Elimination of the utility must-purchase obligation can lead to unanticipated consequences.
Cliff Rochlin is market advisor at Sempra Energy. Contact him at firstname.lastname@example.org. The content hereof reflects the views of the author and does not necessarily reflect the views of the Southern California Gas Co., which has no responsibility for such content. Endnotes:
The Energy Policy Act of 2005 (EPACT) adds a new section of the Public Utility Regulatory Policies Act (PURPA) of 1978. Section 210(m) of PURPA now provides for the termination of an electric utility’s obligation to purchase energy and capacity from qualifying cogeneration facilities if the Federal Energy Regulatory Commission (FERC) finds certain conditions are met.1
If qualifying facility (QF) cogenerators lose the utility must-purchase obligation established by PURPA, and if states do not intervene to maintain this requirement, then market conditions will dictate the amount of QF power purchased.
In this case, QF power sales become mainly a function of production costs. Since the primary function for most QFs is to provide electric and thermal energy for industrial uses for most hours of the day, power production for sale takes a secondary role. (No attempt was made to quantify other reasons for becoming a QF.) As a result, the electrical efficiency of a QF may be less than the efficiency of new, merchant combined-cycle power plants that use the waste heat to produce more electricity. If forced to compete on the cost of producing electricity based solely on the efficiency of its electric generation facilities, the QF may no longer find it profitable to operate in a baseload mode needed to meet its thermal host’s requirements.
When modeling the behavior of QFs in competition with merchant electric generation, it is reasonable to assume that the QF could use some of its cost savings related to the production of thermal energy to offset its relatively higher cost of producing electricity. The QF could discount its production costs in the hope that it can increase its market-determined hours of operation and meet the needs of its thermal host. The key question is whether the thermal savings provide enough of a discount for the QF to remain economically viable.
The answer to this question is important because the amount of discount applied to a QF’s incremental production costs influences its economic dispatch. The amount of thermal savings available for discount seems to be unit-specific and empirical in nature. The two distinct perspectives that follow differ with respect to the amount of fuel available to produce thermal energy. If the amount of discount is over-estimated, the loss of QF cogeneration production could be much greater than expected.2
Generic Cogeneration Efficiency
The joint production of heat and power provides both society and the QF with economic benefits. While the QF is directly compensated for its thermal and electric sales, or indirectly compensated through the foregone purchase of electricity and thermal energy, the production of combined heat and power (CHP) results in an overall fuel savings relative to producing each separately.
A report prepared for the California Energy Commission (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).
For an IER of 7,975, Table 1 shows that 70.1 units of fuel would be needed to replace the cogenerator’s electric output and 62.5 units of fuel would be needed to replace the cogenerator’s thermal output. This implies a fuel savings of 32.6 units. This is a 32.6 percent fuel savings from combined heat and power cogeneration based on the full use of the waste heat.
Cogeneration Merchant Discount
The first perspective (Stand Alone) on the amount of thermal savings available for discount is based upon producing thermal energy on a stand-alone basis. Assume the cogenerator puts in 100 units of fuel and gets 50 units of thermal output to meet its thermal host requirements. If the cogenerator produced its host’s thermal requirements on a standalone basis, with an industrial boiler efficiency of 0.8, the stand-alone thermal production would take 62.5 units of fuel to produce 50 units of thermal output.
From this perspective, cogeneration results in a saving of 12.5 units or 12.5 percent of its total fuel input (100). If the utility must-purchase obligation is relaxed, the QF can use up to 12.5 percent of its total fuel costs for peak and mid-peak hours of operation to discount its cost of producing electricity in off-peak hours when forced to compete against more efficient power plants. Realistically, taking into account transaction costs related to QF status like utility standby charges, the available discount should be reduced by about 10 percent. The maximum available discount related to thermal fuel savings is 11.25 percent.
Residual Fuel represents a second perspective on the amount of discount available to the QF. Based on the contract heat rates shown in column 1 of Table 1, the IER is used to determine the amount of fuel required to replace the cogenerator’s electrical output. This is the fuel value the contract places on the QF’s electric output. Given this value, one can conclude that the QF gets its full thermal output for the residual fuel input.
For example, with an IER of 9,600 the stand-alone fuel value requires 84.4 units to replace the QF’s electric output of 30 units. Although one does not know the QF’s total fuel usage, following the assumptions in Table 1, if the QF’s total fuel input were 100 and the fuel value of its electric output were 84.4, then the residual fuel input would be 15.6 (100-84.4) units. Using this residual fuel for stand-alone thermal production would lead to a thermal output of 12.5 (15.6*0.8) units. Since the QF gets a useful thermal output of 50 units, the amount of thermal output available for discount is 37.5 (50-12.5) units. Taking transactions costs into account, the maximum discount available is 90 percent of the thermal savings. The discount is 33.75 percent.
Table 2 shows the perceived thermal savings available for discount from both perspectives. As explained above, the Stand Alone’s savings available for discount remains constant, because it reflects the savings from standalone thermal production. However, for Residual Fuel, as the IER decreases, the percentage available for discount falls because as the system grows more efficient, the stand-alone fuel needed for the production of electricity falls, increasing the amount of residual fuel that can be used to produce the QF’s thermal output. The implicit thermal subsidy to the QF is reduced.
Table 2 also shows the perceived savings available for discount as a percentage of the societal-fuel savings related to CHP QFs. Residual Fuel expects a savings discount of almost three quarters of the social benefit, while Stand Alone expects a savings discount of about one quarter to one-third the social benefit.
Table 3 shows the thermal fuel discounts in dollars per megawatt-hour, when 90 percent of the fuel discount is available. The discounts, shown from both perspectives, vary as fuel prices and IER vary.
To the extent that all of the thermal energy is not fully utilized, the potential cogeneration discount will be reduced. For example, if the amount of used thermal energy in assumption A3 were 40 units instead of 50 units, the PURPA operating standard would fall to 57.1 percent [40/(30+40)*100%]. The amount of perceived thermal savings falls. The values in Tables 2(40) and 3(40) would be replaced by Table 3 (40) and Table 4 (40), respectively.
If QFs were forced to compete with merchant generation, one could expect the QFs to discount their electric generation production costs up to 90 percent of their thermal savings. However, the perceived amount of thermal savings can vary greatly depending on the IER and the amount of thermal energy utilized. In addition, as the price of natural gas varies, the amount of discount in dollars per megawatt also varies.
Given the disparity in the perception over the amount of thermal discount available and the recent volatility in natural-gas prices, the elimination of the utility must-purchase obligation can lead to an unanticipated major reduction in QF cogeneration production and the loss of social benefits directly related to the fuel savings attributed to CHP.