This chart shows total wholesale cost of serving load for the months of December through February in 2010-2011, 2011-2012, 2012-2013, and 2013-2014.
The 2013/14 Winter Reliability program was intended to provide a short-term solution to mitigate the regions reliance on natural gas and other concerns about fuel availability. As part of the program, oil and dual fuel units were compensated for securing fuel inventory and fuel switching capability. In total, ISO-NE accepted bids for oil inventory and demand resources equivalent to 1,950,600 MWh, or 3,057,554 barrels of oil. The total program costs were estimated to be about $75 million, but will be about $9 million less given unit unavailability and failure to procure oil. Additionally, the program allowed dual fuel units to recover the costs of a successful test demonstrating the ability to switch fuels.
ISO-NE has announced that they will be seeking to implement another winter reliability program for 2014/15 that will seek to address the same concerns as the winter 2013/14 winter reliability program, however, the details of the program will differ. The long-term sustainability of a winter reliability program focused on back-up oil has serious reliability and cost implications. The winter 2013/14 winter reliability program had a potential cost of $75 million and did not alleviate the price spikes that added billions of dollars to ratepayer bills. As gas dependence grows and environmental regulations put added pressures on oil fired generators, the consequences of reliance on oil generators will increase the likelihood of reliability issues, as oil generators retire or face restricted operating hours, and negative economic pressures. Lastly, the potential of PI to put added pressure on the economic viability of oil fired units could radically
0 1 2 3 4 5 6 2011 2012 2013 2014 Who le sal e Load To tal Co st ($B il) New England
alter the market. Therefore, the long-term reliability of the electric system will depend on access to firm gas supplies and alternative resources connected by an expanded transmission system. Despite ISO New England’s efforts to reduce winter peak demand, acutely constrained pipelines have continued to threaten New England’s reliability and increase customer costs. These trends are likely to continue and become exacerbated in the future – as the following modeling scenarios will demonstrate. This necessitates further action to avert these challenges and affordably meet demand.
FORECAST:
FUEL USAGE FOR ELECTRIC GENERATION,
2014-
2024
DEEP expects the region’s generation fleet to become even more dependent on natural gas over the next ten years. Nuclear power will remain the second largest source of generation even with the loss of Vermont Yankee at the end of 2014. Coal-fired generation will remain very low due to coal retirements and low utilization of the small remaining plants in a low gas-priced environment. Significant development of new renewable generation, particularly new wind developed through 2017 and new solar PV developed through 2020, is expected to increase the share of renewable generation to increase from 6% in 2007 to 13% in 2024.
The combined effect of these changes on total generation by fuel type is shown in Figure 11, which includes data for historical years 2007 and 2012, and projections for 2014, 2017, 2019, and 2024 for Connecticut and New England.71
This shows a steep decline in coal and oil generation and an increase in gas. Total generation in Connecticut has increased since 2007, mostly because of two factors: (1) the 2011 addition of the Kleen generating station (an efficient 620 MW natural gas-fired combined-cycle plant); and (2) starting in 2017, the inclusion of the existing 745 MW Lake Road electric generating station in Connecticut with completion of components of the Interstate Reliability Project.
71 Regional natural gas and oil generation for historical years are estimated by The Brattle Group. For forecast
Figure 11
Base Case Projection of Annual Generation by Fuel Type
Connecticut (TWh) New England (TWh)
On the demand side, changes in the electric sector point to growing reliance on non-firm gas. New England is losing a substantial amount of non-gas generation and could lose more. Vermont Yankee nuclear (600 MW), Salem Harbor coal/oil (600 MW), and Norwalk Harbor oil (300 MW) will retire by 2014; and Brayton Point coal/oil (1,500 MW) will retire by 2017. These plants would generally have been generating on cold winter days and would now be replaced by 3,200 MW of gas-fired generation when gas is available. That would require approximately 530 MMcf/d of gas, assuming a 7,000 Btu/kWh heat rate for marginal gas-fired combined-cycle generation (or less if the non-gas generation would have been operating less than 24 hours per day) to maintain the system at the current level of gas constraint.
New renewable generation will help relieve the region’s reliance on gas to some extent. The 2014 IRP projects cumulative renewable additions of about 1,800 MW of (nameplate) renewable capacity by 2017.72 Assuming an average capacity factor of 25% and a 7,000 Btu/kWh heat rate
for marginal gas-fired combined-cycle generation, the renewable additions would displace roughly 76 MMcf/d of natural gas consumption.
72 This reflects all planned and contracted renewable resources, including resources contracted under
Connecticut’s Section 106, LREC/ZREC, Section 127, Project 150, and Section 6. Nuclear Coal Gas Oil Other Net Imports 0 5 10 15 20 25 30 35 40 2007 2012 2014 2017 2019 2024 Energy
Requirements Energy Exports
New RPS Class 1 Hydro Nuclear Coal Gas Oil Other Net Imports 0 20 40 60 80 100 120 140 160 2007 2012 2014 2017 2019 2024 Energy Requirements New RPS Class 1