By comparison to natural gas prices, the prices of coal, oil, and emissions allowances will influence wholesale market outcomes to a much lesser extent. Future oil prices are projected to remain much higher than natural gas prices using current forward prices. Delivered coal prices, affecting only about 1,000 MW of capacity in New England after the planned retirements of Brayton Point and Salem Harbor 3, are projected at just over $4/MMBtu in each study year.108
With respect to emissions allowances, prices for CO2 allowances under the Regional Greenhouse
Gas Initiative (RGGI) are assumed to increase to moderate levels, from current levels of about $5 per short ton, to $8.00/ton by 2017, $9.23/ton by 2019, and $10.63/ton by 2024.109
Prices for NOx
and SO2 are both projected to be zero over the study horizon: New England is exempt from
delivery, rising to $4.32/MMBtu for 2017, $4.69/MMBtu for 2019, and $6.22 for 2024. This is a 58% increase in nominal dollars. In real terms (constant 2014 dollars), this represents a smaller “real” increase in price of about $1.35/MMBtu from 2014 to 2024.
105
Assuming 8,000 Btu/kWh market heat rate and natural gas as the marginal fuel.
106 Based on September 16, 2013 through October 15, 2013 trade dates.
107 Assuming 8,000 Btu/kWh market heat rate and natural gas as the marginal fuel. 108
Coal prices are based on NYMEX Central Appalachian futures, plus transportation costs.
109 These projections are based on the Regional Greenhouse Gas Initiative Integrated Planning Model projections
for the Updated Model Rule. The analysis also does not presume implementation of a Federal climate policy implementing a carbon price within the 10-year study horizon. RGGI expires in 2020. This analysis assumes CO2 prices increase at a similar rate thereafter.
EPA’s proposed Cross-State Air Pollution Rule, and ozone season NOx emissions from electric
generating units in Connecticut remain below the Clean Air Interstate Rule allowance budget. Clean Air Act Title IV allowances are assumed to have near-zero cost due to emission reductions associated with other programs. SO2 allowance prices are assumed to be negligible for all
electric generating units.110
FORECAST:
WHOLESALE CAPACITY PRICES
Capacity prices in New England are determined primarily through ISO-NE’s 3-year forward capacity auctions (FCA). The two most recent auctions have shown a dramatic shift in fundamentals: The auction from the 2016/17 delivery cleared with excess capacity at the administratively-determined price floor of about $3/kW-month, similar to the prior several auctions. The following auction, for the 2017/18 delivery year, eliminated the price floor and might have cleared at a lower price had fundamentals stayed the same. Instead, unanticipated resource retirements and a reduction in capacity imports created a slight shortage and drove the price up to $7/kW-month ($15 in the NEMA/Boston zone), Capacity prices would have been even higher had it not been for an administrative pricing rule that was triggered.
Figure 18
Projected Capacity Prices (2014$/kW-month)
110 Both ozone season NOx and annual NOx allowance prices were assumed to be negligible for all electric
generating units. Therefore, the 2014 IRP modeling does not include any policy mechanisms for additional NOx controls, and electric generating units are assumed to emit NOx at their current rates. Additionally,
Connecticut’s fuel sulfur content regulations are not expected to significantly impact electric generating unit operations. Therefore, the 2014 IRP modeling does not include any policy mechanisms for additional SO2
Going forward, fundamentals are projected to remain tight as peak load grows, and even higher prices can be expected.111
Rising capacity prices will likely first attract low-cost supply to meet growing load. Based on the assumed demand response supply cost function,112 some new
incremental supply is likely to be demand response, but it could just as well be other low-cost supply such as generation uprates or imports. New contracted renewables may also help to meet regional capacity requirements to some degree, although the contribution will be limited by relatively low capacity values of wind and solar during peak hours compared to other types of resources. Ultimately, as low-cost supply is exhausted, the capacity market will need to attract new conventional gas-fired resources to meet capacity requirements.
Recent capacity market results indicate that the timing of capacity shortage could be as soon as 2018/19, although it still remains to be seen how much low-cost supply will enter the market at that time. The 2014 IRP projected capacity prices are shown in Figure 18.113
These prices reflect the most recent 2017/18 capacity auction results, as well as recent estimates of the gross Cost of New Entry.114 As the figure shows, prices in the Base Case increase to almost $10.5/kW-month
(2014 dollars) in the 2018/19 auction, then remain approximately at that level in real terms (rising with inflation). This price level equates to about $1.1-1.2 billion (2014 dollars) in annual capacity payments by Connecticut customers, and on average is what would be expected of a functioning capacity market in order to attract new gas-fired combined cycle generators to meet the system’s capacity needs through 2024.115
Actual prices will undoubtedly differ as market conditions change, but this price projection is a reasonable estimate of expected average prices given currently available information. For example, a large amount of new low-cost supply from increased demand response, generator uprates, or imports could lead to lower prices. Conversely, prices could be higher if, for example, new market rules increase the risk of participation and drive out some less reliable resources and if new generation requires higher prices or longer lead-times to enter. Section VI will explore the potential price impacts of these types of uncertainties through scenario analysis.
111 Future capacity auctions will also incorporate two major new market design elements that FERC approved in
May of 2014: a demand curve and performance incentives. Even with the rule changes, the fundamentals will be about the same as in the IRP modeling analysis, which was conducted before the rule changes were approved: prices will have to be high enough on average to attract new supply.
112
The IRP capacity market model models economic entry and exit at various costs until the market clears, as described in Appendix B (Resource Adequacy). The model thereby solves for both quantities and prices.
113 Prices are shown by capacity delivery year. For example, the 2017/18 price is for capacity deliveries from June
1, 2017 through May 31, 2018.
114
These parameters are described in more detail in Appendix B (Resource Adequacy).
115 This long-run equilibrium price is about $10-11/kW-month (2014 dollars), based on an analysis conducted for
ISO-NE, and explained in more detail in Appendix B (Resource Adequacy). This price assumes that a generic new natural gas combined cycle powerplant would earn enough from capacity plus energy margins to cover fixed costs and earn a competitive return on capital.