Hold on to your hats. The vaunted and vilified “standard market design”, once thought dead and buried, has been resuscitated, with all attendant chaos and rhetoric, but this time in the guise of a...

## Not Economically Viable? Wrestling With Market-Based Cogeneration

Elimination of the utility must-purchase obligation can lead to unanticipated consequences.

(CEC) provides a methodology for determining the natural-gas savings attributable to cogeneration. ^{3} For a cogenerator, a fuel input of 100 units yields a cogeneration electrical output of 30 units and a cogeneration useful thermal energy output of 50 units. This relationship results in a PURPA Operating Standard of 62.5 percent [50/(30+50)*100%]. The report also assumes that the boiler efficiency of cogeneration and stand-alone industrial boilers are the same, at 80 percent. These relationships determine the natural-gas savings attributable to combined heat and power cogeneration.

Table 1 lists the basic assumptions and computes the natural-gas savings for three different average annual system heat rates. For example, if the average annual heat rate was 9,600 Btu/kWh, the gas-fired system thermal efficiency would be 0.356. ^{4} The standalone gas-fired system fuel needed to replace the cogeneration electrical output of 30 would be 84.4 (30/0.356). With an industrial boiler thermal efficiency of 0.80, the boiler fuel required to replace the cogeneration useful thermal energy would be 62.5 (50/0.8) units. If produced separately, it would take 146.9 (62.5 + 84.4) units of fuel input to replace the electrical and thermal output that cogeneration produces with a fuel input of only 100 units. The fuel savings due to cogeneration is 46.9 units. ^{5}

The second half of Table 1 shows the fuel savings associated with different average annual heat rates.

#### Recent QF Contracts

In implementing PURPA, FERC let the states decide on the appropriate compensation for the energy supplied by QFs. The basic California short-run avoided cost (SRAC) formula is variable O&M plus the incremental energy rate (IER) multiplied by the sum of the border index price of natural gas and intrastate gas-delivery costs. ^{6}

The selection of an IER has a long and contentious history in California because of its pivotal role in determining the utility’s SRAC payments to QFs. Clearly, the higher the IER, the greater the QF’s compensation. Instead of replicating the IER process, a negotiated average annual system heat rate can be used as a proxy. In what follows, IER and average annual system heat rate are used interchangeably.

Two recently negotiated QF contracts explicitly define an average annual system heat rate, or IER. The first contract provides for a period-hours weighted annual IER of 8,700. The on-peak and mid-peak periods have an IER of 1.2 times the average IER. The off-peak and super off-peak periods have an IER of about 0.87 times the average IER.

For an IER of 8,700, Table 1 shows that 76.5 units of fuel are required to replace the cogenerator’s electric output and 62.5 units of fuel are needed to replace the cogenerator’s thermal output. This implies a fuel savings of 39 units. There is a 39 percent fuel savings due to CHP cogeneration if the waste heat were fully utilized. The last column of the table clearly shows that there is both an economic and societal benefit to cogeneration.

The second contract explicitly lists the heat rate for each of the seasonal time periods. The period-hours weighted annual heat rate (IER) is 7,975 *(see Contract 2 IER). *