By Shilpa Kokate
Editor’s Note: This article is based on a paper presented at POWER-GEN International on Dec. 14, 2016.
The United States electric energy sector that includes utilities, independent power producers, public power authorities, renewable developers etc. has been traditionally considered a relatively safe and defensive investment due to its potential for providing a steady stream of dividend income.
|The Crescent Dunes Solar Energy Project near Tonopah, about 190 miles northwest of Las Vegas, Nevada.|
The electric energy sector’s vulnerability to shifting market conditions has become more evident in recent years due to environmental regulations, a sustained push for higher penetration of renewables and continued volatility in fuel prices. While part of the problem facing renewable developers includes a heavy debt burden and an inflexible market structure that is not necessarily aligned with the changing mix of resources, the conundrum that other market participants are facing include the relentless pressure on coal market participants due to various environmental regulations1 and lower natural gas prices and the adverse impact on the profitability of certain nuclear power plants due to lower natural gas prices.
Figure 1 shows capacity additions by fuel type in gigawatts from 2000 to 2020 while Figure 2 lists the retirement of power generating facilities during the same time period. The first five years starting year 2000 saw the emergence of merchant power facilities across the nation followed by a period of high natural gas prices. While new coal facilities were being proposed around the 2009-2012 time frame, stricter environmental regulations forced cancelation of new coal units as well as shutting down of uneconomic coal-fired plants. Renewable resources started leveraging the federal tax credits and state level mandates starting 2008, with occasional spikes in construction activity following the extension of federal tax credits, and continue to grow at a steady pace. Nuclear facilities, while currently facing losses in certain market areas in the country, the Southeast is experiencing growth for second generation nuclear facilities by 2020.
The current electric energy landscape, while promoting fuel diversity through the use of fossil-fired power plants running on coal, natural gas, oil etc. along with plants running on energy generated from the sun, wind, nuclear fuel, hydro, biomass, geothermal, landfill gas, fuel cell etc., also attempts to maintain a diversified set of resources while taking into account the potential and limitations of various regions in the country.
Figure 3 lists the resource mix, in percentage for three representative years (i.e. 2005, 2016 and 2040) across five regions that include ERCOT or Texas, MW (Midwest), NE (Northeast), SE (Southeast) and Western Electricity Coordinating Council (WECC) or areas covering California, the Northwest Power Pool, Rocky Mountain Power Area etc., under the ABB Base Case as forecasted by ABB EPM Advisors2.
The ABB Base Case is a forecast of future conditions based on fundamentals of demand or load forecast and supply or fossil-fired and renewable resources as well as fuel prices (natural gas, oil, uranium, coal), non-power demand curves, energy efficiency, demand response, distributed generation, power market, emission, and renewables rules, transmission topology etc. Markets covered include the Electric Reliability Council of Texas market or ERCOT, the MW region that includes the PJM Regional Transmission Organization (RTO) covering 13 states and District of Columbia, the MISO RTO covering 15 U.S. states and the Canadian Province of Manitoba, the Southwest Power Pool (SPP), Saskatchewan region, the Northeast region that includes the New York ISO, the New England ISO and the Canadian provinces of Ontario, Quebec and Ontario, the Southeast region of United States and the WECC region that includes the California ISO, the Northwest Power Pool, Rocky Mountain Power Area, the Desert Southwest etc.
The resource mix graph listed above shows the decline in coal from 19 percent in 2005 to 15 percent by 2040 in ERCOT, from 43 percent in 2005 to 22 percent by 2040 in the Midwest, from 36 percent in 2005 to 17 percent by 2040 in the Southeast, from 9 percent in 2005 to 1 percent by 2040 in the Northeast region and from 19 percent in 2005 to 8 percent by 2040 in the WECC region. As indicated earlier, these coal retirements (i.e. announced, age-based and economic3) are driven not just by environmental regulations but also by lower natural gas prices in the ABB Base Case. In order to maintain reserve margins across the five regions and to meet future forecasted load growth, new power plants, typically natural gas-fired, are added to the resource mix and by 2040, they account for 57 percent in ERCOT, 56 percent in the Midwest, 64 percent in the Southeast, 61 percent in the Northeast and 36 percent in the WECC region.
Lower natural gas prices and the ability of natural gas-fired units (i.e. Combined Cycle Gas Turbine) to run as baseload units are an obvious driver for resource additions in the ABB Base Case but it is also important to note the level of uncertainty associated with the natural gas market. Examples include the price spikes related to hurricane Katrina in 2005, the polar vortex of 2014 as well as the 2016 methane leak at a Southern California natural gas storage facility. But the share of renewable resources increases by 2040 across all the regions due to favorable federal and state policies4 and declining cost of solar and wind assets. By 2040, the share of renewables increases to 24 percent in ERCOT, 14 percent in the Midwest, 5 percent in the Southeast, 16 percent in the Northeast and 36 percent in the WECC region. In sharp contrast, the corresponding 2005 share of renewables in ERCOT is 2 percent, 1 percent in the Midwest and Southeast regions, 3 percent in the Northeast region and 4 percent in the WECC region. The share of nuclear resources in 2005 that range from 6 percent in ERCOT and WECC regions, 11-12 percent in the Midwest and Southeast regions to 13 percent in the Northeast region is reduced to 4 percent in ERCOT and the Midwest regions, 5 percent in the Northeast region, 3 percent in the WECC region and 8 percent in the Southeast region. The decline in nuclear power capacity by 2040 is driven by lower natural gas prices as well as expiration of their operational licenses.
Carbon Emissions in the Power Sector (United States)
What does the forecasted change in resource mix between 2005 and 2040 mean for carbon emissions? Figure 4 lists the impact on CO2 emissions5 under three scenarios6 that include the ABB Base Case, the High Renewable Penetration and Nuclear Life Extension scenarios. Carbon emissions in 2005 were at 2,500 millions of tons but the forecasted capacity additions and retirements in the ABB Base Case result in lower carbon emissions throughout the forecast horizon of 2016 to 2040. CO2 emissions peak at 22 percent below 2005 levels by 2019 and decline to 6 percent below 2005 levels by the end of forecast period in the ABB Base Case.
While CO2 emissions are also lower in the High Renewable Penetration and the Nuclear Life Extension scenarios7, the option of choosing a particular type of resource mix becomes clearer under these scenarios. There is no denying the fact that higher penetration of renewables is inevitable given their declining cost (i.e. solar and wind) and favorable renewable policies in the country but if United States is to cost effectively meet its carbon emission reduction targets while preserving fuel diversity, perhaps a rethinking of our expectation for the future resource mix is warranted?
High Renewable Penetration Scenario
The High Renewable Penetration scenario that reflects the same assumptions as those in the ABB Base Case except for an additional 173 gigawatts of renewable resources results in carbon emissions that is 11 percent below 2005 levels. In contrast to the High Renewable Penetration scenario, carbon emissions under the Nuclear Life Extension scenario are 13 percent below 2005 levels. The Nuclear Life Extension scenario has the same assumptions as the ABB Base Case except for the assumption that all nuclear units receive approval for life extension beyond their current license period thus resulting in the availability of approximately 100 gigawatts of nuclear capacity through 2040. Key takeaways from these scenarios is not the just the potential for reductions in carbon emissions8, but also the level of investment involved and the cost-to-benefit impact.
Figure 5 that displays the resource mix under the High Renewable Penetration scenario9 depicts the expected decline in nuclear and coal resources through the forecast period as driven by lower natural gas prices and environmental regulations. In order to meet load growth and reserve margin requirements, the resource mix is supplemented by new natural gas-fired resources and a large number of renewable resources during the forecast horizon. But renewable resources such as solar and wind, while effective at lowering carbon emissions, are also weather dependent, may end up being curtailed during periods of over-production and have lower capacity factors necessitating dependence on flexible natural-gas fired resources as a backup resource.
Nuclear Life Extension Scenario
Extending the life of nuclear resources, on the other hand, not only reduces the investment flows related to new natural gas-fired resources that are added during the forecast period but also ensures compliance with the 2012 carbon emissions target at a more sustainable pace in comparison to the ABB Base Case. Figure 6 lists the resource mix under the Nuclear Life Extension scenario10. In comparison to the ABB Base Case, this scenario results in a decline in new natural gas-fired resource additions through the forecast period due to the availability of additional baseload power from nuclear resources that run at relatively higher capacity factors.
Despite the advantages that nuclear resources appear to display in comparison to other types of resources, whether renewable resources or fossil-fired plants, a number of nuclear power plants today are in a near crisis state. Nuclear power plants in New York, California, and Illinois11 are some prime examples and the plant owners and operators blame lower natural gas prices, lack of price for carbon, and higher cost of operating the power plants for the looming crisis. Higher investment and financing costs, waste disposal costs, lingering safety issues especially after the Fukushima accident regarding radioactive contamination risks and longer lead times for new nuclear power plants are cited as constraints for new nuclear facilities. Despite these concerns, it is important to note that there are some nuclear plants that are well located in certain markets, are profitable and therefore not facing the threat of closure.
Does this mean that it is a doom-and-gloom scenario for nuclear facilities across the country? Not if you take into consideration the United States Department of Energy’s (DOE) target of 200 gigawatts of nuclear capacity additions by mid-century in its June 2016 Vision & Strategy report for advanced reactors. The DOE has called for at least two advanced reactor concepts to be developed, and to have reached technical maturity and completed licensing reviews, by 2030. It has also announced $82 million in funding to support advanced nuclear energy research, with 93 projects in 28 states receiving awards. The federal agency has also indicated that it would support cost-shared, industry-led research and development for concept-level development and conduct research into high-temperature reactor concepts, liquid metal cooled fast reactors, gas fast reactors and molten salt cooled reactors to further enhance its testing capabilities and support the timely deployment of advanced reactors.
In New York, the Public Service Commission (NYPSC) Staff proposed and the Governor of the state recently approved, a nuclear tier12 under its Clean Energy Standard (CES) to extend a lifeline to the struggling upstate nuclear power plants and to provide a ‘bridge’ until renewable resources are developed on a large scale. Under the state’s nuclear tier, the nuclear operators are eligible to earn Zero Emission Credits (ZECs) although the maximum price for the ZEC would be administratively set by the NYPSC. Also like RECs, ZECs will be tradable, but the two types of products would not be interchangeable under the CES.
Low Carbon and/or Carbon-free Outlook
While there are undeniable benefits under a Low Carbon13 or a Carbon-free14 outlook in terms of lower carbon emissions for the future electricity grid, there are numerous challenges that need to be addressed. Both wind and solar powered facilities can look forward to lower capital costs over the next decade or more. Figure 7 displays the wind and solar experience curves15 which represents the percent decrease in prices with the doubling of worldwide installed capacity. For onshore wind, the percent decrease in prices is 19 percent with four doubling of capacity in the past 15 years and for solar PV modules, the percent decrease in prices is 24 percent with 7 doubling of capacity in the past 15 years. The extension of federal tax credits also bodes well for the renewables sector.
All the same, the Low Carbon or a Carbon-free grid outlooks will need to take into consideration challenges such as vast dollar outflows related to strengthening of the transmission infrastructure to deliver power from remote locations to consumption markets, financing difficulties, existing market designs16, variable generation, rate structures etc.
One of the many challenges to highlight would be the lack of tax equity capacity posing a strong impediment for further growth in the renewables market. The Production Tax Credit (PTC), a key driver for wind projects has allowed developers to monetize tax credits17. The monetization involves a ‘partnership flip’ structure that removes the tax credits and delivers them to an equity owner in a partnership. The project developer thus holds a minimum level of equity with about 90 percent of the equity transferred to a partner that can use the credits to offset taxable earnings, or that can package those credits and sell them to other parties with a tax appetite. When the after tax rate of return is achieved, usually timed with the 10-year expiration of the PTC, the partnership structure flips, with the developer taking 99 percent of the equity in the project. The dearth in these types of innovative mechanisms post expiration of the tax credits will continue to pose a challenge.
Another potential area to re-evaluate is reconciliation of policies that require economic competitiveness as well as cost effectiveness for consumers at the same time. As an example, let’s look at the potential conflict arising from the re-design of the Regional Greenhouse Gas Initiative (RGGI) market versus state of Maryland’s objectives. In 2014, RGGI set an emissions cap of 91 million tons that declines by 2.5 percent annually to 78.2 million tons by 2020. Environmental advocates and Massachusetts state officials have called for doubling the rate of decrease to 5 percent annually but that could potentially create problems for Maryland. Power plants in this state operate and sell into the PJM markets and compete against generators in Pennsylvania, Ohio, West Virginia and Kentucky states that aren’t impacted by the same restrictions. Under the proposed RGGI market re-design, the proposed emissions cuts could price power producers in Maryland out of the market. Therefore, the state of Maryland has requested a consideration of economic competitiveness and the cost of energy to local ratepayers in the re-design of RGGI market.
Does the current market structure create sufficient incentives to meet the objectives under the Low Carbon or Carbon-free grid Outlooks? Rate design challenges is another area that will need to be looked at under the Low Carbon or Carbon-free grid Outlook. A large portion of a typical utility’s costs are fixed but a major portion of their revenues is variable. The typical utility rate design consisting of a small monthly fixed charge and a volumetric energy charge does not help in recovering the utility’s fixed costs. The expectation of a higher penetration of renewables and load dampening through demand response and energy efficiency will slow down the already anemic growth in sales and therefore the typical utility rate design will not be able to assist in recovering the utility’s required revenues.
Another aspect to consider is the level of technological and market structure related changes that will be required to achieve carbon emission reductions under the Low Carbon or the Carbon-free grid Outlooks. The magnitude of technological and market structure related changes to achieve, for example, the 2030 carbon emission reductions, may be very different from what will be required to get to the next frontier in carbon emission reductions (i.e. 2040 and/or 2050 carbon emission reductions).
The future as envisaged under the Low Carbon or Carbon-free grid Outlooks may appear daunting but remains feasible provided policies and implementation mechanisms, whether technological and/or regulatory, are allowed to develop and evolve. This will require bringing about changes in rate structures, market design, regulatory policy, operating procedures etc. in addition to innovative technical solutions.
Shilpa Kokate is an advisory consultant for ABB Enterprise Software Inc.