Russian gas-to-power competition mounts as demand is squeezed

The announcement on 4 September by E.ON Russia of a new $8.5 billion (284 billion ruble) contract to buy gas from Novatek shows how rapidly Russia’s gigantic gas-to-power market is developing. Under the deal, Novatek will supply the Surgutskaya GRES-2 power station in 2014-2027, largely replacing volumes previously supplied by the oil company Surgutneftegaz.

The new agreement is in addition to a larger-volume contract, signed between E.ON Russia and Novatek in August last year, for the delivery of 708 billion rubles worth of gas over 15 years (2013-2027) to four power stations. E.ON Russia, which needs about 13.5 bcm/year in total and whose contracts with Gazprom expired last year, also buys gas from Lukoil and the power company SUEK.

The E.ON Russia-Novatek deal confirms the trend for the non-Gazprom producers – i.e. Novatek, the Russian oil companies and some smaller players – to compete for long term contracts with prime buyers, particularly in the power sector, at a discount to the regulated gas prices at which most Gazprom volumes are sold. Novatek’s accounts show that whereas in 2007 its sales prices were more than 15% higher than Gazprom’s, in 2012 they were slightly lower.

The background to growing competition in the gas-to-power market is the reform of the electricity sector itself.  The privatisation and reorganisation of 2006-07 has been followed by some consolidation – and investment in new capacity is now coming through. That has depressed gas demand, and is another potential factor in sharpening competition between suppliers.

It’s far from plain sailing. Regulation constrains electricity tariffs, power producers say that spark spreads are being squeezed too hard … and the heat produced by the combined heat and power (CHP) plants that make up most of Russia’s fleet is hardly paid for. But market forces play an ever-increasing role.

(Quasi) competition breaks out  

While Russian legislation has for many years guaranteed third-party access to the gas transportation system, Gazprom in practice refused access to other producers, transporting only small volumes and seeking to purchase gas at low prices at the well-head. The non-Gazprom producers’ key breakthrough to power customers came in 2009, when Novatek signed a deal to supply OGK-1, the state controlled power generator, with 57 bcm of gas in 2010-2015. Other gas-to-power deals followed, including with Surgutneftegaz to supply Gazprom-owned OGK-2 and with Novatek to supply about 2 bcm/year to TGK-10, the territorial generating company owned by Fortum of Finland.

By 2012, many of Gazprom’s supply contracts were expiring, and its largest competitors had clearly reached an understanding with government that third-party access would now be implemented for their volumes. Things snowballed. TNK-BP, the oil company (since taken over by Rosneft), signed long-term (15-18 year) deals to supply three territorial generating companies (TGKs) with 15-17 bcm each; Novatek agreed to supply 9.05 bcm/year in 2013-15 to Mosenergo, the Gazprom subsidiary that supplies power to the Moscow region, and one of Russia’s biggest gas consumers with a 27 bcm/year requirement.

The biggest deal of all was signed in December last year between Rosneft, the largest state-owned oil company, and Inter-RAO, the state-controlled power holding company, for the supply of up  to 875 bcm of gas, with a 35 bcm/year take-or-pay provision, over the 25-year period 2016-2040. This deal is at Novatek’s, rather than Gazprom’s expense: these volumes will mainly replace those being purchased by Inter-RAO from Novatek, under its contract with OGK-1 (which is controlled by Inter RAO) and under another deal to supply 7.7 bcm in 2010-2015.

The largest – but shrinking – source of gas demand

Such is the role of gas-fired power generation in Rusisa that it will be the main source of gas demand far into the future – but industry observers think that it may not expand much in the coming years. Russia’s power sector generates more than 1000 billion kwH of electricity, of which more than 700 billion kwH comes from its thermal stations. (In capacity terms, thermal generation accounts for 161 GW out of 233 GW; the remainder is hydro (48 GW) and nuclear (24 GW). Of that thermal generation, more than 70% is fired by gas, and despite long-standing government policy to reduce the power sector’s dependence on gas, its share has been rising steadily throughout the late Soviet and post-Soviet periods. (See Table 1.)

Much of Russia’s electricity is generated by CHPs, heat from which is sold into a market where reform is only now underway, where tariffs are heavily discounted and where most buyers are municipal services providers, usually owned by local authorities, with poor payment records.

During the privatisation of Russia’s power sector in 2006-07,  its assets were divided between wholesale generating companies (OGKs) that mainly own large thermal plants, territorial generating companies (TGKs) that mainly own urban-based CHPs, and some regional generating companies in outlying regions. Gas consumption by these types of companies was recorded in 2011 by the Association for Forecasting Energy Balances (an agency of the energy ministry) as follows:

Power and heat sector gas consumption, bcm, in 2011
Total

167.8

OGKs (mostly thermal power stations)

56.7

TGKs (mostly CHPs)

81.6

Other, i.e. Regional companies

29.5

Source: AFEB

Power stations’ gas consumption was recorded by the state statistics agency, Rosstat, as 189.5 bcm, i.e. more than 20 bcm higher than the figures shown. In addition, there was 67.3 bcm used by boilers that, alongside urban CHP, supply Russia’s ubiquitous – and mostly aging and inefficient – district heating systems.

For many years prior to the economic crisis, it was assumed that electricity demand would continue to rise by 2-4% per year. After falling in 2009 it resumed strong growth in 2010, but then the curve flattened. Now analysts are much more cautious: the consensus is that growth will be at 1-1.5% per year, or less. This, combined with efficiency improvements, means that gas-for-power demand growth is expected to be slow or flat.

Power sector reform

Russia’s plans for power sector reform envisaged major investment in new capacity by generating companies. Agreements with the companies, under which they made investment commitments, were a condition of privatisation. In return, the government committed itself both to establishing a long-term capacity market to help fund investment and to deregulating both wholesale and retail electricity prices.

Privatisation was followed by the economic crisis of 2008-09 and plans were changed: initial ambitious targets for new capacity were scaled down; price deregulation was constrained and postponed, due to fears of inflation and consequent damage to the economic recovery; and the companies argued that they could not fulfil their investment commitments under these new conditions.

Price liberalisation was due to be completed in the wholesale electricity market from 1 January 2011, but price monitoring and control mechanisms remain in place. The retail electricity market is also open to competition under law, but a large portion of retail consumers retain the right to purchase electricity at regulated prices through arrangements for suppliers of last resort, whose prices are regulated by regional energy commissions. And the capacity market has been re-regulated on a number of grounds.

The result of the constraints on electricity prices is that spark spreads are being squeezed, as this table shows:

Average spark spreads, rubles/MWh
 
2008

211

2009

86

2010

151

2011

143

2012 (first half)

47

Source: Alfa Bank

Earlier this year, government officials joined power industry representatives in warning that, unless the pace of increases in regulated electricity tariffs resumed, it would be impossible to continue the programme of increases in gas tariffs.  Average gas tariffs for power and industrial sector customers are estimated by Gazprom at 3669 rubles ($122/mcm, assuming 30 rubles to the dollar) this year: an increase planned for next year, of 15% (to 4219 rubles/mcm), is now likely to be scaled back to 5%. The issue is further complicated by the recent fall of the ruble against the dollar (to 32.8 rubles/$ at the time of writing).

However rapidly regulated gas and electricity tariffs rise from here, they are already at a level where (a) gas producers are able to sell gas profitably to power sector customers, resulting in the competition described above, and (b) owners of gas-fired power sector capacity are investing in upgrades and efficiency improvements.

Another important factor is that the substantial increase in gas prices over the last decade has not produced the result that many expected – a shift to coal in the power sector. In European Russia, where gas-fired power stations dominate, there has been no noticeable fuel switching since gas prices overtook coal prices (per unit of energy) in the last two or three years. In the Far East and Eastern Siberia, and some parts of the Urals, plants that use coal have continued to do so, but it appears that for gas-fired plants switching costs are too great, and the future availability and price of coal too unpredictable, to have depressed gas demand. (See Table 2.)

The heat sector

While power sector reform has suffered delays, heat sector reform in Russia has yet to really take off. In 2010 a law “on heat supply” was passed, envisaging a transition away from “cost plus” tariff setting towards a system of long-term contracts and/or regulated asset base regulation to underpin investment. A federal regulator has been set up, but heat tariffs continue to be set regionally, and have risen only slowly, due to political pressures.

Most Russian cities have large integrated district heating systems, fuelled by CHP or boilers. The district heating companies sell the heat to municipal services supply companies; in some regions these entities are owned by local government, in others by private companies, but the low level of heat tariffs has meant that investment remains minimal. A further problem is that in many cities, residents are disconnecting from district systems because of their poor quality, and acquiring autonomous heat sources (mini boilers, etc); this further aggravates the inefficiency of the district systems.

Low heat prices and rising gas prices spells trouble for district heating companies and TGKs – and non-payment in the heat sector, mainly from district heating companies who can not offset losses on heat with power sales, reached 12% last year, according to Gazprom. District heating accounted for 83.1 billion rubles of the total of 143 billion rubles of unpaid bills.

Government and energy companies alike agree that renovating systems is urgent. A flagship project in the Mytishi district near Moscow, where 41 boiler houses and 215 km of heat pipes supply about 2000 buildings, achieved a 31% reduction in gas consumption (down to about 0.2 bcm/year) and a 33% reduction in electricity consumption. Once reform gets going, such upgrades could take big chunks out of gas demand.

Power station new build begins 

While the brakes have been put on electricity price reform, and heat sector reform, the state has expanded its role in the Russian power sector via the consolidation in 2010-12 of more than half of generation capacity into state-controlled generating companies.  In October last year, two of the five largest wholesale generating companies, OGK-1 and OGK3 and one territorial generating company, TGK-11, were taken over the Inter RAO, the state energy holding company. In the same month, RusHydro, the state-owned hydro power monopoly, took over the Eastern Siberia energy company, the largest of the regional generators.

By the end of last year, the four largest owners of generating capacity, all state-controlled, accounted for more than half of Russia’s total capacity (134 GW of 233 GW): Gazpromenergoholding (Gazprom’s power sector division), with 38 GW; Roshydro with 37 GW; Inter RAO, with 34 GW (up from 8 GW in 2010), and Rosatom, the nuclear generator (25 GW). Foreign-owned energy companies – principally E.ON Russia, Fortum and Enel – also control substantial capacity.

The corporate consolidation has led to the first substantial investment in new power generation capacity in post-Soviet times – and that brings with it the prospect of downward pressure on gas demand. The average age of power station units in 2011 was 33.4 years and rising, so new capacity tends immediately to replace the oldest and most inefficient plants, with substantial efficiency savings.

The first wave of new capacity commissioning, in 2010-11, was mainly undertaken by private companies. After many years during which new capacity commissioning did not exceed a few hundred MW per year, in 2010 1661 MW of new capacity was commission, and in 2011 – 4598 MW. Almost all of these plants were combined-cycle gas turbines (CCGT) and gas turbines – which have efficiency levels of 55-58%, compared to levels of 32-38% of the plant they are replacing.

From 2012, the state-owned companies are playing a greater part. The lion’s share of new capacity either planned or under construction between now and 2020 – which Alfa Bank estimates at 28 GW, or 12% of Russia’s total – is by state companies. While most of the new-build is thermal, 8.9 GW of new nuclear capacity is due to come on stream, while 3.7 GW is decommissioned, resulting in a net increase of 5.2 GW. All this will run as base-load and further decrease demand.

It is difficult to forecast how this investment will impact gas demand, but it seems clear that it will exert significant downward pressure. Natalia Porokhova, an analyst at Gazprombank, published research earlier this year suggesting that nuclear new-build in Russia’s large industrial regions could displace as much as 20 bcm of gas demand by 2030. Even if this turns out to be an over-estimate, it does suggest that new-build, not only of nuclear but also of CCGTs, could cancel out any demand increases generated by the now relatively gentle growth of electricity demand.

Table 1

Table 1. Shares of thermal electricity generation
 

1980

1990

2000

 

2005

2006

2007

2008

2009

2010

2011

Gas

24.2

58.8

63.8

 

70.3

69.2

71.2

69.7

70.1

69.9

71.7

Coal

37.3

28.4

30.6

 

26.4

26.9

26.2

28.4

27.8

28.3

26.6

Oil products

35.7

11.9

5.1

 

2.7

3.3

1.9

1.9

2.0

1.68

1.6

Other

2.8

0.9

0.5

 

0.6

0.6

0.6

0.1

0.1

0.12

0.1

Table 2

Table 2. Gas and coal prices (2011)
 
Federal district Share of power sector fuel supply   Average prices, rubles per unit of standard fuel
Gas Coal   Gas Coal
 
Central

93.41

5.63

 

2961

2829

North-west

84.24

9.38

 

2854

2056

Southern

82.42

17.02

 

2936

2068

Volga

97.87

0.63

 

2601

2389

Urals

76.25

23.54

 

2060

1714

Siberia

7.68

91.75

 

2537

1388

Far East

24.07

72.96

 

2396

2529

 

Source: AFEB, Oxford Institute for Energy Studies

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