**4. US and Canadian liquefied natural gas**

US and Canadian gas consumers are averse to long-term physical contracts—the traditional mechanism for securing liquefied natural gas (LNG) in the world market. The US and Canadian natural gas market is wedded to spot transactions. This is partly a reaction to costly experiences unwinding long-term, reserve-based, bundled supply and transportation contracts that were well above spot prices a few decades ago, and partly a reflection of just how comfortable market participants have become in relying on the spot market whenever they need to buy or sell physical gas.

Globalization of the Natural Gas Market on

0

Fig. 3. Global LNG Supply Growth

**4.3 Oil-indexation, Yen and Euros** 

their risk, at prices that have proven to be desirable.

Source: EIA, Barclays Capital

Euro.

1

2

3

**billion cubic feet per day**

4

5

6

on line.

Natural Gas Prices in Electric Power Generation and Energy Development 207

This boom in global LNG supply is facilitated by a second significant event – the intermediation of energy companies as supply off-takers for many new liquefaction projects. Sensing a growing global need for new LNG supply, a number of new supply projects were launched, with energy companies – rather than end-users – contracting for the new supply. There is essentially no unsold LNG supply from liquefaction projects that are under construction. Committing to LNG supply without an end-use buyer may be risky. The large, liquid US market provides a convenient destination of last resort for any supply that does not otherwise find an end-user by the time the liquefaction project comes

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Energy company intermediaries have never intended to hold vast quantities of LNG supply for spot market sales. With global prices for natural gas remaining robust, and with strong demand growth for natural gas in non-North American markets, a growing number of new long-term contracts have allowed these energy companies to commit this LNG to end-users. These long-term end-user contracts allow the companies controlling the supply to reduce

Beyond new, long-term LNG contracts to non-North American end-users, two additional powerful trends are driving LNG away from US shores. First, typical European and Asian long-term LNG contracts are linked to oil prices. With oil selling at an increasing premium to natural gas (Figure 4) oil-linked LNG in non-US markets carries an automatic premium to US Henry Hub at current market levels. Many countries that import LNG do not have functioning gas markets; thus, prices must be linked to another commodity, typically oil. Oil-linked LNG provides buyers and sellers an opportunity to hedge. The second trend is the strength of the yen and euro compared with the US dollar, with the dollar declining 9% against the yen over the years (2005-2007), and falling 25% against the

The LNG industry, by contrast, is wedded to long-term contracts. Two drivers are responsible. First, long-term contracts with credit-worthy off-takers were necessary to underpin the large capital investments for the first several LNG projects. Second, buyers who must depend on LNG and are thereby displacing other fuels, require dedicated upstream resources; liquefaction trains and tankers for assurance the gas will be there when needed. The US and Canada (and the UK) attract supply with price, while Europe and Asia attract new supply with long-term contracts.

Flows of LNG to the US are not simply a function of the relative attractiveness of North American spot prices. The lack of US and Canadian commitment to LNG clashes with the dependency that North American countries will have on this new supply.

#### **4.1 Power sector need for LNG**

Power sector demand growth alone will boost the need for gas. Electricity consumption has grown at an annual average rate of 1.3% per year in the last decade. With the latest round of new power plant capacity more than 90% gas-fuelled, natural gas is serving a large and growing share of power sector demand growth. The outlook is for more with natural gas slated to serve the larger share of power plant additions ahead. Power sector use of gas added an average of 0.75 bcf per day of gas demand each year in the past decade (Figure 2).

Source: EIA, Barclays Capital

Fig. 2. Gas Consumption in the Power Sector

#### **4.2 Global LNG supply boom**

The expected reliance of the US and Canada on LNG parallels two significant events in the LNG industry. The first is a boom in global LNG supplies. These have grown 9 bcf per day since the start of the last decade and are set to grow an additional 9 bcf per day by the end of the decade (Figure 3). The 5 bcf per day of LNG supply additions in 2008 would be the largest single year of supply additions in the industry's history.

The LNG industry, by contrast, is wedded to long-term contracts. Two drivers are responsible. First, long-term contracts with credit-worthy off-takers were necessary to underpin the large capital investments for the first several LNG projects. Second, buyers who must depend on LNG and are thereby displacing other fuels, require dedicated upstream resources; liquefaction trains and tankers for assurance the gas will be there when needed. The US and Canada (and the UK) attract supply with price, while Europe and Asia

Flows of LNG to the US are not simply a function of the relative attractiveness of North American spot prices. The lack of US and Canadian commitment to LNG clashes with the

Power sector demand growth alone will boost the need for gas. Electricity consumption has grown at an annual average rate of 1.3% per year in the last decade. With the latest round of new power plant capacity more than 90% gas-fuelled, natural gas is serving a large and growing share of power sector demand growth. The outlook is for more with natural gas slated to serve the larger share of power plant additions ahead. Power sector use of gas added an average of 0.75 bcf per day of gas demand each year in the past

2003 2004 2005 2006 2007 2008 2009 2010

Power demand growth

The expected reliance of the US and Canada on LNG parallels two significant events in the LNG industry. The first is a boom in global LNG supplies. These have grown 9 bcf per day since the start of the last decade and are set to grow an additional 9 bcf per day by the end of the decade (Figure 3). The 5 bcf per day of LNG supply additions in 2008 would be the

Annual US + Canadian total demand growth

dependency that North American countries will have on this new supply.

attract new supply with long-term contracts.


Fig. 2. Gas Consumption in the Power Sector

largest single year of supply additions in the industry's history.

**bcf per day**

Source: EIA, Barclays Capital

**4.2 Global LNG supply boom** 

**4.1 Power sector need for LNG** 

decade (Figure 2).

This boom in global LNG supply is facilitated by a second significant event – the intermediation of energy companies as supply off-takers for many new liquefaction projects. Sensing a growing global need for new LNG supply, a number of new supply projects were launched, with energy companies – rather than end-users – contracting for the new supply. There is essentially no unsold LNG supply from liquefaction projects that are under construction. Committing to LNG supply without an end-use buyer may be risky. The large, liquid US market provides a convenient destination of last resort for any supply that does not otherwise find an end-user by the time the liquefaction project comes on line.

Source: EIA, Barclays Capital Fig. 3. Global LNG Supply Growth

### **4.3 Oil-indexation, Yen and Euros**

Energy company intermediaries have never intended to hold vast quantities of LNG supply for spot market sales. With global prices for natural gas remaining robust, and with strong demand growth for natural gas in non-North American markets, a growing number of new long-term contracts have allowed these energy companies to commit this LNG to end-users. These long-term end-user contracts allow the companies controlling the supply to reduce their risk, at prices that have proven to be desirable.

Beyond new, long-term LNG contracts to non-North American end-users, two additional powerful trends are driving LNG away from US shores. First, typical European and Asian long-term LNG contracts are linked to oil prices. With oil selling at an increasing premium to natural gas (Figure 4) oil-linked LNG in non-US markets carries an automatic premium to US Henry Hub at current market levels. Many countries that import LNG do not have functioning gas markets; thus, prices must be linked to another commodity, typically oil. Oil-linked LNG provides buyers and sellers an opportunity to hedge. The second trend is the strength of the yen and euro compared with the US dollar, with the dollar declining 9% against the yen over the years (2005-2007), and falling 25% against the Euro.

Globalization of the Natural Gas Market on

boost deliveries to North America.

0

Note: \*Estimated. Source: EIA, Barclays Capital

supply can be marketed on a spot basis to buyers.

much as the US and Canadian market, with spot pricing.

2,000

4,000

6,000

8,000

**million cubic feet per day**

10,000

12,000

14,000

16,000

Natural Gas Prices in Electric Power Generation and Energy Development 209

Some utilities have a free-rider approach: let others bring the LNG to market, enjoy the

Global LNG supply growth will moderately outstrip non-North American consumption, allowing deliveries to the US to grow. Regasification capacity and shipping capacity pose no restriction to US imports. Regasification capacity, which registered substantial growth in 2008, should further outstrip available supply to fill it (Figure 5). Should economic growth boom overseas, particularly in Asia, LNG deliveries to the US would dwindle far below the amounts shown in Figure 5. Conversely, faster pace of LNG supply growth or more moderate rates of gas demand growth in the other fifteen LNG consuming countries would

US + Canadian Terminal Capacity

2004 2005 2006 2007\* 2008 2009 2010

It is incorrect to add up all non-North American LNG supply contract volumes and assume these will not be available to the US and Canada. End-use LNG buyers contract for more supply than is needed. This allows surpluses to be marketed in the spot market. New LNG contracts offer greater flexibility to divert cargoes. The large storage market in the US provides a ready destination for surplus volumes. There have even been modest signs of interest in buyers securing LNG supply, notably in California. Thus, a growing slice of LNG

In competition for these supplies will be any market in need. Asian markets, which typically clear on volume and not price, have shown a penchant to out-bid these spot cargoes. European buyers have shown more price responsiveness, while the UK market operates

downward price pressure that results, and buy it on the spot market.

Imports

Fig. 5. US and Canadian LNG Imports versus Regasification Capacity

**4.5 LNG imports to remain de-linked with US spot prices** 

Source: EIA, Barclays Capital

Fig. 4. Growing Oil Premium to Natural Gas (Japanese Crude Cocktail (JCC) oil prices compared with US Henry Hub)

#### **4.4 Standby for LNG**

With US and Canadian end-users averse to long-term physical contracts for LNG the risk remains that, without committing to LNG, it may not be available if needed in the years ahead. It is unlikely that none would be available on a spot basis for a given sustained period in the years ahead, when forecast non-North American gas demand is compared with global LNG supply. Yet, there remains the risk that in any given period, LNG flows could fall to low levels, even zero, depending on events outside of North America. The US and Canada do not have control over LNG flows into their markets.

US and Canadian buyers should not rush out at this time to contract for LNG. This is because:


Some utilities have a free-rider approach: let others bring the LNG to market, enjoy the downward price pressure that results, and buy it on the spot market.

#### **4.5 LNG imports to remain de-linked with US spot prices**

208 Modeling and Optimization of Renewable Energy Systems

Henry Hub Natural Gas

JCC

1999 2000 2001 2002 2003 2004 2005 2006 2007

With US and Canadian end-users averse to long-term physical contracts for LNG the risk remains that, without committing to LNG, it may not be available if needed in the years ahead. It is unlikely that none would be available on a spot basis for a given sustained period in the years ahead, when forecast non-North American gas demand is compared with global LNG supply. Yet, there remains the risk that in any given period, LNG flows could fall to low levels, even zero, depending on events outside of North America. The US

US and Canadian buyers should not rush out at this time to contract for LNG. This is

Financial hedges combined with flexible, short-term physical supply offers fewer

Some LNG contracts include marine risk (as part of force majeure); LNG tankers do not

An energy supplier is more likely to offer a buyer portfolio gas rather than specifically

 If utilities continue to be judged on their purchase prices against the spot market, then a drought of LNG that pushes spot prices higher for everyone presents no inherent risk

 An increasingly smaller amount of LNG remains uncommitted. The opportunity available to sellers of Pacific LNG, for example, is a Japanese Crude Cocktail (JCC)-

A long-term contract represents a tremendous contractual liability of a buyer's balance

linked price. No utilities are interested in signing oil-linked LNG contracts.

enjoy hurricanes, for example. This risk creates a challenge for some buyers.

Fig. 4. Growing Oil Premium to Natural Gas (Japanese Crude Cocktail (JCC) oil prices

and Canada do not have control over LNG flows into their markets.

LNG under a US-destined long-term physical contract.

LNG is not necessarily cheaper than portfolio gas.

headaches for buyers and sellers.

for a utility so judged.

sheet.

Source: EIA, Barclays Capital

**4.4 Standby for LNG** 

because:

compared with US Henry Hub)

**Dollars per MMBtu**

Global LNG supply growth will moderately outstrip non-North American consumption, allowing deliveries to the US to grow. Regasification capacity and shipping capacity pose no restriction to US imports. Regasification capacity, which registered substantial growth in 2008, should further outstrip available supply to fill it (Figure 5). Should economic growth boom overseas, particularly in Asia, LNG deliveries to the US would dwindle far below the amounts shown in Figure 5. Conversely, faster pace of LNG supply growth or more moderate rates of gas demand growth in the other fifteen LNG consuming countries would boost deliveries to North America.

Note: \*Estimated. Source: EIA, Barclays Capital

Fig. 5. US and Canadian LNG Imports versus Regasification Capacity

It is incorrect to add up all non-North American LNG supply contract volumes and assume these will not be available to the US and Canada. End-use LNG buyers contract for more supply than is needed. This allows surpluses to be marketed in the spot market. New LNG contracts offer greater flexibility to divert cargoes. The large storage market in the US provides a ready destination for surplus volumes. There have even been modest signs of interest in buyers securing LNG supply, notably in California. Thus, a growing slice of LNG supply can be marketed on a spot basis to buyers.

In competition for these supplies will be any market in need. Asian markets, which typically clear on volume and not price, have shown a penchant to out-bid these spot cargoes. European buyers have shown more price responsiveness, while the UK market operates much as the US and Canadian market, with spot pricing.

Globalization of the Natural Gas Market on

\*

tce – ton coal equivalent

Rossii" in 2000 - 2006

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

"EES Rossii" 1998-2006

heat at thermal power plants (TPPs).

Source: Annual reports of RAO "EES Rossii"

Heat supplied by boiler plants of agricultural

Natural Gas Prices in Electric Power Generation and Energy Development 211

**Type of final energy and generation sources Gas consumption** 

Table 4 indicates the structure of fuel consumption by the generation companies of RAO "EES Rossii" in 2000-2006 for electricity and heat production. It is virtually impossible in Russia to consider separately the production of electricity and centralized heat at cogeneration plants (CPs), because almost 1/3 of electricity is generated in combination with

Gas, bln. m3 127.1 131.2 132.4 135.6 139.7 142.6 148.1 Fuel oil, mln. t 8.5 7.6 7 6.8 53 49 6.2 Coal, mln. t 120.1 109.6 106 109.3 101.2 104.4 109.2

Table 4. Structure of Fuel Consumption by Subsidiary Generation Companies of RAO "EES

Conversion of data from Table 4 to standard fuel enables the share of each resource of fuel

supply to be indicated for the generation capacities. This is indicated in Figure 7.

1998 1999 2000 2001 2002 2003 2004 2005 2006

Fig. 7. Share of individual fuel resources in fuel supply for generation capacities of RAO

2000 2001 2002 2003 2004 2005 2006

Electricity supplied by fuel-fired power plants 129 / 112 Heat supplied by fuel-fired power plants 65.9 / 57 Heat supplied by industrial and residential boiler plants 81.8 / 71

enterprises 2.7 / 2 Total: 270.4 / 243

Table 3. Gas Consumption for Electricity and Heat Production in Russia in 2005

**mln. tce\*/ bln.m3**

Coal Fuel oil Gas

Source: EIA, NYMEX, Barclays Capital

Fig. 6. US LNG Imports versus Gas Prices (Henry Hub)

This standby method of purchasing LNG attracts it to the US at some times, and not at others. Figure 6 illustrates the historical relationship between US pricing and LNG deliveries. Spot prices are not the primary driver of flows into the US. The general trend in increased deliveries in 2007 was due to more available spot LNG supply, not stronger US prices.

With US and Canadian end-users averse to long-term physical contracts for LNG the risk remains that, without committing to LNG, it may not be available if needed in the years ahead. It is unlikely that none would be available on a spot basis for a given sustained period in the years ahead, when forecast non-North American gas demand is compared with global LNG supply. There remains the risk that in any given period, LNG flows could fall to low levels, even zero, depending on events outside of North America. The US and Canada do not have control over LNG flows into their markets.

Energy information and the New York Mercantile Exchange information is available at the websites: (i) Energy Information Administration (EIA), "International Energy Outlook 2007, www.eia.doe.gov. and (ii) New York Mercantile Exchange (NYMEX), www.nymex.com .

## **5. Impact of natural gas market on power generation development in Russia**

This Section discusses the natural gas market and its impact on power generation development in Russia

A large part of natural gas consumed in Russia is used for electricity and centralized heat production. Table 3 presents gas volumes consumed in 2005 in Russia for electricity and heat production [11].

Of 397 bln m3 of natural gas used in Russia in 2005, electricity and heat generation required 243 bln m3 or 61 %; the remaining 39 % was used by the population and other branches: metallurgy, petro-chemistry, agro-chemistry, etc. Almost the same relation in shares has been observed in recent years.


\* tce – ton coal equivalent

210 Modeling and Optimization of Renewable Energy Systems

Cargoes (LHS)

Henry Hub Price (RHS)

Jan 05 Jun 05 Nov 05 Apr 06Sep 06 Feb 07 Jul 07

This standby method of purchasing LNG attracts it to the US at some times, and not at others. Figure 6 illustrates the historical relationship between US pricing and LNG deliveries. Spot prices are not the primary driver of flows into the US. The general trend in increased deliveries in 2007 was due to more available spot LNG supply, not stronger US

With US and Canadian end-users averse to long-term physical contracts for LNG the risk remains that, without committing to LNG, it may not be available if needed in the years ahead. It is unlikely that none would be available on a spot basis for a given sustained period in the years ahead, when forecast non-North American gas demand is compared with global LNG supply. There remains the risk that in any given period, LNG flows could fall to low levels, even zero, depending on events outside of North America. The US and

Energy information and the New York Mercantile Exchange information is available at the websites: (i) Energy Information Administration (EIA), "International Energy Outlook 2007, www.eia.doe.gov. and (ii) New York Mercantile Exchange (NYMEX), www.nymex.com .

**5. Impact of natural gas market on power generation development in Russia**  This Section discusses the natural gas market and its impact on power generation

A large part of natural gas consumed in Russia is used for electricity and centralized heat production. Table 3 presents gas volumes consumed in 2005 in Russia for electricity and

Of 397 bln m3 of natural gas used in Russia in 2005, electricity and heat generation required 243 bln m3 or 61 %; the remaining 39 % was used by the population and other branches: metallurgy, petro-chemistry, agro-chemistry, etc. Almost the same relation in shares has

Henry Hub Gas Price (dollars per

MMBtu)

Fig. 6. US LNG Imports versus Gas Prices (Henry Hub)

Canada do not have control over LNG flows into their markets.

Source: EIA, NYMEX, Barclays Capital

prices.

development in Russia

heat production [11].

been observed in recent years.

Number of Cargoes Delivered to US

(by month)

Table 3. Gas Consumption for Electricity and Heat Production in Russia in 2005

Table 4 indicates the structure of fuel consumption by the generation companies of RAO "EES Rossii" in 2000-2006 for electricity and heat production. It is virtually impossible in Russia to consider separately the production of electricity and centralized heat at cogeneration plants (CPs), because almost 1/3 of electricity is generated in combination with heat at thermal power plants (TPPs).


Source: Annual reports of RAO "EES Rossii"

Table 4. Structure of Fuel Consumption by Subsidiary Generation Companies of RAO "EES Rossii" in 2000 - 2006

Conversion of data from Table 4 to standard fuel enables the share of each resource of fuel supply to be indicated for the generation capacities. This is indicated in Figure 7.

Fig. 7. Share of individual fuel resources in fuel supply for generation capacities of RAO "EES Rossii" 1998-2006

Globalization of the Natural Gas Market on

Development

Field

Bovanen-

Kharasa-

Rusanov-

Fields of Gydan Peninsula

Moscow Region, \$/1000 m3

because of the uncertainty factor.

Lenin-

Natural Gas Prices in Electric Power Generation and Energy Development 213

Production and preparation

kovskoye 12-15 30-35 53-59 95-109 102

veyskoye 12-15 30-35 54-60 95-110 103

gradskoye 18-20 45-50 60-67 123-137 130

skoye 18-20 45-50 64-71 127-141 134

Table 5. Primary Cost of Gas for the Main Fields of new Gas Production Areas in the

The values of primary cost of gas in Table 3 were calculated on the base of the corresponding specific capital and operating costs that are reasonable only for the present day. Correspondingly, the obtained preliminary figures for primary cost of gas of new gas production areas should be considered correct only for the current gas production. At the time of actual start of gas production from the considered fields the figures can change

According to Table 5, the most probable prime cost of gas in the Moscow region could make up currently \$100/1000 m3--\$105/1000 m3 (for Yamal), \$130/1000 m--\$135/1000 m3 (for the shelf of the Kara Sea) and \$128/1000 m3 (for the fields of the Gydan Peninsula). It can be said with reasonable confidence that the specific capital and operating costs will increase with lapse of time and hence the primary cost of gas in new gas production areas will also rise. Based on different data for the period from 2000 to 2006 the indicated specific costs increased on the whole by 70--100%. Even if the growth rates of specific costs for the period to 2020 are not so high and make up about 50% with respect to those for the present day, by 2020 primary cost of gas will increase to \$150/1000 m3 for the Yamal gas, to 200/1000 m3 for

In the foregoing, only the prime cost is discussed. Hence, the average gas price of \$170/1000 m3 (that was calculated by the gas price formula) can be considered quite real in 10-15 years. So much so, the gas share in new gas production areas in 15-20 years will

Thus, the gas price rise in the domestic market of Russia, in particular for generation companies is inevitable. This will involve an increase in price of electricity generated and correspondingly an increase in price of all types of industrial products and service industries. There are various methods by which this process could be dampened. One is to decrease the share of a costly resource (gas) in favor of one that is more financially accessible (in this situation it is coal). In addition, the increase in diversification of the fuel mix in Russia (gas

the Kara Sea shelf and to \$180/1000 m3 for the Gydan Peninsula.

amount to 70--75% of the total gas production in the country.

Prime cost components Prime cost

15-18 35-40 64-70 114-128 121

Transport

Range of possible values

Average values

Figure 7 shows that over these 8 years (1998-2006) the share of natural gas used for the production of electricity (and centralized heat at cogeneration plants) at thermal power plants increased from 63% to 70 %.

For the same period the price of gas supplied to industrial consumers and power plants increased from \$10/1000 m3 to \$51/1000 m3 (the last figure is for 2007). Note that the indicated prices are controlled and are several times lower than those for European countries and USA.

Such a situation for gas prices in Russia cannot last long. Prices will inevitably rise because of the following:


The necessity to sharply increase domestic gas prices is also understood by the Government of the Russian Federation (RF). The change of wholesale domestic gas prices to year 2010 was determined on 30 November 2006. Based on different factors (depletion of the main gas fields in the current gas production areas, growth of gas demands, aging of fixed production assets, growing demands of the industry for investments, etc.) the gas price level for industry and the electric power industry in 2011 will approach \$115/1000 m3--\$120/1000 m3. Further, the possibility for including *the gas price formula* (approved by the Federal Tariff Service of RF in July 2007) in long-term contracts for domestic consumers is examined at present [12]. (*It will take into account primary cost of gas of a concrete gas production area in a concrete gas consumption area including the necessary charges, taxes, and dues).* The average gas price calculated by this formula was about \$170 /1000 m3 in 2007. Prior to 2007 this price was hypothetic, in 10-15 years such a price will be real for the reasons mentioned above.

#### **5.1 Cost of primary gas for the main gas fields**

Table 5 gives values of cost of primary gas for the main gas fields of the Yamal Peninsula (Bovanenkovskoye and Kharasaveyskoye), the shelf of the Kara Sea (Leningradskoye and Rusanovskoye) and the fields of the Gydan Peninsula in the Moscow region (i.e. in the center of the European part of Russia) that were calculated at the Energy Systems Institute, Irkutsk, Russia.

The prime cost of gas for the above field (Table 3) represents the relation between the total capital and operating costs for the whole time period of infrastructure creation on the field and the total gas production for the same time period. Here the total costs are the costs for creation and operation of:


Figure 7 shows that over these 8 years (1998-2006) the share of natural gas used for the production of electricity (and centralized heat at cogeneration plants) at thermal power

For the same period the price of gas supplied to industrial consumers and power plants increased from \$10/1000 m3 to \$51/1000 m3 (the last figure is for 2007). Note that the indicated prices are controlled and are several times lower than those for European countries and USA. Such a situation for gas prices in Russia cannot last long. Prices will inevitably rise because

 The tendency of RAO "EES Rossii" to achieve equal profitability of the gas industry in the external and domestic gas markets (in 2006 the gas price in the European countries

 The price increase will be caused by objective necessity for Russia to move to new (with very expensive development) areas of natural gas production (the Yamal and Gydan Peninsulas, shelves of the Barents and Kara Seas). This seems to be the main reason for

The necessity to sharply increase domestic gas prices is also understood by the Government of the Russian Federation (RF). The change of wholesale domestic gas prices to year 2010 was determined on 30 November 2006. Based on different factors (depletion of the main gas fields in the current gas production areas, growth of gas demands, aging of fixed production assets, growing demands of the industry for investments, etc.) the gas price level for industry and the electric power industry in 2011 will approach \$115/1000 m3--\$120/1000 m3. Further, the possibility for including *the gas price formula* (approved by the Federal Tariff Service of RF in July 2007) in long-term contracts for domestic consumers is examined at present [12]. (*It will take into account primary cost of gas of a concrete gas production area in a concrete gas consumption area including the necessary charges, taxes, and dues).* The average gas price calculated by this formula was about \$170 /1000 m3 in 2007. Prior to 2007 this price was hypothetic, in 10-15 years such a price will be real for the reasons mentioned above.

Table 5 gives values of cost of primary gas for the main gas fields of the Yamal Peninsula (Bovanenkovskoye and Kharasaveyskoye), the shelf of the Kara Sea (Leningradskoye and Rusanovskoye) and the fields of the Gydan Peninsula in the Moscow region (i.e. in the center of the European part of Russia) that were calculated at the Energy Systems Institute,

The prime cost of gas for the above field (Table 3) represents the relation between the total capital and operating costs for the whole time period of infrastructure creation on the field and the total gas production for the same time period. Here the total costs are the costs for

Production and social infrastructure required for development of the considered field

Systems of long-distance gas transportation from the field to the area of its consumption.

Systems of gas production and preparation for long-distance transportation;

plants increased from 63% to 70 %.

was at the level of \$250/1000 m3);

**5.1 Cost of primary gas for the main gas fields** 

of the following:

price increase.

Irkutsk, Russia.

creation and operation of:

and later on – its exploitation;


Table 5. Primary Cost of Gas for the Main Fields of new Gas Production Areas in the Moscow Region, \$/1000 m3

The values of primary cost of gas in Table 3 were calculated on the base of the corresponding specific capital and operating costs that are reasonable only for the present day. Correspondingly, the obtained preliminary figures for primary cost of gas of new gas production areas should be considered correct only for the current gas production. At the time of actual start of gas production from the considered fields the figures can change because of the uncertainty factor.

According to Table 5, the most probable prime cost of gas in the Moscow region could make up currently \$100/1000 m3--\$105/1000 m3 (for Yamal), \$130/1000 m--\$135/1000 m3 (for the shelf of the Kara Sea) and \$128/1000 m3 (for the fields of the Gydan Peninsula). It can be said with reasonable confidence that the specific capital and operating costs will increase with lapse of time and hence the primary cost of gas in new gas production areas will also rise. Based on different data for the period from 2000 to 2006 the indicated specific costs increased on the whole by 70--100%. Even if the growth rates of specific costs for the period to 2020 are not so high and make up about 50% with respect to those for the present day, by 2020 primary cost of gas will increase to \$150/1000 m3 for the Yamal gas, to 200/1000 m3 for the Kara Sea shelf and to \$180/1000 m3 for the Gydan Peninsula.

In the foregoing, only the prime cost is discussed. Hence, the average gas price of \$170/1000 m3 (that was calculated by the gas price formula) can be considered quite real in 10-15 years. So much so, the gas share in new gas production areas in 15-20 years will amount to 70--75% of the total gas production in the country.

Thus, the gas price rise in the domestic market of Russia, in particular for generation companies is inevitable. This will involve an increase in price of electricity generated and correspondingly an increase in price of all types of industrial products and service industries.

There are various methods by which this process could be dampened. One is to decrease the share of a costly resource (gas) in favor of one that is more financially accessible (in this situation it is coal). In addition, the increase in diversification of the fuel mix in Russia (gas

Globalization of the Natural Gas Market on

tce annually.

two purposes:

utilities, etc.).

possibilities to produce fuel resources in the country.

*680 bln m3*. This is on the assumption that:

60-80 bln m3/year in 2015-2020.

production of electricity and centralized heat;

The results of the comparison are presented in Table 6.

*210-mln tce* of coal that can be supplied by the coal industry.

bln m3/year in 2020;

Natural Gas Prices in Electric Power Generation and Energy Development 215

that are adaptive to expected conditions of gas industry development (including changes in the gas prices within the set ranges) are determined. At the same time (at the FEC level) account is taken of the conditions for expansion of all types of generation capacities and

Analysis of factors determining the structure of the generation capacities within multi-step modeling reveals that in addition to gas and coal prices themselves, the key factors for Russia (at least up to 2020) are *physical capabilities* of involving gas and coal in the fuel mix of the country. In turn the volumes of such involvement will largely depend on the

The volume of national coal production can be increased substantially. With the investments available and with the demand for coal, its production can reach 450-500 mln t/year or 270- 300 mln tce by 2020 [17] compared with the current production level of 300 mln t or 180 mln

It is not easy to increase the volumes of gas production. Aside from the need to invest huge sums of money in the development of new gas production areas it is necessary to consider time lag. For example, it will take 12-13 years at best for the volume of gas production on

In 2006 the country produced 656-bln m3 of gas. Based on the estimates of the Energy Systems Institute, Irkutsk, Russia, gas production level in Russia in 2020 will be *not exceed* 

gas production on Yamal will start in 2010 and will then grow and reach the level of 240

gas production at the Shtokmanovskoye field will start in 2011-2012 reaching the

 total volume of gas production in other new areas (the Sakhalin Island Shelf, Irkutsk region, the Sakha republic (Yakutia) and other regions) will reach 40-bln m3 in 2010 and

Taking into account the above, the potential volumes of gas and coal involvement in the fuel mix of Russia, and the potential volumes of their use for production of electricity and centralized heat at co-generation plants have been compared up to 2020. The model-based studies took into consideration that all gas and coal involved in the fuel mix is consumed for

use by all other categories of consumers (industry, population, housing and public

Separation of coal and gas demand for production of electricity and heat, and for other needs allows estimation of the extent to which the shares of these energy resources will be redistributed in the future. For example the demand for fuel at thermal power plants in 2020 can be met owing to *290-mln tce* of gas that can be supplied by the gas industry and up to

Yamal to reach 240-250 bln m3/year (this is a maximum volume) from scratch.

maximum annual production 60-80 bln m3/year in 2020-2025;

development of all fuel industries – in terms of fuel inter-changeability and reserves.

share is 80% of total fuel consumption) will have a positive impact on the level of Russia's energy security.

#### **5.2 Structure of generation capacities for Russia considering increase in involvement of coal**

Using the required data, the change in share of gas-fired thermal power plants in the structure of generation capacities for Russia due to increase in the coal share can be evaluated. The data relates to:


A technique for electric power industry development planning which accounts for its interrelations with other branches of the Fuel and Energy Complex (FEC) in Russia has been developed [14]. It is similar to the integrated resource planning approach [15, 16]. The approach is integrated planning of electric power systems and gas supply systems expansion in a market environment. Consideration is given to the practical approach of using such techniques in multi-step planning of Russia's power industry development, taking into account prospects for development of the national gas industry and bearing in mind the possible substantial rise in the price of gas used in the electric power industry.

Such multi-step modeling supposes two-level studies:


At first level the territorial and production model of the national Fuel and Energy Complex (FEC) is employed to determine the main relationships between development of the fuel industries and the electric power industry, taking into consideration their interaction in the considered time horizon. Then, involving a more detailed mathematical model of electric power industry development, the prospective structure of generation capacities and their allocation are determined.

The next step assumes creation of scenarios of possible deviations in gas industry development from the basic conditions (considered at the FEC level). The scenarios are studied from the viewpoint of their impact on electric power industry development. Then, based on analysis of the studies and using alternately the models of FEC, electric power industry and gas industry, the solutions of potential electric power industry development

share is 80% of total fuel consumption) will have a positive impact on the level of Russia's

**5.2 Structure of generation capacities for Russia considering increase in involvement** 

Using the required data, the change in share of gas-fired thermal power plants in the structure of generation capacities for Russia due to increase in the coal share can be

increase in gas price for Russia's electric power industry from 50 \$/1000 m3--currently

change in relationships between coal and gas prices (in terms of standard fuel) from

national electricity demand, taken on the basis of the Energy strategy of Russia up to

technical and financial constraints on replacement of worn and obsolete generation

 specific capital investments in the construction of new generation capacities of different types (gas- and coal-fired thermal power plants, nuclear and hydro power plants) and

A technique for electric power industry development planning which accounts for its interrelations with other branches of the Fuel and Energy Complex (FEC) in Russia has been developed [14]. It is similar to the integrated resource planning approach [15, 16]. The approach is integrated planning of electric power systems and gas supply systems expansion in a market environment. Consideration is given to the practical approach of using such techniques in multi-step planning of Russia's power industry development, taking into account prospects for development of the national gas industry and bearing in mind the possible substantial rise in the price of gas used in the electric power

At first level the territorial and production model of the national Fuel and Energy Complex (FEC) is employed to determine the main relationships between development of the fuel industries and the electric power industry, taking into consideration their interaction in the considered time horizon. Then, involving a more detailed mathematical model of electric power industry development, the prospective structure of generation capacities and their

The next step assumes creation of scenarios of possible deviations in gas industry development from the basic conditions (considered at the FEC level). The scenarios are studied from the viewpoint of their impact on electric power industry development. Then, based on analysis of the studies and using alternately the models of FEC, electric power industry and gas industry, the solutions of potential electric power industry development

specific operating costs for currently operating and new capacities, etc.

energy security.

2020 [13]

industry.

allocation are determined.

evaluated. The data relates to:

to 170 \$/1000 m3 in 2020

1:1.1--currently up to 1:1.6-1.8 in 2020

equipment and construction of new capacities

Such multi-step modeling supposes two-level studies: 1. entire Fuel and Energy Complex of the country; 2. systems of electric power and gas supply.

**of coal** 

that are adaptive to expected conditions of gas industry development (including changes in the gas prices within the set ranges) are determined. At the same time (at the FEC level) account is taken of the conditions for expansion of all types of generation capacities and development of all fuel industries – in terms of fuel inter-changeability and reserves.

Analysis of factors determining the structure of the generation capacities within multi-step modeling reveals that in addition to gas and coal prices themselves, the key factors for Russia (at least up to 2020) are *physical capabilities* of involving gas and coal in the fuel mix of the country. In turn the volumes of such involvement will largely depend on the possibilities to produce fuel resources in the country.

The volume of national coal production can be increased substantially. With the investments available and with the demand for coal, its production can reach 450-500 mln t/year or 270- 300 mln tce by 2020 [17] compared with the current production level of 300 mln t or 180 mln tce annually.

It is not easy to increase the volumes of gas production. Aside from the need to invest huge sums of money in the development of new gas production areas it is necessary to consider time lag. For example, it will take 12-13 years at best for the volume of gas production on Yamal to reach 240-250 bln m3/year (this is a maximum volume) from scratch.

In 2006 the country produced 656-bln m3 of gas. Based on the estimates of the Energy Systems Institute, Irkutsk, Russia, gas production level in Russia in 2020 will be *not exceed 680 bln m3*. This is on the assumption that:


Taking into account the above, the potential volumes of gas and coal involvement in the fuel mix of Russia, and the potential volumes of their use for production of electricity and centralized heat at co-generation plants have been compared up to 2020. The model-based studies took into consideration that all gas and coal involved in the fuel mix is consumed for two purposes:


The results of the comparison are presented in Table 6.

Separation of coal and gas demand for production of electricity and heat, and for other needs allows estimation of the extent to which the shares of these energy resources will be redistributed in the future. For example the demand for fuel at thermal power plants in 2020 can be met owing to *290-mln tce* of gas that can be supplied by the gas industry and up to *210-mln tce* of coal that can be supplied by the coal industry.

Globalization of the Natural Gas Market on

lever for encouraging increased gas use.

such that a single global market is emerging [18].

Natural Gas Prices in Electric Power Generation and Energy Development 217

capital-intensive coal relative to natural gas. This suggests that financial reform could be a

Traditionally, gas supplies have been delivered entirely within regional markets—usually with little geographical distance between the source of gas and its ultimate combustion. However, a significant and growing fraction of world gas is traded longer distances via pipeline and, increasingly, as LNG. The rising role of LNG is interconnecting gas markets

Within this increasingly integrated gas market, the role of China remains highly uncertain. Today, China's share of the global gas market is tiny; with a natural gas market that is smaller than California's [19], but the future demand for natural gas in China is potentially enormous. With an average gross domestic product (GDP) growth of 9.6% for the last twenty years (China National Bureau of Statistics, 2006) [20] and no signs of slowing down, China's demand for energy commodities—coal and oil, notably—has been expanding

Potential drivers for increased natural gas demand within the Chinese energy system are now examined where three regions are focused on: Beijing, Shanghai and Guangdong. This regional model reflects that natural gas sourcing and the downstream natural gas market vary greatly by region due to climatic and geographical barriers. For example, Guangdong receives no pipeline gas and is dependent on LNG imports (at present from Australia), while domestic pipelines principally supply Beijing's and Shanghai's gas demands. The major off-takers for the gas differ between regions as well. In Shanghai, for example, the industrial sector consumes almost all of the gas, while peaking power plants are major off-takers in Guangdong. The regional organization reflects the political realities of decision-making in China. While there are national policies on energy in China, most decisions that affect the usage of natural gas are made at the provincial and local level and driven by the economics and consumption patterns of each locale.

In analyzing the energy systems of Beijing, Guangdong, and Shanghai, three separate, regional MARKAL models are used. Given a projected level of total energy demand services, each MARKAL model solves for a least cost optimal solution) [21] over the course of twenty years (2000-2020), utilizing a menu of technologies that is provided as an input for the models. The specific types of energy and emissions control technology are characterized by performance and cost parameters. The model solves by selecting a combination of technologies that minimizes the total system cost and meets the estimated energy demand. The goal is not necessarily to produce a firm prediction of future gas use, since key input assumptions, such as the level of demand services, are highly uncertain. Rather, such models are particularly

Some of the major factors that are likely to affect future demand for gas have been identified

Financial reforms that affect the cost of capital for different sectors of the economy (i.e.,

rapidly. With appropriate policies, natural gas could also grow rapidly.

A regional focus is therefore useful to model the nuances unique to each area.

well suited to reveal how sensitive natural gas demand is to key factors.

Rate at which more efficient end-use technology is made available

Stringency of local and regional environmental constraints

power, industry, residential, commercial, transportation)

to include:

Pricing and availability of gas.


\*Gas and coal volumes that can be used at Thermal Power Plants

Table 6. Comparison of Possible Coal and Gas Involvement in Fuel Mix of Russia and Volumes of use for Production of Electricity and Centralized Heat (2020)\*

Thus, the prospective relationship between gas and coal use for production of electricity and centralized heat at cogeneration plants can make up 58% or 290 mln tce of natural gas against 42% or 210 mln tce of coal.

It should be noted that in 2006 the gas share neared 70%. Besides, there was fuel oil in the fuel mix in 2006. For 2020 fuel oil (as a basic fuel) was not considered in the fuel mix: by that time this kind of fuel should be only used as an emergency reserve and process fuel (for example ignition of steam generators at cogeneration plants).

In summary, the gas share at thermal power plants of Russia, despite a sharp gas price rise (from 50\$/1000 m3 in 2007 to 170 \$/1000 m3 in 2020), can be decreased only 11-12% in favor of increase in the coal share, which to some extent will enable one to mitigate the cost rise of the electricity and centralized heat produced at TPPs in the natural gas demand zone. The above can be real if future coal generation is based on clean coal, modern technologies.

#### **6. China: Future of natural gas coal consumption in Beijing, Guangdong and Shanghai – An assessment utilizing MARKAL**

There are many uncertainties regarding the future level of natural gas consumption in China. Using an economic optimization model MARKAL [21], drivers including the level of sulphur dioxide emissions constraints set by the government, the cost of capital, the price and available supply of natural gas, and the rate of penetration of advanced technology on both the supply and demand sides are considered. The results show that setting strict rules for SO2 emissions will be instrumental in encouraging the use of natural gas, and may also cause some reduction in CO2 emissions. Conversely, the currently differentiated cost of capital for various sectors within the Chinese economy artificially boosts the economics of

*Natural gas, bln m3*

Reserve\* up to 250 Reserve in mln tce up to 290

Reserve\* up to 345 Reserve in mln tce up to 210

Table 6. Comparison of Possible Coal and Gas Involvement in Fuel Mix of Russia and

Thus, the prospective relationship between gas and coal use for production of electricity and centralized heat at cogeneration plants can make up 58% or 290 mln tce of natural gas

It should be noted that in 2006 the gas share neared 70%. Besides, there was fuel oil in the fuel mix in 2006. For 2020 fuel oil (as a basic fuel) was not considered in the fuel mix: by that time this kind of fuel should be only used as an emergency reserve and process fuel (for

In summary, the gas share at thermal power plants of Russia, despite a sharp gas price rise (from 50\$/1000 m3 in 2007 to 170 \$/1000 m3 in 2020), can be decreased only 11-12% in favor of increase in the coal share, which to some extent will enable one to mitigate the cost rise of the electricity and centralized heat produced at TPPs in the natural gas demand zone. The above can be real if future coal generation is based on clean coal, modern technologies.

**6. China: Future of natural gas coal consumption in Beijing, Guangdong and** 

There are many uncertainties regarding the future level of natural gas consumption in China. Using an economic optimization model MARKAL [21], drivers including the level of sulphur dioxide emissions constraints set by the government, the cost of capital, the price and available supply of natural gas, and the rate of penetration of advanced technology on both the supply and demand sides are considered. The results show that setting strict rules for SO2 emissions will be instrumental in encouraging the use of natural gas, and may also cause some reduction in CO2 emissions. Conversely, the currently differentiated cost of capital for various sectors within the Chinese economy artificially boosts the economics of

Volumes of use for Production of Electricity and Centralized Heat (2020)\*

\*Gas and coal volumes that can be used at Thermal Power Plants

example ignition of steam generators at cogeneration plants).

**Shanghai – An assessment utilizing MARKAL** 

against 42% or 210 mln tce of coal.

Potential production up to 500 Possible import 15 Possible export 90

*Coal, mln t*

Domestic demand 170 (except for electricity and heat production at TPP)

Domestic demand 80 (except for the electricity and heat production

at TPP)

Potential production up to 680 Own needs of the industry 60 Possible import 60 Possible export 260

capital-intensive coal relative to natural gas. This suggests that financial reform could be a lever for encouraging increased gas use.

Traditionally, gas supplies have been delivered entirely within regional markets—usually with little geographical distance between the source of gas and its ultimate combustion. However, a significant and growing fraction of world gas is traded longer distances via pipeline and, increasingly, as LNG. The rising role of LNG is interconnecting gas markets such that a single global market is emerging [18].

Within this increasingly integrated gas market, the role of China remains highly uncertain. Today, China's share of the global gas market is tiny; with a natural gas market that is smaller than California's [19], but the future demand for natural gas in China is potentially enormous. With an average gross domestic product (GDP) growth of 9.6% for the last twenty years (China National Bureau of Statistics, 2006) [20] and no signs of slowing down, China's demand for energy commodities—coal and oil, notably—has been expanding rapidly. With appropriate policies, natural gas could also grow rapidly.

Potential drivers for increased natural gas demand within the Chinese energy system are now examined where three regions are focused on: Beijing, Shanghai and Guangdong. This regional model reflects that natural gas sourcing and the downstream natural gas market vary greatly by region due to climatic and geographical barriers. For example, Guangdong receives no pipeline gas and is dependent on LNG imports (at present from Australia), while domestic pipelines principally supply Beijing's and Shanghai's gas demands. The major off-takers for the gas differ between regions as well. In Shanghai, for example, the industrial sector consumes almost all of the gas, while peaking power plants are major off-takers in Guangdong. The regional organization reflects the political realities of decision-making in China. While there are national policies on energy in China, most decisions that affect the usage of natural gas are made at the provincial and local level and driven by the economics and consumption patterns of each locale. A regional focus is therefore useful to model the nuances unique to each area.

In analyzing the energy systems of Beijing, Guangdong, and Shanghai, three separate, regional MARKAL models are used. Given a projected level of total energy demand services, each MARKAL model solves for a least cost optimal solution) [21] over the course of twenty years (2000-2020), utilizing a menu of technologies that is provided as an input for the models. The specific types of energy and emissions control technology are characterized by performance and cost parameters. The model solves by selecting a combination of technologies that minimizes the total system cost and meets the estimated energy demand. The goal is not necessarily to produce a firm prediction of future gas use, since key input assumptions, such as the level of demand services, are highly uncertain. Rather, such models are particularly well suited to reveal how sensitive natural gas demand is to key factors.

Some of the major factors that are likely to affect future demand for gas have been identified to include:


Globalization of the Natural Gas Market on

scenario "P", but is not entirely out of the question.

status quo.

model.

other.

investigate, namely:

patterns.

**6.2 Results** 

natural gas consumption.

consumed within the system.

**6.2.1 Constraints on SO2 emissions** 

constraint leads to a higher gas demand.

consumes what volume of natural gas.

Natural Gas Prices in Electric Power Generation and Energy Development 219

Scenario "P" is the case in which the output SO2 emissions are reduced by 40% from the reference case and is defined as the "plausible" scenario. This scenario tests the system response if SO2 emissions are capped at a level 40% below what is currently expected in the

Scenario "Ag" is the case in which SO2 emissions are reduced by 75% from the baseline. This is defined as the "aggressive" scenario and is less likely to represent the future than

Having defined the core SO2 scenarios, the "More Gas" scenarios ("M") were developed. The goal of these extensions is to find out how the system would react to sensitivity parameters with a plausible SO2 constraint and more gas supply available to the region (such as might be available from a successful effort to develop international pipelines and price gas favorably). With the "MoreGas" scenarios, it is possible to determine the relative effects of gas availability and pricing as compared with the other drivers in the

Within each of the core scenarios, how gas demand would vary with two other factors was studied. First, the rate at which efficient, advanced end-use technology is allowed to enter the market (the "Fast" scenarios) was changed. Second, how specifying different costs of capital for each of the sectors would impact on consumption patterns (the "Diffcost" scenarios) was investigated. The factors were also combined with each

In all, twelve scenarios were studied. These scenarios allow four broad hypotheses to be

1. Policies that constrain total SO2 emissions from the entire system lead to increased

2. The rate of technological diffusion significantly influences the amount of natural gas

3. Varying the cost of capital for different sectors has an effect on energy consumption

4. Gas prices and the availability of gas are important factors in determining which sector

Figure 8 shows projections of natural gas consumption for the reference (R), the plausible (P, 40% reduction in emissions), and the aggressive (Ag, 75% reduction) scenarios from 2000 to 2020 in all three areas. The estimates for consumption vary widely depending on which SO2 constraint is implemented in the system. From 2000 to 2020 in the reference base case, natural gas consumption increases by about six times in Beijing and fifty times in Shanghai. Guangdong goes from zero gas consumption to around 5 bcm. The natural gas consumed in 2020 in the aggressive scenario for all three regions is close to 50 bcm greater than the amount consumed in the reference scenario. These results suggest that a tighter SO2

The most important drivers (apart from polices that directly influence the price of natural gas relative to other fuels) that affect the consumption of natural gas are the implementation of SO2 controls in the system and financial reforms. For very tight limits on SO2 emissions, a switch to natural gas in the power and industrial sectors becomes the economically optimal alternative to other fossil fuels in many cases. When the rise in gas demand is in the industrial sector, this gas displaces oil. In the power sector, where gas competes with coal, it is much harder for gas to gain a substantial share of the market. A side benefit to SO2 emissions reduction policies is a corresponding decline in CO2 emissions of the order of 60 million tons CO2 for some locales (equivalent to about a quarter of the entire stock of Clean Development Mechanism projects in China) (UNEP, 2007)1.

This suggests that a leverage point for governments in developing countries like China to start addressing global concerns about climate change is through regulation of local pollutants that yield visible and immediate benefits while also fortuitously limiting growth of CO2.

As for the effects of financial policies on energy consumption, with differentiation of the cost of capital by sector as occurs in China today, the consumption of coal is particularly favored. The power sector has access to cheaper capital than other sectors within the economy, providing an incentive to build power plants with a high ratio of capital to operating costs. This arrangement favors large coal facilities, which are expensive to build and cheap to operate, over natural gas plants, which are cheap to build but expensive to operate because of the higher price of gas. While the situation is now changing due to financial reforms, it may help explain why gas has had a particularly difficult time making inroads in the power sector. This also suggests that financial reforms could have a big impact on the country's CO2 emissions.

#### **6.1 Methodology**

The pivotal policy driver for each of the regional model scenarios is the implementation of sulphur dioxide (SO2) constraints upon the energy system. SO2 is used as a proxy for the full range of local pollutants -- future studies might model other pollutants more directly. Currently, data for SO2 is the most complete and accurate of all the pollutants that are monitored in China (compared to data for NOx, PM 10, PM 2.5, CO2).

To examine the influence of SO2 constraints, three "core" scenarios were developed. In the base case reference scenario (R), it is assumed that no changes are made to the status quo. The model operates on a least cost optimization paradigm so that it solves for the most economically favorable solution. In this situation, coal is expected to out-compete gas in all sectors due to the lower fuel cost. Some emissions control programs are already in place on the national and regional levels; the reference case scenario only includes policies that are currently implemented, as well as highly likely extensions of those policies. From this starting point, there are two main scenario developments.

<sup>1</sup> UNEP Riso Centre, Capacity Development for the Clean Development Mechanism, http://www.cdmpipeline.org

Scenario "P" is the case in which the output SO2 emissions are reduced by 40% from the reference case and is defined as the "plausible" scenario. This scenario tests the system response if SO2 emissions are capped at a level 40% below what is currently expected in the status quo.

Scenario "Ag" is the case in which SO2 emissions are reduced by 75% from the baseline. This is defined as the "aggressive" scenario and is less likely to represent the future than scenario "P", but is not entirely out of the question.

Having defined the core SO2 scenarios, the "More Gas" scenarios ("M") were developed. The goal of these extensions is to find out how the system would react to sensitivity parameters with a plausible SO2 constraint and more gas supply available to the region (such as might be available from a successful effort to develop international pipelines and price gas favorably). With the "MoreGas" scenarios, it is possible to determine the relative effects of gas availability and pricing as compared with the other drivers in the model.

Within each of the core scenarios, how gas demand would vary with two other factors was studied. First, the rate at which efficient, advanced end-use technology is allowed to enter the market (the "Fast" scenarios) was changed. Second, how specifying different costs of capital for each of the sectors would impact on consumption patterns (the "Diffcost" scenarios) was investigated. The factors were also combined with each other.

In all, twelve scenarios were studied. These scenarios allow four broad hypotheses to be investigate, namely:


#### **6.2 Results**

218 Modeling and Optimization of Renewable Energy Systems

The most important drivers (apart from polices that directly influence the price of natural gas relative to other fuels) that affect the consumption of natural gas are the implementation of SO2 controls in the system and financial reforms. For very tight limits on SO2 emissions, a switch to natural gas in the power and industrial sectors becomes the economically optimal alternative to other fossil fuels in many cases. When the rise in gas demand is in the industrial sector, this gas displaces oil. In the power sector, where gas competes with coal, it is much harder for gas to gain a substantial share of the market. A side benefit to SO2 emissions reduction policies is a corresponding decline in CO2 emissions of the order of 60 million tons CO2 for some locales (equivalent to about a quarter of the entire stock of Clean Development Mechanism projects in China) (UNEP,

This suggests that a leverage point for governments in developing countries like China to start addressing global concerns about climate change is through regulation of local pollutants that yield visible and immediate benefits while also fortuitously limiting growth

As for the effects of financial policies on energy consumption, with differentiation of the cost of capital by sector as occurs in China today, the consumption of coal is particularly favored. The power sector has access to cheaper capital than other sectors within the economy, providing an incentive to build power plants with a high ratio of capital to operating costs. This arrangement favors large coal facilities, which are expensive to build and cheap to operate, over natural gas plants, which are cheap to build but expensive to operate because of the higher price of gas. While the situation is now changing due to financial reforms, it may help explain why gas has had a particularly difficult time making inroads in the power sector. This also suggests that financial reforms could have a big impact on the country's

The pivotal policy driver for each of the regional model scenarios is the implementation of sulphur dioxide (SO2) constraints upon the energy system. SO2 is used as a proxy for the full range of local pollutants -- future studies might model other pollutants more directly. Currently, data for SO2 is the most complete and accurate of all the pollutants that are

To examine the influence of SO2 constraints, three "core" scenarios were developed. In the base case reference scenario (R), it is assumed that no changes are made to the status quo. The model operates on a least cost optimization paradigm so that it solves for the most economically favorable solution. In this situation, coal is expected to out-compete gas in all sectors due to the lower fuel cost. Some emissions control programs are already in place on the national and regional levels; the reference case scenario only includes policies that are currently implemented, as well as highly likely extensions of those policies. From this

monitored in China (compared to data for NOx, PM 10, PM 2.5, CO2).

UNEP Riso Centre, Capacity Development for the Clean Development Mechanism,

starting point, there are two main scenario developments.

2007)1.

of CO2.

CO2 emissions.

 1

http://www.cdmpipeline.org

**6.1 Methodology** 

#### **6.2.1 Constraints on SO2 emissions**

Figure 8 shows projections of natural gas consumption for the reference (R), the plausible (P, 40% reduction in emissions), and the aggressive (Ag, 75% reduction) scenarios from 2000 to 2020 in all three areas. The estimates for consumption vary widely depending on which SO2 constraint is implemented in the system. From 2000 to 2020 in the reference base case, natural gas consumption increases by about six times in Beijing and fifty times in Shanghai. Guangdong goes from zero gas consumption to around 5 bcm. The natural gas consumed in 2020 in the aggressive scenario for all three regions is close to 50 bcm greater than the amount consumed in the reference scenario. These results suggest that a tighter SO2 constraint leads to a higher gas demand.

Globalization of the Natural Gas Market on

Natural Gas Prices in Electric Power Generation and Energy Development 221

apparent in Guangdong. In the case of the aggressive scenario, about 99 million tons less of coal would be used in 2020 compared to the reference case. Figure 10 explains the carbon consequences of this fuel switch for Guangdong. Imposing a 75% emissions cap on the SO2 emissions can avert about 57 million tons of carbon dioxide emissions. For comparison, 50 million tons is about a quarter of the CO2 saved by the entire stock of Clean Development Mechanisms (CDM) projects in China in 2006. It is also a quarter of Europe's Kyoto commitment [23]. While in absolute numbers these savings alone will not alter the global trajectory of climate change, they do suggest new ways of thinking about the climate issue, especially with regard to how to bring developing countries to the climate negotiation table.

Fig. 9. Coal and Natural Gas Consumption in the Guangdong (Power Sector)

Fig. 8. Natural gas consumption for all study areas: Comparison of results for reference and SO2 constrained scenarios

#### **6.2.2 Effects of differing costs of capital across sectors**

This section examines effect of varying costs of capital reflective of the historical reality of the Chinese financial system (P Diffcost) and compares it with behavior under a uniform cost of capital across all sectors. For reference runs, what has been done many times in other models is replicated, which is to assume that there is a uniform discount rate across all sectors (10%) reflecting the assumption that the cost of capital is uniform. For the scenarios that vary cost of capital, however, the actual differentiated discount rate system under which the Chinese economy has been operating is simulated by assigning different lending rates for each sector in MARKAL [22]. These different discount rates should lead to a significantly different energy system.

Coal consumption in the modest environmental constraints scenario is higher in the case of differentiated costs of capital between sectors. With their high investment and low O&M costs, coal-fired power plants benefit disproportionately from the low cost of capital for the power sector, while gas plants with their low fixed and high O&M costs are comparatively disadvantaged.

Taking a look at Guangdong, coal consumption is a dramatic 88% higher under differentiated costs of capital, with natural gas consumption lower by about 40% (Figure 9). Advanced coal plants with pollution control equipment (FGD, ESP) are built at the expense of LNG-fired power plants. In fact, the situation on the ground is already evolving in this direction due to rising LNG prices in recent years.

Next, what affect that some of the scenarios may have on CO2 emissions is examined. In particular, the hypothesis that limits on SO2 could yield some reduction in CO2 due to greater use of natural gas is considered. CO2 emissions reductions in response to SO2 limits are most

Fig. 8. Natural gas consumption for all study areas: Comparison of results for reference and

This section examines effect of varying costs of capital reflective of the historical reality of the Chinese financial system (P Diffcost) and compares it with behavior under a uniform cost of capital across all sectors. For reference runs, what has been done many times in other models is replicated, which is to assume that there is a uniform discount rate across all sectors (10%) reflecting the assumption that the cost of capital is uniform. For the scenarios that vary cost of capital, however, the actual differentiated discount rate system under which the Chinese economy has been operating is simulated by assigning different lending rates for each sector in MARKAL [22]. These different discount rates should lead to a

Coal consumption in the modest environmental constraints scenario is higher in the case of differentiated costs of capital between sectors. With their high investment and low O&M costs, coal-fired power plants benefit disproportionately from the low cost of capital for the power sector, while gas plants with their low fixed and high O&M costs are comparatively

Taking a look at Guangdong, coal consumption is a dramatic 88% higher under differentiated costs of capital, with natural gas consumption lower by about 40% (Figure 9). Advanced coal plants with pollution control equipment (FGD, ESP) are built at the expense of LNG-fired power plants. In fact, the situation on the ground is already evolving in this

Next, what affect that some of the scenarios may have on CO2 emissions is examined. In particular, the hypothesis that limits on SO2 could yield some reduction in CO2 due to greater use of natural gas is considered. CO2 emissions reductions in response to SO2 limits are most

SO2 constrained scenarios

significantly different energy system.

direction due to rising LNG prices in recent years.

disadvantaged.

**6.2.2 Effects of differing costs of capital across sectors** 

apparent in Guangdong. In the case of the aggressive scenario, about 99 million tons less of coal would be used in 2020 compared to the reference case. Figure 10 explains the carbon consequences of this fuel switch for Guangdong. Imposing a 75% emissions cap on the SO2 emissions can avert about 57 million tons of carbon dioxide emissions. For comparison, 50 million tons is about a quarter of the CO2 saved by the entire stock of Clean Development Mechanisms (CDM) projects in China in 2006. It is also a quarter of Europe's Kyoto commitment [23]. While in absolute numbers these savings alone will not alter the global trajectory of climate change, they do suggest new ways of thinking about the climate issue, especially with regard to how to bring developing countries to the climate negotiation table.

Globalization of the Natural Gas Market on

**6.4 Key findings** 

decades:

Natural Gas Prices in Electric Power Generation and Energy Development 223

There are five key findings on competitiveness of natural gas in China over the next two

1. China is a supply-constrained environment for natural gas. Growth in gas demand in China could lead to a surge of natural gas imports, as demand is likely to far outstrip domestic supplies in certain parts of the country. This supply constraint provides an impetus for the Chinese government to seek out new supplies, such as a large international pipeline from Russia, Kazakhstan, or Turkmenistan, and more LNG regasification terminals. It should be noted, however, that such international supplies

(especially via pipelines) are often challenging and time-consuming to realize. 2. Gas demand is highly dependent on financial policies. The current Chinese financial system provides extremely low costs of capital for the power sector. This makes the construction of capital-intensive coal-fired power plants especially attractive. Because coal and natural gas are in direct competition as the fuel source in most cases, this diminishes the opportunity for more natural gas combined cycle plants to be built. In Guangdong, for example, the MARKAL model would predict almost 50% lower coal consumption by 2020 if a 10% discount rate were applied to all sectors. While policies related to the banking system do not usually factor into considerations for planning an energy system, the study shows that this is an important aspect to consider in creating

3. The industrial sector can in some cases be more attractive for fuel switching than the power sector.The study found that looking outside of the power sector for fuel switching opportunities could prove to be a cost effective option. According to the model, a switch from coal to natural gas boilers would be cheaper than forcing a switch in power plants in the case of Shanghai where the industrial sector is currently dependent on inefficient coal boilers. Replacing an inefficient coal boiler requires much less upfront capital than converting a power plant from coal to natural gas. When there are enough boilers in the industrial sector to make a difference in emissions, this is an

4. The fuel mix for electricity generation is unlikely to change dramatically. In all of the scenarios that were tested in the model, coal remains the dominant fuel in the energy mix. Coal is simply too cheap and abundant to leave unused (China has the world's third largest coal reserves). Aggressive sulfur reductions do shift the electricity mix somewhat towards a greater role for natural gas, but sulfur reductions can often be met more cheaply through fuel shifts in the industrial sector and by installing end-of-pipe

5. Non-climate policies could have a large impact on carbon emissions. While China is unlikely to accept binding carbon dioxide emissions reductions targets in the near future, very large CO2 reductions might be realized as a side benefit from other policies enacted for reasons other than climate concerns. For example, in the case of China, a cap on SO2 emissions could have a significant effect on CO2 emissions by promoting the use of cleaner burning fuels and more advanced technology. An SO2 policy might be more palatable to the Chinese government than explicit CO2 regulation because it addresses immediate local concerns about air quality and health that directly affects its citizens. Such issues are much more likely to gain traction and spur change in the near term.

the right incentives for a sustainable energy plan.

especially attractive alternative.

solutions on coal plants.

#### **6.3 Implications for CO2**

Top to bottom: Transportation; Residential; Industrial; Commercial; Power

#### **6.4 Key findings**

222 Modeling and Optimization of Renewable Energy Systems

Top to bottom: Transportation; Residential; Industrial; Commercial; Power

Fig. 10. CO2 Emissions from Guangdong in the Reference, Plausible, and Aggressive

**6.3 Implications for CO2** 

Scenarios

There are five key findings on competitiveness of natural gas in China over the next two decades:


Globalization of the Natural Gas Market on

Santiago

Argentina

**<sup>27</sup> <sup>37</sup>**

accommodate the use of gas to power generation.

America Region.

coordination [25].

**1 7**

Chile

**COLOMBIA ECUADOR**

**4 6**

Colombia

**VENEZUELA**

Bogotá Manaus

Bolivia

Caracas

**192**

La Paz

Urucu

Pisco

**PERU**

Lima

**3 1**

Equador

**17 <sup>4</sup>**

Peru

**ARGENTINA**

**49**

Natural Gas Prices in Electric Power Generation and Energy Development 225

Venezuela

**BRAZIL**

**19**

Belo Horizonte

Brasília

São Paulo

Vitória Rio de Janeiro

*Source: countriesofficialauthorithies*

Salvador

Fortaleza

Recife

**23 28**

New reserves?

Brasil

supply Tcf

demand Tcf

**2006**

**/ 15 <sup>2006</sup>**

Porto Alegre

Buenos Aires

Montevideo

**PARAGUAY**

**BOLIVIA** Cuiabá

Porto Velho

**URUGUAY**

Fig. 12. Outlook of Potential Demand and Current Natural Gas Reserves in the South

While the "non-power" consumption of NG is practically constant (firm), gas consumption for thermal power plants is variable and strongly dependent on hydrological conditions. Hydro plants are able, during most of the time, to displace thermal energy production, which are then operated in complementation mode. This is achieved through hydrothermal

Over the period 2004-2008, Chile and Brazil decided to implement re-gasification plants to start importing LNG from 2009. Motivation for the two countries is quite similar: (i) to diversify the gas supply for the country (in case of Chile, to diversify from Argentina and in case of Brazil to diversify from Bolivia) and (ii) to create a flexible supply able to

**2**

**Existingpipeline Plannedpipeline**
