BP statistical review show the same trend.

So Gazprom steadily losing indicates that they were doing something wrong, especially in the early part of

the decade when there was no objection against buying more Russian gas. Simply it was a measure of price and in

the final period of this decade, the gas war with Ukraine when Gazprom shut supplies to Europe for two or three

weeks, plus the crisis and the appearance of the unconventional gas in the market helped add more to this decline.


Numerically, Russian exports increased but this growth was well below the market. You can see that

Norway has added more, increased sales much more than Gazprom. Gazprom’s incremental sales were just

marginal compared to the development of the whole European market. Actually this is 10 years of Gazprom being

under the control of Vladimir Putin. (Laughter.)

(00:35:26)

Putin got this performance of Gazprom, I must tell that international gas abilities of Mr. Putin are

exaggerated by the media. Yeah, if you compare Russia with Norway, this chart shows monthly sales of Russian gas

and Norwegian gas to OECD Europe, Norway was more successful. The gap between Norwegian supplies and

those from Russia was narrowing and if in June 2005, Norwegian exports to this region represented just 42 percent

of the Russian volumes and in the end of the period, the last month is June 2010, Norwegian sales represented

already 87 percent.

It’s hard looking at the financial reports at least of Statoil and Gazprom, it’s hard to tell why exactly and

what are the prices of sales to Europe because Statoil sells a lot of gas to the U.K. But I think Norwegian price must

be substantially lower to give incentives for importers to buy more from gas from Statoil than from Gazprom.

Tony Melling already used this quotation of Mr. Putin. I took it from the English version of Putin’s

website, official website. There was also a discussion or exchange of opinions between CEO of Ruhrgas, Klaus

Schäfer, and Vladimir Putin, who is effectively CEO of Gazprom. Mr. Schäfer in August said that it’s time to

change the long-term contracts. They do not reflect the realities of today’s market. Mr. Putin responded in Sochi,

ordering Gazprom to stay tough and not to give in.

(00:38:08)

Today’s Russian business daily, Kommersant, has an interview with Mr. Schäfer where CEO of Ruhrgas

says that – repasts that the Russian context has to be changed, especially the price level which is the base price,

indexation and renegotiation rules has to be adjusted to market realities. He also added a very important line, that

Ruhrgas needs to keep Russian gas imports at the current level, which means a very low level. The German

company, it’s not going to import more gas unless Gazprom changes the contract rules.

Another interesting point that Russia’s pipeline investment program is not – does not depend on market

situation. Gazprom wants to build 25,000 kilometers of new pipelines irrespectively, whatever the market situation

is. The new version of the Russian natural gas strategy to 2030, which is gas plan, has some controversial lines. For

instance, in the risk section, they do accept a risk of lower gas demand in Europe and surprisingly they add a line that

to minimize the risk of low demand, Gazprom is building – expanding export pipeline capacity, which is kind of

inadequate reaction I think.


In my view, there is serious risk of bankruptcy of Gazprom because of huge costs to be – huge capital to be

invested into the expansion of pipeline system, which is not needed. So Russia gas will be less competitive in the

market because of sharply decreasing load of the whole gas transportation system and increase of transportation

cost. Looking at the Russian part of the market, the growth of domestic price of gas is limited. Just in three years

from now, Russian industries and power plants will be buying gas at prices higher than now in the U.S.

(00:41:13)

Yesterday, Vladimir Putin had a meeting with top Russian gas and energy officials and they approved this

2030 gas plan. The surprising part of this meeting was very realistic talk of the energy minister of Russia, which

indicated there is an opposition or some hints of opposition inside the Russian government. Specifically the energy

minister mentioned the scenario of flat gas demand in Europe, which was discussed by the European Union. Just a

few weeks ago, Putin said that all exports indicate that European market will grow – will need additional 200 million

cubic meters just in 10 years from now.

The energy minister also pointed out that the additional European demand can be met by imports of LNG

from sources out of Russia. Then he worried about the pipeline expansion – output pipeline expansion plan,

mentioning that the capacity will reach 350 billion cubic meters compared to the current, or last year export of 141

BCM. He also questioned the competitiveness of Russian gas in Europe if this pipeline construction plan is realized.

Nevertheless, Vladimir Putin said the 2030 production target at 1 trillion cubic meters per year, which is nearly 50

percent, about 50 percent increase from the level of 2010.

(00:43:19)

For some reason, Mr. Putin and whoever the authors of the gas strategy, believe that the current market

situation is better than in 2000, 2005, when for instance the Russian industries were buying gas at $12 or $20 and $30

per MBTU – not per MBTU, per thousand cubic meters, which is less than $1 per MBTU. They expect the

consumption to grow faster at the prices of $150 to $200 per thousand cubic meters.

In my view, the unrealistic demand and production numbers are needed for one reason, to justify the

construction of the 25,000 kilometers of new pipelines. It’s all about kickbacks. Thank you. (Applause.)

MR. VATANSEVER: Thank you, Mikhail. Our next speaker is Hidehiro Nakagami. He will provide the

importers’ perspective in the changing global gas markets. Hidehiro Nakagami is a vice president at Tokyo Gas and

he’s representing Tokyo Gas in their New York office. He is managing the research about Atlantic LNG markets

and supply demand in the U.S., and in the past he has been also in charge of spot trading and LNG inventory

management of Tokyo Gas.

(00:45:13)


HIDEHIRO NAKAGAMI: Thank you. Thank you for your kind introduction. Again, I am Hidehiro

Nakagami from Tokyo Gas. I’m based in New York office right now but talking about my career in the past, I’m

more on the commercial side rather than on analyst or research stuff. So if I could share with you today about what

had happened up to now and what could happen in the future in the market of Asia, or Japanese market, talking

about LNG.

So it’s my agenda. So this slide really shows the energy demand and supply in Asia. By the way, I really

appreciated what Tony has said. We as Japanese or in Asia, we are in a market where really 100 percent constrained

almost. So we are in a mindset of the constrained world, whereas you in the U.S., or Europe, even Europe is more

liquid compared to the Japanese market or Asian market. So I’m from that kind of world to express these slides

today.

(00:46:30)

Okay, so these slides really show energy demand and supply in Asia. This bar chart really made by Institute

of Energy Economics Japan, what we call IEEJ. They expect the energy demand in Asia would be somewhere in

between 200 and 300 million tons per annum. With this slide, what I would like to specifically emphasize is that the

orange part, which they called portfolio LNG, which was originally destined for Atlantic market but thanks to the

weak demand in Europe or Atlantic, we could enjoy this portfolio LNG, which had been and could be diverted to

Asian market.

This volume would affect the prices in Asia, of course in Japan too. This portfolio LNG would be really

supplying Asian demand up until sometime when this portfolio LNG would find strong demand somewhere else

other than Asia. Next slide shows energy demand in traditional Asian market; traditional I mean Japan, Korea and

Taiwan here. As you can see, up to 2030, we will have a strong increase in LNG demand. But as for the long term,

demand outlook for power generation in Asia is expected to shrink significantly.

According to the government’s strong will to decrease CO2 emissions, which is expressed by the strategic

energy plan in June this year, whereas on the other hand, a natural gas shift from oil, especially in the industry sector,

in city gas business in Japan would grow significantly, roughly more than 20 million tons per annum. So talking

about Japan specifically, we will still see the transition from oil to natural gas rather than more shift onto the power

generation sector. Talks about the Korean and Taiwanese demand, they are also recovering more strongly from the

recession.

(00:49:09)

One of the important factors we have to carefully look at includes the demand-supply gap that has resulted

from the gas industry restructuring happening in Korea. As for Taiwan, we have to carefully look at the four nuclear

power plant in Taiwan when we look at the demand from Taiwan. So even bigger uncertainties are China and India

where policy priority either over pipeline or energy imports is not still clear – (inaudible) – IEEJ forecasts that China


LNG demand in 2020 would be 24 million tons per annum whereas Wood Mackenzie expects that to be 46 million

tons per annum. So with that you can see high range of the outlook based on each institute or consulting firm.

One of the important factors for China’s energy demand in the future is that whether Central Asia and

Russia will continue to supply the majority of their gas to Europe or they will become swing producers between

Europe and Asia. Now, talks about the supply side, looking at the conventional gas supply potential for Asia, there

are ample supplies, especially in Australia and Russia.

(00:50:41)

As previously mentioned, LNG cargoes are being and will be diverted from Atlantic market too. This cargo

flow, once again, would affect landed LNG prices to some extent or to a large extent in the future. Additionally

there are plans of new types of LNG projects that utilize new technology such as floating LNG in Southeast Asia.

In addition to conventional gas resources, there is a number of unconventional gas projects, not only the

pipeline gas but also LNG. I’m talking about CBM-based energy projects that are around Australia east side of

Australia. One of them is almost close to commercialization and we are one of the buyers from such kind of

unconventional LNG resources, we as Tokyo Gas.

China is believed to possess significant shale gas potential and exploration and production are being already

implemented in areas like Chungking and Szechuan. While resource base of unconventional gas is huge, there is

uncertainty about shale gas development in relation to mainly environmental as well as political consequences.

(00:52:12)

So talks about the global energy flows, traditional LNG flows are from Southeast Asia, Australia, Middle

East to Northeast Asia, as you can see the big arrow right-hand side; another big flow is from Africa to Europe, as

you are already aware. Fuel trades have been made between Asia and Atlantic market. However, Middle East,

especially Qatar, has emerged as the swing producers in new gasification (ph) and regasification tunnels have been

constructed in many countries. The price difference between markets are mainly Atlantic and Pacific.

With that situation, we expect liquidity of LNG market to be enriched. But here I mean liquidity is not so

liquid as American or not so liquid as European. Again, we are in a really constrained word, we as Japanese or Asian

market. So thanks to portfolio LNG, which I mentioned earlier, we have been seeing the entire regional trace and

expect that situation to be continued until these supplies find solid demand somewhere once again. Traditionally,

pricing varies between the regions – crude oil linkage in Asia, oil production in continental Europe and hub-based

pricing mainly in the U.S. and U.K.

But hub-based pricing is becoming more influential recently in continental Europe because, as many people

have already mentioned, they are succeeding to reflect the current demand-supply balance to their prices, not only


the spot but also the contract prices. Hub prices decreased significantly below oil link prices. Again, this created the

huge price differential between Atlantic and Pacific. Due to the fact where portfolio LNG being diverted from

Atlantic to Pacific, spot based pricing is not only being influential in Europe but also would be influential in some

way in Asia again.

(00:54:53)

With that said, we can tell that the interactions between Atlantic and Asian markets are being increased not

only physical flows but energy pricing as well. Talks a little bit about the European energy transactions, vertical axis

shows the million tons per annum imports to Europe whereas the horizontal axis shows the timeline. As you can

see, although the natural gas demand in Europe has been deceased due to the recession mainly, they have increased

the import of LNG. Mostly they have increased short and short term contracts, which is of course linked to spot

price, meaning hub price based, load priced LNG.

So here’s my summary. So there are several points that I would like to emphasize. Firstly, that everyone

should know or should be already aware is that there would be ample supplies in the future from conventional as

well as unconventional almost all over the world. Secondly, pricing changes in continental Europe has been resulting

in downward pressure on natural gas prices on time contract; again, not only the spot but also the term contracts.

That is a key issue.

(00:56:47)

Spot-based pricing brings some influence on Asian market, that will bring cross-regional trading from

Atlantic to Asian market as a catalyst, which is good for importers like us in Japan. This will also bring good

opportunities for Atlantic-based LNG players or LNG sellers bruise they can find any new business opportunities in

Asia, which is historically and will be probably – they have a higher price compared to the ones in Atlantic so that

they can enjoy this economic benefit as well.

This LNG flow from Atlantic to pacific will stimulate – (inaudible) – price competition in Asian market,

which again has been really constrained market only by traditional LNG suppliers. If prices are being adjusted in

Asia, more natural gas in downstream, then more LNG sells by suppliers, which will bring benefit to suppliers as

well. That had been my presentation.

Lastly, although we as Tokyo Gas is really local distribution company in Japan, we are vertically integrated

local distribution company, which I mean we do own upstream equity in somewhere around Australia and we do

also have a fleet, LNG fleet, and we do own LNG receiving facilities and distribution networks. So although we see

ourselves as a local distribution company, we are very much global company as well. So we do own offices around

the globe, New York where I am based in, of course the headquarters is Tokyo. Thank you so much. (Applause.)

(00:59:06)


MR. VATANSEVER: Thank you very much, Hidehiro. I would like to start the discussion now and we’ll

have a Q&A session and I guess we have about 20 minutes for that and after that, Chris Goncalves will provide a

wrap-up which will summarize and raise quite a few additional questions as well. I’d like to kick off the discussion

by asking a question directed at Vello first. You provided a great overview of the constraints that are facing

European unconventional gas development. I just wonder whether if you imagine a scenario where Europe is

shifting towards hub-based pricing predominantly. Would that be a constraint or would that foster development of

unconventional gas in Europe.

MR. KUUSKRAA: I think if you would add to that what do you think the hub-based price would be and

then I can answer that question. I think it really does come down to the quality of resource and its economics.

We’ve seen in the U.S. unconventional gas change from the highest cost resource to now the lowest cost resource. It

took some time. That was a 30-year process.

(01:00:30)

It shouldn’t take as long in Europe because we can learn from the past. But there are other constraints that

will stand in the way. I don’t expect much to happen in the next five to 10 years but after that, I think basically it’s

uncertain at that point if the gas quality is really high, there will be large amounts of domestic, starting with Poland

and then possibly in Germany, potentially in Australia, some in the Eastern European countries as well, Ukraine,

Belarus and so on.

MR. VATANSEVER: Thank you, Vello. Yes, please?

MR. KORCHEMKIN: Vello, as far as you might, when you do expect the first results of Polish – cost

results for Polish shale gas?

MR. KUUSKRAA: Okay. Well, part of it is being developed now. It really becomes an issue of public

disclosure of results, like I mentioned some of the exploration wells that are going on and I’ve got a good idea of

what the costs are. The costs are quite high, probably looking at well costs of $10 to $20 million. However, what

the big uncertainty is what’s the productivity and we just at this point don’t know. That has not been made public.

It will be up to how much will be required of companies to divulge. If I can see basically some fundamentals and

early IP and tie that to geology, we can get that answer relatively quickly. Hold that back, it could be some time.

(01:02:24)

MR. KORCHEMKIN: Are we talking about years?


MR. KUUSKRAA: If they’re allowed to hold the test results confidential for two years, for example, then

that’s right. At the point where the test results are available, those who know the geologic – (inaudible) – was done,

can tie that and begin to extrapolate across these various spaces.

MR. KORCHEMKIN: Thanks.

MR. VATANSEVER: Thank you. Let me open up the session for question and answers. Please identify

yourself and also the person whom you would like to answer the question, as we have quite a few presenters. If you

like, you can still ask questions for the author of the study. He’s here.

(01:03:17)

Q: So many questions today. Robert Johnson, Eurasia group, again. Mr. Korchemkin, I really enjoyed

your presentation. I share your skeptical outlook on Gazprom and I think the number of people who are willing to

believe in a Gazprom bankruptcy now versus three years ago has increased. But I’d be interested in your opinion on

another side. What could turn it around for them? How do they avoid the debacle that you’re outlining? Is it a

matter of just cutting back on some of those pipeline projects or being more flexible in pricing? Can they make that

switch to more flexible pricing in the market? I’d be curious to know your thoughts.

MR. KORCHEMKIN: The most important thing – (inaudible) – something that can change the current

performance for that. We need to stop the construction of – (inaudible) – and stop the – (inaudible) – the old plan

of Gazprom has seemed to involve reserves to be linked with the currently producing reserves of West Siberia –

(inaudible) – exactly the right, the new production – (inaudible) – so it’s a perfect combination – (inaudible) – and

utilization of existing capacity. Currently, Gazprom plans to attend good working corridor of pipelines from West

Siberia to central Russia and Europe and build a new system – (inaudible) – will be much lower and the cost will be

much higher.

Secondly, as to the export sales, we need to basically the benefits from reduction of price whereas it’s better

to have smaller product than not to have any product at all and they are doing exactly that. We are certainly in the

middle and we don’t have any new sales in the near future. Nobody wants to buy Russian gas and they are unable to

sell new gas and sign new contracts at the lower price, competing with the existing contracts – (inaudible.)

(01:06:15)

MR. TERZIC: A question, how much can Russia squeeze the domestic price of gas? Is there room for the

domestic price of gas to cover some of Gazprom’s shortfall?

MR. KORCHEMKIN: This is a very good question. Russian industry is a very low efficiency, fuel

efficiency. So I know some sectors it might seem for – (inaudible) – Russian top price they can survive – (inaudible)

– and so in the immediate term, particularly in Russian steel sector, steel production, fertilizer production, some


other chemical production, they will be out of business. It’s like, if you wish, it’s like – (inaudible) – government

decides to – (inaudible) – cheap domestically resources like – (inaudible) – subsidizes the whole Russian Federation –

(inaudible) – the truth is it cannot be done in three years’ time, as the current plan seems.

Russian countries do not have free capital to invest in improvements in energy efficiency. It should be,

again, most importantly – (inaudible) – position and high prices. The real market price of gas in Russia is much

lower than what Gazprom believes. Until I think two years ago, December 2008, Russia had gas exchange where –

(inaudible) – a year were sold by independent – (inaudible) – free market price and the free market price has never

been even a half of the – (inaudible) – that’s why Gazprom has closed the gas exchange – (inaudible.)

(01:09:12)

MR. VATANSEVER: Thank you, Mikhail. Any other questions?

Q: John Lyman of the Atlantic Council. What if the current plan of Putin’s is to keep the pressure on

Europe and the Nabucco Pipeline, et cetera, but what if there’s a possibility there’s a real game plan is to not build all

the pipelines in any case but to simply start preserving the cost of the budget in order to start moving pipelines more

in towards China and India?

MR. KORCHEMKIN: Yes, the market does not involve the construction of any pipeline toward Europe

right now. First of all, the current export of Gazprom is about 200 MBTUs a year while the natural gas exports are

about 140 and they have never been at full capacity ever.

(01:10:20)

So from the standpoint of European consumers, it’s good to have excessive capacity because it would put

the pressure but not the producers I think understand the risk except for Gazprom. They simply consider it as –

actually it’s an old plan I think of Vladimir Putin who wanted to encircle Europe by Gazprom and the idea was to

buy all gas producers around Europe and resell it on Gazprom’s terms.

But fortunately for European consumers, there is too much gas around and nobody can buy all of it.

Simply, for instance the Turkmenistan reserves, when this doctrine was developed, the Turkmenistan reserves were

underestimated and Russia wanted to buy all of them, all Turkmen gas. Now, they see it as impossible, same with all

other reserves brought in by new technologies and geological efforts.

If you look from the standpoint of Turkmen or Azerbaijan producers, Nabucco is the shortest link between

them and Europe. A route through Russia and South Stream is 1,000 kilometers longer and costs are higher. So the

netback from sales through Nabucco would be higher than in case of selling through Russia. There’s another point

why Russia does not need all the South Stream pipeline. It is designed to re-export Caspian and Turkmen and

Azerbaijani gas.


(01:12:28)

But this business does not bring, generate any profits for Gazprom. Gazprom buys it at the price equal to

Europe price minus transmission cost. There may be dollars of profit, not more. But the export basket of Gazprom

remains the same. If you add more foreign gas, which is exported at zero profit and tax free, then you have to

reduce the Russian gas, which is the major generator of export duties for the state budget and profit of Gazprom.

So it’s a no-win situation.

Q: What about the possible movement to China and India?

MR. KORCHEMKIN: Expansion of the current LNG plant is the best way. But Gazprom is trying to

combine it with extremely long pipelines, which is a way of making contractors and intermediaries of Gazprom

wealthy. So if you add additional transportation costs through long and very expensive pipeline, that would kill the

whole project. But LNG is a very good option.

MR. VATANSEVER: Vello, you have a question?

(01:13:56)

MR. KUUSKRAA: Yeah, if I should just stand up? About a year ago, Gazprom dismissed European, both

Western and Eastern European unconventional gas as a myth and I’m curious to know what their viewpoint is today.

Is it still that or is it emerging?

MR. KORCHEMKIN: At the most recent shareholders meeting of Gazprom in the summer, Miller, the

CEO of Gazprom, repeated that shale gas is a PR similar to global warming. All of it is just paid publications by

Western companies presumably. But two weeks ago, Gazprom placed a tender to organize shale gas conference. So

it looks like they have changed their mind and started to look at shale gas seriously. But they would still keep naming

it a myth.

MR. VATANSEVER: Okay, I see a lot of the attention is on Russia, which is naturally the largest exporter.

Are there questions that are not related to Russia especially?

(01:15:40)

Q: David Godfrey, Department of Energy. This is a question for Mr. Melling. I’m wondering about – I

guess two-part question – today and March 2011, what is the capacity for individual power generators and large

wholesale consumers, cement facilities, et cetera, to access these spot market prices directly in Europe and I guess

the second part of that question is if they are able to access these markets directly, what is the future of E. ON, Eni,

et cetera, these large wholesale, quasi state energy buyers? Thank you.


TONY MELLING: So was that specific to any particular country?

Q: I’m interested in E. ON in particular.

MR. MELLING: In E. ON, yes, yes. Okay, I think in Germany it still depends on where you are as to

what prices you can get because as the gas flows down the gas chain to the smaller distributors, it gets considerably

more expensive and so people like cement producers, for example, would not get a gas price by the time it reached

them that would match the fuels that they’re currently using. I mean, cement manufacturers are notorious for using

the cheapest possible fuel that they can get away with from – (inaudible) – perspective.

(01:17:21)

Yes, I mean, in theory there’s a full connection between the border and the end consumer and anyone can

access that, but as I say, it does get more expensive. So consumers can also access – sorry, power generation

consumers can also access gas theoretically at any point in Germany.

The problem with power generation – I mean, there are a number of problems but one of the biggest ones

is this mismatch between the power nominations and the gas nominations, which is improving but unless you have a

nomination procedure where you can actually nominate the right amount of gas for a prompt period in power

generation, then you have this mismatch and in that case it restricts the short term opportunities and that’s what’s

happening across Europe, the short term opportunities are very difficult to access.

In fact that’s one of the things that the E.U. has on its agenda for the next stage of legislation is to provide a

much better match and a much better interface between gas and electricity, particularly CCGT power generation

markets.

MR. TERZIC: (Off mike.)

(01:18:51)

MR. MELLING: Yes, nominations for pipeline capacities just don’t match the nominations for the

electricity markets in a lot of areas of Europe. There’s for example the balancing mechanism in gas can be in some

cases daily. In some cases it’s hourly. In electricity, it can be half-hourly, I think even quarter-hourly nominations.

So you don’t have an exact match. Yeah.

MR. KORCHEMKIN: I’d like Tony and Hidehiro to comment on one thing. Hidehiro said that

historically Asian, specifically Japanese market, has been the one with the highest price of LNG but this has changed

lately. We have seen prices in Japan, LNG prices in Japan below the price of pipeline gas in Europe. So what do

you think will be? Is it a sign of globalization or just a trend of unexpected thing to become true, same as –

(inaudible) – of continental companies in Europe back 10, 15 years ago?


MR. MELLING: Yeah. I don’t think I was the one that said LNG prices in Japan were higher than

elsewhere, although quite often they are. There’s quite clearly some lower priced cargo getting through to that

market. It is becoming a slightly more liquid market, which is a good thing. Yeah, I think the spot market is always

going to be quite responsive to price, particularly in LNG.

(01:20:59)

MR. VATANSEVER: Yes, I’ll take one final question before the wrap up.

MR. NAKAGAMI: Sorry, could I answer that question?

MR. NAKAGAMI: So I am sorry that I am not really aware that there has been lower prices in Europe

than Japan in the past or recently or whatever. But the one thing that I should have mentioned in my presentation is

that the question is the European prices now affecting in Asia or in Japan. The answer would be yes. But it’s really,

really limited and having understood the negotiations between traditional energy buyers and traditional energy

suppliers in the Asian market, to my knowledge there have not been yet really the changes of indexations from oil to

let’s say – (inaudible.)

(01:22:14)

So in considering that most of the energy imports through Asia, or specifically Japan, is comprised by long

term traditional contracts, so although I repeatedly said that European prices are really affecting, but the magnitude is

really limited. So to answer your question, it might be affecting something, but not really entirely change the

paradigm yet.

MR. VATANSEVER: Okay, we’ll have the last question.

Q: My question is the second largest natural gas resources are in the Islamic Republic of Iran and it hasn’t

been mentioned here. How do you – I don’t know, maybe one of you or someone else – how do you see all of these

resources in the next 25 or 30 years? They haven’t been tapped much but they are there.

MR. MELLING: Yeah, yeah. Shall I answer that? What Europe is looking for is reliable supplies. We’ve

already seen – we’ve seen some supplies coming through from Iran through Turkey and there have been a lot of

quality problems with those. So Turkey has actually cut down a lot on the volumes. It’s very difficult to tell whether

that’s actually that they just don’t want the gas, they’ve got too much gas or whether it is real quality problems. I’m

sure there’s an element of quality problems there.

(01:23:59)


I mean, I think as soon as they get the quality problems right, they get the supplies right and they come up

with a convincing package, then I think that will be attractive to Europe. I think there are people in Europe that will

buy it and it will probably come through Turkey. So it’s out there as a resource for the future. But I think as people

see it right now, it’s just not at a state of development where people would consider buying it. Assuming that trade

restrictions go away, I could see it flowing one day. But then again somebody else might come along and displace it.

MR. VATANSEVER: Great. We are moving on to the wrapup session. Chris Goncalves is going to

provide this very broad overview of the gas markets. Let me say just very quickly a few words about him. He is a

vice president in CRA’s energy and environmental practice. He has over 20 years of experience in the energy and

financial industries.

He has a broad expertise in strategic business planning, economic and market analysis, regulation,

commercial negotiations, project development and financing, asset transaction, international cargo markets and the

UN clean development mechanism and he is an expert in testimony for energy litigation and arbitration disputes. He

has advised clients on energy infrastructure and commerce involving LNG, natural gas, oil, power generation and

renewable energy. His experience spans the Americas, Western Europe, Eastern Europe, Eurasia and the Middle

East.

(01:25:48)

CHRIS GONCALVES: Thanks, Adnan. First of all, let me congratulate Tony on an excellent paper. I

think you’ve truly captured the drama of the moment in terms of what’s going on in Europe. The metaphor, the

battleground, is appropriate, and it’s fascinating to see somebody with your wealth of knowledge putting together

really a tour de force about the issue and understanding very clearly where the battle lines are drawn. So I think

that’s been an excellent discussion.

Also I wanted to congratulate Adnan on putting this together because this is – from my perspective, I go to

a lot of conferences. I participate in a lot of discussions and this is one of the best sort of global gas discussions with

a wide variety of perspectives really from around the world, truly expert in Asia, in Europe, in Russia and so forth,

United States, that we’ve really got a great view of perspective.

(01:26:47)

So this is a very tough act to follow and I’m going to do my best to wrap it up. I don’t think there’ll be too

much time for questions afterwards, although if you would like to have a few, I’d be interested in the discussion or

I’ll stick around for the coffee.

I’m going to give some data and then I’ll try to address the pressing question at the end. I’ll be brief here

because we’ve already addressed the issue of the growth in shale, really tremendous growth of over 10 BCFD over


the last six years. The difference between my number and Vello's is just the inclusion of the Canadians and even

over approximately 7 BCFD just in the last several years, really tremendous growth by any measure.

Actually let me just put that in perspective. The last four years at 7 BCFD, that’s about 70 BCM. That’s

about 70 percent of the U.K. market, just to give it a context. I looked into the liquefaction project news over the

last several years to see if my hypothesis that LNG has been pulling back as a function of this vast supply of shale

was correct. A lot of people were arguing that that has happened or is going to happen and it’s not actually correct.

(01:28:15)

There have been some cancellations and suspensions in the Middle East, namely the two Iranian projects.

There was a small cancellation in the Atlantic. But there are also very substantial additions in the Pacific, a lot of new

Australian projects coming to market, so that you get a net increase of 4.4 BCFD of capacity or about 44 BCM of

new LNG proposed for the market just over the last few years and we’ve already identified that the Russians aren’t

backing off either.

So when you look at the impact on prices, we have here a chart of WTI oil index, Henry Hub, the major

U.S. hub price, NBP in the U.K., and BEB, the German – I’ll call it the quasi oil index price, although arguably lately

with some gas market impacts creping in and you can see a very distinct change in the trend from pre-2006 to after

2006. Little bit of distribution around the onslaught of the crisis in late2008 but then pretty quickly back to the same

pattern where you have U.S. and European gas prices ranging from half to two-thirds of oil prices on a BTU basis.

(01:29:36)

So what’s going to happen in the future? We’ve discussed and identified that liquidity is probably the most

critical issue to understanding thinking about whether prices will continue to become more competitive, liberalized,

whether the spot market prices, the LNG liquidity will continue to pressure long term contract prices, index prices in

Europe and around the world. So let’s go through supply and demand and see where we may get. These are

independent results coming from our global gas and LNG models.

In a moderate scenario, and I want to emphasize moderate scenario for climate and environmental

compliance, there’s nothing substantial here in terms of a big carbon policy on a global scale or anything like that but

there is continued growth in North America, Europe and Asia in gas that’s related to gradual switching from coal to

gas in the power sector and so forth.

You see that total gas demand in the major LNG importing regions –we’re including a few major producers

like Russia and Australia – but the places that imported LNG growing by about 62 BCFD by 2020. Very substantial

growth of I think about 30 BCFD in Asia at about a 6 percent clip but also meaningful growth in the Middle East

itself as well as about 9 BCFD, 90 BCM in Europe and about 70 BCM or 7 BCFD in the United States.


(01:31:11)

On the supply side, unconventional gas production and LNG production could each increase over 20

BCFD, which would trump a 10 BCFD increase in pipeline imports from FSU and Africa into Europe and Asia.

This Is over the next decade we are making those adjustments that were referred to by Mikhail I think in our FSU

scenario we’re including Nabucco, Nord Steam and Medgaz and excluding just about everything else. We’re

including about 5 BCFD of capacity into Asia from FSU, including the Caspian, and all together that roughly 15

BCFD of capacity running at an approximately 70 to 75 percent load factor gives the additional 10. But I think it’s

quite striking that the LNG production capacity and the shale capacity are really forcing the pipeline gas back into

the future.

North America, contrary to some perceptions, will need LNG for growth. Unless you assume a very

conservative demand scenario or a very optimistic shale production scenario and we have the range of scenarios that

we’re working with here on the screen in terms of the brown and orange colors. You just don’t get the additional

gas in the United States needed for the growth of the 7 BCFD and that’s simply because the decline in conventional

production is so substantial.

(01:32:45)

Essentially the shale production growth is required to offset that decline and in an optimistic scenario it may

exceed that decline by some measure. But to truly achieve additional growth, some level of LNG will be required.

The green area reflects our view of LNG available to the United States after every other market in the world has

been served.

So that’s in a sense you could say surplus LNG, or surplus available LNG available to North American and

if you look at the demand numbers on the chart there, you’ll see the United States requires approximately half of

that. So there’s still some surplus out there.

Looking at prices, comparing shale gas production cost to our shale gas model with an outlook for LNG

opportunity cost prices driven by a forecast of European prices, you see that only in the short term is there really any

intersection.

Overall the range of shale gas production from the highest kind of cost we’re looking at including a

reasonable return to the lowest costs is pretty consistently below the opportunity cost of an LNG cargo diversion

from Europe. What that says to us is that he U.S. will import surplus LNG only, will do it on a seasonal basis and it

will probably be able to get essentially a discounted price for the LNG compared to a European price. In other

words it will be LNG that Europe does not require.

(01:34:22)


So where does it all go? As far as this notion of how deep the spot market prices penetrate into Europe or

to whether and to what extent that kind of pricing structure starts to make itself felt in Asia, you have to understand

first of all that there is a reasonable chance of a surplus gas supply continuing over the next decade, not just for a

couple of years as Gazprom suggests, that North American prices for gas are likely to be below the world level for

LNG and then you can look at the shipping differentials in the various basins. These are very high level figures.

They’re based on a lot of averages. You can’t take every route for every cargo and simplify it very easily.

But we’ve done some weighted averages and some simple averages just to give a flavor of it. If you look on

the left side of the chart for North America versus Europe, costs from the Middle East, which is clearly the largest

supplier, cost about 30 or 40 cents more than it costs to go to Europe. So you would think the price signal into

Europe would be around that order of magnitude higher but still based on gas.

(01:35:38)

Looking at Asia, it costs – for several of the markets, not India which is so close to the Middle East, on that

same order of magnitude more to go to North America versus going to Asia and some of the Asian markets like

Japan and Korea from a shipping cost perspective could be – and these are average shipping costs over a decade –

could be on the order of rough parity with European pricing, just to give a flavor of where those price signals might

be.

I wanted to use this slide to tee up discussion but I didn’t realize that the discussion would have been over

by now. But I’ll just throw out my two cents on that and if we have some time for discussion that would be great. I

guess my own view is that the culture of oil index pricing in Asia, because as Hide said, the culture of the gas market

in an island economy or a peninsula economy like Japan and Korea, an economy that’s not traditionally integrated

with other gas markets, doesn’t have a lot of cross-border pipelines is such that the perception at least is of

constraint, is of limited supply and dependence on LNG for supply.

So the question becomes to what extent any level of surplus available in the market starts to break down

that perception and create opportunities to renegotiate existing contracts, even on a term basis but with a different

pricing index or to take some risks on a certain level in a supply portfolio on spot market pricing. I think the signals

are there. The numbers that you saw in our surplus figures are not enormous. There has been some pullback on

supply and if you take a conservative view on some of the Russian and FSU supplies by pipeline, then you do get a

tightening over the market of the market over the next decade.

(01:37:36)

But in an environment of surplus, with a lot of competition coming from the Australians and the Qataris,

from new trains coming to market, you probably also know the Qataris have been shut down partially for the last

half year trying to basically reengineer some of the terminals and trying to get out more supply from those terminals.


All that volume is coming back to market next year. I think there could be a two to five year period where there’s

enough supply on the market that the buying power is substantial and you’ll see increased risk taking.

I don’t believe that oil index pricing is gone or will go away any time soon. I don’t think there’s that much

market power and I also think those old habits and the culture of buying gas in that way will die hard. So I think it’s

a shade of gray, somewhere in the middle and it’s more likely to be a process subject to dispute and negotiation,

maybe dispute in Europe, renegotiation in Asia, than it is to be anything as dramatic as a global revolution. So those

are my comments. Any questions would be great.

(01:38:40)

MR. VATANSEVER: Thank you, Chris. Unfortunately, we will not have time for questions as this place

needs to be vacated pretty soon. I would like to thank each of our presenters for excellent presentations and also I

would like to thank all of you for coming here and especially for staying with us throughout these two panels. It’s

been over three hours already. Thank you very much. (Applause.)

(END)

THE CHANGING FUNDAMENTALS OF GLOBAL GAS MARKETS: … · ADNAN VATANSEVER: Good morning. (00:00:11)...

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