Throughout most of the 20th century, energy services in North America were operated under monopoly conditions. A single company provided a given area with everything from energy generation to meter reading and billing. Deregulation moves the market toward a more competitive business environment, encouraging separate markets for most of the individual services required to produce and deliver energy.

The deregulated electricity markets have been separated into three distinct categories: Generation, Supply, and Delivery (local utilities). Open market competition of energy supply phase benefits the end user with lower costs than the default utility rates.

The Federal Energy Regulatory Commission (FERC), an independent agency of the U.S. Government with authority over electric utilities operating in the United States “estimates that consumers may benefit from a cost savings of $20 billion per year from deregulation.” – Haskew, B.S., Kyle, R. (2009) Electricity Deregulation – What, Why and How. MTSU (Middle Tennessee State University)

The electricity grid is run on regional and national levels by non-profit regulators who monitor demand and dictate generation. This complex process requires detailed forecasting and planning, as well as moment by moment routing and adjusting of power generation to meet constantly fluctuating demands. The grid operators also oversee and monitor the purchase and sale of electricity on a wholesale level, which ensures reliable operation of the entire system.


FERC’s Energy Policy Act of 1992 followed by FERC Orders 888 and 889 in 1996 laid the foundation for the deregulation of the electricity industry and creation of the network of Open Access Same-Time Information System (OASIS) nodes. OASIS nodes allowed for energy to be scheduled across multiple power systems, creating complex strings of single “point-to-point” transactions which could be connected to travel across the continent. This frequently created situations where it was difficult or impossible for transmission system operators to ascertain all of the transactions impacting their local system or take any corrective actions to alleviate situations which could put the power grid at risk of damage or collapse. The North American Electric Reliability Corporation (NERC) implemented the first energy tagging process to solve the problems introduced by deregulation. NERC Tags now track the increasingly complicated energy transactions which are produced as a result of electricity deregulation in North America. A NERC Tag (or E-Tag) represents a transaction on the North American bulk electricity market scheduled to flow within, between or across electric utility company territories. – NERC. (2008, August). In Wikipedia, the free encyclopedia. Retrieved June 24, 2010, from from http://en.wikipedia.org/wiki/North_American_Electric_Reliability_Corporation


While supply and generation have been deregulated, delivery remains regulated. What this means is that a consumer can choose their supplier but must utilize their Local Utility (LDC) for the delivery of supply.


A wholesale electricity market exists when competing generators offer their electricity output to retailers. The retailers then re-price the electricity and take it to market. Large end-users seeking to cut out unnecessary overhead in their energy costs are beginning to recognize the advantages inherent in such a purchasing move. Buying wholesale electricity is not without its drawbacks (market uncertainty, membership costs, set up fees, collateral investment), however, the larger the end user’s electrical load, the greater the benefit and incentive to make the switch. For an economically efficient electricity wholesale market to flourish, it is essential that a number of criteria are met. The market needs a coordinated spot market that has “bid-based, security-constrained, economic dispatch with nodal prices”. The theoretical price of electricity at each node on the network is a calculated “shadow price,” in which it is assumed that one additional kilowatt-hour (kWh) is demanded at the node in question, and the hypothetical incremental cost to the system that would result from the optimized redispatch of available units establishes the estimated production cost of the hypothetical kilowatt-hour. This is known as locational marginal pricing (LMP) or nodal pricing and is used in some deregulated markets, most notably in the PJM Interconnection (Mid-Atlantic), New York, and New England markets.

In LMP markets, where constraints exist on a transmission network, there is a need for more expensive generation to be dispatched on the downstream side of the constraint. Prices on either side of the constraint separate giving rise to congestion pricing and constraint rentals.

A constraint can be caused when a particular branch of a network reaches its thermal limit or when a potential overload occurs due to a contingent event on another part of the network (e.g., failure of a generator or transformer or a line outage). The latter is referred to as a security constraint. Transmission systems are operated to allow for continuity of supply even if a contingent event, like the loss of a line, were to occur. This is known as a security constrained system.

The system price in the day-ahead market is, in principle, determined by matching offers from generators to bids from consumers at each node to develop a classic supply and demand equilibrium price. This usually occurs on an hourly interval, and is calculated separately for sub regions in which the system operator’s load flow model indicates that constraints will bind transmission imports. In practice, the LMP algorithm described above is run, incorporating a security-constrained, least-cost dispatch calculation with supply based on the generators that submitted offers in the day-ahead market, and demand based on bids from load-serving entities draining supplies at the nodes. In most systems, the algorithm used is a Direct Current (DC) model rather than an Alternating Current (AC) model, so constraints and redispatch resulting from thermal limits are identified/predicted, but constraints and redispatch resulting from reactive power deficiencies are not. Some systems take marginal losses into account. The prices in the real-time markets are determined by the LMP algorithm described above, balancing supply from available units. This process is carried out for each 5-minute, half-hour or hour (depending on the market) interval at each node on the transmission grid. The hypothetical redispatch calculation that determines the LMP must respect security constraints, and the redispatch calculation must leave sufficient margin to maintain system stability in the event of an unplanned outage anywhere on the system.