The Impact of the New England Clean Energy Connect on the Wholesale Energy Market Summary and Analysis January 2020 Stepwise Data Research www.stepwiseresearch.com 207.808.2045 Summary of Findings In May 2019, the Maine Public Utilities Commission (MPUC) granted approval to Central Maine Power (CMP) to construct and operate the New England Clean Energy Connect (NECEC).i NECEC is a transmission corridor that will connect 1,200 megawatts (MW) of hydropower from Quebec, Canada with the New England electricity grid. The corridor will serve as the conduit for Hydro Quebec to sell 9.45 terawatt hours (TWh) of power annually to Massachusetts electric utilities for the next twenty years. As a point of reference, 9.45 TWh is roughly 9% of New England’s current electricity generation and 8% of its electricity consumption (which includes power that is imported from outside of New England).ii The approval process spanned 18 months and included thousands of pages of documents and hundreds of hours of testimony from experts and supporters and opponents of the project. Given the complexity of the proceedings, Mainers for Clean Energy Jobs (a coalition with members including the Maine State Chamber of Commerce, Maine businesses, labor unions, and other NECEC supporters) asked Stepwise Data Research to summarize NECEC’s projected impact on New England’s wholesale energy market, with a particular focus on the revenue impact to power generators of different fuel types (e.g., natural gas and oil). This request was made with the understanding that the wholesale cost of energy is the primary driver of residential electricity costs, and that changes in New England’s wholesale market are ultimately felt by Maine consumers and businesses. It was also an acknowledgement that some of the opposition to NECEC from power generators may stem from concerns about revenue losses, and that understanding the revenue implications for current generators may be important context as the project continues to be discussed among the coalition’s members. Stepwise reviewed the trove of publicly-available documents and projections submitted to the MPUC as part of CMP’s application for a Certificate of Public Convenience and Necessityiii as well as the most recent electricity generation data from ISO New England,iv the entity that oversees the region’s electricity market. Based on this information, we find that: • • • There is broad consensus that a 9.45 TWh increase in the supply of wholesale energy enabled by NECEC will lower wholesale energy prices in the New England market. The most detailed and objective analysis, conducted by London Economics International (LEI) at the request of the MPUC, estimated an average annual benefit in the wholesale energy market of $134 million for each of the next 15 years (in nominal dollars;15 years is the duration of LEI’s modeling), which translates to an average annual reduction of roughly $1.29 per megawatt hour (MWh).v Based on historical and projected power generation data, NECEC will result in an estimated revenue loss for fossil fuel generators of between $61 million and $75 million annually, and between $915 million and $1.1 billion over 15 years (in nominal dollars). For nuclear generators, the revenue loss is estimated to range from $37 million to $45 million annually, and between $549 million and $671 million over the next 15 years, if both nuclear generators remain in operation. The estimates for revenue losses are derived in part from LEI's estimate of the change in wholesale energy prices once NECEC is in operation. As a result, they are subject to the same assumptions and risks to which LEI’s conclusions are subject. The revenue loss estimates are also based in part on applying today’s distribution of power generation by fuel type to projections of future generation developed by ISO New England, which carry with them uncertainty surrounding the structure of New England’s wholesale electricity market ten years hence. Note also that this analysis only relates to changes in the wholesale energy market; revenue changes due to NECEC that manifest in the forward capacity market are not included. In the two charts below, the shaded bar represents the projected revenue loss based on projected annual power generation over the next 10 years, with the two red lines representing the revenue loss if power generation is plus or minus ten percent of the projection. The dotted blue line represents the revenue loss based on the 3-year historical average generation (2015-2018). 1 Range of Projected Annual Revenue Losses (energy market only) Range of Projected 15-Year Revenue Losses (energy market only) NECEC’s Impact on New England’s Wholesale Energy Market Introduction While the intricacies and inner workings of New England’s wholesale electricity market are complex, the essence of how New England “keeps the lights on” is relatively straightforward. Electric power is bought and sold in several competitive marketplaces, overseen by ISO New England,vi where multiple buyers and sellers interact to purchase and sell electricity to meet the demands of the region’s residential, commercial, and industrial users. There is a “day-ahead” market where power for the next day is committed; a “real-time” market where hourly adjustments to the previous day’s commitments are made; and a “forward capacity” market where generators are paid for their capacity to generate electricity, regardless of whether that electricity is actually generated. (This report addresses only electricity that is bought and sold in the day-ahead and realtime markets – that is, it addresses the wholesale energy market; the implications of NECEC on the forward capacity market are not included.) Each marketplace is competitive, in an “auction-type” format, with multiple offers to buy or sell electricity that reflect the value to each buyer or seller of a given amount of electricity delivered in a given timeframe. The competitive nature of the market means that the price an electricity generator is willing to sell electricity for depends primarily on their marginal costs of producing that electricity. Lower-cost generators will be willing to sell at lower prices while higher-cost generators will require higher prices. The competing offers and bids are assessed to determine a market clearing price that balances supply and demand. For a given market and timeperiod (e.g., today’s “day-ahead” market), the clearing price is the price that all willing buyers pay all willing suppliers. In other words, once the clearing price is established through a competitive process, electricity generators all get paid the same price (again, for a given period of time). Some electricity generators have separate Power Purchase Agreements (PPAs) with utilities or other entities that guarantee the purchase of a given quantity of power at a specified price. These generators still have to offer their electricity through the ISO New England marketplaces. However, because their power has already been purchased – and in fact, because they may have contractual obligations to supply it – they offer their power in the marketplace at a price of zero dollars to guarantee that their power will be below the clearing price and part of the supply purchased by electricity buyers. Generally speaking, and with some exceptions, renewable power generators are more likely to have long-term PPAs in place while baseload power generators (e.g., natural gas and nuclear) are less likely. For generators with PPAs, the price they receive for their power is dependent on their PPA and not the market’s clearing price; however, the PPAs themselves are based 2 heavily on expectations of competitive market prices and over the long run are affected by and will generally converge to the competitive prices set within the marketplaces. Conceptual Impact of More Low-Cost Supply The PPAs related to NECEC will effectively increase the annual supply of electricity offered into the ISO New England market at a price of zero dollars by 9.45 TWh. Following standard microeconomic theory, additional low-cost supply will shift the market supply curve outward and result in a lower clearing (or equilibrium) price. Chart 1 illustrates this: the current supply of electricity (upward sloping, solid blue line) shifts right with the additional supply. The new supply curve (dotted line) intersects the demand for electricity from wholesale buyers (downward sloping orange line) at a lower price. Point B represents the new lower price that results from the increase in supply. The vertical difference between point B and point A, the average clearing price without the additional supply, represents the reduction in price as a result of the new supply. Because of the way the competitive electricity markets function, all willing electricity sellers will receive the lower clearing prices, and all willing buyers will pay the lower prices. Some higher-cost sellers may be unable to accept the lower prices and therefore will sell less electricity. While this chart illustrates the impact on average annual prices, in actuality the power associated with NECEC will likely be supplied in every hour of the year and will have an effect on wholesale energy prices that will vary depending on other market fundamentals, but will always be lower than it would have been without this additional supply of power. Chart 1: Conceptual Illustration of Additional Low-Cost Supply Price Reductions Due to NECEC During the MPUC hearings, there was broad agreement that the addition of 9.45 TWh of supply from Hydro Quebec will follow a similar process to the simplified illustration above and result in lower wholesale energy prices. In its order granting CMP a Certificate of Public Convenience and Necessity, the MPUC concluded that, “The evidence in the record in this proceeding demonstrates that the NECEC will result in a reduction to 3 wholesale energy prices in Maine and across the New England region.”vii This conclusion was based on three dynamic models of New England’s electricity market presented to the Commission: • • • Daymark, Inc., a firm hired by CMP, used their Aurora model to estimate that NECEC will cause an average annual price reduction of $3.70/MWh in nominal dollars between 2023 and 2041. Over fifteen years (to be consistent with LEI’s analysis below), this translates to $384 million in average annual wholesale energy market benefits for New England and $44 million for Maine.viii GINT, representing electricity generators opposed to the project (Calpine Corporation, Vistra Energy Corporation, and Bucksport Generation, LLC) used Calpine Corporation’s UPLAN model to estimate an annual price reduction of between $2.30/MWh and $3.21/MWh in 2023, the first year of operation for NECEC. GINT did not translate this to a total energy market benefit.ix London Economics International (LEI), an outside consulting firm retained by the MPUC with no financial stake in the project, used their POOLMod model to estimate total wholesale energy market benefits of $134 million for New England and $14 million for Maine between 2023 and 2037. LEI’s estimate of a dollar per megawatt hour reduction was redacted from the public version of their report because of proprietary information contained within their model. However, they did compare their estimate of total benefits ($134 million) to Daymark’s estimate ($384 million) for the same fifteen-year time period. Since LEI’s total energy market benefit estimate is roughly 35% of Daymark’s estimate it is reasonable to assume that LEI’s price reduction would also be 35% of Daymark’s price reduction, or $1.29/MWh.x Both LEI and Daymark also estimated benefits to Maine and New England from lower prices in the forward capacity market. Although the MPUC concluded, “The evidence in the record also indicates that the NECEC will likely result in a reduction to wholesale capacity prices in Maine and across the New England region”, those estimates are not addressed in this report because of the uncertainty surrounding the impact.xi Similarly, the mitigating impact on prices from NECEC in times of extreme events that drive wholesale prices exponentially higher (e.g., unseasonably cold temperatures in winter) were discussed in the MPUC proceedings and modeled by LEI and Daymark but are not included in this report. Charts 2 and 3 below illustrates the range of expected price impacts in the wholesale energy market. LEI’s estimated price reduction is the most conservative and objective, and is the estimate used in the revenue estimates to follow. Chart 2: Range of Projected Annual $/MWh Reductions Chart 3: Range of Projected Annual Wholesale Energy Market Benefits 4 Electricity Generation by Fuel Type Over the past three years, New England electricity generators supplied an annual average of 104,000 gigawatt hours (GWh) of electricity to customers in the ISO New England market. This represented approximately 85% of the 123,000 GWh of total net energy used for electricity in the system (what ISO New England refers to as “net energy used for load”), with the balance imported from power generators outside of New England.xii New England’s fossil fuel generators (natural gas, coal, and oil) supplied an average of 53,200 GWh, or 43% of the total supply of electricity; nuclear generators supplied an average of 31,900 GWh (26%); and a variety of other New England generators including hydro, wind, wood, solar, methane, landfill gas, refuse, and other sources supplied another 18,900 GWh (15%). (This category of generation is referred to as “Renewables and Other”) in the tables below.)xiii Table 3: Historical Electricity Generation by Fuel Type (GWh) 2016 2017 Fossil Fuel 55,100 51,600 52,800 53,200 43% Nuclear 32,700 31,500 31,400 31,900 26% Renewables and Other 17,700 19,400 19,600 18,900 15% 105,600 102,600 103,700 104,000 85% 18,800 18,700 19,700 19,100 16% 124,400 121,200 123,500 123,000 100% Total NE Generators Net Imports, minus Pumping Loadxiv Total 2018 3-yr Avg 3-yr Avg % ISO New England projects future aggregate demand for electricity through 2028, but does not project supply by fuel type. They expect the total electricity bought and sold in the system to decline slightly from roughly 123,000 GWh today to just over 121,000 GWh in 2028, primarily because of the expectation of more “behindthe-meter” solar power and increases in energy efficiency over time. The average net annual energy is projected to be 121,500 GWh. Under the assumption that the distribution of generation by fuel type will remain roughly as it is today, New England’s fossil fuel generators are projected to supply an average of 52,500 GWh each year between today and 2028; nuclear generators are projected to supply an annual average of 31,500 GWh; and renewable and other New England generators are projected to supply an annual average of 18,700 GWh.xv Conceptually, these estimates can be viewed as the baseline for today’s current generators, or what could reasonably be expected to take place if NECEC was not built. (Net imports are not included in the table below, which is why the average percentages total 85%.) Table 4: Projections of Electricity Generation by Fuel Type (GWh) 3-yr Historical Avg % Fossil Fuel 43% Nuclear 26% Renewables and Other 15% Projected 10-yr Avg Total Net Energy for Load Projected Annual Avg 52,500 121,500 31,500 18,700 5 There is clearly uncertainty surrounding these projections, so Table 5 reports these projections with a range of plus or minus ten percent. Together, the projections and the 3-year historical annual average provide a reasonable range of annual generation by fuel type over the next 10-15 years, shown in Table 5, in the absence of NECEC. In the Chart 4, the shaded bar represents the projected generation for each fuel type based on the total annual power generation projected over the next 10 years, with the two red lines representing generation plus or minus ten percent of the projection. The dotted blue line represents the average power generation over the past three years. Table 5: Range of Projected Electricity Generation by Fuel Type Based On: 3-yr Historical Avg Generation 10-yr Projection - 10% 10-yr Projection 10-yr Projection + 10% Fossil Fuel 53,200 47,300 52,500 57,800 Nuclear 31,900 28,300 31,500 34,600 Renewables and Other 18,900 16,800 18,700 20,500 Chart 4: Generation by Fuel Type Revenue Changes after NECEC The revenue impact to current generators in the energy market as a result of NECEC will be felt in two ways: first, by a dollar per MWh reduction in the price they are paid for selling wholesale power; and second, through a reduction in the amount of electricity they sell, which will come about as low-cost NECEC electricity displaces higher-cost generation. Revenue losses can be estimated for the first source of revenue loss for each generation fuel type by multiplying the annual wholesale price reduction of $1.29/MWh (derived from the LEI estimate) by the range of annual electricity generation described above. For higher-cost fossil fuel and nuclear generators, this estimate should be viewed as conservative because it does not include assumptions about less electricity being sold; in other words, the estimates are based on today’s generation levels. As NECEC displaces some of the higher-cost power that generators sell today, their revenue losses compared to a market 6 without NECEC will be higher because they will lose the entire value of their unsold electricity, not just the price differential. Those impacts would be additive to the estimates below. Table 6 indicates that New England’s fossil fuel generators will lose an estimated $61 million to $75 million of revenue annually. Over the 15 years that correspond to the LEI estimate, this translates to between $915 million and $1.1 billion in nominal dollars. Nuclear generators will see annual revenue declines of between $37 million and $45 million. It is uncertain whether New England’s two nuclear generators will be in full operation fifteen years hence, but assuming they are, they are projected to lose between $549 million and $671 million in the fifteen-year window, in nominal dollars. Revenue impacts for renewable and other generators are included in the table for completeness; however their impact in the short-term is less clear as it will likely be significantly mitigated by the high prevalence of PPAs external to the ISO New England marketplaces. Table 6: Range of Projected Annual Revenue Losses by Fuel Type (energy market only) Based On: 3-yr Historical Avg Generation 10-yr Projection - 10% 10-yr Projection 10-yr Projection + 10% Fossil Fuel $68,643,000 $61,011,000 $67,790,000 $74,569,000 Nuclear $41,174,000 $36,596,000 $40,663,000 $44,729,000 Renewables and Other $24,408,000 $21,694,000 $24,105,000 $26,515,000 Table 7: Range of Projected 15-Year Revenue Losses by Fuel Type (energy market only) Based On: 3-yr Historical Avg Generation 10-yr Projection - 10% 10-yr Projection 10-yr Projection + 10% $1,029,650,000 $915,169,000 $1,016,855,000 $1,118,540,000 Nuclear $617,613,000 $548,944,000 $609,938,000 $670,932,000 Renewables and Other $366,124,000 $325,417,000 $361,574,000 $397,731,000 Fossil Fuel In the charts below, the shaded bar represents the revenue loss based on the 10-year annual average generation, with the red lines representing plus or minus ten percent of this average. The dotted blue line represents the revenue loss based on the 3-year historical average generation. 7 Chart 5: Range of Projected Annual Revenue Losses (energy market only) Chart 6: Range of Projected 15-Year Revenue Losses (energy market only) In summary, there is broad consensus that NECEC will lower wholesale energy prices paid to New England electricity generators, resulting in a significant reduction in revenues for fossil fuel and nuclear generators. While outside the scope of this analysis, lower wholesale electricity costs will translate to lower retail costs for businesses and consumers in the New England market. ENDNOTES i State of Maine Public Utilities Commission, Docket No. 2017-00232, Order Granting Certificate of Public Convenience and Necessity and Approving Stipulation, May 3rd, 2019. ii 9.45 TWh divided by 2018 total energy for load of about 123.5 Twh = 7.7%; 9.45 TWh divided by current New England generation of 103.7 TWh = 9.1%. iii Materials available for Docket No. 2017-00232 here: https://mpuc-cms.maine.gov/CQM.Public.WebUI/ExternalHome.aspx iv ISO New England data available here: https://www.iso-ne.com/about/key-stats v LEI’s “15-yr annual average, $nominal million” estimate for energy market benefits for New England = $134 million is 35% of Daymark’s estimate of $384 million. 35% of Daymark’s estimate of a $3.70 MWh price reduction equals $1.29. vi https://www.iso-ne.com/about vii State of Maine Public Utilities Commission, Docket No. 2017-00232, Order Granting Certificate of Public Convenience and Necessity and Approving Stipulation, May 3rd, 2019, page 31 viii Daymark Energy Advisors, NECEC Transmission Project: Benefits to Maine Ratepayers, September 27, 2017, MPUC Exhibit NECEC-5, Docket 2017-00232, ix Prepared Direct Testimony of Tanya L. Bodell on Behalf of Calpine Corporation, April 30, 2017, MPUC Docket 2017-00232, Exhibit TLB-1. x London Economics International LLC, Independent Analysis of Electricity Market and Macroeconomic Benefits of the New England Clean Energy Connect Project, Prepared for Maine Public Utilities Commission, May 21, 2018. While the LEI report is through 2037, the Daymark analysis extends to 2041. In LEI’s analysis, they report Daymark’s total wholesale impact through 2037 in order to compare it to their 15-year timeline. However, the estimate of the average price reduction through 2027 was not publicly available. A visual inspection of the chart of $/MWh reduction on page 12 of the Daymark report indicates that an average for 2023-2037 may be somewhat lower than for 2023-2041; however because that information is not publicly available, $3.70 was the price reduction used to derive the LEI $/MWh price impact. 8 xi The PUC hearings included a range of opinions on whether the power generated by Hydro Quebec and transmitted via NECEC would be eligible for inclusion in the forward capacity market. Because of the uncertainty surrounding Hydro Quebec’s eligibility, changes in revenue in the capacity market were not included in the calculations above. If Hydro Quebec is eligible and ultimately participates in the capacity market, the increase in the supply of capacity by would lead to additional revenue losses for other generators who currently are paid for their capacity. As a point of reference, LEI estimated $255 annual capacity market benefits for New England and Daymark estimated $355 million (15-yr annual average, nominal dollars). The impact of NECEC on market prices for power when extreme events, weather-related or otherwise, occur is also not included in this analysis. However, the additional capacity made possible by NECEC would likely lower market prices in the case of extreme price increases. As a point of reference, LEI modeled the impacts of NECEC on recent system “stress events” and found wholesale benefits to New England in excess of $50m for a summer stress event and $72 million for a winter event. Those revenue impacts are not included in this analysis. xii The balance also includes energy used for pumping water into storage ponds, referred to as “Pumping Load.” xiii ISO New England Net Energy and Peak Load by Source files, 2016-2018, available here: https://www.isone.com/isoexpress/web/reports/load-and-demand/-/tree/net-ener-peak-load xiv Pumping load is the load required to pump water into storage ponds. xv ISO New England, 2019-2028 Forecast Report of Capacity, Energy, Loads, and Transmission, May 1st, 2019. Reprinted below, available at: https://www.iso-ne.com/system-planning/system-forecasting/load-forecast Net Annual Energy - GWh GROSS - Without reductions Reduced for BTM PV NET - Reduced for BTM PV & EE 2028 10-yr avg (calc) 2019 2020 2021 2022 2023 2024 2025 2026 2027 145,610 146,650 148,011 150,201 152,016 154,243 155,571 157,253 158,999 161,312 152,987 143,120 143,801 144,798 146,652 148,132 150,033 151,088 152,504 154,003 156,090 149,022 125,823 123,560 121,876 121,288 120,576 120,544 119,924 119,916 120,227 121,336 121,507 9