The United States doesn’t have one single monolithic “deregulated market” – instead, we have a quilt of regional markets, each with its own rules, pricing dynamics, and quirks. If your business operates in multiple states or if you’re comparing opportunities in different deregulated areas, it’s important to recognize these differences. This page highlights some of the major regional competitive electricity markets and what commercial buyers should know about each. We’ll cover a few key regions: Texas (ERCOT), the Mid-Atlantic/Midwest (PJM), New York (NYISO), New England (ISO-NE), and touch on others like MISO and California (CAISO). The goal is to illustrate why a one-size-fits-all procurement strategy may not work nationwide and how to adapt.
Texas (ERCOT) – The Texas market (managed by ERCOT) is often considered an outlier. Texas has a fully deregulated retail market in most areas of the state, meaning virtually all commercial customers choose a supplier (except in municipal/co-op territories). Unique features of ERCOT: it’s an energy-only market with no capacity payments. This means generators only get paid through energy prices, not separate capacity revenues. As a result, wholesale prices in ERCOT can be extremely volatile – there’s a high price cap (currently $5,000 per MWh). During normal times, prices in Texas can be among the lowest in the nation (especially when wind and solar production is high, sometimes prices even go negative). But during scarcity (e.g., a major heatwave or a grid emergency like the Feb 2021 winter storm), prices have spiked to the cap, sending monthly average prices through the roof. For buyers, this means if you’re on an index contract in ERCOT, you must have a risk plan (like curtailment or backup generation) for those rare but impactful events. On the flip side, no capacity charge means your bill might have fewer components – you largely worry about energy and transmission. Strategies in ERCOT: many savvy users do block & index or caps to enjoy low periods but shield from spikes, and demand response is popular (getting paid to help during emergencies). Also, Texas has abundant renewables, so some companies sign direct PPAs with wind/solar farms as a hedge and green source (see Sustainability page). In summary, ERCOT offers low average costs but high risk of price shocks – tailor your contract and possibly invest in onsite solutions to manage that.
PJM (Mid-Atlantic & Midwest) – PJM is a huge multi-state RTO covering 13 states from New Jersey to Illinois. Most states in PJM are deregulated for retail. PJM operates a full suite of markets, notably it has a capacity market (Reliability Pricing Model). For consumers, this means you’ll see a capacity charge on your bill or included in your rate, which in recent years has become quite significant. For instance, capacity auction results for 2022-2023 led to sharply higher costs – some customers saw a ~30% uptick in their all-in power cost just from capacity increases. Thus, managing your capacity tag (5CP – five coincident peaks) is key in PJM. The region’s energy prices are generally moderate (benefiting from diverse generation), but do fluctuate with gas prices and weather (hot summers, cold winters). Regional differences within PJM: it’s one market, but pricing can vary by zone due to transmission constraints. For procurement, a common approach is fixed pricing but with a strategy to handle capacity – e.g., some contracts pass capacity through so you can attempt peak shaving. Demand response programs are mature in PJM, so you can get paid for curtailing load on critical peak days (or even provide capacity via gensets). In PJM, an astute buyer will pay attention to both the energy and capacity components. It’s often worth investing in load control tech to hit those peak hours and reduce next year’s costs. Overall risk in PJM is moderate – you won’t see $5,000/MWh energy prices (cap is ~$2,000 and rarely hit), but capacity cost swings and seasonal peaks are your focus.
NYISO (New York) – New York has its own market with some unique attributes. It also has a capacity market, with different zones (NYC being highest cost). New York often has high energy prices relative to other regions because of transmission constraints and expensive generation (especially downstate). Winters can see price spikes due to natural gas pipeline limitations (if it’s very cold, gas for heating leaves power plants short, they burn oil, prices jump). For commercial buyers in NY, a big cost driver is the capacity tag (the ICAP tag) – if you have operations in NYC, your capacity charge per kW can be multiple times that of an upstate facility. The strategy is similar to PJM: watch for the single peak hour of the year (they typically call “peak day” alerts) and try to reduce usage then. Also, New York has aggressive renewable energy goals, so more customers are interested in green supply options (some utilities offer “green supply” and community solar projects abound). Another note: the NYISO market has “buyer-side mitigation” rules affecting how new resources bid in – arcane, but mentionable if you follow policy (it can affect how easy it is to integrate your own behind-meter generation or DR in the market). In general, NYISO’s costs are high but predictable if managed – lots of companies just do fixed contracts to avoid wild winter surprises, unless they’re large enough to play the peak-shaving game.
ISO New England (New England states) – This market covers 6 states in the Northeast. It’s known for having some of the highest electricity costs in the continental US. Why? New England relies heavily on natural gas for generation but has limited gas pipeline capacity, so in winter gas is scarce and expensive. This has led to infamous price spikes in cold snaps. Also, New England has a forward capacity market – capacity charges are significant and rising as older plants retire and grid reliability is a concern. If you operate in say Massachusetts or Connecticut, you’ll likely see energy rates that are double those in Texas on average, plus high transmission costs (due to lots of transmission investment in the region). Strategies: demand response is heavily used here (if you can cut load on very cold days or hot days, do it). Many companies invest in energy efficiency and on-site generation (solar, etc.) to simply buy less from the grid since it’s so pricey. Some also look at fuel switching – e.g., those with dual-fuel boilers might use oil on peak gas days (not great environmentally, but potentially cost-saving in an emergency). For procurement, fixed contracts that avoid winter index exposure are common (some will do seasonal hedges – e.g., lock in winter completely, maybe float a bit in mild spring/fall). New England buyers have to be quite proactive; even the default utility rates here have been shockingly high in some seasons (e.g., winter default rates of 15+ ¢/kWh for businesses). Battery storage is an emerging tool to shave peaks in this region as well (with state incentives).
MISO (Midcontinent ISO) – This is a bit of a hybrid market because not all states in MISO are deregulated (some Midwest states like Illinois have retail choice, others like Indiana do not). MISO also has a capacity market but historically lower prices than PJM/NYISO. If you’re in a deregulated part of MISO (like Illinois or Michigan’s electric choice program for certain customers), you’ll want to watch capacity planning but the bigger driver is often just wholesale energy which is influenced by a mix of coal, gas, wind in that region. MISO has seen some constraints in certain areas (like Illinois had tight capacity a year or two ago). But overall, costs tend to be a bit lower than East Coast. Still, if you’re in Illinois which is part of PJM actually (northern IL), or Michigan (part MISO), you adapt accordingly. It’s a reminder: know which market your deregulated state is tied to – for example, Illinois is split (ComEd area is PJM, Ameren area is MISO), with different dynamics.
California (CAISO) – California’s situation is unique: the state is only partially deregulated (large businesses can go direct to suppliers or join community choice aggregators, but it’s complex). For those participating in the market, CAISO prices can be volatile due to solar influx (low midday prices, high evening prices) and occasional tight supply in late summer. There’s also no formal capacity market like PJM’s; they handle resource adequacy differently. If you have load in California, you likely have some regulated utility involvement unless you’re on a Direct Access program. Managing time-of-use is critical in California – running operations in the middle of the day can be cheaper (lots of solar), whereas the 4-9pm period is expensive. California also has carbon costs baked into power prices and aggressive renewable requirements.
General Advice by Region: Always factor in local market traits when crafting your energy strategy. In capacity-heavy markets (PJM, NYISO, ISO-NE), focus on capacity management – it can make or break your costs. In energy-only volatile markets (ERCOT, CAISO), focus on price response and hedges – how will you handle that 99th percentile event? Also, consider regulatory trends: e.g., some regions are pushing for more renewables which could lower energy prices long-term but maybe increase transition costs; others might tighten capacity rules. Keeping an ear to the ground (or having a broker/consultant who briefs you) on regional market news is valuable.
Lastly, if your company spans multiple regions, you might think about balancing strategies: maybe you keep Texas on index because you have on-site generation there, but you fix pricing in New England because you can’t risk those spikes. It’s okay to not have a uniform approach across all operations – regional optimization is key.
(The Working with Energy Brokers page can be helpful if navigating these different markets feels daunting – brokers often have expertise in multi-region procurement. And if you’re interested in leveraging those abundant renewables in places like Texas or new programs in states, check out Sustainability in Energy Procurement next.)