How electricity is traded
Like the city kid who thinks milk comes from the supermarket, many consumers assume that electricity comes from the utility that sends them a bill every month. Your electric utility does distribute the electricity — reducing the voltage from massive transmission lines to household levels and providing the wires to bring it to your home. However, your utility may not generate the electricity but may buy it from a generating company or wholesale electricity market.
In regions covering about two-thirds of households in the U.S., electricity is bought and sold through markets administered by Regional Transmission Organizations or Independent System Operators (referred to as RTOs). RTOs are independent third-party operators of high-voltage regional transmission systems that enable wholesale buyers and sellers of electricity to transport that electricity from source to destination. There are six RTOs in the country — ISO New England (ISO NE); New York ISO (NY ISO); PJM Interconnection (PJM, covering the Mid-Atlantic and a portion of the Midwest); Midcontinent ISO (MISO); Southwest Power Pool (SPP); and the California ISO (CAISO). These RTOs are regulated by the Federal Energy Regulatory Commission. The Electric Reliability Council of Texas operates an ISO regulated by the state and not FERC.
Why capacity markets don't work
Utilities own (or contract for) generation to provide electricity to their customers. In RTO regions, they may buy electricity in wholesale spot energy markets operated by these RTOs. In some states, utilities no longer own power plants and are more dependent upon these markets.
Some RTOs also have what they call capacity markets, that are supposed to support investment in generation resources to meet future demand for electricity. The American Public Power Association believes they are not really markets — but more about that later.
Capacity is the maximum amount of electricity that a generating resource such as a power plant is capable of producing. Utilities must have enough capacity to cover not only their customers' present needs, but also potential spikes in demand. As a result, utilities are required to own or buy enough capacity to meet their expected peak demand, plus a reserve margin to cover unexpected peaks or equipment outages.
Capacity markets were invented based on the theory that the revenue from these constructs would enable power plants to cover the cost of new infrastructure to supply future needs. In PJM, ISO NE, and part of the NY ISO, the capacity markets are mandatory, meaning that all the generators in those regions must participate and all the customers in those regions are responsible for the auction costs.
Where there are no RTO-operated capacity markets, as in much of the country, utilities either build their own generation or enter into contracts with generators to buy adequate capacity. Open access transmission and competitive wholesale markets allow capacity to be purchased at or near the actual cost, keeping prices low for customers. In these regions without mandatory capacity markets, utilities are able to provide a reliable supply of electricity at a reasonable cost, as has been done for decades. There is no evidence that capacity markets are necessary. Instead, they primarily serve to create windfall profits for certain merchant generation owners.
How capacity markets prices are set
RTOs with capacity markets hold periodic auctions where generation resources like natural gas plants, wind turbines, solar farms, coal plants, and nuclear plants bid to supply future electricity needs. The RTO administratively determines how much capacity will be needed. But capacity auctions do not allow for the purchase of capacity at the lowest cost. Instead, the auction has a single clearing price" set by the most expensive offer of the last resource that is needed to meet the region's capacity needs. RTOs use special tariff rules to determine the clearing price when capacity markets are determined not to be adequately competitive.
Until recently, all generators could submit any offer price, as long as it did not exceed a cap. As a result, many capacity owners bid at zero to ensure their capacity clears the auction and is paid the clearing price. These generators are usually paid through another arrangement — such as a long-term bilateral sales contract — or use their generation to serve their own customers' load. Moreover, their fixed costs may be already fully paid off. As a result, they are indifferent to the capacity auction price — their goal is just to clear the auction.
Self-supply keeps prices low
The ability to self-supply a customer's load through ownership or bilateral contracting is central to the public power business model. Outside of the mandatory capacity markets, public power can achieve self-supply without impediment. Within the RTO-operated mandatory capacity markets, public power also seeks to self-supply at least a portion of its customers' load as a means to reduce dependence upon the capacity markets.
Self-supply provides a viable alternative to the mandatory capacity market auctions, where prices are artificially driven up, offering windfall profits to some generators and driving up prices for customers.
How self-supply protections were removed
Capacity market rules make it very difficult for public power entities to self-supply their customers' electricity needs. Specific rules stand in the way in the PJM, ISO NE, and NY ISO-operated markets. They are called "buyer-side mitigation" or "minimum offer price" rules, which we'll refer to as BSM rules.
BSM rules are based on the unfounded fear of "buyer-side market power" — a scenario where an entity that generates and buys capacity might bid capacity it's selling into the auction at a low price — just to lower the price for capacity it must buy. These BSM rules allow the RTOs to set a minimum price on bids from new generation resources into the auctions, putting such resources at risk of not clearing the auction. If a buyer's capacity does not clear the market, it means that the buyer would pay twice for the capacity — once for owning or buying the capacity and a second time to purchase the same amount of capacity from the auction to meet their reliability requirement.
When the PJM and ISO NE capacity market rules were developed in 2006, public power utilities negotiated a guarantee that self-supply resources would clear the capacity auctions. States received an exemption from BSM rules for projects developed to resolve a projected capacity shortfall. But FERC removed these exemptions.
Frustrated with the high prices and limited new generation, New Jersey, Maryland, and Connecticut all established competitive bidding processes to buy capacity through long-term contracts. These state programs achieved what the capacity markets did not: installing cleaner and more efficient new resources in regions where they were needed most. But by bringing in additional generation at zero bids, state programs threatened the merchant generators' earnings potential. As a result, regional merchant generator associations filed complaints with FERC seeking to block such state efforts by tightening BSM rules and removing exemptions for self-supply.
In 2011, FERC removed the self-supply exemption from ISO NE and PJM's capacity markets. Problematic precedents were set in the New York ISO as well.
Rebuilding the right to self-supply
Public power has taken steps to rebuild its self-supply rights in the RTO regions. In PJM, negotiations in 2012 resulted in a limited exemption for self-supply resources from the minimum offer price rule if the owner of the resource is a load-serving entity such as a utility and meets some other criteria. FERC approved that limited exemption and denied rehearing, but generators in PJM have asked a court to overturn FERC's orders. In July 2017, the D.C. Circuit court vacated FERC’s order approving the exemption and remanded it back to FERC for reconsideration. What FERC will decide and whether it will act before the May 2018 PJM capacity auction is uncertain.
In the New York ISO, FERC granted an exemption from BSM rules for self-supplied resources in 2015, saying that it allowed load-serving entities like utilities to provide more stable prices and make decisions based on their customers' unique needs. But the NYISO’s proposed rule changes to implement FERC’s order have been challenged public power and state agencies because these rules would make it very difficult for self-supply resources to qualify for the exemption. Thus far, no exemption has been approved by FERC for the NYISO.
These self-supply exemptions are the culmination of years of effort by public power to rebuild their fundamental rights. But there is still no complete exemption for self-supply, as was agreed to in the original design of the capacity markets in PJM and ISO NE. A self-supply exemption recognizes that public power utilities are not-for-profit entities serving their customers at least cost, without the interest or ability to manipulate the market.
Public power’s ability to self-supply is closely tied to states’ abilities to procure needed resources. FERC recognized the difficulties facing the states in procuring resources within these capacity markets and held a two-day technical conference in May 2017 that explored how to accommodate these state policies. PJM and ISO-NE are also exploring this issue, and the outcome of these processes will also likely affect public power’s self-supply rights.
Unfortunately, public power has become collateral damage as the rules of the capacity markets are continuously adjusted under the influence of the merchant generators to block new entry and maintain high prices. Public power utilities will therefore need to continue to spend time and effort carefully guarding their business model against future market challenges."