Market Structure Fundamentals: Regulated vs. Deregulated

Understanding the fundamental structure of electricity markets is the first step in navigating their complexities. The U.S. electricity landscape is a patchwork of different models, primarily divided between traditionally regulated markets and restructured, or deregulated, markets.

Regulated vs. Deregulated Markets

In a traditionally regulated electricity market, a single entity, the vertically integrated utility, typically owns and operates all aspects of the power system: generation (power plants), transmission (high-voltage lines), and distribution (local wires to customers). This utility usually enjoys a regional monopoly, meaning consumers in that area have no choice but to buy power from them. Rates are set by state Public Utility Commissions (PUCs) through lengthy regulatory processes designed to allow the utility to recover its costs plus a "fair" rate of return on its investments. This model provides price stability but often lacks incentives for innovation and efficiency, and offers no consumer choice.

In contrast, a deregulated (or restructured) market aims to introduce competition, primarily in the generation segment. The functions are unbundled:

  • Generation: Multiple companies (Generators or GENCOs) compete to produce and sell electricity into a wholesale market.
  • Transmission: High-voltage lines often remain regulated or are managed by an independent entity.
  • Distribution: Local delivery (poles and wires) typically remains a regulated monopoly function provided by the local utility (often called a Transmission and Distribution Utility or TDU/TDSP).
  • Retail: In many deregulated states, consumers can choose their Retail Electric Provider (REP) from competing companies that buy wholesale power and sell it to end-users.

The goal of deregulation is to leverage market forces to drive down costs, encourage innovation, and offer consumers choices in price plans and services.

Historical Evolution of Deregulation

The shift towards deregulation in the U.S. began modestly with the Public Utility Regulatory Policies Act (PURPA) of 1978, which required utilities to buy power from certain non-utility generators. The major impetus came with the Energy Policy Act of 1992, which opened up wholesale electricity markets to competition by requiring transmission owners to provide open access to their lines.

Following this, FERC Orders 888 and 889 in the mid-1990s further defined open access transmission rules and encouraged the formation of Independent System Operators (ISOs) to manage the grid impartially. Many states began restructuring their markets in the late 1990s and early 2000s. However, the California energy crisis of 2000-2001, caused by flawed market design and manipulation, led some states to halt or reverse their deregulation efforts. Today, about two-thirds of U.S. electricity load is served within competitive wholesale markets managed by ISOs/RTOs, while roughly one-third remains under traditional vertically integrated utilities. Some regions have hybrid models.

Independent System Operators (ISOs) / Regional Transmission Organizations (RTOs)

To manage competitive wholesale markets and ensure reliable grid operation across large regions, Independent System Operators (ISOs) or larger Regional Transmission Organizations (RTOs) were formed. These non-profit entities operate independently of market participants.

Key functions of ISOs/RTOs include:

  • Operating the high-voltage transmission grid reliably.
  • Administering centralized wholesale markets for energy and ancillary services.
  • Managing transmission congestion.
  • Ensuring non-discriminatory access to the transmission system.
  • Planning transmission system expansion.

Major ISOs/RTOs in the U.S. include:

  • ERCOT (Electric Reliability Council of Texas): Covers ~90% of Texas load. Unique as it operates largely outside FERC jurisdiction and runs an "energy-only" market.
  • PJM Interconnection: The largest RTO, serving 13 Mid-Atlantic and Midwestern states and D.C. Operates under FERC jurisdiction and includes a capacity market.
  • CAISO (California ISO): Manages the grid for most of California. Operates under FERC jurisdiction; uses a resource adequacy requirement instead of a centralized capacity market.
  • NYISO (New York ISO): Operates New York's wholesale market under FERC jurisdiction, including a capacity market.
  • ISO-NE (ISO New England): Serves the six New England states under FERC jurisdiction, with a capacity market.
  • MISO (Midcontinent Independent System Operator): Covers a large swath of the Midwest and parts of the South under FERC jurisdiction, with resource adequacy requirements.
  • SPP (Southwest Power Pool): Operates in the central U.S. under FERC jurisdiction, with resource adequacy requirements.

Understanding which ISO/RTO governs a specific region is crucial as market rules, pricing mechanisms, and reliability requirements can differ significantly.

Energy-Only vs. Capacity Markets: A High-Level View

A fundamental difference in market design relates to how regions ensure they have enough generation capacity to meet future peak demand reliably:

  • Energy-Only Markets (e.g., ERCOT): Generators primarily earn revenue from selling energy and ancillary services. The market relies on allowing prices to rise significantly (to a high cap, e.g., $5,000/MWh in ERCOT) during periods of scarcity. The expectation is that these occasional high prices will provide sufficient revenue over time for generators (especially peaking units) to recover their investment costs and incentivize new construction. Consumers benefit from theoretically lower average costs (no separate capacity charge) but face exposure to price volatility.
  • Capacity Markets (e.g., PJM, NYISO, ISO-NE): In addition to energy markets, these regions operate a separate market where generators (and other resources like demand response) are paid for being available to produce power in the future (typically 1-3 years ahead). Load Serving Entities (LSEs) are required to purchase sufficient capacity credits to meet their share of the region's peak demand plus a reserve margin. This provides a more stable revenue stream for generators, intended to ensure resource adequacy even if energy prices are low. Consumers pay an explicit capacity charge on their bills but theoretically gain greater reliability assurance.

CAISO and MISO use Resource Adequacy (RA) mandates, where regulators require LSEs to contract for capacity bilaterally or through other means, achieving a similar goal without a centralized ISO-run capacity auction.

The debate over which model is superior continues, with each having shown strengths and weaknesses, particularly during extreme weather events. (See Case Studies).

Further Reading: