Setting the Stage for 2014 Regional Energy Policy: Will Gas Beat Hydro?
by Jim Monahan, Vice President of the Dupont Group
The advent of new domestic natural gas reserves in the United States is transforming the energy market in New England. Over the past three years, the price of natural gas, which fuels a meaningful part of the regional electric generating fleet, has dropped dramatically. This dynamic will guide energy policy in New England and New Hampshire in 2014.
Across the New England control area there is a fleet of nearly 350 electric power plants that run on a combination of gas, oil, coal, nuclear and renewable fuels. However, the structure of the regional electric market requires that least-cost power plants are called upon first, in order to ensure low prices. As a result, the lower cost, newer and more efficient gas plants are dispatched more often than other plants. As the chart below indicates, while the lower cost gas plants run more frequently, the region has a strong portfolio of installed generation.
In the current and sometimes constrained gas market, there are concerns that a large call on gas-fired power plants could lead to limited hours with insufficient natural gas available to meet demand. In light of this, the Independent System Operator of New England (ISO-NE) initiated a 2014 winter supply strategy that invested in back-up oil supply and other adjustments to market rules to avoid periods of short supply. (As a general matter, the concern over short supply can be overstated. Any shortfalls are most likely to be for brief periods of time and only reduce contingency supply, which is held in reserve.)
ISO-NE has studied these trends and predicts that, due to the lower cost of gas and increased pollution standards, a number of older coal and oil units are at risk of being shut down over the next five to seven years. As a result, there is an interesting race underway to see who will step into the market to replace the estimated 8,000 megawatts (MW). Competitive solutions include gas, hydro, renewables and energy efficiency resources, each with their own benefits and challenges.
Hydro: The major player on the hydroelectric front is Hydro-Québec, a government owned powerhouse, with a long-term strategic goal of exporting thousands of megawatts of hydropower to US markets – primarily to New England and New York. The largest challenge to this resource is that it is located far away from load centers and requires massive transmission infrastructure to deliver the energy to market. Two major problems exist. First, the price of transmission makes transportation costs a real burden. When regional wholesale prices were higher (pre-gas revolution), the all-in costs of hydro production and transportation made for a better economic model than exists today. As a result, the Canadian hydro industry is attempting to create subsidies in the form of perceived low carbon government-prescribed purchases, or modification of state renewable standards to qualify this power for subsidies. Second, it is increasingly hard for Canadian hydro to get industrial transmission facilities sited. There is well-organized opposition to large overhead towers. Consequently, approval processes will likely be delayed for years. The risk of denial of siting approvals or abandonment of projects has become more substantial. Some project developers are addressing this siting problem by putting projects underground, which they hope will help to gain siting approval, but will increase the costs.
Natural Gas: Efficient natural gas plants can, and have been, building very close to load centers and thus are able to avoid the controversy and cost of large-scale transmission. The impediment that this solution has in New England is that despite an abundance of low cost natural gas being harvested in Mid-Atlantic states, there is not enough pipeline to deliver that gas into the New England market. To address this, new pipelines and expansion of the diameter of existing lines are currently being developed. Siting is less of a challenge, as the pipelines go underground and there is less opposition. However, the financing of gas pipeline projects is an obstacle. Gas pipeline developers typically want customers (electric generating plants and local gas utilities) to sign up for long-term supply contracts in order to support the financing of projects. There has been some lag in developers securing these contracts. Generators are leery of locking-in prices for long periods of time, given the robustness of the market and risk of committing to prices that might prove too high. Local Distribution Companies’ (LDCs’) current system of supply contracts is not structured to adopt a “build it and they will come” approach. Rather, the LDCs, as regulated utilities, must wait for market demand to build before they can invest in the type of supply contracts that pipeline developers are looking for. As a result, the pipeline subscription and financing process is moving slower than might be hoped; but given the market opportunities, most industry watchers assume that within a two-year timeframe, at least two major pipeline projects into New England will be financed and “pipe will be put in the ground.”
Renewables: Renewable energy projects such as wind and solar tend to be much smaller than large gas or hydro transmission projects. Wind projects can range from 20 megawatts (MW) to as much as 200 MW, while gas plants are typically 500 or 700 MW and hydro projects are 800 to 1,200 MW. Solar projects are small also. As a result, the scale of renewable energy needed to keep pace with gas or hydro is challenging. As a general rule, the capital costs for renewable wind and solar projects are higher when viewed as cost per megawatt. While this is balanced against no fuel costs once they are operating, the price a renewable project needs to get into the market is often not enough for it to compete with gas or hydro on a straight energy price. However, there are a number of programs that help renewable projects succeed. These include positive tax treatment at the federal level that provides for accelerated production tax credits; and state renewable energy programs that offer a separate payment stream, as well as some ability to enter into long-term contracts with utilities. These ancillary payment streams allow solar and wind, and to some degree biomass, to get into the New England market. However, it is unlikely that renewables will be able to capture the full 8,000 MW market opportunity that is emerging. In addition, siting problems are beginning to mount, particularly for wind projects, which could slow development.
Efficiency: By far the most cost effective energy investment is to use less energy. Eliminating usage has the same value as not paying the retail rate for power. However, the current market is neither set up to fully reward electric efficiency as load resources, nor can efficiency be used in the same way as generation in support of the market and reliability. Increasingly, the private market is developing financial instruments that will help efficiency capture some portion of the emerging market in New England, but not to the size and scope of hydro, gas and renewables.
Picking Winners and Losers
On the whole in New England, there is a combination of market and public policy forces determining which new resources will be developed over the next three to seven years. The current market-based structure, in which ISO-NE is set up to send appropriate market signals, is designed to ensure the right resource investments are made. In addition, there are public policies being developed at the state level which offer support to some solutions, as well. For example, five of the six New England states have Renewable Portfolio Standards (RPS) that require a portion of retail supply from renewable sources. This set of policies offers separate RPS payments for renewable power plants. Renewable Energy Certificates (RECs) provide renewable power plants a revenue stream that allows them to be price competitive with non-renewable resources.
In the battle between gas and government-owned Canadian hydro, there are no subsidies that might give one solution an advantage over another, in theory. However, as the hydro industry looks ahead to how their energy will price-out over the long-term, they see that it will end up being more expensive than gas. As a result, the hydro industry has begun to look for government-supported subsidies, and it is likely that they will continue to do so in 2014. Support might take the form of a joint procurement agreement among New England states that would offer hydro interests a long-term contract for power – thus locking-in a deal now, before new gas resources get to market. Also, in southern New England, there has been talk about finding a way to socialize some of the expensive transmission costs among rate payers, rather than having hydro developers pay for these costs.
Perhaps by the end of 2014, this combination of the market, regulation and government policy will give some signal of which resources will prevail. The risk is that policy makers might be asked to put a thumb on the scale to meet perceived short-term goals, but make long-term mistakes in the process.