Atlantic Canada Opportunities Agency
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Atlantic Energy Gateway - Balancing Study Report

A Report on Potential Savings in the Case of a Common Unit Commitment and Dispatch Function for Atlantic Canada

Executive Summary

The Atlantic Energy Gateway (AEG) project is a regional initiative of the federal government, the Atlantic provincial governments, electric utilities of Atlantic Canada and the system operators in New Brunswick and Nova Scotia. The objective of the AEG project is to contribute to the development of Atlantic Canada's clean energy resources by identifying the opportunities and assisting in evaluating the advantages of the region’s substantial and diversified renewable energy potential for wind, tidal, solar, biomass/biofuels, geothermal and hydro.

The New Brunswick System Operator (NBSO) has studied the potential savings of a common unit commitment and dispatch function for balancing electricity supply and demand in Atlantic Canada. This work was undertaken at the request of the AEG Steering Committee and performed with direction from the AEG System Operations Technical Committee and an AEG Balancing Study subgroup.  Funding for third-party expenses was provided by the government of Canada in accordance with a contribution agreement.

Fig. 1 Separate BalancingThe fundamental hypothesis behind the study is that savings can be achieved by balancing electric power system resource demand and supply in Atlantic Canada on a common basis rather than separately as is done today. Currently New Brunswick, Northern Maine and Prince Edward Island are balanced as one balancing area.  Nova Scotia and Newfoundland are each balanced on their own as in indicated in Figure 1.

NBSO has no knowledge of a contemporary study of this nature having been undertaken by others.  It is, however, a commonly accepted belief that balancing supply and demand would be less expensive under a regional dispatch.  Diversity of both supply and demand is one driver of savings.  The ability to select supply from a broader portfolio of resources is another driver.

The introduction of intermittent renewable supplies (e.g. wind power, in-stream tidal, and solar) to the power system accentuates the benefits of a common regional dispatch because of the corresponding increase in the need for balancing.  A common regional dispatch can also ease the integration of more conventional but inflexible generation such as nuclear and some co-generation.

Figure 2 explains the sources of expected savings from using a single unit commitment and dispatch function to balance the regional power system in Atlantic Canada.

Fig. 2:  Nature of Expected Cost Savings with Regional Balancing

Cost  =  Quantity x Price

Lower balancing needs due to:
   - diverse consumption (lifestyle, time, season, weather, etc.)
   - diverse inflexible generation (nuclear, wind, tidal, cogeneration, etc.)
   - diverse timing of loss of supply

Less expensive to perform balancing due to:
   - size selection (start a small generator rather than a large generator)
   - flexibility (fast hydro vs. slow thermal units)
   - timing of generation outages and derates
   - timing of hydro conditions (run-off, dry spell, etc.)
   - removal of transmission tariff charges within region
This project created a model, database, and skill-set that could be used for future study work including:

  • an update of this balancing study with forecast errors included;
  • analyzing the impact of various quantities and types of renewable generation;
  • assessing the value of various dispatchable generation, load control, and storage options;
  • identifying the savings of other collaborative balancing options; and
  • quantifying the impact of various provincial and regional emissions policy options.

The opportunity to use this model and database for future regional studies is dependent on utility agreement to allow the confidential portions to persist and be used appropriately.

It is important to note that the results are specific to the timeframes indicated.  Additionally, the results are a function of the assumptions that were made regarding consumption characteristics, supply availability, and the characteristics of the supply.  The study was performed for two test years.  The 2010/11 test year was studied in order to validate the simulation model using actual historical data, and to quantify the potential savings of a common Maritime Provinces dispatch for the current power system.  The 2020 year was studied in order to quantify the potential savings of a common Atlantic Canada dispatch for a single year in which the system would include the Muskrat Falls hydro generation development and interprovincial transmission projects.  The supply resources for that test year would also include generation builds and retirements identified in the AEG Resource Development Technical Committee’s least cost combined integrated resource planning scenario.

The key results of the balancing study are summarized in Table 1.  The table shows savings in two timeframes.  The savings in the 2010/11 year estimate what could have been achieved had the balancing for the Maritime Provinces and northern Maine been performed collaboratively rather than having each of the New Brunswick/PEI/northern Maine system and the Nova Scotia system balanced on its own.  The simulation of the 2020 year estimates the savings of balancing the Atlantic Provinces and Northern Maine as one area rather than as three, given the anticipated expansion of the region’s intermittent renewable energy resources by 2020.  Further details and explanations of the cases are contained within this report.  All dollar figures in this report are in 2015 Canadian dollars unless otherwise indicated and were converted from then-current dollars based on 2% annual inflation.

Unit Commitment and Dispatch Savings

The study indicates a one-year savings in unit commitment and dispatch costs from combining balancing areas of approximately $25.1 million in the 2010/11 test year.  For the 2020 test year the savings indicated by the study are $7.9 million.

Ancillary Services Capacity Savings

Regulation and Load Following are services that are ancillary to electric demand and energy commodities and are used to perform the balancing function.  Regulation service involves adjusting the output of generators within seconds to match short term fluctuations in generation requirements.  Load Following service involves adjusting the output of generators over minutes up to an hour to match increasing or decreasing generator requirements.

Given the reduced requirements for capacity for regulation and load following the savings in the incremental capacity cost associated with these services (based on an assumed cost of $10/MW-h for Regulation, $8/MW-h for Load Following, and $7/MWh for 10-minute spinning reserve) is $0.4 million in 2010/11 and $0.7 million in 2020.

Table 1 Results Summary ($m in 2015 dollars)
  2010/11 2020
Impact of
Sharing (i.e.
One Area
Impact of
Sharing (i.e.
Transmission Current Current - Upgraded Upgraded -
Supply mix Current Current - Combined
Generation costs $840.8 $815.7 $25.1 $706.9 $644.8 $62.1
Costs of imports - - - $6.3 $5.2 $1.1
Revenue from exports - - - $196.8 $141.5 $55.3
Ancillary services costs $1.7 $1.3 $0.4 $2.4 $1.7 $0.7
Total $842.5 $817 $25.5 $518.8 $510.2 $8.6

Due to changes in the inputs, such as fuel costs, that occur over time, it is not valid to simply extrapolate these results out to multiple years.  However, these results do provide an indication of the order of magnitude of the potential savings. 

The model that has been built and validated can be used to study additional system configurations and time periods.  That work would require the assembly of the appropriate additional data, and permission from utilities to re-use the confidential data that was used in this study.  This study has also set a precedent for regional collaboration that could be extended beyond study work to greater collaboration in actual system operations.

This balancing study addresses some of the limitations of the study work that was performed in the AEG resource development study with respect to variability of energy needs, generator characteristics, and ancillary services.  Like all production cost studies, this balancing study complements, but is not a replacement for more technical reliability studies.

The production cost savings assessed in this study are not entirely incremental to those in the resource development study.  They are another view of the same type of costs, but with a more accurate reflection of how the power system operates.  The tradeoff for the operational accuracy is that it was only feasible to study relatively short periods of time (one year in each case) within the scope of the project. 

Building and using a model to simulate multiple years of operation would take longer and be more costly.  This balancing study does isolate the reduction in production costs achievable by operating with combined balancing areas rather than separate ones given the assumed transmission and generation plan.  To follow that transmission and generation plan without implementing regional dispatch would mean that the region would forego these potential savings.

The purpose of this study is to provide indicative quantification of the potential savings.  The results are intended to inform policy makers and help them evaluate the appropriateness of pursuing a common system balancing function.  These estimates of savings do not take into account the costs of implementing the common dispatch or the administrative savings of performing this activity on a regional basis. Furthermore, this study does not consider the potential costs or economies of scale associated with performing other system operations functions on a regional basis.  The impact of performing any system operator function, such as balancing, on a regional basis must account for impacts on various stakeholders including the allocation of the savings.

The savings identified in this report should be considered in conjunction with other AEG work product including those related to how a common regional dispatch might be achieved.  That being said, it is important to note that there are various models that have been suggested as a means to implement a common regional dispatch.  These include a regional system operator, contracting of services to one system operator, coordination agreements between utilities, and a regional system administrator.

The initial objectives of this study have largely been achieved.  A model has been built that addresses some of the limitations of other production cost models in how the power system is balanced operationally.  The potential savings of a common unit commitment and dispatch function for balancing electricity supply and demand in Atlantic Canada for the years 2010 and 2020 have been estimated as planned.  A robust and detailed set of wind power and consumption data has been created.  A set of simulated forecasts for both of these data sets has also been created.  The region has increased its knowledge and skill set with respect to modelling the regional power system. 

The study results and the non-confidential data are available for other analysis and study work related to regional system operations.  While the original objective of being able to sustain the model and portions of the associated database has not been achieved, future study work in the region can benefit from the non-confidential data, knowledge, and skill set produced by this exercise.

View related Atlantic Energy Gateway studies.