Case study

This section shows the impact that Renewable Energies have on a large utility in Northern California. The following study has been developed in [29].

Utilities in different parts of the world will select different sets of technologies depending on patterns of local electric demand, access to natural gas, coal, or other resources, and the extent and mix of local renewable resources.

One virtue of renewables is the large number of technological choices, although such variety also frustrates attempts to make simple, universal statements about their worth. However, a number of basic principles can be illustrated by examining the economics of alternative combinations of technologies that might be installed in a region with good, but not remarkable, access to renewable resources in the period after 2000.

Northern California is a representative area because its wind and solar resources are close to world averages and its use of hydroelectric power approximates the world average of 20%. Investment alternatives for this utility were analysed using the following assumptions:

  • No economic credit was given for environmental or other external benefits of renewable electric generating technologies. Only the cost of meeting present environmental laws was taken into account in the analysis.
  • No energy storage was used except for the storage inherent in hydroelectric reservoirs and in biomass fuel.
  • The amount of wind and solar capacity was varied parametrically; no attempt was made to optimise the mix.
  • Investments in a mix of biomass and conventional generating equipment were made to minimise production costs for each assumed level of intermittent electric and hydroelectric power generation, assuming all new equipment.
  • Any intermittent renewable output in excess of the load at any given hour is wasted.

Ten different capital and electricity generating options were analysed. These were based on the fuel price assumptions of the IPCC renewables-intensive energy scenario together with the above assumptions.

Option 1 conventional fossil
Option 2 best new fossil
Option 3 advanced fossil
Option 4 advanced fossil with 21% hydro
Option 5 advanced fossil with 10% PV and 21% hydro
Option 6 advanced fossil with 10% intermittents and 21% hydro
Option 7 advanced fossil with 30% mixed intermittents
Option 8 advanced fossil with 30% mixed intermittents and 21% hydro
Option 9 advanced biomass and gas with 30% mixed intermittents and 21% hydro
Option 10 advanced biomass and gas with 50% mixed intermittents and 21% hydro

Table 16 Investment options [29]

The average cost of meeting the annual electricity needs and the fraction of electricity generated by each energy source are shown in the Tables below.

Option Cost of electricity CO2 emissions
  (cents per kWh) (related to option 1, in %)
     
1 4.90 100
2 4.60 94
3 4.05 92
4 3.70 73
5 4.45 63
6 4.80 63
7 4.60 63
8 4.30 43
9 4.30 3
10 5.00 4

Table 17: cost of electricity [29]

The average cost of electricity generated with conventional equipment was found to be 4.9 cents per kWh. Costs would be reduced to 4.6 cents per kWh using the best performing gas turbines and coal gasification systems that are now coming onto the market and to 4 cents per kWh using advanced fossil-fuel generating equipment (3.7 cents per kWh if low-cost hydroelectric capacity is also available).

Option Coal Gas Biomass Hydro Wind PV Thermal
  % % % % % % %
1 72 28 - - - - -
2 80 20 - - - - -
3 93 7 - - - - -
4 74 5 - 21 - - -
5 64 5 - 21 - - -
6 64 5 - 21 5 3 2
7 62 8 - - 15 10 5
8 45 5 - 20 15 10 5
9 - 5 45 20 15 10 5
10 - 10 20 25 25 10 10

Table 18: Percent of electricity generated by source [29]

The costs are the result of an hour-by-hour simulation of the utility that considered electricity demand, the variable output of intermittent renewable equipment, the load-levelling capabilities of hydroelectric facilities, and the dispatching of coal, natural gas, and biomass fuelled plants. The selection of coal, biomass, and natural gas-burning plants was done to minimise the cost of serving loads not covered by other equipment within the constrains specified.

The tables show that a large portion (30%) of electricity generation could come from intermittent sources without increasing the average cost of electricity, and that this utility could operate almost entirely on renewable sources of energy (Option 9). The CO2 emissions in this case would be 97% less than for the conventional case (Option1).

Another finding of this analysis is that, with one exception, all the renewable portfolios considered could meet the system’s load at a cost lower than that for a system with typical new coal and gas equipment. Also, in many of the cases, from 90 to 95% of all electricity comes from renewables. The high-renewables cases generates only 3-4% CO2 as the advanced fossil system. Yet, these large reductions in CO2 emissions are achieved at costs between 0 to 1% per kWh higher than in the least costly case.

For comparison, the average electric price for consumers today is 6.3 cents per kWh (a delivered price that includes transmission, distribution, and management costs, as well as generation costs).

Although utility portfolios that involved intermittent for more than 10% of the electricity generated were somewhat more expensive than utilities portfolios that made maximum use of advanced, highly efficient fossil fuel generators, even for the 50% intermittents case, the renewable system cost only 1.5 cents per kWh more than the advanced fossil system.

The reduced costs arising from the buffering demand on a utility system with hydroelectric equipment are apparent for both conventional and renewable-intensive cases. But hydroelectric power is particularly attractive when used to buffer the large fluctuations of output that arise at high penetrations of intermittent renewables.

An important parameter characterising small-scale photovoltaic systems located at sites dispersed throughout the utility system is the credit these systems are due because of their value in reducing transmission and distribution costs and increasing system reliability. This so-called "distributed credit" can reduce the net cost of photovoltaic systems considerably.

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