Competitive Retail Energy Markets
Retail competition in states across the U.S. ranges from full competition of generation supplier for all retail customers (commercial, industrial and residential) to partial retail competition available up to a capped amount for industrial customers only.
The District of Columbia and thirteen states (Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Ohio, Pennsylvania, Rhode Island and Texas) have implemented full retail competition for nearly all customers of investor owned utilities. These competitive jurisdictions represent nearly one-third of all electricity consumption in the continental U.S.
In these states allowing full retail competition, regulated utilities continue to provide transmission and distribution service at regulated rates. Generation service, however, is no longer rate regulated. Instead, the rates paid by customers are those offered by competitive retail electricity suppliers or, for customers who do not receive service from competitive suppliers, utility provided POLR service that is reflective of wholesale market prices.
There are also several additional states in the U.S. that offer limited electric customer choice and may be considered “hybrid” models. For example, states including California, Michigan, Arizona, Oregon, Nevada, Virginia, Washington and Montana allow limited portions of total load to be served competitively at retail.
Competitive Wholesale Markets
Distinct from retail markets, which involve the sales of electricity directly to consumers, wholesale markets involve the sales of electricity among electric utilities and electricity marketers before it is eventually sold to end-use consumers. These jurisdictions include many of the most populous states.
Some regions of the country have evolved further in terms of forming ISOs or RTOs, which are FERC-regulated entities that coordinate, control, and monitor the operation of the electrical power system. Examples include PJM, ISO-NE and NYISO. Approximately two-thirds of the nation’s wholesale electricity sales occur in competitive markets managed by the ISOs or RTOs. These regions have independent oversight of the wholesale markets, and are regulated by FERC, which provides oversight of the operators that encompass multiple states (all but ERCOT). ISOs and RTOs generally afford more formalized and structured wholesale electricity markets than non-ISO or non-RTO regions and have implemented mechanisms to facilitate market monitoring, reliability and efficiency. ISO/RTO-guided initiatives, such as locational marginal pricing and capacity markets, are designed to send the appropriate price signal for new investment in capacity when new capacity is needed to maintain system reliability. ERCOT is unique in that its locational marginal pricing is based solely on system energy and congestion, with no accounting for marginal losses occurring on the system. While not yet formalized into an ISO or RTO, many of the previously fragmented dispatch and control areas in the Western part of the US are starting to combine, as they recognize both the operational benefits, as well as the ability to save money for customers through sharing and co-optimization of generation resources and reserves.
PJM. 65% of our generation fleet, measured by net generating capacity, operates within the PJM market. By MW, our generation fleet in PJM consists of approximately 78% nuclear, 9% renewables, 8% gas and 5% oil. PJM is the largest power market in the US and is comprised of all or parts of 13 Mid-Atlantic and Midwestern states and the District of Columbia. PJM is one of the most advanced power markets in the U.S., with nodal day-ahead and real-time energy markets, ancillary service products, and a forward capacity market (the Reliability Pricing Model or RPM) that clears capacity three years in advance of the capacity commitment period.
PJM forecasted 150.2 GW of peak load in the 2022/2023 delivery year with a minimum reserve margin of 14.50%. PJM relies heavily on natural gas-fired and coal-fired generation. PJM’s installed capacity mix in 2020 includes 28% coal, 27% natural gas, 18% nuclear, 15% gas / other secondary capacity, 5% water, 5% oil and 2% other.
Natural gas pricing is one of the primary drivers of energy prices throughout PJM. The discovery and production of vast amounts of shale gas in the U.S., particularly from the Marcellus and Utica shales within the bounds of PJM, combined with development of significant amounts of new efficient gas-fired generation has resulted in a decline in wholesale power prices in PJM.
State policies also impact the investment decisions of resources in the PJM market, including state RPS programs, ZEC and/or CMC programs in Illinois and New Jersey, and the Regional Greenhouse Gas Initiative (RGGI). RGGI is a mandatory greenhouse gas cap and trade program that imposes costs via the purchase of allowances for in-state fossil fuel generators. Eleven states in the Northeast and Mid-Atlantic are members of the RGGI program and Pennsylvania is in the process of joining the program.
Source: PJM Capacity By Fuel Type 2020, PJM 2022/2023 RPM Base Residual Auction Planning Period Parameters.
ERCOT. 12% of our generation fleet, measured by net generating capacity, operates within the ERCOT market. By MW, our generation fleet in ERCOT consists of approximately 97% gas and 3% renewables. ERCOT is the system operator for most of Texas and is not under FERC jurisdiction due to the market being solely located within the state of Texas and not being synchronously interconnected to another part of the U.S. The ERCOT market is projected to have 86.8 GW of capacity available in summer 2021 to meet a peak demand of 75.2 GW, resulting in a reserve margin of 15.5%. ERCOT’s fuel mix for 2021 is projected to consist of 32% gas (combined-cycle), 28% wind, 19% coal, 12% nuclear, 6% gas, and 3% solar, with less than 0.2% from biomass, hydro and other.
As an energy-only market, ERCOT’s market design is different from other competitive electricity markets in the U.S. Other markets, including PJM, maintain a minimum reserve margin through regulated planning, resource adequacy requirements and/or capacity markets. In contrast, ERCOT’s resource adequacy is predominately dependent on free market processes and energy market price signals. All electricity prices are subject to a system-wide offer cap, which is $9,000/MWh, as of July 2021.
Source: ERCOT 2021 Fuel Mix Report, ERCOT December 2020 Capacity Demand and Reserves Report.
NYISO. 6% of our generation fleet, measured by net generating capacity, operates within the NYISO Market. By MW, our generation fleet in NYISO consists of almost 100% nuclear. Established in 1999 as one of the first ISOs, NYISO features liquid day-ahead and real-time energy and ancillary service markets. NYISO also has a spot capacity market, called the ICAP market, which clears capacity up to 6 months in advance of the delivery period. As a result, power generation within NYISO can earn revenues from liquid ancillary, energy and capacity markets. There are four distinct supply and demand zones in the NYISO market: ROS (generally encompassing upstate New York), Zone G-J (known as the “G-J Locality” and located in the Lower Hudson Valley), Zone J (New York City), and Zone K (Long Island). The overall market is known as NYCA.
NYISO is projected to have 41.1 GW of capacity available to meet 32.3 GW of projected peak demand in 2021, resulting in a reserve margin of 27.0%. NYISO is heavily reliant on natural gas and oil-fired generators with hydro and nuclear resources rounding out most of the remainder. NYISO’s generation supply stack is characterized by numerous aging plants. Over 15 GW of generating capacity, representing over 38% of NYISO’s total generation capacity, is over 50 years old.
Source: NYISO 2021 Gold Book, April 2021.
Other power markets. The remaining 17% of our generation fleet operates in other markets including CAISO, ISO-NE, MISO and SPP in the U.S. and AESO in Canada. Our generation in these markets, by MW, consists of approximately 20% nuclear, 46% gas, 13% oil and 20% renewables.
The CAISO market serves customers primarily in California. CAISO features day-ahead and real-time energy markets and ancillary service markets. While CAISO does not operate a formal capacity market, it does have a mandatory resource adequacy requirement supported through bilateral contracts.
The ISO-NE market covers the six states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. It offers day-ahead and real time energy markets, ancillary service products, and a forward capacity market.
MISO is an RTO that covers all or parts of 15 states: Arkansas, Illinois, Indiana, Iowa, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, North Dakota, South Dakota, Texas, and Wisconsin; as well as the Canadian province of Manitoba. MISO operates day-ahead and real time energy markets and ancillary service markets. Capacity requirements are addressed through bilateral transactions or a voluntary annual auction that MISO administers.
SPP has members in 14 states: Arkansas, Iowa, Kansas, Louisiana, Minnesota, Missouri, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wyoming. It also provides contract reliability coordination services in Arizona, Colorado and Utah. SPP operates day-ahead and real-time energy markets and transmission service markets.
AESO provides the function of Independent System Operator in Alberta, Canada, where we own one generation asset. It is currently an energy-only model and does not operate a capacity market. AESO also operates a separate ancillary services market where resources provide specific services that help maintain grid reliability.