Although nearly all energy experts agree that demand for electric energy in Texas will outstrip supply in the coming years, developers of new power generation facilities are facing significant headwinds. The cause of the problems is a unique mix of circumstances.
The competitive energy markets managed by the Electric Reliability Council of Texas (ERCOT) have been hailed by some as the best in the country for allowing the “free hand” of the wholesale generation market alone to send the appropriate pricing signals for new power plant construction. The following factors, however, pose challenges to ERCOT’s future energy supply:
- An unwillingness on the part of suppliers to enter into long-term power purchase agreements.
- A related lack of liquidity in the term energy markets.
- A general reluctance on the part of lenders to provide financing for “merchant” projects.
- Regulatory changes affecting both existing generators and developers of new power plants.
- The absence of a capacity market.
Because the time needed to develop and complete an electric generating facility can exceed three years, Texans may face serious power shortages if some of these issues aren’t resolved in the near term.
Demand for electricity in ERCOT is rapidly approaching the level of existing supply. ERCOT has a target reserve margin (the percentage of available resources above peak demand) of 13.75%. Maintaining that reserve margin is critical to ensuring stability of supply and avoiding blackouts and brownouts. However, in each reporting year after 2014, ERCOT currently projects the reserve margin to fall below this target level.
Three main factors make adding new generation in Texas difficult: its deregulated market, regulatory issues specific to ERCOT, and weak market signals.
A Deregulated Energy Market
As of Dec. 31, 2001, investor-owned utilities (IOUs) in ERCOT were required to unbundle their operations. Following deregulation of the ERCOT electricity markets in areas served by IOUs, the provision of service to end-use retail customers became competitive, and electric providers no longer had a captive body of retail customers. Without a captive body of customers, it became extremely difficult for suppliers to predict prospective demands for power. As a result, they are now generally unwilling to commit to long-term wholesale power purchase agreements or to the construction of new projects.
Although the useful life of a thermal generation facility can exceed 40 years, the capital costs to complete those facilities are extremely high. Though a 40-year power purchase agreement is not necessary to induce investors to build a new power plant, some level of predictable cash flows for a significant period of time will likely be necessary.
Those investors having a larger appetite for risk may be willing to invest without a long-term contact, but in order to do so, these higher-risk investors would also expect higher returns on their investment and would need to see forward pricing fundamentals/signals that suggest that those higher returns are forthcoming.
In recent times, however, the low price of natural gas has depressed the forward market for power and, as a result (with limited exceptions), those higher-risk investors have yet to see sufficient potential returns at the level required to start construction.
Moreover, even if such investors are persuaded that their equity investment is warranted, in most instances, project debt will also be needed to finance construction.
As lenders tend to be risk-averse, securing financing for uncontracted projects is likely to be a challenge in the current debt markets.
A Unique Regulatory Environment
The Environmental Protection Agency (EPA) has promulgated multiple regulations in recent years that affect the production of electricity. In addition, President Obama recently renewed his commitment to combatting global warming and described his plans to impose strict limits on greenhouse gas (GHG) emissions. These existing and pending regulations affect both existing generation, because the laws will require many owners to complete expensive capital upgrades, and developers of new power generation projects, because of the regulatory uncertainty, the added time required to obtain the necessary permits, and the resultant higher costs of development.
In the case of existing power generation, these regulations will give rise to the need for capital improvements and/or increased costs of compliance for many facility owners. Certain types of existing generation (namely, coal-fired) could be rendered uneconomic and forced offline if the costs to comply with environmental laws exceed the expected profits. Rather than investing significant funds in retrofitting existing units, investors may prefer to dismantle or mothball them if they cannot reasonably expect to recover those additional costs through future operations. In some extreme cases, carbon dioxide emissions standards may not be achievable because the technology does not yet exist to bring plants into compliance. In such circumstances, even if producers were prepared to invest in the necessary capital improvements, they will have no choice but to decommission their units.
Implementation of these new environmental regulations has proven to be particularly difficult in the ERCOT area because of the nature of the deregulated market. In regulated markets, utilities can reasonably expect to be able to recover the added costs of compliance through rate increases for their customers. In many parts of ERCOT, however, generators have no mechanism by which they can pass those costs along because customers are free to choose another provider at any time.
Development of new generation in Texas has also been rendered more difficult because of the recent changes in federal environmental regulations and Texas’s legal challenges to EPA actions. Developers seeking to build new large fossil-fueled power generation facilities must ordinarily obtain a Prevention of Significant Deterioration (PSD) permit under the federal Clean Air Act. PSD permits can be issued by the EPA; however, if a state is willing, the EPA may delegate its authority to the state. Alternatively, in accordance with a concept referred to as “cooperative federalism,” if a state develops and the EPA approves a state implementation plan (SIP), which in this context is basically an air permitting program sufficiently similar to that of the EPA, federal law allows the state to run its own PSD permitting program.
In late 2010, the EPA decided that SIPs that did not address GHG-emitting sources were inadequate. At that time, the EPA concluded that 13 states’ SIPs did not include GHG permitting. Twelve of those states either revised their SIPs consistent with the EPA’s nascent GHG permitting program or sought delegation of the EPA’s authority.
Texas, however, refused. In response, the EPA imposed a federal implementation plan that purportedly put the EPA directly in charge of issuing a part of the PSD permit related to GHG emissions in Texas. As a result, the PSD permitting process became bifurcated between Texas and the EPA, and developers of new power plants are now required to obtain two permits (one from the state of Texas and another from the EPA).
This bifurcation has caused a fair amount of regulatory confusion, which has resulted in a significant increase in the time needed to get full authorization to proceed with new power projects, especially considering the additional requirements imposed by other federal laws, such as the Endangered Species Act, when the EPA is the issuing agency. Furthermore, regardless of which agency is responsible for issuing PSD permits, controlling GHG emissions under the general legal requirement that facilities must apply Best Available Control Technology where no reasonably economic control technology exists for carbon dioxide and other GHGs has introduced substantial uncertainty into the permitting process. These added requirements, bureaucracy, and “technical” uncertainties have substantially contributed to the chilling of new development.
In a market where long-term supply contracts are extremely rare, forward pricing plays a significant role in determining whether an investor will be willing to build a new facility. With most forecasts anticipating low gas prices for the foreseeable future, the market is not currently sending the necessary pricing signals to those power plant developers/investors that might take the risk of building without a long-term contract.
Unlike other regions in the country, ERCOT does not have an organized capacity market (pursuant to which generators can be compensated for having available generation regardless of whether or not such generation is actually producing power). Many market participants in ERCOT believe that the development of a capacity market could help to mitigate the impending supply problem. However, detractors suggest that while a capacity market may help to keep existing power generation units online, it may not provide the necessary incentives to construct new generation.
This is because most envision the development of a capacity market similar to the one that currently exists in PJM (a regional transmission organization that coordinates the movement of wholesale electricity in all or part of 13 northeastern states and the District of Columbia). PJM uses a “reliability pricing model,” which is based on the use of capacity auctions to obtain a one-year capacity commitment three years ahead of the delivery period. Though this model does provide some increased certainty around project revenues, that certainty is fairly limited because pricing beyond the near term cannot be predicted and, in fact, is subject to myriad factors that could potentially cause volatility in prices.
As an example, the recent 2016/2017 reliability pricing model auction for PJM resulted (in many areas) in significantly lower prices than those obtained in its 2015/2016 auction, leading many market participants to be concerned with the reliability of the capacity market to be able to support new development. Given the recent events in PJM, questions remain as to whether implementation of a similar capacity market in ERCOT would provide the necessary incentives to both retain existing generators and incentivize new sources of supply.
Bridging the Pending Supply Gap
Though the challenges of power generation facility development abound, all hope is not lost. Certain regulatory changes being considered, along with other commercial innovations, might be just enough to deliver to ERCOT the additional power generation resources that it so desperately needs. Some new generation is being constructed, and efforts are being made to reduce demand and potentially increase revenues for power generators in ERCOT. Additionally, developers are working to find creative ways in which to make new projects economically feasible.
New Generation. Even with the challenges affecting developers of new generation, wind power remains economically viable in ERCOT. Through a combination of federal production tax credits and various financial and physical hedging, certain skilled wind power producers have been able to obtain the necessary capital to start construction of new wind farms.
Moreover, the regulatory approval process for wind generation is far less arduous than it is for fossil-fired power generators. While wind energy adds to the available supply in ERCOT, it produces other problems of its own. Intermittency is a material problem, as is the timing of much of the wind generation. Because the wind typically blows strongest at night, it results in a spike in supply when demand is generally at its lowest point. In addition, as the wind cannot be predicted with any certainty, other sources of more reliable power generation must also be included as part of the incremental supply of generation.
Another source of potential supply—energy storage—is being considered by many both because of its ability to balance the timing of power supply and demand and because of its ability to provide another source of revenue (in the form of ancillary services) to the investors in such products.
Demand Response. Demand response is a meaningful way to help address ERCOT’s pending supply shortfall. The ability to reduce demand through voluntary conservation, however, is limited by the availability of willing participants during peak periods of the day. At some point, though, even full conservation by willing participants will not prevent shortfalls in supply. Although demand response may help ERCOT in the near term, new power generation facilities will ultimately be needed.
Raising the Price Cap. In October 2012, the Public Utility Commission of Texas voted to double the cap on wholesale electricity prices over the succeeding three years. The commission stated that raising prices was necessary to encourage more plant construction and prevent power outages in areas served by ERCOT. Although this may encourage more interest in the ERCOT market, the continual increase in the price cap does not guarantee that prices at those higher levels will actually be achieved. It may actually give rise to potential concerns for investors, because a facility that experiences an outage when it is committed in the day-ahead market could see significant penalties if there is a spike in power prices in the hourly market.
Capacity Market. As described above, though there are significant issues to consider with the development of a capacity market in ERCOT, such a regulatory solution may be critical to spawning the much-needed construction of new power generation facilities. In the short term, a capacity market could induce generators to keep existing generation resources online or remove them from mothball status.
Though this may provide a short-term solution, the uncertainty of future pricing remains an impediment to new development. It is also worth mentioning that keeping older generation around, while effective, may be costly in the short term because older units are generally less efficient and more expensive to operate.
Other Solutions. Creative structuring has also been used to get new projects built in ERCOT. In addition to the wind facilities discussed above, at least one company has been able to begin new construction on two different gas-fired projects. Panda Energy is currently building two large power generation facilities—Sherman and Temple—and each is being partially funded with project debt. By using revenue put options in lieu of a long-term power purchase agreement, Panda was able to assure its investors of a stable stream of revenues sufficient to obtain the necessary commitment of capital.
Reason for Hope
Although the challenges facing developers in the ERCOT market today are significant, new and creative solutions are emerging that have the potential to provide ERCOT with the energy supply that it needs in the coming years. Energy demand is expected to grow significantly because of the high population growth rate anticipated for the state of Texas. As a result, finding viable solutions to ERCOT’s supply shortage is extremely important.
Many of the short-term fixes mentioned above may be helpful in alleviating the problem, but some regulatory changes may be necessary in order to allow ERCOT to be certain that it can meet the demands of its end users over the long term.
— Stuart Zisman is a partner and Katherine Milton is an associate with Bracewell & Giuliani LLP in Houston.