TODAY’S STUDY: DOUBLING WIND IN MID-ATLANTIC STATES CUTS ELECTRIC RATES
The Net Benefits of Increased Wind Power in PJM Final Report
May 9, 2013 (Synapse Energy Economics)
By the end of 2012, wind power accounted for roughly 3.4% of PJM’s installed capacity supply (6,300 MW of approximately 185,000 MW total, excluding demand side resources). It provided 12,634 GWh of annual energy, about 1.5%% of PJM’s total. Over the next 13 years, the presence of renewable portfolio standards (RPS) in the PJM states will result in significant increases in supplied renewable energy, with most of the increase coming from wind power. PJM States have RPS goals for renewable resources totaling roughly 14% of all energy consumed by 2026. PJM estimates that about 11 of the 14%, or 108,539 GWh total, will be from wind in 2026.4 In this analysis, we examine the effects of roughly doubling the level of currently projected wind power in PJM by 2026, with much of the increase in wind installations beyond that of the “RPS case” or base case coming in the last five years of the 2013-2026 horizon analyzed.
Increased transmission required to enable the base case will likely be in place by the turn of the decade or in the early part of the following decade, and additional transmission infrastructure coupled with the RPS case transmission overlays will allow for continuing integration of an increased amount of wind. Improved overall “flexibility”5 of the PJM system – arising from coal-fired power plant retirement and increasing installations of newer, flexible gas-fired combined cycle and combustion turbine resources coupled with key transmission improvements - will balance energy needs and allow the system to operate reliably even with a relatively high level of variable energy output from wind resources. Continuing declining costs and improving performance of wind power will lead to beneficial economic and emission results for consumers in PJM.
These findings, based on the modeled year 2026, validate an economic preference for an energy future with greater levels of wind power than current renewable portfolio standards suggest. It is a future where wind-powered resources displace a significant portion of energy that would otherwise be obtained from traditional fossil fuels, all the while retaining sufficient resource adequacy to ensure reliable grid operation.
Increased wind power displaces fossil-fueled generation, primarily gas and coal-fired production.
It lowers emissions and exerts downward price pressure on wholesale energy markets. While not analyzed in this report, it creates jobs in installation and manufacturing across both the PJM region and other parts of the country, and its lowering of emissions reduces health costs. Even adding in the cost of wind-enabling transmission and recognizing that ongoing installations of gasfired resources will be required to offset the retirement of coal plants and add balancing capacity to the system, a doubling of wind power by 2026 relative to what would otherwise be in place with current RPS standards will allow consumers to reap economic and emission benefits.
Purpose of Study
Synapse conducted this analysis to assess the overall economic and emissions effect on PJM ratepayers of alternative electricity futures that include higher levels of wind than will be seen under current renewable standards. By testing the effects of different combinations of increased renewable energy supply, increased transmission infrastructure, reductions in the use of fossilfueled resources, and increases in the overall flexibility of the thermal resource base in PJM, we are able to draw broad conclusions about the relative benefits and costs to consumers of pursuing a clean energy future in the PJM region that roughly doubles the amount of wind power that would otherwise be in place by 2026 under current standards.
Methodology and Key Assumptions
Synapse modeled the economic and emissions effects of a PJM electricity future in 2026 that includes significantly higher levels of renewable energy (primarily wind) than a reference case tied to current state renewable portfolio standards (RPS). The reference case achieves an aggregate 14% RPS by 2026 across the PJM States, with most of that (11%) sourced from wind. The two wind cases developed for this analysis roughly double that level of supplied renewable energy, with increased wind power. One wind case distributes the wind around the PJM region; a second wind case allows for a portion of the total wind to be sourced from higher-performing wind regions (the Midwest) and then imported into PJM via high voltage DC lines.7
The reference case includes transmission increases projected from PJM information on a planned RPS Overlay8, and the wind cases include incremental transmission beyond the planned RPS overlays to allow even higher levels of wind power to be integrated onto the grid. All cases include coal plant retirement and gas plant additions to ensure resource adequacy, and all cases presume that at least part of the cost of carbon emissions will be internalized; we use a $30/ton emissions adder for CO2 in 2026 to estimate this internalization. We ran one sensitivity without this adder for base and wind cases.
Synapse used the ProSym production cost modeling tool9 to gauge energy impacts in year 2026 for each case. ProSym is an hourly dispatch and unit commitment production cost model that provides a detailed picture of the operation of the electric power sector over the course of a year. It uses a 10-zone configuration for the PJM system, and it performs a unit commitment and economic dispatch for 168-hour “typical weeks” over the course of the year, respecting variations in wind output and outages of conventional generation. It is based on an extensive assumption set, including load, resource mix, transmission system configuration, fuel prices, and operational constraints. The model output includes generation by resource type, marginal prices, and transmission flows for hourly periods of the year 2026.
Synapse used a capital investment spreadsheet tool to track projected overall costs associated with generation, transmission, and demand response (DR) in each of the cases. It also tracked additional offshore wind capital costs for a sensitivity case. The tool tracked the year-by-year capital investment requirements, and used benchmark financial assumptions including a proxy for weighted average cost of capital, and depreciation periods to estimate annual revenue requirements associated with all new capital investment for each of the base and wind cases. Using the production cost modeling and capital investment accounting tool, Synapse computed production cost and energy market impacts from the wind cases, relative to the base case; and determined the incremental revenue requirements needed to pay for the increased capital investment of the wind cases. We then estimated the net impacts in 2026 of the alternative wind cases, relative to a base case using less wind (and more natural gas).
An additional production cost simulation run was executed to test the sensitivity of the results to increased levels of offshore wind. Additional model runs were also conducted to help determine how the power system responds to different sets of resource addition or transmission addition assumptions. The results of those model runs provided important insights into the economics of power system operation under different resource assumptions, and helped to shape the final sets of resource assumptions used in the wind scenarios.
The study did not build up overall rate impact effects on PJM consumers, but rather focused on the difference in aggregate impacts that would be seen from a base case when greater levels of wind are integrated onto the system. We note that net benefits accrue beyond the PJM region in this study, as the sizable increases in wind additions effect transfers at the PJM borders and the economic dispatch in adjacent Eastern Interconnection regions. The study added resource capacity to maintain planning reserve margins, with slightly higher margins for the wind cases in the out years (2020-2026) to address the increased operating reserve requirement that may be needed to integrate large levels of wind power. The study did not attempt to model any effects of the PJM RPM capacity market, which is a near-term, three-year forward construct. Our interest was long-term outcomes under clean energy scenarios; the annual revenue requirement construct was used to estimate the relative long-term investment outcomes.
Synapse presumes that at least a portion of the societal costs of carbon emissions will be internalized across the PJM system by 2026, and to support a consistent comparative framework, we assumed the same carbon emission cost in all three scenarios. To test the broad cost/benefit outcomes in the absence of a carbon emission cost, we ran the production cost model without the carbon cost adder for the base and PJM wind case, but leaving coal retirement assumptions unchanged. In those model runs, we found the broad results still show net benefit: the production cost savings exceeded the capital investment for a net benefit of roughly $2.6 billion/year in 2026.
Our key resource assumptions, listed in detail in Chapter 2, include the following:
Based on our findings, we conclude the following:
1. The cost to increase wind installations and wind output across the PJM region up to 2 times beyond what current renewable portfolio standards call for by 2026 (including the costs associated with increased transmission, and gas generation investment needed to maintain resource adequacy margins) is more than offset by production efficiency gains seen across the broader PJM and interconnected regions. Wind output displaces coal, gas and oil-fired generation; this displacement is the source of the production cost (and corresponding reduced emissions) benefits we observe in the modeling results.
2. We draw this conclusion based on the results of year 2026 ProSym production cost model runs, and our capacity/investment cost accounting model that includes the costs of all wind, transmission and gas resource supply requirements associated with the base and high wind scenarios. It estimates the annual investment cost requirements associated with each of the base and high wind cases, accounting for the timing of resource need and projections of investment or capital costs for the supply resources. The incremental investment costs for the high wind scenarios (compared to the base case) can be compared to the decreased production costs (compared to the base case) seen in the high wind cases.
3. By 2026, our modeled wind scenarios (total PJM wind = 65.4 GW) lead to a production cost savings on the order of $14.5 to $14.9 billion dollars per year ($2026) compared to the base scenario (total PJM wind = 32.1 GW) that includes roughly half that level of installed wind.
4. We computed annual revenue requirements for the incremental investment associated with the base and wind cases. The annual revenue requirement increase above the base case for the wind case ranges from $7.6 to $8.0 billion per year ($2026). Thus, net production cost efficiency gains from the increased wind scenarios are on the order of $6.9 billion per year by 2026, when the higher levels of wind are in place.
5. Production cost efficiency gains from improved average wind resource performance (from a portion of wind resources sourced from the higher-performing MISO region) are roughly offset by the increased transmission costs to deliver those resources to PJM.
6. PJM carbon emissions in the wind scenarios are 14% lower than base case emissions. SO2 emissions are 6% lower and NOx emissions are 10% lower than base case levels. Base case levels include the effect associated with retiring roughly 58 GW of coal-fired plants in PJM.
7. Load-weighted average annual energy market prices in the PJM zones are lower under the wind cases. Average annual energy prices differences for the PJM zones in aggregate are roughly $1.74/MWh lower for the wind cases, relative to base case prices. This is generally expected given that wind output reduces, or displaces, the use of fossilfueled resources that set the market clearing price in PJM. The price differences are greatest in the non-summer months, when wind output is highest, load is lowest and supply margins are greatest.
Notably for this study, peak load summer months see market prices higher in the wind cases relative to the base cases, reflecting the more difficult balancing act required in the high wind cases, the greater variation in wind output during those times, and the presence of a steep marginal cost of supply during those periods that renders clearing prices more sensitive to these factors than during less resource-tight months. In simpler terms: the wind cases see more summer peak period energy from “peaking” fossil resources, and less summer peak period energy from base-loaded and intermediate-loaded fossil resources, relative to the base case. This is a consequence of using economically optimal unit commitment and dispatch while respecting fossil-fuel plant operating constraints and the time profiles of wind output. It is also arises from increased exports from or reduced imports to the PJM zone, relative to the base case.
Prices in regions adjacent to PJM are also lower, as the interconnected nature of the grid results in greater flows from PJM to those neighboring regions than is seen in the base case. This illustrates that some of the production cost efficiency benefits seen in the study could flow outside the PJM region, depending on how individual resource and load contractual arrangements are structured throughout the areas.
8. If all production cost efficiency gains flow to consumers based on consumers paying the annual revenue requirements for incremental wind installed in the PJM region, then consumers are clearly much better off economically with increased wind resources, relative to a base case with less wind and more gas. In a market environment however, consumers would not pay the “annual revenue requirements” associated with the increases in wind power. Instead, they pay spot prices for power, and merchant investment would cover the costs of incremental wind – and receive spot market revenue streams. In this analysis, we assume that consumers both pay for the increased wind plant, and retain the production cost efficiencies that result.
9. Increasing the amount of “PJM wind” that is sourced from further west regions, in this analysis modeled as MISO-sourced wind, leads to incrementally greater wind performance and higher production cost efficiencies. These savings are roughly offset by increased transmission costs associated with delivering more of this wind to PJM via HVDC lines, the proxy delivery method used in this analysis.
Observations, Conclusions, and Next Steps
Observations and Conclusions
While analyzing the PJM system under different wind and gas resource addition assumptions, the modeling results clearly indicated that large, annual, net benefits from production cost efficiency gains exist for high wind scenarios. Displacing fossil-generated electricity with wind power leads to lower overall production costs. In most months, our modeling also indicates that PJM market prices are also lower in the wind cases. Tellingly, summer month periods with low levels of wind power output can still lead to higher market prices (compared to the base case) for those months in the high wind scenarios. This occurs because of the different mix of generation used, arising from the more complex operational solutions required (in the wind cases) when responding to large variations in wind energy output during those months. It is also influenced by the pattern of PJM to neighboring region imports and exports under the different scenarios. We summarize our observations and conclusions below.
1. Increased installation of wind power resources in the PJM region at roughly double the levels specified by existing RPS statutes lead to annual production cost reductions that range from $14.5 to $14.9 billion per year. This result, arising from the use of the ProSym production cost modeling tool, is based on a set of reasonable assumptions concerning future carbon costs in the electric sector, load, coal retirement levels, natural gas resource additions, improved transmission system infrastructure, and natural gas prices.
2. Consumers see significantly improved emission profiles in the wind scenarios. Carbon, SO2 and NOx emissions are all reduced.
3. The incremental costs to achieve these production cost gains ranges from $7.6 to $8.0 billion per year by 2026. This indicates that in general a planned expansion of wind power in the region will lead to net benefits for consumers.
4. The energy market price impact of a high wind case is seen to be relative high in nonsummer months, and market prices in the summer period are high in the wind cases. PJM consumers could be exposed to these market prices, but to the extent that PJM consumers pay for the incremental wind power assumed for the wind scenarios, consumers are hedged against those market prices. We assume that all production cost efficiency gains seen in this analysis flow to consumers, and all required investments are borne by consumers. We also note that the Eastern interconnection-wide nature of the energy modeling leads to a relative increase in exports from PJM in the wind cases, compared to the base case (with PJM net imports).
Additional analysis is required to determine the relative effects of varying any number of critical assumptions. To further test the robustness of the results seen in this analysis, Synapse recommends the following additional scenarios, or sensitivities, be analyzed using the production cost modeling and capital investment recovery model:
1. Assume large scale retirements of coal plant resources throughout the Eastern Interconnection, not just in the PJM region. A rebalancing of capacity requirements in each major area would be necessary to ensure resource adequacy.
2. Conduct iterative runs of the production cost modeling by incrementally stepping up transmission system transfer capacities, and simultaneously reducing the overall planning reserve margin, to optimize the tradeoffs between building more transmission and building sufficient balancing capacity with new gas-fired resources.
3. Continue to test production cost effects on different combinations of increased demandside resources, including energy efficiency and demand response. Given the relatively high summer period prices and transmission congestion during those periods, it appears that non-wind related constraints can lead to increasing production costs, since summer wind output is relatively low in the model.
4. Test the effects of multiple combinations of increasing wind, solar and energy efficiency resources.
5. Test varying potential cost profiles for offshore wind and solar resources.
6. Examine PJM boundary interactions, and assess the extent to which different import/export flow patterns are influenced by resource decisions within and outside of PJM.