Appendix A DG Benefits Methodology – An Example This appendix presents an example of a methodology that has been applied to estimate potential DG
A.1 Example Approach to Estimating Deferred Generation Capacity
Utilities use the loss-of-load probability (LOLP) or loss-of-load expectation (LOLE) approach to
determine the level of generation reserves that are required to maintain a given level of system reliability. This is often considered to be a rigid reliability requirement for capacity in an area.
Many restructured markets have organized capacity markets to ensure they have enough capacity available.84 Thus, the marginal capacity price reflects the supply and demand equilibrium for power
supplies; in other words, the capacity clearing price is the marginal offer at which existing power plant capacity is equal to the level of peak demand plus reserve requirements. If the market is working properly, and the price for capacity is adequate to encourage new investment, there should be sufficient capacity to meet the planning reserve margin over the system peak.
84 Note that a capacity market is different than a market for energy, where suppliers actually produce something; in capacity markets, suppliers are being paid to have capacity available to offer into the energy market. The need for capacity markets stem partly from the existence of price caps in the energy market, which prevent plants running only a few hours out of the year from covering all their fixed costs through energy sales.
Figure A-1. Equilibrium in the Capacity Market
Time
MW
Peak Demand Plus Reserve Requirements Existing Capacity New Capacity Requirements Peak Demand 15% Equilibrium
Figure A.1 shows the dynamic changes between capacity and supply that form the basis for the organized wholesale markets for electric capacity. This graph shows the peak demand growing over time and the existing capacity decreasing due to the retirement of aging power plants. The combination of growing peak demand and power plant retirements leads to the need for new capacity. These changes lead to adjustments in the observed equilibrium price where the equilibrium price is the net cost of capacity for the marginal generation unit (i.e., net of any revenue from energy sales). When there is sufficient capacity, the marginal unit already exists and the marginal cost of capacity is close to zero (as shown at the “equilibrium” time in Figure A.1); when there is not sufficient capacity, the marginal unit is a new unit with a potentially high cost of capacity.
The value of the deferred generation investment to the utility is the change in the marginal capacity price with and without the installed DG minus any capacity payments from the utility to the DG owner. For example, if the capacity price without a DG installation is $75/kW per year and the additional installation of DG capacity reduces capacity prices to $60/kW per year, then the value of the DG capacity is $15/kW per year. All units up to the last unit that provide capacity to meet demand and reserves in the market earn the capacity price. Thus, the total savings provided by the DG owner is the $15/kW per year
capacity price reduction multiplied by the peak plus reserve demand. The utility should be willing to pay the DG owner up to $15/kW per year for the new DG capacity after accounting for any utility
administrative costs in managing that DG facility. Any additional savings in generation investment deferral that accrue to the utility is expected to be passed through directly to consumers or through reduced rates.
The value of deferred generation capacity (capacity price net of energy margin) depends on the existing supply-demand balance. As shown in Figure A.2, the value of deferred generation capacity is lowest in a market where generation units economically retire due to excess capacity and highest in a capacity
deficient market. Note that the netback price is the price less any payments to deliver the capacity such as the payment for transmission and losses.
Figure A-2. Competitive Market Capacity Price Setting Mechanisms – Illustrative
T im e , D e m a n d “ C ap aci ty Pri c e” – A n n u al Pr ic e Sp ik e R e ven ue s ( $ /kW -yr ) P rice to avoid e xce ssive re tire m e n t
P ric e to avo id e xce ssive c om b in e d
cyc le m o th b a llin g
P rice to avo id e xce ssive O il/G a s ste am m o th b a llin g
P rice to a vo id e xce ssive in te rrup tio n o f inte rru ptib le cu sto m e rs
N e tb ac k – C o st o f E xtra T ra n sm iss io n U p gra d e – O ne W h e e l N e tb a ck – C ost o f E xtra T ra n sm ission U p gra d e – T w o W h e e ls N e t C o s t o f N e w U n it P rice C a p/C o st o f B la cko u t
Least-cost production cost simulation models are used to determine the capacity price of a power system. Generally the capacity price of a system is mathematically expressed as:
Capacity Price ($/kW-year) = Capital Cost ($/KW) x Capital Charge Rate (%) + Fixed Cost ($/kW-yr) - Net Energy Margin85.
where the Capital Charge Rate is a combined rate that covers debt payments, property taxes, insurance and return on equity.
The savings to consumers would be the capacity price differential multiplied by all the installed capacity up to the established reserve levels minus any payments made to the owners of the cogeneration and small power production facilities. This capacity-price-setting approach is an industry standard used in many industry-standard production cost models, such as the Integrated Planning Model (IPM®) used by ICF
International (ICF) for the U.S. Environmental Protection Agency’s power sector emission policy analyses.