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  • ORIGINAL REPORTING: The ideal time-of-use rate and why it matters
  • ORIGINAL REPORTING: The new demand response and the future of the power sector

  • TODAY’S STUDY: New Energy – A Global Overview
  • QUICK NEWS, June 19: Things To Do About Climate Change; Why Customer Choice

  • TODAY’S STUDY: Study Shows Solar Is NOT Going Just To The Rich
  • QUICK NEWS, June 18: Buying A Home In A Time Of Climate Change; New Reasons To Buy New Energy

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  • FRIDAY WORLD, June 22:

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  • Emerging New Energy Markets Are Key

    Wednesday, December 18, 2013


    Exploring Natural Gas and Renewables in ERCOT, Part II: Future Generation Scenarios for Texas

    Ira Shavel, et. al., December 10, 2013 (Texas Clean Energy Coalition)

    Introduction and Summary

    All over the world, electric power systems are experiencing the impacts of cheaper renewable energy, expanded unconventional natural gas and oil, new policies to address global climate change risk, and dramatic technical progress on the many facets of electricity control, efficiency, and pricing. These and other factors are prompting large changes in the expansion and management of the electric power grid.

    In the electrically-independent power system of Texas known as ERCOT, the evolution of the power sector is especially related to the development path for renewable energy and natural gas-fired power. With over 12,000 MW of installed capacity, Texas is the largest state producer of wind-powered electricity in the U.S.1 Wind resources in Texas are more than double the next two largest wind capacity states combined.2 At the same time, Texas is the leading U.S. producer of natural gas, and the state generates nearly half its electricity from natural gas plants, substantially more than it generates from coal or nuclear power.3 Texas also has abundant, high-quality wind resources and solar energy potential.

    In June of this year, we produced a white paper for the Texas Clean Energy Coalition (TCEC) exploring qualitatively the short- and long-run interaction between natural gas and renewables in Texas’ energy future. This preliminary review found that the relationship between natural gas and renewables had aspects that were both complementary and, in some cases, substitutive. We found that over the next two decades the degree to which natural gas or renewables “crowd out” the other source, as opposed to develop together, was a function of future policies and market design features, technological developments, and the price of electric fuels and resources of all types.

    In this report, we examine the future of gas and renewable power in Texas analytically through the simulation of several future grid expansion scenarios. Using a state-of-the-art modeling system, we simulate the ERCOT system through 2032 under the six scenarios shown in Table I-1: a reference scenario which includes a required reserve margin requirement; a similar case without a reserve margin requirement; a scenario with high natural gas prices; a scenario with high gas prices and lower renewable energy costs; and two scenarios with potential EPA coal power plant rules. Table I-1 summarizes our scenarios and Section Three describes them in more detail.

    In each scenario, our modeling system simulates both the market-driven additions and retirements of capacity by power generators and the operation of the system by ERCOT, down to the intra-hour time frame, once these additions are installed. By combining the long- and short-term time frames, our approach insures that the resource addition selected by the market result in a system that is able to provide grid power at the lowest total cost consistent with reliability standards.

    Our modeling approach is guided by the assumption that as the amount of variable (or intermittent) renewable energy added to an electricity system increases, so does the relevance of short-term dynamics such as the ability to quickly start and ramp power resources up and down to closely follow the fluctuating renewable supplies. Traditional approaches to analyzing the optimal addition and retirement of power plants over time tend to represent such dynamics in a very simplified form at best. Our approach allows us to model the shorter term operational constraints made more prominent by the introduction of variable renewable sources in a very detailed fashion.

    Our models were run using data on generating units and fuel prices primarily from ERCOT, the U.S. Energy Information Administration, and the Electric Power Research Institute. We supplemented these data with our own analysis and calculations regarding renewable energy costs and installation rates, environmental retrofits, and other specialized assumptions. Our sources are discussed in more detail in Sections II and III.

    Important Study Considerations

    As noted, the purpose of this study is to examine broad patterns of interaction between natural gas and renewable resources over the next twenty years. Our analysis is largely limited to interactions in the wholesale power markets and the large-scale transmission system, with limited representation of the distribution system and the retail sector. Moreover, our results are based on a set of scenarios that are necessarily smaller and narrower than the range of possible price and policy outcomes in the ERCOT region. To process a manageable number of scenarios, we necessarily made a number of assumptions and limited the options evaluated.

    First, we do not model scenarios with potential major technical breakthroughs, such as the development of significantly cheaper power storage or substantially cheaper carbon capture and sequestration (CCS). While we are certain that the future holds many technological surprises, we did not incorporate any of them into our limited set of scenarios.

    Second, increases in electric vehicle use or other new sources of demand or customer-sited supply are limited to those embedded within ERCOT’s most current net load and sales forecast. Texas utilities have continued to exceed their state energy efficiency goals for almost a decade now and are likely to have surpassed their 2013 goal of 30% reduction in demand growth.5 A study of efficiency efforts potential has not been conducted since 2008 but there it is likely great additional energy efficiency potential. Greater energy efficiency would reduce the rate of overall energy use as well as peak load growth below the current 1.7% average rate, reducing the need for resources of all types. While strong efficiency policies are certain to have an impact in total new generator additions, and are a fruitful area for further research and policymaking, it is not obvious how these improvements would affect the proportionate balance between gas and renewable resources.

    Third, the solar PV in our scenarios is best interpreted as utility-scale installations located at a set of sites at which solar irradiation approximately equals the ERCOT average we employ. These PV plants are also assumed to require transmission roughly equivalent to that needed for new fossil generation sited in the same regions.6 This omits any consideration of the unique impacts of large-scale deployment of rooftop or community-scale PV, which could reduce transmission import requirements, reduce or increase distribution system costs, and significantly change the pattern of distribution system loads and flows. We have also not examined in detail the possibility of co-locating PV with wind in the areas connected through the new CREZ lines. It is possible that locating PV systems there would lead to lower overall transmission costs relative to separate solar and wind sites.

    Fourth, our examination of demand response (DR) is limited to the large-scale approximations currently employed by ERCOT in its modeling efforts. Research in Texas and other markets suggests that there is substantial additional potential for price-responsive demand using an array of pricing, market, and policy measures. In particular, in the future some portion of rapidly-controllable DR could substitute for some of the gas-fired combustion turbines added in our scenario results. This remains an area for further study.

    Fifth, within the bulk power market, we assume that transmission costs do not vary between resources scenarios. Large wind build-outs in West Texas (including the panhandle region) are assumed to require an expansion of the CREZ system when new builds reach a threshold that renders the CREZ expansion economic. For modeling purposes, however, we assume that transmission additions throughout ERCOT are rolled in to statewide postage-stamp transmission tariffs, and are not a factor in generation developers’ decisions.

    Sixth, we have not considered the potential addition of concentrated solar power resources to the Texas energy mix. At present, we are unaware of any concrete plans for new CSP projects in ERCOT. Nonetheless, depending on the evolution of its cost as more and more CSP projects go online across the world, it is possible that CSP could play a role in the future ERCOT energy mix, given its ability to integrate some amount of storage and hence achieve a better coincidence with peak demand in electricity systems with heavy air conditioning load such as Texas.

    Finally, our modeling system does not formally include the impact of uncertainty in the future price of natural gas, nor does it reflect all of the time-variability of solar-electric output. We discuss the effect of these two directionally offsetting considerations further in the final results section below. In a later phase of this research, we hope to use our modeling system to explore the impacts of additional solar and demand response technologies together and in more detail, thus addressing some of the limitations in the present work…

    Concluding Observations

    Before offering some concluding thoughts, we briefly reiterate some of the important features of our analysis that were necessarily limited. First, the six scenarios we examine are certainly not a complete range of possible outcomes, nor are any of these scenarios our own predicted most likely path. Second, our modeling approach did not fully incorporate the effects of gas price uncertainty nor the full variability of solar energy. Third, we modeled only a specific set of large-scale supply alternatives, recognizing fully that other technologies exist today and that technical breakthroughs may change supply options in the future. Fourth, our models do not examine transmission expansion in much detail and assume that additional CREZ transmission would be built as needed following the current payment model. Fifth, we assume that all wind and solar tax supports other than the 10% ITC are phased out by 2018. Sixth, our scenarios including a required reserve margin make no assumptions about the detailed form of the rules that implement this requirement. Finally, we did not fully incorporate the effects of enhanced energy efficiency, demand response, distributed generation sources, or storage, all of which have significant potential and merit further study.

    Under this limited range of scenarios and assumptions, our results show that natural gas and renewables both play substantial roles in ERCOT and together provide all new generation. Within this definitive conclusion, however, the share of generation provided by these two forms of energy varies significantly. Under conditions of forecasted gas prices, expired renewables tax supports, and no breakthroughs in renewable capacity costs, the share of energy from renewable plants in Texas could actually decline from its current 12% level today to about 7% by 2032. At the other extreme, a strong federal carbon rule, higher gas prices, and lower renewable costs yields a future in which renewables supply 43% of ERCOT’s generation by 2032. In the less extreme scenarios, wind and solar grow to generation shares between 25 and 33%. Natural gas-fired generation provides all of the remaining incremental generation, adding 12 to 25 GW of new combined-cycle capacity.

    These results highlight the unsurprising conclusion that the mix of new gas and renewables generation is sensitive to the price of natural gas and cost declines in wind and solar power. Changes in these three factors can cause significant shifts in the mix of future installations, leading to a wide range of plausible generation shares for wind, solar, and natural gas. Higher gas prices were found to be more impactful than small declines in wind and solar costs, but by 2032 under nearly all conditions the cost of wind and solar both decline to the point where they are highly competitive with gas-fired power. Although it is difficult to discern from graphs that end in 2032, our results clearly indicate that wind and solar additions will dominate gas capacity in the later years of the 2030s and beyond.

    Our modeling approach allowed us to examine the importance of ancillary services and fast-responding natural gas capacity, the only fast-balancing option included in our study. We found that the ERCOT system could accommodate all levels of variable renewables likely to occur during this period with no reliability problems. However, accommodating higher levels of renewables required us to model an additional ancillary service, which we called “Intra-day Commitment option,” and to adjust the levels of current ancillary services. There are certainly other ways that market participants or ERCOT might achieve the same result.

    Among gas-fired power plants, nearly all future additions are combined-cycle plants rather than gas turbines. This is largely due to the fact that CCGTs are more efficient and new models are expected to increase their ability to start quickly and rapidly change output levels. The flexible modern gas technologies that are coming on line (both simple- and combined-cycle) will make it possible to accommodate higher renewable levels with fewer curtailments due to minimum generation and ramp constraints.

    The implementation of a reserve requirement helps improve the reserve margin, as intended. One of the effects of the reserve margin requirement is to delay the retirement of current gas-and oil-fired installations in ERCOT. Conversely, a required reserve margin slightly disfavors solar PV and peak-coincident wind energy, although it provides a small boost to Panhandle wind. However, while capacity installations are changed significantly by the required reserve policy, the generation mix (and thus air emissions) is much more sensitive to gas prices and other policies than the existence of a reserve margin.

    With respect to coal-fired plants, we find that existing units in ERCOT remain profitable and are not retired unless a relatively stringent federal carbon rule is adopted. Federal carbon rule requiring 90% capture and storage of carbon would prompt the retirement of most ERCOT coal units, while a 50% capture and storage rule reduces coal plant margins but does not force retirements. Under the strong federal rule scenario, gas and renewable generation would together replace the energy formerly supplied by coal plants. In this scenario renewable energy could rise to become 43% of ERCOT generation by 2032. New coal plants, which will almost certainly require carbon capture and sequestration, are not built in any scenario.

    Our analysis shows that greenhouse gas and other air pollution emissions vary greatly across the scenarios we examine with surprisingly moderate impacts on market prices. Carbon dioxide emissions are largely unchanged by the required reserve policy, but are reduced to zero growth by high gas prices and are reduced by as much as 66% versus 2012 levels in the remaining scenarios. In particular, the moderate carbon rule reduces CO2 by over 16% by 2032 and the strong rule reduces it by 66%. The same scenarios create comparable reductions in SO2 emissions and smaller but parallel reductions in NOx.29

    All these outcomes occur at average annual total costs of energy that are in broadly in keeping with historic energy prices and expectations. Using the year 2010 as the base, average annual total wholesale power costs increase from a low of 0.74% a year in the reference case with no required reserves to 2.5% a year under a strong federal carbon rule, high gas prices, and a required reserve margin. In these results, the strongest drivers of prices are higher gas prices and, starting in 2025, the effect of a strong carbon rule.

    Finally, we have noted several times that demand response and energy efficiency remain important elements of the Texas resource mix. Our scenarios confirm that DR is particularly important in the absence of a required reserve margin, and that further study and policy development for these resources is useful.

    The electric power industry is in an era of dramatic change, and the range of uncertainties surrounding the expansion of any power system has never been greater. Within this highly uncertain world, we find that the future of ERCOT’s power system is very likely to combine substantial amounts of both renewable energy and gas-fired power. The economic and environmental attractiveness of these electricity sources, the strong Texas resource base, and the evolution of power markets and systems all point to these energy options as the likely foundation of all new supplies to the ERCOT system in the next several decades ahead.


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